[Title 40 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2016 Edition]
[From the U.S. Government Publishing Office]
[[Page i]]
Title 40
Protection of Environment
________________________
Part 60 (Sec. Sec. 60.1 to 60.499)
Revised as of July 1, 2016
Containing a codification of documents of general
applicability and future effect
As of July 1, 2016
Published by the Office of the Federal Register
National Archives and Records Administration as a
Special Edition of the Federal Register
[[Page ii]]
U.S. GOVERNMENT OFFICIAL EDITION NOTICE
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[[Page iii]]
As of July 1, 2016
Title 40, Part 60 (Sec. 60.1-end of part 60 sections)
Revised as of July 1, 2015
Is Replaced by
Title 40, Part 60 (Sec. Sec. 60.1-60.499)
and
Part 60 (Sec. Sec. 60.500-end of part 60 sections)
[[Page v]]
Table of Contents
Page
Explanation................................................. vii
Title 40:
Chapter I--Environmental Protection Agency 3
Finding Aids:
Table of CFR Titles and Chapters........................ 607
Alphabetical List of Agencies Appearing in the CFR...... 627
List of CFR Sections Affected........................... 637
[[Page vi]]
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Cite this Code: CFR
To cite the regulations in
this volume use title,
part and section number.
Thus, 40 CFR 60.1 refers
to title 40, part 60,
section 1.
----------------------------
[[Page vii]]
EXPLANATION
The Code of Federal Regulations is a codification of the general and
permanent rules published in the Federal Register by the Executive
departments and agencies of the Federal Government. The Code is divided
into 50 titles which represent broad areas subject to Federal
regulation. Each title is divided into chapters which usually bear the
name of the issuing agency. Each chapter is further subdivided into
parts covering specific regulatory areas.
Each volume of the Code is revised at least once each calendar year
and issued on a quarterly basis approximately as follows:
Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1
The appropriate revision date is printed on the cover of each
volume.
LEGAL STATUS
The contents of the Federal Register are required to be judicially
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie
evidence of the text of the original documents (44 U.S.C. 1510).
HOW TO USE THE CODE OF FEDERAL REGULATIONS
The Code of Federal Regulations is kept up to date by the individual
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To determine whether a Code volume has been amended since its
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EFFECTIVE AND EXPIRATION DATES
Each volume of the Code contains amendments published in the Federal
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OMB CONTROL NUMBERS
The Paperwork Reduction Act of 1980 (Pub. L. 96-511) requires
Federal agencies to display an OMB control number with their information
collection request.
[[Page viii]]
Many agencies have begun publishing numerous OMB control numbers as
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PAST PROVISIONS OF THE CODE
Provisions of the Code that are no longer in force and effect as of
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2001, consult the List of CFR Sections Affected compilations, published
for 1949-1963, 1964-1972, 1973-1985, and 1986-2000.
``[RESERVED]'' TERMINOLOGY
The term ``[Reserved]'' is used as a place holder within the Code of
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INCORPORATION BY REFERENCE
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This material, like any other properly issued regulation, has the force
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What is a proper incorporation by reference? The Director of the
Federal Register will approve an incorporation by reference only when
the requirements of 1 CFR part 51 are met. Some of the elements on which
approval is based are:
(a) The incorporation will substantially reduce the volume of
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(b) The matter incorporated is in fact available to the extent
necessary to afford fairness and uniformity in the administrative
process.
(c) The incorporating document is drafted and submitted for
publication in accordance with 1 CFR part 51.
What if the material incorporated by reference cannot be found? If
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CFR INDEXES AND TABULAR GUIDES
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alphabetical list of agencies publishing in the CFR are also included in
this volume.
[[Page ix]]
An index to the text of ``Title 3--The President'' is carried within
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the revision dates of the 50 CFR titles.
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INQUIRIES
For a legal interpretation or explanation of any regulation in this
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available at www.ecfr.gov.
Oliver A. Potts,
Director,
Office of the Federal Register.
July 1, 2016.
[[Page xi]]
THIS TITLE
Title 40--Protection of Environment is composed of thirty-seven
volumes. The parts in these volumes are arranged in the following order:
Parts 1-49, parts 50-51, part 52 (52.01-52.1018), part 52 (52.1019-
52.2019), part 52 (52.2020-end of part 52), parts 53-59, part 60 (60.1-
60.499) , part 60 (60.500-end of part 60, sections), part 60
(Appendices), parts 61-62, part 63 (63.1-63.599), part 63 (63.600-
63.1199), part 63 (63.1200-63.1439), part 63 (63.1440-63.6175), part 63
(63.6580-63.8830), part 63 (63.8980-end of part 63), parts 64-71, parts
72-79, part 80, part 81, parts 82-86, parts 87-95, parts 96-99, parts
100-135, parts 136-149, parts 150-189, parts 190-259, parts 260-265,
parts 266-299, parts 300-399, parts 400-424, parts 425-699, parts 700-
722, parts 723-789, parts 790-999, parts 1000-1059, and parts 1060 to
end. The contents of these volumes represent all current regulations
codified under this title of the CFR as of July 1, 2016.
Chapter I--Environmental Protection Agency appears in all thirty-
seven volumes. Regulations issued by the Council on Environmental
Quality, including an Index to Parts 1500 through 1508, appear in the
volume containing parts 1060 to end. The OMB control numbers for title
40 appear in Sec. 9.1 of this chapter.
For this volume, Ann Worley was Chief Editor. The Code of Federal
Regulations publication program is under the direction of John Hyrum
Martinez, assisted by Stephen J. Frattini.
[[Page 1]]
TITLE 40--PROTECTION OF ENVIRONMENT
(This book contains part 60, Sec. Sec. 60.1 to 60.499)
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Part
chapter i--Environmental Protection Agency (Continued)...... 60
[[Page 3]]
CHAPTER I--ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)
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Editorial Note: Nomenclature changes to chapter I appear at 65 FR
47324, 47325, Aug. 2, 2000; 66 FR 34375, 34376, June 28, 2001.
SUBCHAPTER C--AIR PROGRAMS (CONTINUED)
Part Page
60 Standards of performance for new stationary
sources................................. 5
[[Page 5]]
SUBCHAPTER C_AIR PROGRAMS (CONTINUED)
PART 60_STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES--Table of Contents
Subpart A_General Provisions
Sec.
60.1 Applicability.
60.2 Definitions.
60.3 Units and abbreviations.
60.4 Address.
60.5 Determination of construction or modification.
60.6 Review of plans.
60.7 Notification and record keeping.
60.8 Performance tests.
60.9 Availability of information.
60.10 State authority.
60.11 Compliance with standards and maintenance requirements.
60.12 Circumvention.
60.13 Monitoring requirements.
60.14 Modification.
60.15 Reconstruction.
60.16 Priority list.
60.17 Incorporations by reference.
60.18 General control device and work practice requirements.
60.19 General notification and reporting requirements.
Table 1 to Subpart A of Part 60--Detection Sensitivity Levels (grams per
hour)
Subpart B_Adoption and Submittal of State Plans for Designated
Facilities
60.20 Applicability.
60.21 Definitions.
60.22 Publication of guideline documents, emission guidelines, and final
compliance times.
60.23 Adoption and submittal of State plans; public hearings.
60.24 Emission standards and compliance schedules.
60.25 Emission inventories, source surveillance, reports.
60.26 Legal authority.
60.27 Actions by the Administrator.
60.28 Plan revisions by the State.
60.29 Plan revisions by the Administrator.
Subpart C_Emission Guidelines and Compliance Times
60.30 Scope.
60.31 Definitions.
Subpart Ca [Reserved]
Subpart Cb_Emissions Guidelines and Compliance Times for Large Municipal
Waste Combustors That Are Constructed on or Before September 20, 1994
60.30b Scope and delegation of authority.
60.31b Definitions.
60.32b Designated facilities.
60.33b Emission guidelines for municipal waste combustor metals, acid
gases, organics, and nitrogen oxides.
60.34b Emission guidelines for municipal waste combustor operating
practices.
60.35b Emission guidelines for municipal waste combustor operator
training and certification.
60.36b Emission guidelines for municipal waste combustor fugitive ash
emissions.
60.37b Emission guidelines for air curtain incinerators.
60.38b Compliance and performance testing.
60.39b Reporting and recordkeeping guidelines and compliance schedules.
Table 1 to Subpart Cb of Part 60--Nitrogen Oxides Guidelines for
Designated Facilities
Table 2 to Subpart Cb of Part 60--Nitrogen Oxides Limits for Existing
Designated Facilities Included in an Emissions Averaging Plan
at a Municipal Waste Combustor Plant
Table 3 to Subpart Cb of Part 60--Municipal Waste Combustor Operating
Guidelines
Subpart Cc_Emission Guidelines and Compliance Times for Municipal Solid
Waste Landfills
60.30c Scope.
60.31c Definitions.
60.32c Designated facilities.
60.33c Emission guidelines for municipal solid waste landfill emissions.
60.34c Test methods and procedures.
60.35c Reporting and recordkeeping guidelines.
60.36c Compliance times.
Subpart Cd_Emissions Guidelines and Compliance Times for Sulfuric Acid
Production Units
60.30d Designated facilities.
60.31d Emissions guidelines.
[[Page 6]]
60.32d Compliance times.
Subpart Ce_Emission Guidelines and Compliance Times for Hospital/
Medical/Infectious Waste Incinerators
60.30e Scope.
60.31e Definitions.
60.32e Designated facilities.
60.33e Emission guidelines.
60.34e Operator training and qualification guidelines.
60.35e Waste management guidelines.
60.36e Inspection guidelines.
60.37e Compliance, performance testing, and monitoring guidelines.
60.38e Reporting and recordkeeping guidelines.
60.39e Compliance times.
Table 1A to Subpart Ce of Part 60--Emissions Limits for Small, Medium,
and Large HMIWI at Designated Facilities as Defined in Sec.
60.32e(a)(1)
Table 1B to Subpart Ce of Part 60--Emissions Limits for Small, Medium,
and Large HMIWI at Designated Facilities as Defined in Sec.
60.32e(a)(1) and (a)(2)
Table 2A to Subpart Ce of Part 60--Emissions Limits for Small HMIWI
Which Meet the Criteria Under Sec. 60.33e(b)(1)
Table 2B to Subpart Ce of Part 60--Emissions Limits for Small HMIWI
Which Meet the Criteria Under Sec. 60.33e(b)(2)
Subpart D_Standards of Performance for Fossil-Fuel-Fired Steam
Generators
60.40 Applicability and designation of affected facility.
60.41 Definitions.
60.42 Standard for particulate matter (PM).
60.43 Standard for sulfur dioxide (SO2).
60.44 Standard for nitrogen oxides (NOX).
60.45 Emission and fuel monitoring.
60.46 Test methods and procedures.
Subpart Da_Standards of Performance for Electric Utility Steam
Generating Units
60.40Da Applicability and designation of affected facility.
60.41Da Definitions.
60.42Da Standard for particulate matter (PM).
60.43Da Standards for sulfur dioxide (SO2).
60.44Da Standards for nitrogen oxides (NOX).
60.45Da Alternative standards for combined nitrogen oxides
(NOX) and carbon monoxide (CO).
60.46Da [Reserved]
60.47Da Commercial demonstration permit.
60.48Da Compliance provisions.
60.49Da Emission monitoring.
60.50Da Compliance determination procedures and methods.
60.51Da Reporting requirements.
60.52Da Recordkeeping requirements.
Subpart Db_Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units
60.40b Applicability and delegation of authority.
60.41b Definitions.
60.42b Standard for sulfur dioxide (SO2).
60.43b Standard for particulate matter (PM).
60.44b Standard for nitrogen oxides (NOX).
60.45b Compliance and performance test methods and procedures for sulfur
dioxide.
60.46b Compliance and performance test methods and procedures for
particulate matter and nitrogen oxides.
60.47b Emission monitoring for sulfur dioxide.
60.48b Emission monitoring for particulate matter and nitrogen oxides.
60.49b Reporting and recordkeeping requirements.
Subpart Dc_Standards of Performance for Small Industrial-Commercial-
Institutional Steam Generating Units
60.40c Applicability and delegation of authority.
60.41c Definitions.
60.42c Standard for sulfur dioxide (SO2).
60.43c Standard for particulate matter (PM).
60.44c Compliance and performance test methods and procedures for sulfur
dioxide.
60.45c Compliance and performance test methods and procedures for
particulate matter.
60.46c Emission monitoring for sulfur dioxide.
60.47c Emission monitoring for particulate matter.
60.48c Reporting and recordkeeping requirements.
Subpart Ea_Standards of Performance for Municipal Waste Combustors for
Which Construction Is Commenced After December 20, 1989 and On or Before
September 20, 1994
60.50a Applicability and delegation of authority.
60.51a Definitions.
60.52a Standard for municipal waste combustor metals.
60.53a Standard for municipal waste combustor organics.
60.54a Standard for municipal waste combustor acid gases.
60.55a Standard for nitrogen oxides.
60.56a Standard for municipal waste combustor operating practices.
[[Page 7]]
60.57a [Reserved]
60.58a Compliance and performance testing.
60.59a Reporting and recordkeeping requirements.
Subpart Eb_Standards of Performance for Large Municipal Waste Combustors
for Which Construction is Commenced After September 20, 1994 or for
Which Modification or Reconstruction is Commenced After June 19, 1996
60.50b Applicability and delegation of authority.
60.51b Definitions.
60.52b Standards for municipal waste combustor metals, acid gases,
organics, and nitrogen oxides.
60.53b Standards for municipal waste combustor operating practices.
60.54b Standards for municipal waste combustor operator training and
certification.
60.55b Standards for municipal waste combustor fugitive ash emissions.
60.56b Standards for air curtain incinerators.
60.57b Siting requirements.
60.58b Compliance and performance testing.
60.59b Reporting and recordkeeping requirements.
Subpart Ec_Standards of Performance for New Stationary Sources:
Hospital/Medical/Infectious Waste Incinerators
60.50c Applicability and delegation of authority.
60.51c Definitions.
60.52c Emission limits.
60.53c Operator training and qualification requirements.
60.54c Siting requirements.
60.55c Waste management plan.
60.56c Compliance and performance testing.
60.57c Monitoring requirements.
60.58c Reporting and recordkeeping requirements.
Table 1 to Subpart Ec of Part 60--Emissions Limits for Small, Medium,
and Large HMIWI at Affected Facilities as Defined in Sec.
60.50c(a)(1) and (2)
Table 1A to Subpart Ec of Part 60--Emissions Limits for Small, Medium,
and Large HMIWI at Affected Facilities as Defined in Sec.
60.50c(a)(1) and (2)
Table 1B to Subpart Ec of Part 60--Emissions Limits for Small, Medium,
and Large HMIWI at Affected Facilities as Defined in Sec.
60.50c(a)(3) and (4)
Table 2 to Subpart Ec of Part 60--Toxic Equivalency Factors
Table 3 to Subpart Ec of Part 60--Operating Parameters To Be Monitored
and Minimum Measurement and Recording Frequencies
Subpart F_Standards of Performance for Portland Cement Plants
60.60 Applicability and designation of affected facility.
60.61 Definitions.
60.62 Standard for particulate matter.
60.63 Monitoring of operations.
60.64 Test methods and procedures.
60.65 Recordkeeping and reporting requirements.
60.66 Delegation of authority.
Subpart G_Standards of Performance for Nitric Acid Plants
60.70 Applicability and designation of affected facility.
60.71 Definitions.
60.72 Standard for nitrogen oxides.
60.73 Emission monitoring.
60.74 Test methods and procedures.
Subpart Ga_Standards of Performance for Nitric Acid Plants for Which
Construction, Reconstruction, or Modification Commenced After October
14, 2011
60.70a Applicability and designation of affected facility.
60.71a Definitions.
60.72a Standards.
60.73a Emissions testing and monitoring.
60.74a Affirmative defense for violations of emission standards during
malfunction.
60.75a Calculations.
60.76a Recordkeeping.
60.77a Reporting.
Subpart H_Standards of Performance for Sulfuric Acid Plants
60.80 Applicability and designation of affected facility.
60.81 Definitions.
60.82 Standard for sulfur dioxide.
60.83 Standard for acid mist.
60.84 Emission monitoring.
60.85 Test methods and procedures.
Subpart I_Standards of Performance for Hot Mix Asphalt Facilities
60.90 Applicability and designation of affected facility.
60.91 Definitions.
60.92 Standard for particulate matter.
60.93 Test methods and procedures.
Subpart J_Standards of Performance for Petroleum Refineries
60.100 Applicability, designation of affected facility, and
reconstruction.
60.101 Definitions.
60.102 Standard for particulate matter.
60.103 Standard for carbon monoxide.
[[Page 8]]
60.104 Standards for sulfur oxides.
60.105 Monitoring of emissions and operations.
60.106 Test methods and procedures.
60.107 Reporting and recordkeeping requirements.
60.108 Performance test and compliance provisions.
60.109 Delegation of authority.
Subpart Ja_Standards of Performance for Petroleum Refineries for Which
Construction, Reconstruction, or Modification Commenced After May 14,
2007
60.100a Applicability, designation of affected facility, and
reconstruction.
60.101a Definitions.
60.102a Emissions limitations.
60.103a Design, equipment, work practice or operational standards.
60.104a Performance tests.
60.105a Monitoring of emissions and operations for fluid catalytic
cracking units (FCCU) and fluid coking units (FCU).
60.106a Monitoring of emissions and operations for sulfur recovery
plants.
60.107a Monitoring of emissions and operations for fuel gas combustion
devices and flares.
60.108a Recordkeeping and reporting requirements.
60.109a Delegation of authority.
Table 1 to Subpart Ja of Part 60--Table 1 to subpart Ja of Part 60--
Molar Exhaust Volumes and Molar Heat Content of Fuel Gas
Constituents
Subpart K_Standards of Performance for Storage Vessels for Petroleum
Liquids for Which Construction, Reconstruction, or Modification
Commenced After June 11, 1973, and Prior to May 19, 1978
60.110 Applicability and designation of affected facility.
60.111 Definitions.
60.112 Standard for volatile organic compounds (VOC).
60.113 Monitoring of operations.
Subpart Ka_Standards of Performance for Storage Vessels for Petroleum
Liquids for Which Construction, Reconstruction, or Modification
Commenced After May 18, 1978, and Prior to July 23, 1984
60.110a Applicability and designation of affected facility.
60.111a Definitions.
60.112a Standard for volatile organic compounds (VOC).
60.113a Testing and procedures.
60.114a Alternative means of emission limitation.
60.115a Monitoring of operations.
Subpart Kb_Standards of Performance for Volatile Organic Liquid Storage
Vessels (Including Petroleum Liquid Storage Vessels) for Which
Construction, Reconstruction, or Modification Commenced After July 23,
1984
60.110b Applicability and designation of affected facility.
60.111b Definitions.
60.112b Standard for volatile organic compounds (VOC).
60.113b Testing and procedures.
60.114b Alternative means of emission limitation.
60.115b Reporting and recordkeeping requirements.
60.116b Monitoring of operations.
60.117b Delegation of authority.
Subpart L_Standards of Performance for Secondary Lead Smelters
60.120 Applicability and designation of affected facility.
60.121 Definitions.
60.122 Standard for particulate matter.
60.123 Test methods and procedures.
Subpart M_Standards of Performance for Secondary Brass and Bronze
Production Plants
60.130 Applicability and designation of affected facility.
60.131 Definitions.
60.132 Standard for particulate matter.
60.133 Test methods and procedures.
Subpart N_Standards of Performance for Primary Emissions from Basic
Oxygen Process Furnances for Which Construction is Commenced After June
11, 1973
60.140 Applicability and designation of affected facility.
60.141 Definitions.
60.142 Standard for particulate matter.
60.143 Monitoring of operations.
60.144 Test methods and procedures.
Subpart Na_Standards of Performance for Secondary Emissions from Basic
Oxygen Process Steelmaking Facilities for Which Construction is
Commenced After January 20, 1983
60.140a Applicability and designation of affected facilities.
60.141a Definitions.
60.142a Standards for particulate matter.
60.143a Monitoring of operations.
60.144a Test methods and procedures.
60.145a Compliance provisions.
[[Page 9]]
Subpart O_Standards of Performance for Sewage Treatment Plants
60.150 Applicability and designation of affected facility.
60.151 Definitions.
60.152 Standard for particulate matter.
60.153 Monitoring of operations.
60.154 Test methods and procedures.
60.155 Reporting.
60.156 Delegation of authority.
Subpart P_Standards of Performance for Primary Copper Smelters
60.160 Applicability and designation of affected facility.
60.161 Definitions.
60.162 Standard for particulate matter.
60.163 Standard for sulfur dioxide.
60.164 Standard for visible emissions.
60.165 Monitoring of operations.
60.166 Test methods and procedures.
Subpart Q_Standards of Performance for Primary Zinc Smelters
60.170 Applicability and designation of affected facility.
60.171 Definitions.
60.172 Standard for particulate matter.
60.173 Standard for sulfur dioxide.
60.174 Standard for visible emissions.
60.175 Monitoring of operations.
60.176 Test methods and procedures.
Subpart R_Standards of Performance for Primary Lead Smelters
60.180 Applicability and designation of affected facility.
60.181 Definitions.
60.182 Standard for particulate matter.
60.183 Standard for sulfur dioxide.
60.184 Standard for visible emissions.
60.185 Monitoring of operations.
60.186 Test methods and procedures.
Subpart S_Standards of Performance for Primary Aluminum Reduction Plants
60.190 Applicability and designation of affected facility.
60.191 Definitions.
60.192 Standard for fluorides.
60.193 Standard for visible emissions.
60.194 Monitoring of operations.
60.195 Test methods and procedures.
Subpart T_Standards of Performance for the Phosphate Fertilizer
Industry: Wet-Process Phosphoric Acid Plants
60.200 Applicability and designation of affected facility.
60.201 Definitions.
60.202 Standard for fluorides.
60.203 Monitoring of operations.
60.204 Test methods and procedures.
60.205 Recordkeeping.
Subpart U_Standards of Performance for the Phosphate Fertilizer
Industry: Superphosphoric Acid Plants
60.210 Applicability and designation of affected facility.
60.211 Definitions.
60.212 Standard for fluorides.
60.213 Monitoring of operations.
60.214 Test methods and procedures.
60.215 Recordkeeping.
Subpart V_Standards of Performance for the Phosphate Fertilizer
Industry: Diammonium Phosphate Plants
60.220 Applicability and designation of affected facility.
60.221 Definitions.
60.222 Standard for fluorides.
60.223 Monitoring of operations.
60.224 Test methods and procedures.
60.225 Recordkeeping.
Subpart W_Standards of Performance for the Phosphate Fertilizer
Industry: Triple Superphosphate Plants
60.230 Applicability and designation of affected facility.
60.231 Definitions.
60.232 Standard for fluorides.
60.233 Monitoring of operations.
60.234 Test methods and procedures.
60.235 Recordkeeping.
Subpart X_Standards of Performance for the Phosphate Fertilizer
Industry: Granular Triple Superphosphate Storage Facilities
60.240 Applicability and designation of affected facility.
60.241 Definitions.
60.242 Standard for fluorides.
60.243 Monitoring of operations.
60.244 Test methods and procedures.
60.245 Recordkeeping.
Subpart Y_Standards of Performance for Coal Preparation and Processing
Plants
60.250 Applicability and designation of affected facility.
60.251 Definitions.
60.252 Standards for thermal dryers.
60.253 Standards for pneumatic coal-cleaning equipment.
60.254 Standards for coal processing and conveying equipment, coal
storage systems, transfer and loading systems, and open
storage piles.
[[Page 10]]
60.255 Performance tests and other compliance requirements.
60.256 Continuous monitoring requirements.
60.257 Test methods and procedures.
60.258 Reporting and recordkeeping.
Subpart Z_Standards of Performance for Ferroalloy Production Facilities
60.260 Applicability and designation of affected facility.
60.261 Definitions.
60.262 Standard for particulate matter.
60.263 Standard for carbon monoxide.
60.264 Emission monitoring.
60.265 Monitoring of operations.
60.266 Test methods and procedures.
Subpart AA_Standards of Performance for Steel Plants: Electric Arc
Furnaces Constructed After October 21, 1974 and On or Before August 17,
1983
60.270 Applicability and designation of affected facility.
60.271 Definitions.
60.272 Standard for particulate matter.
60.273 Emission monitoring.
60.274 Monitoring of operations.
60.275 Test methods and procedures.
60.276 Recordkeeping and reporting requirements.
Subpart AAa_Standards of Performance for Steel Plants: Electric Arc
Furnaces and Argon-Oxygen Decarburization Vessels Constructed After
August 7, 1983
60.270a Applicability and designation of affected facility.
60.271a Definitions.
60.272a Standard for particulate matter.
60.273a Emission monitoring.
60.274a Monitoring of operations.
60.275a Test methods and procedures.
60.276a Recordkeeping and reporting requirements.
Subpart BB_Standards of Performance for Kraft Pulp Mills
60.280 Applicability and designation of affected facility.
60.281 Definitions.
60.282 Standard for particulate matter.
60.283 Standard for total reduced sulfur (TRS).
60.284 Monitoring of emissions and operations.
60.285 Test methods and procedures.
Subpart BBa_Standards of Performance for Kraft Pulp Mill Affected
Sources for Which Construction, Reconstruction, or Modification
Commenced After May 23, 2013
60.280a Applicability and designation of affected facility.
60.281a Definitions.
60.282a Standard for filterable particulate matter.
60.283a Standard for total reduced sulfur (TRS).
60.284a Monitoring of emissions and operations.
60.285a Test methods and procedures.
60.286a Affirmative defense for violations of emission standards during
malfunction.
60.287a Recordkeeping.
60.288a Reporting.
Subpart CC_Standards of Performance for Glass Manufacturing Plants
60.290 Applicability and designation of affected facility.
60.291 Definitions.
60.292 Standards for particulate matter.
60.293 Standards for particulate matter from glass melting furnace with
modified-processes.
60.294-60.295 [Reserved]
60.296 Test methods and procedures.
Subpart DD_Standards of Performance for Grain Elevators
60.300 Applicability and designation of affected facility.
60.301 Definitions.
60.302 Standard for particulate matter.
60.303 Test methods and procedures.
60.304 Modifications.
Subpart EE_Standards of Performance for Surface Coating of Metal
Furniture
60.310 Applicability and designation of affected facility.
60.311 Definitions and symbols.
60.312 Standard for volatile organic compounds (VOC).
60.313 Performance tests and compliance provisions.
60.314 Monitoring of emissions and operations.
60.315 Reporting and recordkeeping requirements.
60.316 Test methods and procedures.
Subpart FF [Reserved]
[[Page 11]]
Subpart GG_Standards of Performance for Stationary Gas Turbines
60.330 Applicability and designation of affected facility.
60.331 Definitions.
60.332 Standard for nitrogen oxides.
60.333 Standard for sulfur dioxide.
60.334 Monitoring of operations.
60.335 Test methods and procedures.
Subpart HH_Standards of Performance for Lime Manufacturing Plants
60.340 Applicability and designation of affected facility.
60.341 Definitions.
60.342 Standard for particulate matter.
60.343 Monitoring of emissions and operations.
60.344 Test methods and procedures.
Subpart KK_Standards of Performance for Lead-Acid Battery Manufacturing
Plants
60.370 Applicability and designation of affected facility.
60.371 Definitions.
60.372 Standards for lead.
60.373 Monitoring of emissions and operations.
60.374 Test methods and procedures.
Subpart LL_Standards of Performance for Metallic Mineral Processing
Plants
60.380 Applicability and designation of affected facility.
60.381 Definitions.
60.382 Standard for particulate matter.
60.383 Reconstruction.
60.384 Monitoring of operations.
60.385 Recordkeeping and reporting requirements.
60.386 Test methods and procedures.
Subpart MM_Standards of Performance for Automobile and Light Duty Truck
Surface Coating Operations
60.390 Applicability and designation of affected facility.
60.391 Definitions.
60.392 Standards for volatile organic compounds.
60.393 Performance test and compliance provisions.
60.394 Monitoring of emissions and operations.
60.395 Reporting and recordkeeping requirements.
60.396 Reference methods and procedures.
60.397 Modifications.
60.398 Innovative technology waivers.
Subpart NN_Standards of Performance for Phosphate Rock Plants
60.400 Applicability and designation of affected facility.
60.401 Definitions.
60.402 Standard for particulate matter.
60.403 Monitoring of emissions and operations.
60.404 Test methods and procedures.
Subpart PP_Standards of Performance for Ammonium Sulfate Manufacture
60.420 Applicability and designation of affected facility.
60.421 Definitions.
60.422 Standards for particulate matter.
60.423 Monitoring of operations.
60.424 Test methods and procedures.
Subpart QQ_Standards of Performance for the Graphic Arts Industry:
Publication Rotogravure Printing
60.430 Applicability and designation of affected facility.
60.431 Definitions and notations.
60.432 Standard for volatile organic compounds.
60.433 Performance test and compliance provisions.
60.434 Monitoring of operations and recordkeeping.
60.435 Test methods and procedures.
Subpart RR_Standards of Performance for Pressure Sensitive Tape and
Label Surface Coating Operations
60.440 Applicability and designation of affected facility.
60.441 Definitions and symbols.
60.442 Standard for volatile organic compounds.
60.443 Compliance provisions.
60.444 Performance test procedures.
60.445 Monitoring of operations and recordkeeping.
60.446 Test methods and procedures.
60.447 Reporting requirements.
Subpart SS_Standards of Performance for Industrial Surface Coating:
Large Appliances
60.450 Applicability and designation of affected facility.
60.451 Definitions.
60.452 Standard for volatile organic compounds.
60.453 Performance test and compliance provisions.
60.454 Monitoring of emissions and operations.
60.455 Reporting and recordkeeping requirements.
[[Page 12]]
60.456 Test methods and procedures.
Subpart TT_Standards of Performance for Metal Coil Surface Coating
60.460 Applicability and designation of affected facility.
60.461 Definitions.
60.462 Standards for volatile organic compounds.
60.463 Performance test and compliance provisions.
60.464 Monitoring of emissions and operations.
60.465 Reporting and recordkeeping requirements.
60.466 Test methods and procedures.
Subpart UU_Standards of Performance for Asphalt Processing and Asphalt
Roofing Manufacture
60.470 Applicability and designation of affected facilities.
60.471 Definitions.
60.472 Standards for particulate matter.
60.473 Monitoring of operations.
60.474 Test methods and procedures.
Subpart VV_Standards of Performance for Equipment Leaks of VOC in the
Synthetic Organic Chemicals Manufacturing Industry for which
Construction, Reconstruction, or Modification Commenced After January 5,
1981, and on or Before November 7, 2006
60.480 Applicability and designation of affected facility.
60.481 Definitions.
60.482-1 Standards: General.
60.482-2 Standards: Pumps in light liquid service.
60.482-3 Standards: Compressors.
60.482-4 Standards: Pressure relief devices in gas/vapor service.
60.482-5 Standards: Sampling connection systems.
60.482-6 Standards: Open-ended valves or lines.
60.482-7 Standards: Valves in gas/vapor service and in light liquid
service.
60.482-8 Standards: Pumps and valves in heavy liquid service, pressure
relief devices in light liquid or heavy liquid service, and
connectors.
60.482-9 Standards: Delay of repair.
60.482-10 Standards: Closed vent systems and control devices.
60.483-1 Alternative standards for valves--allowable percentage of
valves leaking.
60.483-2 Alternative standards for valves--skip period leak detection
and repair.
60.484 Equivalence of means of emission limitation.
60.485 Test methods and procedures.
60.486 Recordkeeping requirements.
60.487 Reporting requirements.
60.488 Reconstruction.
60.489 List of chemicals produced by affected facilities.
Subpart VVa_Standards of Performance for Equipment Leaks of VOC in the
Synthetic Organic Chemicals Manufacturing Industry for Which
Construction, Reconstruction, or Modification Commenced After November
7, 2006
60.480a Applicability and designation of affected facility.
60.481a Definitions.
60.482-1a Standards: General.
60.482-2a Standards: Pumps in light liquid service.
60.482-3a Standards: Compressors.
60.482-4a Standards: Pressure relief devices in gas/vapor service.
60.482-5a Standards: Sampling connection systems.
60.482-6a Standards: Open-ended valves or lines.
60.482-7a Standards: Valves in gas/vapor service and in light liquid
service.
60.482-8a Standards: Pumps, valves, and connectors in heavy liquid
service and pressure relief devices in light liquid or heavy
liquid service.
60.482-9a Standards: Delay of repair.
60.482-10a Standards: Closed vent systems and control devices.
60.482-11a Standards: Connectors in gas/vapor service and in light
liquid service.
60.483-1a Alternative standards for valves--allowable percentage of
valves leaking.
60.483-2a Alternative standards for valves--skip period leak detection
and repair.
60.484a Equivalence of means of emission limitation.
60.485a Test methods and procedures.
60.486a Recordkeeping requirements.
60.487a Reporting requirements.
60.488a Reconstruction.
60.489a List of chemicals produced by affected facilities.
Subpart WW_Standards of Performance for the Beverage Can Surface Coating
Industry
60.490 Applicability and designation of affected facility.
60.491 Definitions.
60.492 Standards for volatile organic compounds.
60.493 Performance test and compliance provisions.
60.494 Monitoring of emissions and operations.
60.495 Reporting and recordkeeping requirements.
60.496 Test methods and procedures.
[[Page 13]]
Authority: 42 U.S.C. 7401 et seq.
Source: 36 FR 24877, Dec. 23, 1971, unless otherwise noted.
Subpart A_General Provisions
Sec. 60.1 Applicability.
(a) Except as provided in subparts B and C, the provisions of this
part apply to the owner or operator of any stationary source which
contains an affected facility, the construction or modification of which
is commenced after the date of publication in this part of any standard
(or, if earlier, the date of publication of any proposed standard)
applicable to that facility.
(b) Any new or revised standard of performance promulgated pursuant
to section 111(b) of the Act shall apply to the owner or operator of any
stationary source which contains an affected facility, the construction
or modification of which is commenced after the date of publication in
this part of such new or revised standard (or, if earlier, the date of
publication of any proposed standard) applicable to that facility.
(c) In addition to complying with the provisions of this part, the
owner or operator of an affected facility may be required to obtain an
operating permit issued to stationary sources by an authorized State air
pollution control agency or by the Administrator of the U.S.
Environmental Protection Agency (EPA) pursuant to Title V of the Clean
Air Act (Act) as amended November 15, 1990 (42 U.S.C. 7661). For more
information about obtaining an operating permit see part 70 of this
chapter.
(d) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant
in Elkton, Virginia. (1) This paragraph applies only to the
pharmaceutical manufacturing facility, commonly referred to as the
Stonewall Plant, located at Route 340 South, in Elkton, Virginia
(``site'').
(2) Except for compliance with 40 CFR 60.49b(u), the site shall have
the option of either complying directly with the requirements of this
part, or reducing the site-wide emissions caps in accordance with the
procedures set forth in a permit issued pursuant to 40 CFR 52.2454. If
the site chooses the option of reducing the site-wide emissions caps in
accordance with the procedures set forth in such permit, the
requirements of such permit shall apply in lieu of the otherwise
applicable requirements of this part.
(3) Notwithstanding the provisions of paragraph (d)(2) of this
section, for any provisions of this part except for Subpart Kb, the
owner/operator of the site shall comply with the applicable provisions
of this part if the Administrator determines that compliance with the
provisions of this part is necessary for achieving the objectives of the
regulation and the Administrator notifies the site in accordance with
the provisions of the permit issued pursuant to 40 CFR 52.2454.
[40 FR 53346, Nov. 17, 1975, as amended at 55 FR 51382, Dec. 13, 1990;
59 FR 12427, Mar. 16, 1994; 62 FR 52641, Oct. 8, 1997]
Sec. 60.2 Definitions.
The terms used in this part are defined in the Act or in this
section as follows:
Act means the Clean Air Act (42 U.S.C. 7401 et seq.)
Administrator means the Administrator of the Environmental
Protection Agency or his authorized representative.
Affected facility means, with reference to a stationary source, any
apparatus to which a standard is applicable.
Alternative method means any method of sampling and analyzing for an
air pollutant which is not a reference or equivalent method but which
has been demonstrated to the Administrator's satisfaction to, in
specific cases, produce results adequate for his determination of
compliance.
Approved permit program means a State permit program approved by the
Administrator as meeting the requirements of part 70 of this chapter or
a Federal permit program established in this chapter pursuant to Title V
of the Act (42 U.S.C. 7661).
Capital expenditure means an expenditure for a physical or
operational change to an existing facility which exceeds the product of
the applicable ``annual asset guideline repair allowance percentage''
specified in the latest edition of Internal Revenue Service (IRS)
Publication 534 and the existing facility's basis, as defined by section
1012 of the Internal Revenue Code.
[[Page 14]]
However, the total expenditure for a physical or operational change to
an existing facility must not be reduced by any ``excluded additions''
as defined in IRS Publication 534, as would be done for tax purposes.
Clean coal technology demonstration project means a project using
funds appropriated under the heading `Department of Energy-Clean Coal
Technology', up to a total amount of $2,500,000,000 for commercial
demonstrations of clean coal technology, or similar projects funded
through appropriations for the Environmental Protection Agency.
Commenced means, with respect to the definition of new source in
section 111(a)(2) of the Act, that an owner or operator has undertaken a
continuous program of construction or modification or that an owner or
operator has entered into a contractual obligation to undertake and
complete, within a reasonable time, a continuous program of construction
or modification.
Construction means fabrication, erection, or installation of an
affected facility.
Continuous monitoring system means the total equipment, required
under the emission monitoring sections in applicable subparts, used to
sample and condition (if applicable), to analyze, and to provide a
permanent record of emissions or process parameters.
Electric utility steam generating unit means any steam electric
generating unit that is constructed for the purpose of supplying more
than one-third of its potential electric output capacity and more than
25 MW electrical output to any utility power distribution system for
sale. Any steam supplied to a steam distribution system for the purpose
of providing steam to a steam-electric generator that would produce
electrical energy for sale is also considered in determining the
electrical energy output capacity of the affected facility.
Equivalent method means any method of sampling and analyzing for an
air pollutant which has been demonstrated to the Administrator's
satisfaction to have a consistent and quantitatively known relationship
to the reference method, under specified conditions.
Excess Emissions and Monitoring Systems Performance Report is a
report that must be submitted periodically by a source in order to
provide data on its compliance with stated emission limits and operating
parameters, and on the performance of its monitoring systems.
Existing facility means, with reference to a stationary source, any
apparatus of the type for which a standard is promulgated in this part,
and the construction or modification of which was commenced before the
date of proposal of that standard; or any apparatus which could be
altered in such a way as to be of that type.
Force majeure means, for purposes of Sec. 60.8, an event that will
be or has been caused by circumstances beyond the control of the
affected facility, its contractors, or any entity controlled by the
affected facility that prevents the owner or operator from complying
with the regulatory requirement to conduct performance tests within the
specified timeframe despite the affected facility's best efforts to
fulfill the obligation. Examples of such events are acts of nature, acts
of war or terrorism, or equipment failure or safety hazard beyond the
control of the affected facility.
Isokinetic sampling means sampling in which the linear velocity of
the gas entering the sampling nozzle is equal to that of the undisturbed
gas stream at the sample point.
Issuance of a part 70 permit will occur, if the State is the
permitting authority, in accordance with the requirements of part 70 of
this chapter and the applicable, approved State permit program. When the
EPA is the permitting authority, issuance of a Title V permit occurs
immediately after the EPA takes final action on the final permit.
Malfunction means any sudden, infrequent, and not reasonably
preventable failure of air pollution control equipment, process
equipment, or a process to operate in a normal or usual manner. Failures
that are caused in part by poor maintenance or careless operation are
not malfunctions.
Modification means any physical change in, or change in the method
of operation of, an existing facility which
[[Page 15]]
increases the amount of any air pollutant (to which a standard applies)
emitted into the atmosphere by that facility or which results in the
emission of any air pollutant (to which a standard applies) into the
atmosphere not previously emitted.
Monitoring device means the total equipment, required under the
monitoring of operations sections in applicable subparts, used to
measure and record (if applicable) process parameters.
Nitrogen oxides means all oxides of nitrogen except nitrous oxide,
as measured by test methods set forth in this part.
One-hour period means any 60-minute period commencing on the hour.
Opacity means the degree to which emissions reduce the transmission
of light and obscure the view of an object in the background.
Owner or operator means any person who owns, leases, operates,
controls, or supervises an affected facility or a stationary source of
which an affected facility is a part.
Part 70 permit means any permit issued, renewed, or revised pursuant
to part 70 of this chapter.
Particulate matter means any finely divided solid or liquid
material, other than uncombined water, as measured by the reference
methods specified under each applicable subpart, or an equivalent or
alternative method.
Permit program means a comprehensive State operating permit system
established pursuant to title V of the Act (42 U.S.C. 7661) and
regulations codified in part 70 of this chapter and applicable State
regulations, or a comprehensive Federal operating permit system
established pursuant to title V of the Act and regulations codified in
this chapter.
Permitting authority means:
(1) The State air pollution control agency, local agency, other
State agency, or other agency authorized by the Administrator to carry
out a permit program under part 70 of this chapter; or
(2) The Administrator, in the case of EPA-implemented permit
programs under title V of the Act (42 U.S.C. 7661).
Proportional sampling means sampling at a rate that produces a
constant ratio of sampling rate to stack gas flow rate.
Reactivation of a very clean coal-fired electric utility steam
generating unit means any physical change or change in the method of
operation associated with the commencement of commercial operations by a
coal-fired utility unit after a period of discontinued operation where
the unit:
(1) Has not been in operation for the two-year period prior to the
enactment of the Clean Air Act Amendments of 1990, and the emissions
from such unit continue to be carried in the permitting authority's
emissions inventory at the time of enactment;
(2) Was equipped prior to shut-down with a continuous system of
emissions control that achieves a removal efficiency for sulfur dioxide
of no less than 85 percent and a removal efficiency for particulates of
no less than 98 percent;
(3) Is equipped with low-NOX burners prior to the time of
commencement of operations following reactivation; and
(4) Is otherwise in compliance with the requirements of the Clean
Air Act.
Reference method means any method of sampling and analyzing for an
air pollutant as specified in the applicable subpart.
Repowering means replacement of an existing coal-fired boiler with
one of the following clean coal technologies: atmospheric or pressurized
fluidized bed combustion, integrated gasification combined cycle,
magnetohydrodynamics, direct and indirect coal-fired turbines,
integrated gasification fuel cells, or as determined by the
Administrator, in consultation with the Secretary of Energy, a
derivative of one or more of these technologies, and any other
technology capable of controlling multiple combustion emissions
simultaneously with improved boiler or generation efficiency and with
significantly greater waste reduction relative to the performance of
technology in widespread commercial use as of November 15, 1990.
Repowering shall also include any oil and/or gas-fired unit which has
been awarded clean coal technology demonstration funding as of January
1, 1991, by the Department of Energy.
[[Page 16]]
Run means the net period of time during which an emission sample is
collected. Unless otherwise specified, a run may be either intermittent
or continuous within the limits of good engineering practice.
Shutdown means the cessation of operation of an affected facility
for any purpose.
Six-minute period means any one of the 10 equal parts of a one-hour
period.
Standard means a standard of performance proposed or promulgated
under this part.
Standard conditions means a temperature of 293 K (68F) and a
pressure of 101.3 kilopascals (29.92 in Hg).
Startup means the setting in operation of an affected facility for
any purpose.
State means all non-Federal authorities, including local agencies,
interstate associations, and State-wide programs, that have delegated
authority to implement: (1) The provisions of this part; and/or (2) the
permit program established under part 70 of this chapter. The term State
shall have its conventional meaning where clear from the context.
Stationary source means any building, structure, facility, or
installation which emits or may emit any air pollutant.
Title V permit means any permit issued, renewed, or revised pursuant
to Federal or State regulations established to implement title V of the
Act (42 U.S.C. 7661). A title V permit issued by a State permitting
authority is called a part 70 permit in this part.
Volatile Organic Compound means any organic compound which
participates in atmospheric photochemical reactions; or which is
measured by a reference method, an equivalent method, an alternative
method, or which is determined by procedures specified under any
subpart.
[44 FR 55173, Sept. 25, 1979, as amended at 45 FR 5617, Jan. 23, 1980;
45 FR 85415, Dec. 24, 1980; 54 FR 6662, Feb. 14, 1989; 55 FR 51382, Dec.
13, 1990; 57 FR 32338, July 21, 1992; 59 FR 12427, Mar. 16, 1994; 72 FR
27442, May 16, 2007]
Sec. 60.3 Units and abbreviations.
Used in this part are abbreviations and symbols of units of measure.
These are defined as follows:
(a) System International (SI) units of measure:
A--ampere
g--gram
Hz--hertz
J--joule
K--degree Kelvin
kg--kilogram
m--meter
m\3\--cubic meter
mg--milligram--10 -3 gram
mm--millimeter--10 -3 meter
Mg--megagram--10\6\ gram
mol--mole
N--newton
ng--nanogram--10 -9 gram
nm--nanometer--10 -9 meter
Pa--pascal
s--second
V--volt
W--watt
[ohm]--ohm
[micro]g--microgram--10 -6 gram
(b) Other units of measure:
Btu--British thermal unit
[deg]C--degree Celsius (centigrade)
cal--calorie
cfm--cubic feet per minute
cu ft--cubic feet
dcf--dry cubic feet
dcm--dry cubic meter
dscf--dry cubic feet at standard conditions
dscm--dry cubic meter at standard conditions
eq--equivalent
[deg]F--degree Fahrenheit
ft--feet
gal--gallon
gr--grain
g-eq--gram equivalent
hr--hour
in--inch
k--1,000
l--liter
lpm--liter per minute
lb--pound
meq--milliequivalent
min--minute
ml--milliliter
mol. wt.--molecular weight
ppb--parts per billion
ppm--parts per million
psia--pounds per square inch absolute
psig--pounds per square inch gage
[deg]R--degree Rankine
scf--cubic feet at standard conditions
scfh--cubic feet per hour at standard conditions
scm--cubic meter at standard conditions
sec--second
sq ft--square feet
std--at standard conditions
(c) Chemical nomenclature:
CdS--cadmium sulfide
[[Page 17]]
CO--carbon monoxide
CO2--carbon dioxide
HCl--hydrochloric acid
Hg--mercury
H2O--water
H2S--hydrogen sulfide
H2SO4--sulfuric acid
N2--nitrogen
NO--nitric oxide
NO2--nitrogen dioxide
NOX--nitrogen oxides
O2--oxygen
SO2--sulfur dioxide
SO3--sulfur trioxide
SOX--sulfur oxides
(d) Miscellaneous:
A.S.T.M.--American Society for Testing and Materials
[42 FR 37000, July 19, 1977; 42 FR 38178, July 27, 1977]
Sec. 60.4 Address.
(a) All requests, reports, applications, submittals, and other
communications to the Administrator pursuant to this part shall be
submitted in duplicate to the appropriate Regional Office of the U.S.
Environmental Protection Agency to the attention of the Director of the
Division indicated in the following list of EPA Regional Offices.
Region I (Connecticut, Maine, Massachusetts, New Hampshire, Rhode
Island, Vermont), Director, Office of Ecosystem Protection, U.S.
Environmental Protection Agency, 5 Post Office Square--Suite 100,
Boston, MA 02109-3912.
Region II (New Jersey, New York, Puerto Rico, Virgin Islands), Director,
Air and Waste Management Division, U.S. Environmental Protection Agency,
Federal Office Building, 26 Federal Plaza (Foley Square), New York, NY
10278.
Region III (Delaware, District of Columbia, Maryland, Pennsylvania,
Virginia, West Virginia), Director, Air Protection Division, Mail Code
3AP00, 1650 Arch Street, Philadelphia, PA 19103-2029.
Region IV (Alabama, Florida, Georgia, Kentucky, Mississippi, North
Carolina, South Carolina, Tennessee), Director, Air, Pesticides and
Toxics Management Division, U.S. Environmental Protection Agency, 61
Forsyth St. SW., Suite 9T43, Atlanta, Georgia 30303-8960.
Region V (Illinois, Indiana, Michigan, Minnesota, Ohio, Wisconsin),
Director, Air and Radiation Division, U.S. Environmental Protection
Agency, 77 West Jackson Boulevard, Chicago, IL 60604-3590.
Region VI (Arkansas, Louisiana, New Mexico, Oklahoma, Texas); Director;
Air, Pesticides, and Toxics Division; U.S. Environmental Protection
Agency, 1445 Ross Avenue, Dallas, TX 75202.
Region VII (Iowa, Kansas, Missouri, Nebraska), Director, Air and Waste
Management Division, 11201 Renner Boulevard, Lenexa, Kansas 66219.
Region VIII (Colorado, Montana, North Dakota, South Dakota, Utah,
Wyoming) Director, Air and Toxics Technical Enforcement Program, Office
of Enforcement, Compliance and Environmental Justice, Mail Code 8ENF-AT,
1595 Wynkoop Street, Denver, CO 80202-1129.
Region IX (Arizona, California, Hawaii and Nevada; the territories of
American Samoa and Guam; the Commonwealth of the Northern Mariana
Islands; the territories of Baker Island, Howland Island, Jarvis Island,
Johnston Atoll, Kingman Reef, Midway Atoll, Palmyra Atoll, and Wake
Islands; and certain U.S. Government activities in the freely associated
states of the Republic of the Marshall Islands, the Federated States of
Micronesia, and the Republic of Palau), Director, Air Division, U.S.
Environmental Protection Agency, 75 Hawthorne Street, San Francisco, CA
94105.
Region X (Alaska, Oregon, Idaho, Washington), Director, Air and Waste
Management Division, U.S. Environmental Protection Agency, 1200 Sixth
Avenue, Seattle, WA 98101.
(b) Section 111(c) directs the Administrator to delegate to each
State, when appropriate, the authority to implement and enforce
standards of performance for new stationary sources located in such
State. All information required to be submitted to EPA under paragraph
(a) of this section, must also be submitted to the appropriate State
Agency of any State to which this authority has been delegated
(provided, that each specific delegation may except sources from a
certain Federal or State reporting requirement). The appropriate mailing
address for those States whose delegation request has been approved is
as follows:
(A) [Reserved]
(B) State of Alabama: Alabama Department of Environmental
Management, P.O. Box 301463, Montgomery, Alabama 36130-1463.
(C) State of Alaska, Department of Environmental Conservation, Pouch
O, Juneau, AK 99811.
(D) Arizona:
Arizona Department of Environmental Quality, 1110 West Washington
Street, Phoenix, AZ 85007.
[[Page 18]]
Maricopa County Air Quality Department, 1001 North Central Avenue, Suite
900, Phoenix, AZ 85004.
Pima County Department of Environmental Quality, 33 North Stone Avenue,
Suite 700, Tucson, AZ 85701.
Pinal County Air Quality Control District, 31 North Pinal Street,
Building F, Florence, AZ 85132.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(E) State of Arkansas: Chief, Division of Air Pollution Control,
Arkansas Department of Pollution Control and Ecology, 8001 National
Drive, P.O. Box 9583, Little Rock, AR 72209.
(F) California:
Amador County Air Pollution Control District, 12200-B Airport Road,
Jackson, CA 95642.
Antelope Valley Air Quality Management District, 43301 Division Street,
Suite 206, Lancaster, CA 93535.
Bay Area Air Quality Management District, 939 Ellis Street, San
Francisco, CA 94109.
Butte County Air Quality Management District, 2525 Dominic Drive, Suite
J, Chico, CA 95928.
Calaveras County Air Pollution Control District, 891 Mountain Ranch
Road, San Andreas, CA 95249.
Colusa County Air Pollution Control District, 100 Sunrise Blvd., Suite
A-3, Colusa, CA 95932-3246.
El Dorado County Air Quality Management District, 2850 Fairlane Court,
Bldg. C, Placerville, CA 95667-4100.
Eastern Kern Air Pollution Control District, 2700 ``M'' Street, Suite
302, Bakersfield, CA 93301-2370.
Feather River Air Quality Management District, 1007 Live Oak Blvd.,
Suite B-3, Yuba City, CA 95991.
Glenn County Air Pollution Control District, 720 N. Colusa Street, P.O.
Box 351, Willows, CA 95988-0351.
Great Basin Unified Air Pollution Control District, 157 Short Street,
Suite 6, Bishop, CA 93514-3537.
Imperial County Air Pollution Control District, 150 South Ninth Street,
El Centro, CA 92243-2801.
Lake County Air Quality Management District, 885 Lakeport Blvd.,
Lakeport, CA 95453-5405.
Lassen County Air Pollution Control District, 707 Nevada Street, Suite
1, Susanville, CA 96130.
Mariposa County Air Pollution Control District, P.O. Box 5, Mariposa, CA
95338.
Mendocino County Air Quality Management District, 306 E. Gobbi Street,
Ukiah, CA 95482-5511.
Modoc County Air Pollution Control District, 619 North Main Street,
Alturas, CA 96101.
Mojave Desert Air Quality Management District, 14306 Park Avenue,
Victorville, CA 92392-2310.
Monterey Bay Unified Air Pollution Control District, 24580 Silver Cloud
Court, Monterey, CA 93940.
North Coast Unified Air Quality Management District, 2300 Myrtle Avenue,
Eureka, CA 95501-3327.
Northern Sierra Air Quality Management District, 200 Litton Drive, Suite
320, P.O. Box 2509, Grass Valley, CA 95945-2509.
Northern Sonoma County Air Pollution Control District, 150 Matheson
Street, Healdsburg, CA 95448-4908.
Placer County Air Pollution Control District, 3091 County Center Drive,
Suite 240, Auburn, CA 95603.
Sacramento Metropolitan Air Quality Management District, 777 12th
Street, Third Floor, Sacramento, CA 95814-1908.
San Diego County Air Pollution Control District, 10124 Old Grove Road,
San Diego, CA 92131-1649.
San Joaquin Valley Air Pollution Control District, 1990 E. Gettysburg,
Fresno, CA 93726.
San Luis Obispo County Air Pollution Control District, 3433 Roberto
Court, San Luis Obispo, CA 93401-7126.
Santa Barbara County Air Pollution Control District, 260 North San
Antonio Road, Suite A, Santa Barbara, CA 93110-1315.
Shasta County Air Quality Management District, 1855 Placer Street, Suite
101, Redding, CA 96001-1759.
Siskiyou County Air Pollution Control District, 525 So. Foothill Drive,
Yreka, CA 96097-3036.
South Coast Air Quality Management District, 21865 Copley Drive, Diamond
Bar, CA 91765-4182.
Tehama County Air Pollution Control District, P.O. Box 8069 (1750 Walnut
Street), Red Bluff, CA 96080-0038.
Tuolumne County Air Pollution Control District, 22365 Airport, Columbia,
CA 95310.
Ventura County Air Pollution Control District, 669 County Square Drive,
2nd Floor, Ventura, CA 93003-5417.
Yolo-Solano Air Quality Management District, 1947 Galileo Court, Suite
103, Davis, CA 95616-4882.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(G) State of Colorado, Department of Public Health and Environment,
4300 Cherry Creek Drive South, Denver, CO 80222-1530.
Note: For a table listing Region VIII's NSPS delegation status, see
paragraph (c) of this section.
[[Page 19]]
(H) State of Connecticut, Bureau of Air Management, Department of
Environmental Protection, State Office Building, 165 Capitol Avenue,
Hartford, CT 06106.
(I) State of Delaware, Department of Natural Resources &
Environmental Control, 89 Kings Highway, P.O. Box 1401, Dover, Delaware
19903.
(J) District of Columbia, Department of Public Health, Air Quality
Division, 51 N Street, NE., Washington, DC 20002.
(K) State of Florida: Florida Department of Environmental
Protection, Division of Air Resources Management, 2600 Blair Stone Road,
MS 5500, Tallahassee, Florida 32399-2400.
(L) State of Georgia: Georgia Department of Natural Resources,
Environmental Protection Division, Air Protection Branch, 4244
International Parkway, Suite 120, Atlanta, Georgia 30354.
(M) Hawaii:
Clean Air Branch, Hawaii Department of Health, 919 Ala Moana Blvd.,
Suite 203, Honolulu, HI 96814.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(N) State of Idaho, Department of Health and Welfare, Statehouse,
Boise, ID 83701.
(O) State of Illinois: Illinois Environmental Protection Agency,
1021 North Grand Avenue East, Springfield, Illinois 62794.
(P) State of Indiana: Indiana Department of Environmental
Management, Office of Air Quality, 100 North Senate Avenue,
Indianapolis, Indiana 46204.
(Q) State of Iowa: Iowa Department of Natural Resources,
Environmental Protection Division, Air Quality Bureau, 7900 Hickman
Road, Suite 1, Urbandale, IA 50322.
(R) State of Kansas: Kansas Department of Health and Environment,
Bureau of Air and Radiation, 1000 S.W. Jackson, Suite 310, Topeka, KS
66612-1366.
(S) Commonwealth of Kentucky: Commonwealth of Kentucky, Energy and
Environment Cabinet, Department of Environmental Protection, Division
for Air Quality, 200 Fair Oaks Lane, 1st Floor, Frankfort, Kentucky
40610-1403.
Louisville Metro Air Pollution Control District, 850 Barret Avenue,
Louisville, Kentucky 40204.
(T) State of Louisiana: Louisiana Department of Environmental
Quality, P.O. Box 4301, Baton Rouge, Louisiana 70821-4301.
Note: For a list of delegated standards for Louisiana (excluding
Indian country), see paragraph (e)(2) of this section.
(U) State of Maine, Bureau of Air Quality Control, Department of
Environmental Protection, State House, Station No. 17, Augusta, ME
04333.
(V) State of Maryland, Department of the Environment, 1800
Washington Boulevard, Suite 705, Baltimore, Maryland 21230.
(W) Commonwealth of Massachusetts, Division of Air Quality Control,
Department of Environmental Protection, One Winter Street, 7th floor,
Boston, MA 02108.
(X) State of Michigan: Michigan Department of Natural Resources and
Environment, Air Quality Division, P.O. Box 30028, Lansing, Michigan
48909.
(Y) State of Minnesota: Minnesota Pollution Control Agency, Division
of Air Quality, 520 Lafayette Road North, St. Paul, Minnesota 55155.
(Z) State of Mississippi: Hand Deliver or Courier: Mississippi
Department of Environmental Quality, Office of Pollution Control, Air
Division, 515 East Amite Street, Jackson, Mississippi 39201, Mailing
Address: Mississippi Department of Environmental Quality, Office of
Pollution Control, Air Division, P.O. Box 2261, Jackson, Mississippi
39225.
(AA) State of Missouri: Missouri Department of Natural Resources,
Division of Environmental Quality, P.O. Box 176, Jefferson City, MO
65102.
(BB) State of Montana, Department of Environmental Quality, 1520 E.
6th Ave., PO Box 200901, Helena, MT 59620-0901.
Note: For a table listing Region VIII's NSPS delegation status, see
paragraph (c) of this section.
(CC) State of Nebraska, Nebraska Department of Environmental
Control, P.O. Box 94877, State House Station, Lincoln, NE 68509.
Lincoln-Lancaster County Health Department, Division of Environmental
Health, 2200 St. Marys Avenue, Lincoln, NE 68502
(DD) Nevada:
Nevada Division of Environmental Protection, 901 South Stewart Street,
Suite 4001, Carson City, NV 89701-5249.
Clark County Department of Air Quality and Environmental Management, 500
S. Grand Central Parkway, 1st Floor, P.O. Box 555210, Las Vegas, NV
89155-5210.
Washoe County Health District, Air Quality Management Division, 1001 E.
9th Street, Building A, Suite 115A, Reno, NV 89520.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(EE) State of New Hampshire, Air Resources Division, Department of
Environmental Services, 64 North Main Street, Caller Box 2033, Concord,
NH 03302-2033.
(FF) State of New Jersey: New Jersey Department of Environmental
Protection, Division of Environmental Quality, Enforcement Element, John
Fitch Plaza, CN-027, Trenton, NJ 08625.
(1) The following table lists the specific source and pollutant
categories
[[Page 20]]
that have been delegated to the states in Region II. The (X) symbol is
used to indicate each category that has been delegated.
----------------------------------------------------------------------------------------------------------------
State
Subpart -----------------------------------------------------------------------
New Jersey New York Puerto Rico Virgin Islands
----------------------------------------------------------------------------------------------------------------
D Fossil-Fuel Fired Steam X............... X............... X............... X
Generators for Which
Construction Commenced
After August 17, 1971
(Steam Generators and
Lignite Fired Steam
Generators).
Da Electric Utility Steam X............... X...............
Generating Units for
Which Construction
Commenced After September
18, 1978.
Db Industrial-Commercial- X............... X............... X............... X
Institutional Steam
Generating Units.
E Incinerators.............. X............... X............... X............... X
F Portland Cement Plants.... X............... X............... X............... X
G Nitric Acid Plants........ X............... X............... X............... X
H Sulfuric Acid Plants...... X............... X............... X............... X
I Asphalt Concrete Plants... X............... X............... X............... X
J Petroleum Refineries--(All X............... X............... X............... X
Categories).
K Storage Vessels for X............... X............... X............... X
Petroleum Liquids
Constructed After June
11, 1973, and prior to
May 19, 1978.
Ka Storage Vessels for X............... X............... X...............
Petroleum Liquids
Constructed After May 18,
1978.
L Secondary Lead Smelters... X............... X............... X............... X
M Secondary Brass and Bronze X............... X............... X............... X
Ingot Production Plants.
N Iron and Steel Plants..... X............... X............... X............... X
O Sewage Treatment Plants... X............... X............... X............... X
P Primary Copper Smelters... X............... X............... X............... X
Q Primary Zinc Smelters..... X............... X............... X............... X
R Primary Lead Smelters..... X............... X............... X............... X
S Primary Aluminum Reduction X............... X............... X............... X
Plants.
T Phosphate Fertilizer X............... X............... X............... X
Industry: Wet Process
Phosphoric Acid Plants.
U Phosphate Fertilizer X............... X............... X............... X
Industry: Superphosphoric
Acid Plants.
V Phosphate Fertilizer X............... X............... X............... X
Industry: Diammonium
Phosphate Plants.
W Phosphate Fertilizer X............... X............... X............... X
Industry: Triple
Superphosphate Plants.
X Phosphate Fertilizer X............... X............... X............... X
Industry: Granular Triple
Superphosphate.
Y Coal Preparation Plants... X............... X............... X............... X
Z Ferroally Production X............... X............... X............... X
Facilities.
AA Steel Plants: Electric Arc X............... X............... X............... X
Furnaces.
AAa Electric Arc Furnaces and X............... X............... X...............
Argon-Oxygen
Decarburization Vessels
in Steel Plants.
BB Kraft Pulp Mills.......... X............... X............... X...............
CC Glass Manufacturing Plants X............... X............... X...............
DD Grain Elevators........... X............... X............... X...............
EE Surface Coating of Metal X............... X............... X...............
Furniture.
GG Stationary Gas Turbines... X............... X............... X...............
HH Lime Plants............... X............... X............... X...............
KK Lead Acid Battery X............... X...............
Manufacturing Plants.
LL Metallic Mineral X............... X............... X...............
Processing Plants.
MM Automobile and Light-Duty X............... X...............
Truck Surface Coating
Operations.
NN Phosphate Rock Plants..... X............... X...............
PP Ammonium Sulfate X............... X...............
Manufacturing Plants.
QQ Graphic Art Industry X............... X............... X............... X
Publication Rotogravure
Printing.
RR Pressure Sensitive Tape X............... X............... X...............
and Label Surface Coating
Operations.
SS Industrial Surface X............... X............... X...............
Coating: Large Appliances.
TT Metal Coil Surface Coating X............... X............... X...............
UU Asphalt Processing and X............... X............... X...............
Asphalt Roofing
Manufacture.
VV Equipment Leaks of X............... X...............
Volatile Organic
Compounds in Synthetic
Organic Chemical
Manufacturing Industry.
WW Beverage Can Surface X............... X............... X...............
Coating Industry.
XX Bulk Gasoline Terminals... X............... X............... X...............
FFF Flexible Vinyl and X............... X............... X...............
Urethane Coating and
Printing.
GGG Equipment Leaks of VOC in X............... X...............
Petroleum Refineries.
HHH Synthetic Fiber Production X............... X...............
Facilities.
JJJ Petroleum Dry Clearners... X............... X............... X...............
KKK Equipment Leaks of VOC
from Onshore Natural Gas
Processing Plants.
LLL Onshore Natural Gas X...............
Processing Plants; SO2
Emissions.
OOO Nonmetallic Mineral X............... X...............
Processing Plants.
PPP Wool Fiberglass Insulation X............... X...............
Manufacturing Plants.
----------------------------------------------------------------------------------------------------------------
[[Page 21]]
(GG) State of New Mexico: New Mexico Environment Department, P.O.
Box 5469, Santa Fe, New Mexico 87502-5469. Note: For a list of delegated
standards for New Mexico (excluding Bernalillo County and Indian
country), see paragraph (e)(1) of this section.
(i) Albuquerque-Bernalillo County Air Quality Control Board, c/o
Environmental Health Department, P.O. Box 1293, Albuquerque, New Mexico
87103.
(ii) [Reserved]
(HH) New York: New York State Department of Environmental
Conservation, 50 Wolf Road Albany, New York 12233, attention: Division
of Air Resources.
(II) State of North Carolina: North Carolina Department of
Environment and Natural Resources, Division of Air Quality, 1641 Mail
Service Center, Raleigh, North Carolina 27699-1641 or local agencies,
Forsyth County Environmental Affairs, 201 North Chestnut Street,
Winston-Salem, North Carolina 27101 or Forsyth County Air Quality
Section, 537 North Spruce Street, Winston-Salem, North Carolina 27101;
Mecklenburg County Land Use & Environmental Services Agency, Air
Quality, 700 N. Tryon St., Suite 205, Charlotte, North Carolina 28202-
2236; Western North Carolina Regional Air Quality Agency, 49 Mount
Carmel Road, Asheville, North Carolina 28806.
(JJ) State of North Dakota, Division of Air Quality, North Dakota
Department of Health, P.O. Box 5520, Bismarck, ND 58506-5520.
Note: For a table listing Region VIII's NSPS delegation status, see
paragraph (c) of this section.
(KK) State of Ohio:
(i) Medina, Summit and Portage Counties; Director, Akron Regional
Air Quality Management District, 146 South High Street, Room 904, Akron,
OH 44308.
(ii) Stark County; Director, Canton City Health Department, Air
Pollution Control Division, 420 Market Avenue North, Canton, Ohio 44702-
1544.
(iii) Butler, Clermont, Hamilton, and Warren Counties; Director,
Hamilton County Department of Environmental Services, 250 William Howard
Taft Road, Cincinnati, Ohio 45219-2660.
(iv) Cuyahoga County; Commissioner, Cleveland Department of Public
Health, Division of Air Quality, 75 Erieview Plaza 2nd Floor, Cleveland,
Ohio 44114.
(v) Clark, Darke, Greene, Miami, Montgomery, and Preble Counties;
Director, Regional Air Pollution Control Agency, 117 South Main Street,
Dayton, Ohio 45422-1280.
(vi) Lucas County and the City of Rossford (in Wood County);
Director, City of Toledo, Division of Environmental Services, 348 South
Erie Street, Toledo, OH 43604.
(vii) Adams, Brown, Lawrence, and Scioto Counties; Portsmouth Local
Air Agency, 605 Washington Street, Third Floor, Portsmouth, OH 45662.
(viii) Allen, Ashland, Auglaize, Crawford, Defiance, Erie, Fulton,
Hancock, Hardin, Henry, Huron, Marion, Mercer, Ottawa, Paulding, Putnam,
Richland, Sandusky, Seneca, Van Wert Williams, Wood (Except City of
Rossford), and Wyandot Counties; Ohio Environmental Protection Agency,
Northwest District Office, Air Pollution Control, 347 North Dunbridge
Road, Bowling Green, Ohio 43402.
(ix) Ashtabula, Caroll, Colombiana, Holmes, Lorain, and Wayne
Counties; Ohio Environmental Protection Agency, Northeast District
Office, Air Pollution Unit, 2110 East Aurora Road, Twinsburg, OH 44087.
(x) Athens, Belmont, Coshocton, Gallia, Guemsey, Harrison, Hocking,
Jackson, Jefferson, Meigs, Monroe, Morgan, Muskingum, Noble, Perry,
Pike, Ross, Tuscarawas, Vinton, and Washington Counties; Ohio
Environmental Protection Agency, Southeast District Office, Air
Pollution Unit, 2195 Front Street, Logan, OH 43138.
(xi) Champaign, Clinton, Highland, Logan, and Shelby Counties; Ohio
Environmental Protection Agency, Southwest District Office, Air
Pollution Unit, 401 East Fifth Street, Dayton, Ohio 45402-2911.
(xii) Delaware, Fairfield, Fayette, Franklin, Knox, Licking,
Madison, Morrow, Pickaway, and Union Counties; Ohio Environmental
Protection Agency, Central District Office, Air Pollution control, 50
West Town Street, Suite 700, Columbus, Ohio 43215.
(xiii) Geauga and Lake Counties; Lake County General Health
District, Air Pollution Control, 33 Mill Street, Painesville, OH 44077.
(xiv) Mahoning and Trumbull Counties; Mahoning-Trumbull Air
Pollution Control Agency, 345 Oak Hill Avenue, Suite 200, Youngstown, OH
44502.
(LL) State of Oklahoma, Oklahoma State Department of Health, Air
Quality Service, P.O. Box 53551, Oklahoma City, OK 73152.
(i) Oklahoma City and County: Director, Oklahoma City-County Health
Department, 921 Northeast 23rd Street, Oklahoma City, OK 73105.
(ii) Tulsa County: Tulsa City-County Health Department, 4616 East
Fifteenth Street, Tulsa, OK 74112.
(MM) State of Oregon. (i) Oregon Department of Environmental Quality
(ODEQ), 811 SW Sixth Avenue, Portland, OR 97204-1390, http://
www.deq.state.or.us.
(ii) Lane Regional Air Pollution Authority (LRAPA), 1010 Main
Street, Springfield, Oregon 97477, http://www.lrapa.org.
(NN)(i) City of Philadelphia, Department of Public Health, Air
Management Services, 321 University Avenue, Philadelphia, Pennsylvania
19104.
[[Page 22]]
(ii) Commonwealth of Pennsylvania, Department of Environmental
Protection, Bureau of Air Quality Control, P.O. Box 8468, 400 Market
Street, Harrisburg, Pennsylvania 17105.
(iii) Allegheny County Health Department, Bureau of Environmental
Quality, Division of Air Quality, 301 39th Street, Pittsburgh,
Pennsylvania 15201.
(OO) State of Rhode Island, Division of Air and Hazardous Materials,
Department of Environmental Management, 291 Promenade Street,
Providence, RI 02908.
(PP) State of South Carolina: South Carolina Department of Health
and Environmental Control, 2600 Bull Street, Columbia, South Carolina
29201.
(QQ) State of South Dakota, Air Quality Program, Department of
Environment and Natural Resources, Joe Foss Building, 523 East Capitol,
Pierre, SD 57501-3181.
Note: For a table listing Region VIII's NSPS delegation status, see
paragragh (c) of this section.
(RR) State of Tennessee: Tennessee Department of Environment and
Conservation, Division of Air Pollution Control, 401 Church Street, 9th
Floor, L&C Annex, Nashville, Tennessee 37243-1531.
Knox County Air Quality Management--Department of Public Health, 140
Dameron Avenue, Knoxville, TN 37917.
Air Pollution Control Bureau, Metropolitan Health Department, 311 23rd
Avenue North, Nashville, TN 37203.
Chattanooga-Hamilton County Air Pollution Control Bureau, 6125
Preservation Drive, Chattanooga, TN 37416.
Memphis-Shelby County Health Department--Air Pollution Control Program,
814 Jefferson Avenue, Memphis, TN 38105.
(SS) State of Texas, Texas Air Control Board, 6330 Highway 290 East,
Austin, TX 78723.
(TT) State of Utah, Division of Air Quality, Department of
Environmental Quality, P.O. Box 144820, Salt Lake City, UT 84114-4820.
Note: For a table listing Region VIII's NSPS delegation status, see
paragraph (c) of this section.
(UU) State of Vermont, Air Pollution Control Division, Agency of
Natural Resources, Building 3 South, 103 South Main Street, Waterbury,
VT 05676.
(VV) Commonwealth of Virginia, Department of Environmental Quality,
629 East Main Street, Richmond, Virginia 23219.
(WW) State of Washington. (i) Washington State Department of Ecology
(Ecology), P.O. Box 47600, Olympia, WA 98504-7600, http://
www.ecy.wa.gov/
(ii) Benton Clean Air Authority (BCAA), 650 George Washington Way,
Richland, WA 99352-4289, http://www.bcaa.net/
(iii) Northwest Air Pollution Control Authority (NWAPA), 1600 South
Second St., Mount Vernon, WA 98273-5202, http://www.nwair.org/
(iv) Olympic Regional Clean Air Agency (ORCAA), 909 Sleater-Kinney
Road S.E., Suite 1, Lacey, WA 98503-1128, http://www.orcaa.org/
(v) Puget Sound Clean Air Agency (PSCAA), 110 Union Street, Suite
500, Seattle, WA 98101-2038, http://www.pscleanair.org/
(vi) Spokane County Air Pollution Control Authority (SCAPCA), West
1101 College, Suite 403, Spokane, WA 99201, http://www.scapca.org/
(vii) Southwest Clean Air Agency (SWCAA), 1308 NE. 134th St.,
Vancouver, WA 98685-2747, http://www.swcleanair.org/
(viii) Yakima Regional Clean Air Authority (YRCAA), 6 South 2nd
Street, Suite 1016, Yakima, WA 98901, http://co.yakima.wa.us/cleanair/
default.htm
(ix) The following table lists the delegation status of the New
Source Performance Standards for the State of Washington. An ``X''
indicates the subpart has been delegated, subject to all the conditions
and limitations set forth in Federal law and the letters granting
delegation. Some authorities cannot be delegated and are retained by
EPA. Refer to the letters granting delegation for a discussion of these
retained authorities. The dates noted at the end of the table indicate
the effective dates of Federal rules that have been delegated. Authority
for implementing and enforcing any amendments made to these rules after
these effective dates are not delegated.
NSPS Subparts Delegated to Washington Air Agencies
--------------------------------------------------------------------------------------------------------------------------------------------------------
Washington
-----------------------------------------------------------------------------------------------
Subpart \1\ Ecology
\2\ BCAA \3\ NWAPA \4\ ORCAA \5\ PSCAA \6\ SCAPCA \7\ SWCAA \8\ YRCAA \9\
--------------------------------------------------------------------------------------------------------------------------------------------------------
A General Provisions.................................... X X X X X X X X
B Adoption and Submittal of State Plans for Designated
Facilities.............................................
C Emission Guidelines and Compliance Times..............
[[Page 23]]
Cb Large Municipal Waste Combustors that are Constructed
on or before September 20, 1994 (Emission Guidelines
and Compliance Times)..................................
Cc Municipal Solid Waste Landfills (Emission Guidelines
and Compliance Times)..................................
Cd Sulfuric Acid Production Units (Emission Guidelines
and Compliance Times)..................................
Ce Hospital/Medical/Infectious Waste Incinerators
(Emission Guidelines and Compliance Times).............
D Fossil-Fuel-Fired Steam Generators for which X X X X X X X X
Construction is Commenced after August 17, 1971........
Da Electric Utility Steam Generating Units for which X X X X X X X X
Construction is Commenced after September 18, 1978.....
Db Industrial-Commercial-Institutional Steam Generating X X X X X X X X
Units..................................................
Dc Small Industrial-Commercial-Institutional Steam X X X X X X X X
Generating Units.......................................
E Incinerators.......................................... X X X X X X X X
Ea Municipal Waste Combustors for which Construction is X X X X X X X X
Commenced after December 20, 1989 and on or before
September 20, 1994.....................................
Eb--Large Municipal Waste Combustors.................... X X X X
Ec--Hospital/Medical/Infectious Waste Incinerators...... X X X X X X
F Portland Cement Plants................................ X X X X X X X X
G Nitric Acid Plants.................................... X X X X X X X X
H Sulfuric Acid Plants.................................. X X X X X X X X
I Hot Mix Asphalt Facilities............................ X X X X X X X X
J Petroleum Refineries.................................. X X X X X X X X
K Storage Vessels for Petroleum Liquids for which X X X X X X X X
Construction, Reconstruction, or Modification Commenced
after June 11, 1973 and prior to May 19, 1978..........
Ka Storage Vessels for Petroleum Liquids for which X X X X X X X X
Construction, Reconstruction, or Modification Commenced
after May 18, 1978 and prior to July 23, 1984..........
Kb VOC Liquid Storage Vessels (including Petroleum X X X X X X X X
Liquid Storage Vessels) for which Construction,
Reconstruction, or Modification Commenced after July
23, 1984...............................................
[[Page 24]]
L Secondary Lead Smelters............................... X X X X X X X X
M Secondary Brass and Bronze Production Plants.......... X X X X X X X X
N Primary Emissions from Basic Oxygen Process Furnaces X X X X X X X X
for which Construction is Commenced after June 11, 1973
Na Secondary Emissions from Basic Oxygen Process Steel- X X X X X X X X
making Facilities for which Construction is Commenced
after January 20, 1983.................................
O Sewage Treatment Plants............................... X X X X X X X X
P Primary Copper Smelters............................... X X X X X X X X
Q Primary Zinc Smelters................................. X X X X X X X X
R Primary Lead Smelters................................. X X X X X X X X
S Primary Aluminum Reduction Plants \10\................ X
T Phosphate Fertilizer Industry: Wet Process Phosphoric X X X X X X X X
Acid Plants............................................
U Phosphate Fertilizer Industry: Superphosphoric Acid X X X X X X X X
Plants.................................................
V Phosphate Fertilizer Industry: Diammonium Phosphate X X X X X X X X
Plants.................................................
W Phosphate Fertilizer Industry: Triple Superphosphate X X X X X X X X
Plants.................................................
X Phosphate Fertilizer Industry: Granular Triple X X X X X X X X
Superphosphate Storage Facilities......................
Y Coal Preparation Plants............................... X X X X X X X X
Z Ferroalloy Production Facilities...................... X X X X X X X X
AA Steel Plants: Electric Arc Furnaces Constructed after X X X X X X X X
October 21, 1974 and on or before August 17, 1983......
AAa Steel Plants: Electric Arc Furnaces and Argon-Oxygen X X X X X X X X
Decarburization Vessels Constructed after August 7,
1983...................................................
BB Kraft Pulp Mills \11\................................ X
CC Glass Manufacturing Plants........................... X X X X X X X X
DD Grain Elevators...................................... X X X X X X X X
EE Surface Coating of Metal Furniture................... X X X X X X X X
GG Stationary Gas Turbines.............................. X X X X X X X X
HH Lime Manufacturing Plants............................ X X X X X X X X
KK Lead-Acid Battery Manufacturing Plants............... X X X X X X X X
LL Metallic Mineral Processing Plants................... X X X X X X X X
MM Automobile and Light Duty Truck Surface Coating X X X X X X X X
Operations.............................................
NN Phosphate Rock Plants................................ X X X X X X X X
[[Page 25]]
PP Ammonium Sulfate Manufacture......................... X X X X X X X X
QQ Graphic Arts Industry: Publication Rotogravure X X X X X X X X
Printing...............................................
RR Pressure Sensitive Tape and Label Surface Coating X X X X X X X X
Standards..............................................
SS Industrial Surface Coating: Large Appliances......... X X X X X X X X
TT Metal Coil Surface Coating........................... X X X X X X X X
UU Asphalt Processing and Asphalt Roof Manufacture...... X X X X X X X X
VV Equipment Leaks of VOC in Synthetic Organic Chemical X X X X X X X X
Manufacturing Industry.................................
WW Beverage Can Surface Coating Industry................ X X X X X X X X
XX Bulk Gasoline Terminals.............................. X X X X X X X X
AAA New Residential Wood Heaters........................
BBB Rubber Tire Manufacturing Industry.................. X X X X X X X X
DDD VOC Emissions from Polymer Manufacturing Industry... X X X X X X X X
FFF Flexible Vinyl and Urethane Coating and Printing.... X X X X X X X X
GGG Equipment Leaks of VOC in Petroleum Refineries...... X X X X X X X X
HHH Synthetic Fiber Production Facilities............... X X X X X X X X
III VOC Emissions from Synthetic Organic Chemical X X X X X X X X
Manufacturing Industry Air Oxidation Unit Processes....
JJJ Petroleum Dry Cleaners.............................. X X X X X X X X
KKK Equipment Leaks of VOC from Onshore Natural Gas X X X X X X X X
Processing Plants......................................
LLL Onshore Natural Gas Processing: SO2 Emissions....... X X X X X X X X
NNN VOC Emissions from Synthetic Organic Chemical X X X X X X X X
Manufacturing Industry Distillation Operations.........
OOO Nonmetallic Mineral Processing Plants............... X X X
PPP Wool Fiberglass Insulation Manufacturing Plants..... X X X X X X X X
QQQ VOC Emissions from Petroleum Refinery Wastewater X X X X X X X X
Systems................................................
RRR VOCs from Synthetic Organic Chemical Manufacturing X X X X X X X X
Industry Reactor Processes.............................
SSS Magnetic Tape Coating Facilities.................... X X X X X X X X
[[Page 26]]
TTT Industrial Surface Coating: Surface Coating of X X X X X X X X
Plastic Parts for Business Machines....................
UUU Calciners and Dryers in Mineral Industries.......... X X X X X X X X
VVV Polymeric Coating of Supporting Substrates X X X X X X X X
Facilities.............................................
WWW Municipal Solid Waste Landfills..................... X X X X X X X X
AAAA Small Municipal Waste Combustion Units for which X X X X X X
Construction is Commenced after August 30, 1999 or for
which Modification or Reconstruction is Commenced after
June 6, 2001...........................................
BBBB Small Municipal Waste Combustion Units Constructed
on or before August 30, 1999 (Emission Guidelines and
Compliance Times)......................................
CCCC Commercial and Industrial Solid Waste Incineration X X X X X X
Units for which Construction is Commenced after
November, 30, 1999 or for which Modification or
Reconstruction is Commenced on or after June 1, 2001...
DDDD Commercial and Industrial Solid Waste Incineration
Units that Commenced Construction on or before November
30, 1999 (Emission Guidelines and Compliance Times)....
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Any authority within any subpart of this part that is not delegable, is not delegated. Please refer to Attachment B to the delegation letters for a
listing of the NSPS authorities excluded from delegation.
\2\ Washington State Department of Ecology, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for
40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.
\3\ Benton Clean Air Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part
60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.
\4\ Northwest Air Pollution Authority, for all NSPS delegated, as in effect on July 1, 2000.
\5\ Olympic Regional Clean Air Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40
CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.
\6\ Puget Sound Clean Air Authority, for all NSPS delegated, as in effect on July 1, 2002.
\7\ Spokane County Air Pollution Control Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6,
2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.
\8\ Southwest Clean Air Agency, for all NSPS delegated, as in effect on July 1, 2000.
\9\ Yakima Regional Clean Air Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40
CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.
\10\ Subpart S of this part is not delegated to local agencies in Washington because the Washington State Department of Ecology retains sole authority
to regulate Primary Aluminum Plants, pursuant to Washington Administrative Code 173-415-010.
\11\ Subpart BB of this part is not delegated to local agencies in Washington because the Washington State Department of Ecology retains sole authority
to regulate Kraft and Sulfite Pulping Mills, pursuant to Washington State Administrative Code 173-405-012 and 173-410-012.
(XX) State of West Virginia, Department of Environmental Protection,
Division of Air Quality, 601 57th Street, SE., Charleston, West Virginia
25304.
[[Page 27]]
(YY) State of Wisconsin: Wisconsin Department of Natural Resouces,
101 South Webster St., P.O. Box 7921, Madison, Wisconsin 53707-7921.
(ZZ) State of Wyoming, Department of Environmental Quality, Air
Quality Division, Herschler Building, 122 West 25th Street, Cheyenne, WY
82002.
Note: For a table listing Region VIII's NSPS delegation status, see
paragraph (c) of this section.
(AAA) Territory of Guam: Guam Environmental Protection Agency, P.O.
Box 22439 GMF, Barrigada, Guam 96921.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(BBB) Commonwealth of Puerto Rico: Commonwealth of Puerto Rico
Environmental Quality Board, P.O. Box 11488, Santurce, PR 00910,
Attention: Air Quality Area Director (see table under Sec.
60.4(b)(FF)(1)).
(CCC) U.S. Virgin Islands: U.S. Virgin Islands Department of
Conservation and Cultural Affairs, P.O. Box 578, Charlotte Amalie, St.
Thomas, VI 00801.
(DDD) American Samoa: American Samoa Environmental Protection
Agency, P.O. Box PPA, Pago Pago, American Samoa 96799.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(EEE) Commonwealth of the Northern Mariana Islands: CNMI Division of
Environmental Quality, P.O. Box 501304, Saipan, MP 96950.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(c) The delegation status table for New Source Performance Standards
for Region VIII can be found online athttp://www2.epa.gov/region8/air-
program.
(d) The following tables list the specific part 60 standards that
have been delegated unchanged to the air pollution control agencies in
Region IX. The (X) symbol is used to indicate each standard that has
been delegated. The following provisions of this subpart are not
delegated: Sec. Sec. 60.4(b), 60.8(b), 60.9, 60.11(b), 60.11(e),
60.13(a), 60.13(d)(2), 60.13(g), 60.13(i).
(1) Arizona. The following table identifies delegations for Arizona:
Delegation Status for New Source Performance Standards for Arizona
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
Subpart Arizona Maricopa Pima Pinal
DEQ County County County
----------------------------------------------------------------------------------------------------------------
A General Provisions................ X X X X
D Fossil-Fuel Fired Steam Generators X X X X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating X X X X
Units Constructed After September
18, 1978.
Db Industrial-Commercial- X X X X
Institutional Steam Generating
Units.
Dc Small Industrial-Commercial- X X X X
Institutional Steam Generating
Units.
E Incinerators...................... X X X X
Ea Municipal Waste Combustors X X X X
Constructed After December 20,
1989 and On or Before September
20, 1994.
Eb Large Municipal Waste Combustors X X X
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste X X X
Incinerators for Which
Construction is Commenced After
June 20, 1996.
F Portland Cement Plants............ X X X X
G Nitric Acid Plants................ X X X X
Ga Nitric Acid Plants For Which
Construction, Reconstruction or
Modification Commenced After
October 14, 2011.
H Sulfuric Acid Plant............... X X X X
I Hot Mix Asphalt Facilities........ X X X X
J Petroleum Refineries.............. X X X X
Ja Petroleum Refineries for Which X
Construction, Reconstruction, or
Modification Commenced After May
14, 2007.
K Storage Vessels for Petroleum X X X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X X X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X X X X
Vessels (Including Petroleum
Liquid Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
[[Page 28]]
L Secondary Lead Smelters........... X X X X
M Secondary Brass and Bronze X X X X
Production Plants.
N Primary Emissions from Basic X X X X
Oxygen Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic X X X X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20,
1983.
O Sewage Treatment Plants........... X X X X
P Primary Copper Smelters........... X X X X
Q Primary Zinc Smelters............. X X X X
R Primary Lead Smelters............. X X X X
S Primary Aluminum Reduction Plants. X X X X
T Phosphate Fertilizer Industry: Wet X X X X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: X X X X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X X X X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: X X X X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: X X X X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation and Processing X X X X
Plants.
Z Ferroalloy Production Facilities.. X X X X
AA Steel Plants: Electric Arc X X X X
Furnaces Constructed After
October 21, 1974 and On or Before
August 17, 1983.
AAa Steel Plants: Electric Arc X X X X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
BB Kraft Pulp Mills.................. X X X X
CC Glass Manufacturing Plants........ X X X X
DD Grain Elevators................... X X X X
EE Surface Coating of Metal Furniture X X X X
FF (Reserved)........................
GG Stationary Gas Turbines........... X X X X
HH Lime Manufacturing Plants......... X X X X
KK Lead-Acid Battery Manufacturing X X X X
Plants.
LL Metallic Mineral Processing Plants X X X X
MM Automobile and Light Duty Trucks X X X X
Surface Coating Operations.
NN Phosphate Rock Plants............. X X X X
PP Ammonium Sulfate Manufacture...... X X X X
QQ Graphic Arts Industry: Publication X X X X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label X X X X
Surface Coating Operations.
SS Industrial Surface Coating: Large X X X X
Appliances.
TT Metal Coil Surface Coating........ X X X X
UU Asphalt Processing and Asphalt X X X X
Roofing Manufacture.
VV Equipment Leaks of VOC in the X X X X
Synthetic Organic Industry
Chemicals Manufacturing.
VVa Equipment Leaks of VOC in the X X
Synthetic Organic Industry for
Which Construction,
Reconstruction, or Chemicals
Manufacturing Modification
Commenced After November 7, 2006.
WW Beverage Can Surface Coating X X X X
Industry.
XX Bulk Gasoline Terminals........... X X X X
AAA New Residential Wood Heaters...... X X X X
BBB Rubber Tire Manufacturing Industry X X X X
CCC (Reserved)........................
DDD Volatile Organic Compounds (VOC) X X X X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................
FFF Flexible Vinyl and Urethane X X X X
Coating and Printing.
GGG Equipment Leaks of VOC in X X X X
Petroleum Refineries.
GGGa Equipment Leaks of VOC in X X
Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After
November 7, 2006.
HHH Synthetic Fiber Production X X X X
Facilities.
III Volatile Organic Compound (VOC) X X X X
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners............ X X X X
KKK Equipment Leaks of VOC From X X X X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: X X X X
SO2 Emissions.
MMM (Reserved)........................
[[Page 29]]
NNN Volatile Organic Compound (VOC) X X X X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing X X X X
Plants.
PPP Wool Fiberglass Insulation X X X X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X X X X
Refinery Wastewater Systems.
RRR Volatile Organic Compound X X
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
SSS Magnetic Tape Coating Facilities.. X X X X
TTT Industrial Surface Coating: X X X X
Surface Coating of Plastic Parts
for Business Machines.
UUU Calciners and Dryers in Mineral X X X
Industries.
VVV Polymeric Coating of Supporting X X X X
Substrates Facilities.
WWW Municipal Solid Waste Landfills... X X X
AAAA Small Municipal Waste Combustion X X X
Units for Which Construction is
Commenced After August 30, 1999
or for Which Modification or
Reconstruction is Commended After
June 6, 2001.
CCCC Commercial and Industrial Solid X X X
Waste Incineration Units for
Which Construction Is Commenced
After November 30, 1999 or for
Which Modification or
Reconstruction Is Commenced on or
After June 1, 2001.
EEEE Other Solid Waste Incineration X X
Units for Which Construction is
Commenced After December 9, 2004,
or for Which Modification or
Reconstruction is Commenced on or
After June 16, 2006.
GGGG (Reserved)........................
HHHH (Reserved)........................
IIII Stationary Compression Ignition X X
Internal Combustion Engines.
JJJJ Stationary Spark Ignition Internal X
Combustion Engines.
KKKK Stationary Combustion Turbines.... X X
LLLL New Sewage Sludge Incineration
Units.
OOOO Crude Oil and Natural Gas
Production, Transmission, and
Distribution.
----------------------------------------------------------------------------------------------------------------
(2) California. The following tables identify delegations for each
of the local air pollution control agencies of California.
(i) Delegations for Amador County Air Pollution Control District,
Antelope Valley Air Quality Management District, Bay Area Air Quality
Management District, and Butte County Air Quality Management District
are shown in the following table:
Delegation Status for New Source Performance Standards for Amador County APCD, Antelope Valley AQMD, Bay Area
AQMD, and Butte County AQMD
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
Subpart Amador Antelope Butte
County Valley Bay Area County
APCD AQMD AQMD AQMD
----------------------------------------------------------------------------------------------------------------
A General Provisions................... .......... X
D Fossil-Fuel Fired Steam Generators .......... X X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating .......... X X
Units Constructed After September
18, 1978.
Db Industrial-Commercial-Institutional .......... X X
Steam Generating Units.
Dc Small Industrial-Commercial- .......... X X
Institutional Steam Generating Units.
E Incinerators......................... .......... X X
Ea Municipal Waste Combustors .......... X X
Constructed After December 20, 1989
and On or Before September 20, 1994.
Eb Large Municipal Waste Combustors .......... X
Constructed After September 20, 1994.
Ec Hospital/Medical/Infectious Waste .......... X
Incinerators for Which Construction
is Commenced After June 20, 1996.
F Portland Cement Plants............... .......... X X
G Nitric Acid Plants................... .......... X X
[[Page 30]]
Ga Nitric Acid Plants For Which ..........
Construction, Reconstruction or
Modification Commenced After October
14, 2011.
H Sulfuric Acid Plant.................. .......... X X
I Hot Mix Asphalt Facilities........... .......... X X
J Petroleum Refineries................. .......... X X
Ja Petroleum Refineries for Which .......... X
Construction, Reconstruction, or
Modification Commenced After May 14,
2007.
K Storage Vessels for Petroleum Liquids .......... X X
for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973, and
Prior to May 19, 1978.
Ka Storage Vessels for Petroleum Liquids .......... X X
for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage .......... X X
Vessels (Including Petroleum Liquid
Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters.............. .......... X X
M Secondary Brass and Bronze Production .......... X X
Plants.
N Primary Emissions from Basic Oxygen .......... X X
Process Furnaces for Which
Construction is Commenced After June
11, 1973.
Na Secondary Emissions from Basic Oxygen .......... X X
Process Steelmaking Facilities for
Which Construction is Commenced
After January 20, 1983.
O Sewage Treatment Plants.............. .......... X X
P Primary Copper Smelters.............. .......... X X
Q Primary Zinc Smelters................ .......... X X
R Primary Lead Smelters................ .......... X X
S Primary Aluminum Reduction Plants.... .......... X X
T Phosphate Fertilizer Industry: Wet .......... X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: .......... X X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: .......... X X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: Triple .......... X X
Superphosphate Plants.
X Phosphate Fertilizer Industry: .......... X X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation and Processing .......... X X
Plants.
Z Ferroalloy Production Facilities..... .......... X X
AA Steel Plants: Electric Arc Furnaces .......... X X
Constructed After October 21, 1974
and On or Before August 17, 1983.
AAa Steel Plants: Electric Arc Furnaces .......... X X
and Argon-Oxygen Decarburization
Vessels Constructed After August 7,
1983.
BB Kraft Pulp Mills..................... .......... X X
CC Glass Manufacturing Plants........... .......... X X
DD Grain Elevators...................... .......... X X
EE Surface Coating of Metal Furniture... .......... X X
FF (Reserved)........................... ..........
GG Stationary Gas Turbines.............. .......... X X
HH Lime Manufacturing Plants............ .......... X X
KK Lead-Acid Battery Manufacturing .......... X X
Plants.
LL Metallic Mineral Processing Plants... .......... X X
MM Automobile and Light Duty Trucks .......... X X
Surface Coating Operations.
NN Phosphate Rock Plants................ .......... X X
PP Ammonium Sulfate Manufacture......... .......... X X
QQ Graphic Arts Industry: Publication .......... X X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label .......... X X
Surface Coating Operations.
SS Industrial Surface Coating: Large .......... X X
Appliances.
TT Metal Coil Surface Coating........... .......... X X
UU Asphalt Processing and Asphalt .......... X X
Roofing Manufacture.
VV Equipment Leaks of VOC in the .......... X X
Synthetic Organic Industry Chemicals
Manufacturing.
VVa Equipment Leaks of VOC in the .......... X
Synthetic Organic Industry for Which
Construction, Reconstruction, or
Chemicals Manufacturing Modification
Commenced After November 7, 2006.
WW Beverage Can Surface Coating Industry .......... X X
XX Bulk Gasoline Terminals.............. ..........
AAA New Residential Wood Heaters......... .......... X X
BBB Rubber Tire Manufacturing Industry... .......... X X
CCC (Reserved)........................... ..........
[[Page 31]]
DDD Volatile Organic Compounds (VOC) .......... X X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................... ..........
FFF Flexible Vinyl and Urethane Coating .......... X X
and Printing.
GGG Equipment Leaks of VOC in Petroleum .......... X X
Refineries.
GGGa Equipment Leaks of VOC in Petroleum .......... X
Refineries for Which Construction,
Reconstruction, or Modification
Commenced After November 7, 2006.
HHH Synthetic Fiber Production Facilities .......... X X
III Volatile Organic Compound (VOC) .......... X
Emissions From the Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Air Oxidation Unit Processes.
JJJ Petroleum Dry Cleaners............... .......... X X
KKK Equipment Leaks of VOC From Onshore .......... X X
Natural Gas Processing Plants.
LLL Onshore Natural Gas Processing: SO2 .......... X
Emissions.
MMM (Reserved)........................... ..........
NNN Volatile Organic Compound (VOC) .......... X X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing Plants .......... X X
PPP Wool Fiberglass Insulation .......... X X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum Refinery .......... X
Wastewater Systems.
RRR Volatile Organic Compound Emissions .......... X
from Synthetic Organic Chemical
Manufacturing Industry (SOCMI)
Reactor Processes.
SSS Magnetic Tape Coating Facilities..... .......... X X
TTT Industrial Surface Coating: Surface .......... X X
Coating of Plastic Parts for
Business Machines.
UUU Calciners and Dryers in Mineral .......... X X
Industries.
VVV Polymeric Coating of Supporting .......... X X
Substrates Facilities.
WWW Municipal Solid Waste Landfills...... .......... X
AAAA Small Municipal Waste Combustion .......... X
Units for Which Construction is
Commenced After August 30, 1999 or
for Which Modification or
Reconstruction is Commended After
June 6, 2001.
CCCC Commercial and Industrial Solid Waste .......... X
Incineration Units for Which
Construction Is Commenced After
November 30, 1999 or for Which
Modification or Reconstruction Is
Commenced on or After June 1, 2001.
EEEE Other Solid Waste Incineration Units .......... X
for Which Construction is Commenced
After December 9, 2004, or for Which
Modification or Reconstruction is
Commenced on or After June 16, 2006.
GGGG (Reserved)........................... ..........
HHHH (Reserved)........................... ..........
IIII Stationary Compression Ignition .......... X
Internal Combustion Engines.
JJJJ Stationary Spark Ignition Internal .......... X
Combustion Engines.
KKKK Stationary Combustion Turbines....... .......... X
LLLL New Sewage Sludge Incineration Units. ..........
OOOO Crude Oil and Natural Gas Production, ..........
Transmission, and Distribution.
----------------------------------------------------------------------------------------------------------------
(ii) [Reserved]
(iii) Delegations for Glenn County Air Pollution Control District,
Great Basin Unified Air Pollution Control District, Imperial County Air
Pollution Control District, and Kern County Air Pollution Control
District are shown in the following table:
[[Page 32]]
Delegation Status for New Source Performance Standards for Glenn County APCD, Great Basin Unified APCD, Imperial
County APCD, and Kern County APCD
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
Great
Subpart Glenn Basin Imperial Kern
County Unified County County
APCD APCD APCD APCD
----------------------------------------------------------------------------------------------------------------
A General Provisions................ .......... X .......... X
D Fossil-Fuel Fired Steam Generators .......... X .......... X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating .......... X .......... X
Units Constructed After September
18, 1978.
Db Industrial-Commercial- .......... X .......... X
Institutional Steam Generating
Units.
Dc Small Industrial Steam Generating .......... X .......... X
Units.
E Incinerators...................... .......... X .......... X
Ea Municipal Waste Combustors .......... X
Constructed After December 20,
1989 and On or Before September
20, 1994.
Eb Municipal Waste Combustors
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste
Incinerators for Which
Construction is Commenced After
June 20, 1996.
F Portland Cement Plants............ .......... X .......... X
G Nitric Acid Plants................ .......... X .......... X
H Sulfuric Acid Plants.............. .......... X
I Hot Mix Asphalt Facilities........ .......... X .......... X
J Petroleum Refineries.............. .......... X .......... X
K Storage Vessels for Petroleum .......... X .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum .......... X .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage .......... X .......... X
Vessels (Including Petroleum
Liquid Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters........... .......... X .......... X
M Secondary Brass and Bronze .......... X .......... X
Production Plants.
N Primary Emissions from Basic .......... X .......... X
Oxygen Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic .......... X .......... X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20,
1983.
O Sewage Treatment Plants........... .......... X .......... X
P Primary Copper Smelters........... .......... X .......... X
Q Primary Zinc Smelters............. .......... X .......... X
R Primary Lead Smelters............. .......... X .......... X
S Primary Aluminum Reduction Plants. .......... X .......... X
T Phosphate Fertilizer Industry: Wet .......... X .......... X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: .......... X .......... X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: .......... X .......... X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: .......... X .......... X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: .......... X .......... X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants........... .......... X .......... X
Z Ferroalloy Production Facilities.. .......... X .......... X
AA Steel Plants: Electric Arc .......... X .......... X
Furnaces Constructed After
October 21, 1974 and On or Before
August 17, 1983.
AAa Steel Plants: Electric Arc .......... X .......... X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
BB Kraft pulp Mills.................. .......... X .......... X
CC Glass Manufacturing Plants........ .......... X .......... X
DD Grain Elevators................... .......... X .......... X
EE Surface Coating of Metal Furniture .......... X .......... X
FF (Reserved)........................
GG Stationary Gas Turbines........... .......... X .......... X
HH Lime Manufacturing Plants......... .......... X .......... X
KK Lead-Acid Battery Manufacturing .......... X .......... X
Plants.
LL Metallic Mineral Processing Plants .......... X .......... X
MM Automobile and Light Duty Trucks .......... X .......... X
Surface Coating Operations.
NN Phosphate Rock Plants............. .......... X .......... X
PP Ammonium Sulfate Manufacture...... .......... X .......... X
QQ Graphic Arts Industry: Publication .......... X .......... X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label .......... X .......... X
Surface Coating Operations.
SS Industrial Surface Coating: Large .......... X .......... X
Appliances.
[[Page 33]]
TT Metal Coil Surface Coating........ .......... X .......... X
UU Asphalt Processing and Asphalt .......... X .......... X
Roofing Manufacture.
VV Equipment Leaks of VOC in the .......... X .......... X
Synthetic Organic Chemicals
Manufacturing Industry.
WW Beverage Can Surface Coating .......... X .......... X
Industry.
XX Bulk Gasoline Terminals...........
AAA New Residential Wool Heaters...... .......... X .......... X
BBB Rubber Tire Manufacturing Industry .......... X .......... X
CCC (Reserved)........................
DDD Volatile Organic Compounds (VOC) .......... X .......... X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................
FFF Flexible Vinyl and Urethane .......... X .......... X
Coating and Printing.
GGG Equipment Leaks of VOC in .......... X .......... X
Petroleum Refineries.
HHH Synthetic Fiber Production .......... X .......... X
Facilities.
III Volatile Organic Compound (VOC) .......... X .......... X
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners............ .......... X .......... X
KKK Equipment Leaks of VOC From .......... X .......... X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: .......... .......... .......... X
SO2 Emissions.
MMM (Reserved)........................ .......... .......... ..........
NNN Volatile Organic Compound (VOC) .......... X .......... X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing .......... X .......... X
Plants.
PPP Wool Fiberglass Insulation .......... X .......... X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum .......... X .......... X
Refinery Wastewater Systems.
RRR Volatile Organic Compound .......... .......... .......... X
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
SSS Magnetic Tape Coating Facilities.. .......... X .......... X
TTT Industrial Surface Coating: .......... X X ..........
Surface Coating of Plastic Parts
for Business Machines.
UUU Calciners and Dryers in Mineral .......... X .......... X
Industries.
VVV Polymeric Coating of Supporting .......... X .......... X
Substrates Facilities.
WWW Municipal Solid Waste Landfills... .......... .......... .......... X
----------------------------------------------------------------------------------------------------------------
(iv) Delegations for Lake County Air Quality Management District,
Lassen County Air Pollution Control District, Mariposa County Air
Pollution Control District, and Mendocino County Air Pollution Control
District are shown in the following table:
Delegation Status for New Source Performance Standards for Lake County Air Quality Management District, Lassen
County Air Pollution Control District, Mariposa County Air Pollution Control District, and Mendocino County Air
Pollution Control District
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
Subpart Lake Lassen Mariposa Mendocino
County County County County
AQMD APCD AQMD AQMD
----------------------------------------------------------------------------------------------------------------
A General Provisions................ X .......... .......... X
D Fossil-Fuel Fired Steam Generators X .......... .......... X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating X .......... .......... X
Units Constructed After September
18, 1978.
Db Industrial-Commercial- X
Institutional Steam Generating
Units.
Dc Small Industrial Steam Generating X .......... .......... X
Units.
E Incinerators...................... X .......... .......... X
Ea Municipal Waste Combustors X .......... .......... X
Constructed After December 20,
1989 and On or Before September
20, 1994.
[[Page 34]]
Eb Municipal Waste Combustors
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste
Incinerators for Which
Construction is Commenced After
June 20, 1996.
F Portland Cement Plants............ X .......... .......... X
G Nitric Acid Plants................ X .......... .......... X
H Sulfuric Acid Plants.............. X .......... .......... X
I Hot Mix Asphalt Facilities........ X .......... .......... X
J Petroleum Refineries.............. X .......... .......... X
K Storage Vessels for Petroleum X .......... .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X .......... .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X .......... .......... X
Vessels (Including Petroleum
Liquid Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters........... X .......... .......... X
M Secondary Brass and Bronze X .......... .......... X
Production Plants.
N Primary Emissions from Basic X .......... .......... X
Oxygen Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic X .......... .......... X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20,
1983.
O Sewage Treatment Plants........... X .......... .......... X
P Primary Copper Smelters........... X .......... .......... X
Q Primary Zinc Smelters............. X .......... .......... X
R Primary Lead Smelters............. X .......... .......... X
S Primary Aluminum Reduction Plants. X .......... .......... X
T Phosphate Fertilizer Industry: Wet X .......... .......... X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: X .......... .......... X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X .......... .......... X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: X .......... .......... X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: X .......... .......... X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants........... X .......... .......... X
Z Ferroalloy Production Facilities.. X .......... .......... X
AA Steel Plants: Electric Arc X .......... .......... X
Furnaces Constructed After
October 21, 1974 and On or Before
August 17, 1983.
AAa Steel Plants: Electric Arc X .......... .......... X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
BB Kraft Pulp Mills.................. X .......... .......... X
CC Glass Manufacturing Plants........ X .......... .......... X
DD Grain Elevators................... X .......... .......... X
EE Surface Coating of Metal Furniture X .......... .......... X
FF (Reserved)........................
GG Stationary Gas Turbines........... X .......... .......... X
HH Lime Manufacturing Plants......... X .......... .......... X
KK Lead-Acid Battery Manufacturing X .......... .......... X
Plants.
LL Metallic Mineral Processing Plants X .......... .......... X
MM Automobile and Light Duty Trucks X .......... .......... X
Surface Coating Operations.
NN Phosphate Rock Plants............. X .......... .......... X
PP Ammonium Sulfate Manufacture...... X .......... .......... X
QQ Graphic Arts Industry: Publication X .......... .......... X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label X .......... .......... X
Surface Coating Operations.
SS Industrial Surface Coating: Large X .......... .......... X
Appliances.
TT Metal Coil Surface Coating........ X .......... .......... X
UU Asphalt Processing and Asphalt X .......... .......... X
Roofing Manufacture.
VV Equipment Leaks of VOC in the X .......... .......... X
Synthetic Organic Chemicals
Manufacturing Industry.
WW Beverage Can Surface Coating X .......... .......... X
Industry.
XX Bulk Gasoline Terminals...........
AAA New Residential Wool Heaters...... X .......... .......... X
BBB Rubber Tire Manufacturing Industry X .......... .......... X
[[Page 35]]
CCC (Reserved)........................
DDD Volatile Organic Compounds (VOC) X .......... .......... X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................
FFF Flexible Vinyl and Urethane X .......... .......... X
Coating and Printing.
GGG Equipment Leaks of VOC in X .......... .......... X
Petroleum Refineries.
HHH Synthetic Fiber Production X .......... .......... X
Facilities.
III Volatile Organic Compound (VOC) X .......... .......... X
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners............ X .......... .......... X
KKK Equipment Leaks of VOC From X .......... .......... X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: X .......... .......... X
SO2 Emissions.
MMM (Reserved)........................ .......... .......... ..........
NNN Volatile Organic Compound (VOC) X .......... .......... X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing X .......... .......... X
Plants.
PPP Wool Fiberglass Insulation X .......... .......... X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X .......... .......... X
Refinery Wastewater Systems.
RRR Volatile Organic Compound X
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
SSS Magnetic Tape Coating Facilities.. X .......... .......... X
TTT Industrial Surface Coating:
Surface Coating of Plastic Parts
for Business Machines.
UUU Calciners and Dryers in Mineral X .......... .......... X
Industries.
VVV Polymeric Coating of Supporting X .......... .......... X
Substrates Facilities.
WWW Municipal Solid Waste Landfills... X .......... ..........
----------------------------------------------------------------------------------------------------------------
(v) Delegations for Modoc Air Pollution Control District, Mojave
Desert Air Quality Management District, Monterey Bay Unified Air
Pollution Control District and North Coast Unified Air Quality
Management District are shown in the following table:
Delegation Status for New Source Performance Standards for Modoc County APCD, Mojave Desert AQMD, Monterey Bay
Unified APCD, and North Coast Unified AQMD
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
Monterey North
Subpart Modoc Mojave Bay Coast
County Desert Unified Unified
APCD AQMD APCD AQMD
----------------------------------------------------------------------------------------------------------------
A General Provisions................ X X X X
D Fossil-Fuel Fired Steam Generators X X X X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating X X X X
Units Constructed After September
18, 1978.
Db Industrial-Commercial- X X X X
Institutional Steam Generating
Units.
Dc Small Industrial-Commercial- .......... X X
Institutional Steam Generating
Units.
E Incinerators...................... X X X X
Ea Municipal Waste Combustors .......... X ..........
Constructed After December 20,
1989 and On or Before September
20, 1994.
Eb Large Municipal Waste Combustors .......... X ..........
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste .......... X ..........
Incinerators for Which
Construction is Commenced After
June 20, 1996.
F Portland Cement Plants............ X X X X
G Nitric Acid Plants................ X X X X
[[Page 36]]
Ga Nitric Acid Plants For Which .......... .......... ..........
Construction, Reconstruction or
Modification Commenced After
October 14, 2011.
H Sulfuric Acid Plant............... X X X X
I Hot Mix Asphalt Facilities........ X X X X
J Petroleum Refineries.............. X X X X
Ja Petroleum Refineries for Which .......... X ..........
Construction, Reconstruction, or
Modification Commenced After May
14, 2007.
K Storage Vessels for Petroleum X X X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X X X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X X X X
Vessels (Including Petroleum
Liquid Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters........... X X X X
M Secondary Brass and Bronze X X X X
Production Plants.
N Primary Emissions from Basic X X X X
Oxygen Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic X X X X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20,
1983.
O Sewage Treatment Plants........... X X X X
P Primary Copper Smelters........... X X X X
Q Primary Zinc Smelters............. X X X X
R Primary Lead Smelters............. X X X X
S Primary Aluminum Reduction Plants. X X X X
T Phosphate Fertilizer Industry: Wet X X X X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: X X X X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X X X X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: X X X X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: X X X X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation and Processing X X X X
Plants.
Z Ferroalloy Production Facilities.. X X X X
AA Steel Plants: Electric Arc X X X X
Furnaces Constructed After
October 21, 1974 and On or Before
August 17, 1983.
AAa Steel Plants: Electric Arc X X X X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
BB Kraft Pulp Mills.................. X X X X
CC Glass Manufacturing Plants........ X X X X
DD Grain Elevators................... X X X X
EE Surface Coating of Metal Furniture X X X X
FF (Reserved)........................ .......... .......... ..........
GG Stationary Gas Turbines........... X X X X
HH Lime Manufacturing Plants......... X X X X
KK Lead-Acid Battery Manufacturing X X X X
Plants.
LL Metallic Mineral Processing Plants X X X X
MM Automobile and Light Duty Trucks X X X X
Surface Coating Operations.
NN Phosphate Rock Plants............. X X X X
PP Ammonium Sulfate Manufacture...... X X X X
QQ Graphic Arts Industry: Publication X X X X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label X X X X
Surface Coating Operations.
SS Industrial Surface Coating: Large X X X X
Appliances.
TT Metal Coil Surface Coating........ X X X X
UU Asphalt Processing and Asphalt X X X X
Roofing Manufacture.
VV Equipment Leaks of VOC in the X X X X
Synthetic Organic Industry
Chemicals Manufacturing.
VVa Equipment Leaks of VOC in the .......... X ..........
Synthetic Organic Industry for
Which Construction,
Reconstruction, or Chemicals
Manufacturing Modification
Commenced After November 7, 2006.
WW Beverage Can Surface Coating X X X X
Industry.
XX Bulk Gasoline Terminals........... .......... .......... ..........
AAA New Residential Wood Heaters...... X X X X
[[Page 37]]
BBB Rubber Tire Manufacturing Industry X X X X
CCC (Reserved)........................ .......... .......... ..........
DDD Volatile Organic Compounds (VOC) X X X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................ .......... .......... ..........
FFF Flexible Vinyl and Urethane X X X X
Coating and Printing.
GGG Equipment Leaks of VOC in X X X X
Petroleum Refineries.
GGGa Equipment Leaks of VOC in .......... X ..........
Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After
November 7, 2006.
HHH Synthetic Fiber Production X X X X
Facilities.
III Volatile Organic Compound (VOC) .......... X ..........
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners............ X X X X
KKK Equipment Leaks of VOC From X X X X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: X X X X
SO2 Emissions.
MMM (Reserved)........................ .......... .......... ..........
NNN Volatile Organic Compound (VOC) X X X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing X X X X
Plants.
PPP Wool Fiberglass Insulation X X X X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X X X X
Refinery Wastewater Systems.
RRR Volatile Organic Compound .......... X ..........
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
SSS Magnetic Tape Coating Facilities.. X X X X
TTT Industrial Surface Coating: X X X X
Surface Coating of Plastic Parts
for Business Machines.
UUU Calciners and Dryers in Mineral .......... X X
Industries.
VVV Polymeric Coating of Supporting .......... X X X
Substrates Facilities.
WWW Municipal Solid Waste Landfills... .......... X ..........
AAAA Small Municipal Waste Combustion .......... X ..........
Units for Which Construction is
Commenced After August 30, 1999
or for Which Modification or
Reconstruction is Commended After
June 6, 2001.
CCCC Commercial and Industrial Solid .......... X ..........
Waste Incineration Units for
Which Construction Is Commenced
After November 30, 1999 or for
Which Modification or
Reconstruction Is Commenced on or
After June 1, 2001.
EEEE Other Solid Waste Incineration .......... X ..........
Units for Which Construction is
Commenced After December 9, 2004,
or for Which Modification or
Reconstruction is Commenced on or
After June 16, 2006.
GGGG (Reserved)........................ .......... .......... ..........
HHHH (Reserved)........................ .......... .......... ..........
IIII Stationary Compression Ignition .......... X ..........
Internal Combustion Engines.
JJJJ Stationary Spark Ignition Internal .......... X ..........
Combustion Engines.
KKKK Stationary Combustion Turbines.... .......... X ..........
LLLL New Sewage Sludge Incineration .......... .......... ..........
Units.
OOOO Crude Oil and Natural Gas .......... .......... ..........
Production, Transmission, and
Distribution.
----------------------------------------------------------------------------------------------------------------
(vi) Delegations for Northern Sierra Air Quality Management
District, Northern Sonoma County Air Pollution Control District, Placer
County Air Pollution Control District, and Sacramento Metropolitan Air
Quality Management District are shown in the following table:
[[Page 38]]
Delegation Status for New Source Performance Standards for Northern Sierra Air Quality Management District,
Northern Sonoma County Air Pollution Control District, Placer County Air Pollution Control District, and
Sacramento Metropolitan Air Quality Management District
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-------------------------------------------------
Northern
Subpart Northern Sonoma Placer Sacramento
Sierra County County Metropolitan
AQMD APCD APCD AQMD
----------------------------------------------------------------------------------------------------------------
A General Provisions.................. .......... X .......... X
D Fossil-Fuel Fired Steam Generators .......... X .......... X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating .......... X .......... X
Units Constructed After September
18, 1978.
Db Industrial-Commercial-Institutional .......... .......... .......... X
Steam Generating Units.
Dc Small Industrial Steam Generating .......... .......... .......... X
Units.
E Incinerators........................ .......... X .......... X
Ea Municipal Waste Combustors .......... .......... .......... X
Constructed After December 20, 1989
and On or Before September 20, 1994.
Eb Municipal Waste Combustors .......... .......... .......... X
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste .......... .......... .......... X
Incinerators for Which Construction
is Commenced After June 20, 1996.
F Portland Cement Plants.............. .......... X .......... X
G Nitric Acid Plants.................. .......... X .......... X
H Sulfuric Acid Plants................ .......... X .......... X
I Hot Mix Asphalt Facilities.......... .......... X .......... X
J Petroleum Refineries................ .......... X .......... X
K Storage Vessels for Petroleum .......... X .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973, and
Prior to May 19, 1978.
Ka Storage Vessels for Petroleum .......... X .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage .......... .......... .......... X
Vessels (Including Petroleum Liquid
Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters............. .......... X .......... X
M Secondary Brass and Bronze .......... X .......... X
Production Plants.
N Primary Emissions from Basic Oxygen .......... X .......... X
Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic .......... .......... .......... X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20, 1983.
O Sewage Treatment Plants............. .......... X .......... X
P Primary Copper Smelters............. .......... X .......... X
Q Primary Zinc Smelters............... .......... X .......... X
R Primary Lead Smelters............... .......... X .......... X
S Primary Aluminum Reduction Plants... .......... X .......... X
T Phosphate Fertilizer Industry: Wet .......... X .......... X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: .......... X .......... X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: .......... X .......... X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: .......... X .......... X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: .......... X .......... X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants............. .......... X .......... X
Z Ferroalloy Production Facilities.... .......... X .......... X
AA Steel Plants: Electric Arc Furnaces .......... X .......... X
Constructed After October 21, 1974
and On or Before August 17, 1983.
AAa Steel Plants: Electric Arc Furnaces .......... .......... .......... X
and Argon-Oxygen Decarburization
Vessels Constructed After August 7,
1983.
BB Kraft pulp Mills.................... .......... X .......... X
CC Glass Manufacturing Plants.......... .......... X .......... X
DD Grain Elevators..................... .......... X .......... X
EE Surface Coating of Metal Furniture.. .......... .......... .......... X
FF (Reserved)..........................
GG Stationary Gas Turbines............. .......... X .......... X
HH Lime Manufacturing Plants........... .......... X .......... X
KK Lead-Acid Battery Manufacturing .......... .......... .......... X
Plants.
LL Metallic Mineral Processing Plants.. .......... .......... .......... X
MM Automobile and Light Duty Trucks .......... X .......... X
Surface Coating Operations.
NN Phosphate Rock Plants............... .......... .......... .......... X
[[Page 39]]
PP Ammonium Sulfate Manufacture........ .......... X .......... X
QQ Graphic Arts Industry: Publication .......... .......... .......... X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label .......... .......... .......... X
Surface Coating Operations.
SS Industrial Surface Coating: Large .......... .......... .......... X
Appliances.
TT Metal Coil Surface Coating.......... .......... .......... .......... X
UU Asphalt Processing and Asphalt .......... .......... .......... X
Roofing Manufacture.
VV Equipment Leaks of VOC in the .......... .......... .......... X
Synthetic Organic Chemicals
Manufacturing Industry.
WW Beverage Can Surface Coating .......... .......... .......... X
Industry.
XX Bulk Gasoline Terminals.............
AAA New Residential Wool Heaters........ .......... .......... .......... X
BBB Rubber Tire Manufacturing Industry.. .......... .......... .......... X
CCC (Reserved)..........................
DDD Volatile Organic Compounds (VOC) .......... .......... .......... X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)..........................
FFF Flexible Vinyl and Urethane Coating .......... .......... .......... X
and Printing.
GGG Equipment Leaks of VOC in Petroleum .......... .......... .......... X
Refineries.
HHH Synthetic Fiber Production .......... .......... .......... X
Facilities.
III Volatile Organic Compound (VOC) .......... .......... .......... X
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation Unit
Processes.
JJJ Petroleum Dry Cleaners.............. .......... .......... .......... X
KKK Equipment Leaks of VOC From Onshore .......... .......... .......... X
Natural Gas Processing Plants.
LLL Onshore Natural Gas Processing: SO2 .......... .......... .......... X
Emissions.
MMM (Reserved)..........................
NNN Volatile Organic Compound (VOC) .......... .......... .......... X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing .......... .......... .......... X
Plants.
PPP Wool Fiberglass Insulation .......... .......... .......... X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum .......... .......... .......... X
Refinery Wastewater Systems.
RRR Volatile Organic Compound Emissions .......... .......... .......... X
from Synthetic Organic Chemical
Manufacturing Industry (SOCMI)
Reactor Processes.
SSS Magnetic Tape Coating Facilities.... .......... .......... .......... X
TTT Industrial Surface Coating: Surface .......... .......... .......... X
Coating of Plastic Parts for
Business Machines.
UUU Calciners and Dryers in Mineral .......... .......... .......... X
Industries.
VVV Polymeric Coating of Supporting .......... .......... .......... X
Substrates Facilities.
WWW Municipal Solid Waste Landfills..... .......... .......... .......... X
----------------------------------------------------------------------------------------------------------------
(vii) Delegations for San Diego County Air Pollution Control
District, San Joaquin Valley Unified Air Pollution Control District, San
Luis Obispo County Air Pollution Control District, and Santa Barbara
County Air Pollution Control District are shown in the following table:
[[Page 40]]
Delegation Status for New Source Performance Standards for San Diego County APCD, San Joaquin Valley Unified
APCD, San Luis Obispo County APCD, and Santa Barbara County APCD
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
San
Subpart San Diego Joaquin San Luis Santa
County Valley Obispo Barbara
APCD Unified County County
APCD APCD APCD
----------------------------------------------------------------------------------------------------------------
A General Provisions................ X X X X
D Fossil-Fuel Fired Steam Generators X X X X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating X X X X
Units Constructed After September
18, 1978.
Db Industrial-Commercial- X X X X
Institutional Steam Generating
Units.
Dc Small Industrial-Commercial- X X X X
Institutional Steam Generating
Units.
E Incinerators...................... X X X X
Ea Municipal Waste Combustors X X X
Constructed After December 20,
1989 and On or Before September
20, 1994.
Eb Large Municipal Waste Combustors X X .......... X
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste X .......... .......... X
Incinerators for Which
Construction is Commenced After
June 20, 1996.
F Portland Cement Plants............ X X X
G Nitric Acid Plants................ X X X
Ga Nitric Acid Plants For Which .......... .......... ..........
Construction, Reconstruction or
Modification Commenced After
October 14, 2011.
H Sulfuric Acid Plant............... X X X
I Hot Mix Asphalt Facilities........ X X X X
J Petroleum Refineries.............. X X X X
Ja Petroleum Refineries for Which .......... .......... .......... X
Construction, Reconstruction, or
Modification Commenced After May
14, 2007.
K Storage Vessels for Petroleum X X X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X X X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X X X X
Vessels (Including Petroleum
Liquid Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters........... X X X X
M Secondary Brass and Bronze X X X X
Production Plants.
N Primary Emissions from Basic X X X
Oxygen Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic X X X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20,
1983.
O Sewage Treatment Plants........... X X X X
P Primary Copper Smelters........... X X X
Q Primary Zinc Smelters............. X X X
R Primary Lead Smelters............. X X X
S Primary Aluminum Reduction Plants. X X X
T Phosphate Fertilizer Industry: Wet X X X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: X X X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X X X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: X X X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: X X X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation and Processing X X X
Plants.
Z Ferroalloy Production Facilities.. X X X
AA Steel Plants: Electric Arc X X X
Furnaces Constructed After
October 21, 1974 and On or Before
August 17, 1983.
AAa Steel Plants: Electric Arc X X X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
BB Kraft Pulp Mills.................. X X X
CC Glass Manufacturing Plants........ X X X X
DD Grain Elevators................... X X X X
EE Surface Coating of Metal Furniture X X X
FF (Reserved)........................ .......... .......... ..........
GG Stationary Gas Turbines........... X X X X
HH Lime Manufacturing Plants......... X X X
KK Lead-Acid Battery Manufacturing X X X
Plants.
[[Page 41]]
LL Metallic Mineral Processing Plants X X X
MM Automobile and Light Duty Trucks X X X
Surface Coating Operations.
NN Phosphate Rock Plants............. X X X
PP Ammonium Sulfate Manufacture...... X X X
QQ Graphic Arts Industry: Publication X X X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label X X X
Surface Coating Operations.
SS Industrial Surface Coating: Large X X X
Appliances.
TT Metal Coil Surface Coating........ X X X
UU Asphalt Processing and Asphalt X X X
Roofing Manufacture.
VV Equipment Leaks of VOC in the X X X
Synthetic Organic Industry
Chemicals Manufacturing.
VVa Equipment Leaks of VOC in the .......... .......... .......... X
Synthetic Organic Industry for
Which Construction,
Reconstruction, or Chemicals
Manufacturing Modification
Commenced After November 7, 2006.
WW Beverage Can Surface Coating X X X
Industry.
XX Bulk Gasoline Terminals........... .......... .......... ..........
AAA New Residential Wood Heaters...... X X X X
BBB Rubber Tire Manufacturing Industry X X X
CCC (Reserved)........................ .......... .......... ..........
DDD Volatile Organic Compounds (VOC) X X ..........
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................ .......... .......... ..........
FFF Flexible Vinyl and Urethane X X X
Coating and Printing.
GGG Equipment Leaks of VOC in X X X
Petroleum Refineries.
GGGa Equipment Leaks of VOC in .......... .......... .......... X
Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After
November 7, 2006.
HHH Synthetic Fiber Production X X X
Facilities.
III Volatile Organic Compound (VOC) X X ..........
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners............ X X X
KKK Equipment Leaks of VOC From X X X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: X X X
SO2 Emissions.
MMM (Reserved)........................ .......... .......... ..........
NNN Volatile Organic Compound (VOC) X X ..........
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing X X X X
Plants.
PPP Wool Fiberglass Insulation X X X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X X X
Refinery Wastewater Systems.
RRR Volatile Organic Compound X X X
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
SSS Magnetic Tape Coating Facilities.. X X X
TTT Industrial Surface Coating: X X X
Surface Coating of Plastic Parts
for Business Machines.
UUU Calciners and Dryers in Mineral X X X X
Industries.
VVV Polymeric Coating of Supporting X X X X
Substrates Facilities.
WWW Municipal Solid Waste Landfills... X X X X
AAAA Small Municipal Waste Combustion X .......... .......... X
Units for Which Construction is
Commenced After August 30, 1999
or for Which Modification or
Reconstruction is Commended After
June 6, 2001.
CCCC Commercial and Industrial Solid X .......... .......... X
Waste Incineration Units for
Which Construction Is Commenced
After November 30, 1999 or for
Which Modification or
Reconstruction Is Commenced on or
After June 1, 2001.
EEEE Other Solid Waste Incineration X .......... .......... X
Units for Which Construction is
Commenced After December 9, 2004,
or for Which Modification or
Reconstruction is Commenced on or
After June 16, 2006.
GGGG (Reserved)........................ .......... .......... ..........
HHHH (Reserved)........................ .......... .......... ..........
IIII Stationary Compression Ignition .......... .......... .......... X
Internal Combustion Engines.
JJJJ Stationary Spark Ignition Internal .......... .......... .......... X
Combustion Engines.
[[Page 42]]
KKKK Stationary Combustion Turbines.... X .......... .......... X
LLLL New Sewage Sludge Incineration .......... .......... ..........
Units.
OOOO Crude Oil and Natural Gas .......... .......... ..........
Production, Transmission, and
Distribution.
----------------------------------------------------------------------------------------------------------------
(viii) Delegations for Shasta County Air Quality Management
District, Siskiyou County Air Pollution Control District, South Coast
Air Quality Management District, and Tehama County Air Pollution Control
District are shown in the following table:
Delegation Status for New Source Performance Standards for Shasta County AQMD, Siskiyou County APCD, South Coast
AQMD, and Tehama County APCD
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
Subpart Shasta Siskiyou Tehama
County County South County
AQMD APCD Coast AQMD APCD
----------------------------------------------------------------------------------------------------------------
A General Provisions................... X X X
D Fossil-Fuel Fired Steam Generators X .......... X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating .......... .......... X
Units Constructed After September
18, 1978.
Db Industrial-Commercial-Institutional .......... .......... X
Steam Generating Units.
Dc Small Industrial-Commercial- .......... .......... X
Institutional Steam Generating Units.
E Incinerators......................... X .......... X
Ea Municipal Waste Combustors .......... .......... X
Constructed After December 20, 1989
and On or Before September 20, 1994.
Eb Large Municipal Waste Combustors .......... .......... X
Constructed After September 20, 1994.
Ec Hospital/Medical/Infectious Waste .......... .......... X
Incinerators for Which Construction
is Commenced After June 20, 1996.
F Portland Cement Plants............... X .......... X
G Nitric Acid Plants................... X .......... X
Ga Nitric Acid Plants For Which .......... .......... ..........
Construction, Reconstruction or
Modification Commenced After October
14, 2011.
H Sulfuric Acid Plant.................. X .......... X
I Hot Mix Asphalt Facilities........... X .......... X
J Petroleum Refineries................. X .......... X
Ja Petroleum Refineries for Which .......... .......... X
Construction, Reconstruction, or
Modification Commenced After May 14,
2007.
K Storage Vessels for Petroleum Liquids X .......... X
for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973, and
Prior to May 19, 1978.
Ka Storage Vessels for Petroleum Liquids .......... .......... X
for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage .......... .......... X
Vessels (Including Petroleum Liquid
Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters.............. X .......... X
M Secondary Brass and Bronze Production X .......... X
Plants.
N Primary Emissions from Basic Oxygen X .......... X
Process Furnaces for Which
Construction is Commenced After June
11, 1973.
Na Secondary Emissions from Basic Oxygen .......... .......... X
Process Steelmaking Facilities for
Which Construction is Commenced
After January 20, 1983.
O Sewage Treatment Plants.............. X .......... X
P Primary Copper Smelters.............. X .......... X
Q Primary Zinc Smelters................ X .......... X
[[Page 43]]
R Primary Lead Smelters................ X .......... X
S Primary Aluminum Reduction Plants.... X .......... X
T Phosphate Fertilizer Industry: Wet X .......... X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: X .......... X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X .......... X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: Triple X .......... X
Superphosphate Plants.
X Phosphate Fertilizer Industry: X .......... X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation and Processing X .......... X
Plants.
Z Ferroalloy Production Facilities..... X .......... X
AA Steel Plants: Electric Arc Furnaces X .......... X
Constructed After October 21, 1974
and On or Before August 17, 1983.
AAa Steel Plants: Electric Arc Furnaces .......... .......... X
and Argon-Oxygen Decarburization
Vessels Constructed After August 7,
1983.
BB Kraft Pulp Mills..................... X .......... X
CC Glass Manufacturing Plants........... .......... .......... X
DD Grain Elevators...................... X .......... X
EE Surface Coating of Metal Furniture... .......... .......... X
FF (Reserved)........................... .......... .......... ..........
GG Stationary Gas Turbines.............. .......... .......... X
HH Lime Manufacturing Plants............ X .......... X
KK Lead-Acid Battery Manufacturing .......... .......... X
Plants.
LL Metallic Mineral Processing Plants... .......... .......... X
MM Automobile and Light Duty Trucks .......... .......... X
Surface Coating Operations.
NN Phosphate Rock Plants................ .......... .......... X
PP Ammonium Sulfate Manufacture......... .......... .......... X
QQ Graphic Arts Industry: Publication .......... .......... X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label .......... .......... X
Surface Coating Operations.
SS Industrial Surface Coating: Large .......... .......... X
Appliances.
TT Metal Coil Surface Coating........... .......... .......... X
UU Asphalt Processing and Asphalt .......... .......... X
Roofing Manufacture.
VV Equipment Leaks of VOC in the .......... .......... X
Synthetic Organic Industry Chemicals
Manufacturing.
VVa Equipment Leaks of VOC in the .......... .......... X
Synthetic Organic Industry for Which
Construction, Reconstruction, or
Chemicals Manufacturing Modification
Commenced After November 7, 2006.
WW Beverage Can Surface Coating Industry .......... .......... X
XX Bulk Gasoline Terminals.............. .......... .......... ..........
AAA New Residential Wood Heaters......... .......... X X
BBB Rubber Tire Manufacturing Industry... .......... X X
CCC (Reserved)........................... .......... .......... ..........
DDD Volatile Organic Compounds (VOC) .......... .......... X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................... .......... .......... ..........
FFF Flexible Vinyl and Urethane Coating .......... .......... X
and Printing.
GGG Equipment Leaks of VOC in Petroleum .......... .......... X
Refineries.
GGGa Equipment Leaks of VOC in Petroleum .......... .......... X
Refineries for Which Construction,
Reconstruction, or Modification
Commenced After November 7, 2006.
HHH Synthetic Fiber Production Facilities .......... .......... X
III Volatile Organic Compound (VOC) .......... .......... X
Emissions From the Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Air Oxidation Unit Processes.
JJJ Petroleum Dry Cleaners............... .......... .......... X
KKK Equipment Leaks of VOC From Onshore .......... .......... X
Natural Gas Processing Plants.
LLL Onshore Natural Gas Processing: SO2 .......... .......... X
Emissions.
MMM (Reserved)........................... .......... .......... ..........
NNN Volatile Organic Compound (VOC) .......... .......... X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing Plants .......... .......... X
PPP Wool Fiberglass Insulation .......... .......... X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum Refinery .......... X X
Wastewater Systems.
RRR Volatile Organic Compound Emissions .......... .......... X
from Synthetic Organic Chemical
Manufacturing Industry (SOCMI)
Reactor Processes.
SSS Magnetic Tape Coating Facilities..... .......... X X
[[Page 44]]
TTT Industrial Surface Coating: Surface .......... X X
Coating of Plastic Parts for
Business Machines.
UUU Calciners and Dryers in Mineral .......... .......... X
Industries.
VVV Polymeric Coating of Supporting .......... .......... X
Substrates Facilities.
WWW Municipal Solid Waste Landfills...... .......... .......... X
AAAA Small Municipal Waste Combustion X X X
Units for Which Construction is
Commenced After August 30, 1999 or
for Which Modification or
Reconstruction is Commended After
June 6, 2001.
CCCC Commercial and Industrial Solid Waste .......... .......... X
Incineration Units for Which
Construction Is Commenced After
November 30, 1999 or for Which
Modification or Reconstruction Is
Commenced on or After June 1, 2001.
EEEE Other Solid Waste Incineration Units .......... .......... X
for Which Construction is Commenced
After December 9, 2004, or for Which
Modification or Reconstruction is
Commenced on or After June 16, 2006.
GGGG (Reserved)........................... .......... .......... ..........
HHHH (Reserved)........................... .......... .......... ..........
IIII Stationary Compression Ignition .......... .......... X
Internal Combustion Engines.
JJJJ Stationary Spark Ignition Internal .......... .......... X
Combustion Engines.
KKKK Stationary Combustion Turbines....... .......... .......... X
LLLL New Sewage Sludge Incineration Units. .......... .......... ..........
OOOO Crude Oil and Natural Gas Production, .......... .......... ..........
Transmission, and Distribution.
----------------------------------------------------------------------------------------------------------------
(ix) Delegations for Tuolumne County Air Pollution Control District,
Ventura County Air Pollution Control District, and Yolo-Solano Air
Quality Management District are shown in the following table:
Delegation Status for New Source Performance Standards for Tuolumne County Air Pollution Control District,
Ventura County Air Pollution Control District, and Yolo-Solano Air Quality Management District
----------------------------------------------------------------------------------------------------------------
Air Pollution Control Agency
--------------------------------------------------
Subpart Tuolumne County Ventura County Yolo-Solano
APCD APCD AQMD
----------------------------------------------------------------------------------------------------------------
A General Provisions............... X X
D Fossil-Fuel Fired Steam X X
Generators Constructed After
August 17, 1971.
Da Electric Utility Steam Generating X
Units Constructed After
September 18, 1978.
Db Industrial-Commercial- X X
Institutional Steam Generating
Units.
Dc Small Industrial Steam Generating X
Units.
E Incinerators..................... X
Ea Municipal Waste Combustors X
Constructed After December 20,
1989 and On or Before September
20, 1994.
Eb Municipal Waste Combustors X
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste X
Incinerators for Which
Construction is Commenced After
June 20, 1996.
F Portland Cement Plants........... X
G Nitric Acid Plants............... X
H Sulfuric Acid Plants............. X
I Hot Mix Asphalt Facilities....... X X
J Petroleum Refineries............. X X
Ja Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After May
14, 2007.
K Storage Vessels for Petroleum X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978,
and Prior to July 23, 1984.
[[Page 45]]
Kb Volatile Organic Liquid Storage X
Vessels (Including Petroleum
Liquid Storage Vessels) for
Which Construction,
Reconstruction, or Modification
Commenced After July 23, 1984.
L Secondary Lead Smelters.......... X
M Secondary Brass and Bronze X
Production Plants.
N Primary Emissions from Basic X
Oxygen Process Furnaces for
Which Construction is Commenced
After June 11, 1973.
Na Secondary Emissions from Basic X
Oxygen Process Steelmaking
Facilities for Which
Construction is Commenced After
January 20, 1983.
O Sewage Treatment Plants.......... X
P Primary Copper Smelters.......... X
Q Primary Zinc Smelters............ X
R Primary Lead Smelters............ X
S Primary Aluminum Reduction Plants X
T Phosphate Fertilizer Industry: X
Wet Process Phosphoric Acid
Plants.
U Phosphate Fertilizer Industry: X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants.......... X
Z Ferroalloy Production Facilities. X
AA Steel Plants: Electric Arc X X
Furnaces Constructed After
October 21, 1974 and On or
Before August 17, 1983.
AAa Steel Plants: Electric Arc X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
BB Kraft pulp Mills................. X
CC Glass Manufacturing Plants....... X
DD Grain Elevators.................. X
EE Surface Coating of Metal X
Furniture.
FF (Reserved).......................
GG Stationary Gas Turbines.......... X
HH Lime Manufacturing Plants........ X
KK Lead-Acid Battery Manufacturing X
Plants.
LL Metallic Mineral Processing X
Plants.
MM Automobile and Light Duty Trucks X
Surface Coating Operations.
NN Phosphate Rock Plants............ X
PP Ammonium Sulfate Manufacture..... X
QQ Graphic Arts Industry: X
Publication Rotogravure Printing.
RR Pressure Sensitive Tape and Label X
Surface Coating Operations.
SS Industrial Surface Coating: Large X
Appliances.
TT Metal Coil Surface Coating....... X
UU Asphalt Processing and Asphalt X
Roofing Manufacture.
VV Equipment Leaks of VOC in the X
Synthetic Organic Chemicals
Manufacturing Industry.
VVa Equipment Leaks of VOC in the
Synthetic Organic Chemicals
Manufacturing Industry for Which
Construction, Reconstruction, or
Modification Commenced After
November 7, 2006.
WW Beverage Can Surface Coating X
Industry.
XX Bulk Gasoline Terminals..........
AAA New Residential Wood Heaters..... X
BBB Rubber Tire Manufacturing X
Industry.
CCC (Reserved).......................
DDD Volatile Organic Compounds (VOC) X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved).......................
FFF Flexible Vinyl and Urethane X
Coating and Printing.
GGG Equipment Leaks of VOC in X
Petroleum Refineries.
GGGa Equipment Leaks of VOC in
Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After
November 7, 2006.
HHH Synthetic Fiber Production X
Facilities.
III Volatile Organic Compound (VOC) X
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
[[Page 46]]
JJJ Petroleum Dry Cleaners........... X
KKK Equipment Leaks of VOC From X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: X
SO2 Emissions.
MMM (Reserved).......................
NNN Volatile Organic Compound (VOC) X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing X X
Plants.
PPP Wool Fiberglass Insulation X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X
Refinery Wastewater Systems.
RRR Volatile Organic Compound X
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
SSS Magnetic Tape Coating Facilities. X
TTT Industrial Surface Coating: X
Surface Coating of Plastic Parts
for Business Machines.
UUU Calciners and Dryers in Mineral X
Industries.
VVV Polymeric Coating of Supporting X
Substrates Facilities.
WWW Municipal Solid Waste Landfills.. X X
AAAA Small Municipal Waste Combustion X
Units for Which Construction is
Commenced After August 30, 1999
or for Which Modification or
Reconstruction is Commenced
After June 6, 2001.
CCCC Commercial and Industrial Solid X
Waste Incineration Units for
Which Construction Is Commenced
After November 30, 1999 or for
Which Modification or
Reconstruction Is Commenced on
or After June 1, 2001.
EEEE Other Solid Waste Incineration
Units for Which Construction is
Commenced After December 9,
2004, or for Which Modification
or Reconstruction is Commenced
on or After June 16, 2006.
GGGG (Reserved).......................
IIII Stationary Compression Ignition
Internal Combustion Engines.
JJJJ Stationary Spark Ignition
Internal Combustion Engines.
KKKK Stationary Combustion Turbines...
----------------------------------------------------------------------------------------------------------------
(3) Hawaii. The following table identifies delegations for Hawaii:
Delegation Status for New Source Performance Standards for Hawaii:
Delegation Status for New Source Performance Standards for Hawaii
------------------------------------------------------------------------
Subpart Hawaii
------------------------------------------------------------------------
A General Provisions.............. X
D Fossil-Fuel Fired Steam X
Generators Constructed After
August 17, 1971.
Da Electric Utility Steam X
Generating Units Constructed
After September 18, 1978.
Db Industrial-Commercial- X
Institutional Steam Generating
Units.
Dc Small Industrial Steam X
Generating Units.
E Incinerators.................... X
Ea Municipal Waste Combustors X
Constructed After December 20,
1989 and On or Before September
20, 1994.
Eb Municipal Waste Combustors X
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious X
Waste Incinerators for Which
Construction is Commenced After
June 20, 1996.
F Portland Cement Plants.......... X
G Nitric Acid Plants..............
H Sulfuric Acid Plants............
I Hot Mix Asphalt Facilities...... X
J Petroleum Refineries............ X
Ja Petroleum Refineries for Which
Construction, Reconstruction,
or Modification Commenced After
May 14, 2007.
K Storage Vessels for Petroleum X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978,
and Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X
Vessels (Including Petroleum
Liquid Storage Vessels) for
Which Construction,
Reconstruction, or Modification
Commenced After July 23, 1984.
[[Page 47]]
L Secondary Lead Smelters.........
M Secondary Brass and Bronze
Production Plants.
N Primary Emissions from Basic
Oxygen Process Furnaces for
Which Construction is Commenced
After June 11, 1973.
Na Secondary Emissions from Basic
Oxygen Process Steelmaking
Facilities for Which
Construction is Commenced After
January 20, 1983.
O Sewage Treatment Plants......... X
P Primary Copper Smelters.........
Q Primary Zinc Smelters...........
R Primary Lead Smelters...........
S Primary Aluminum Reduction
Plants.
T Phosphate Fertilizer Industry:
Wet Process Phosphoric Acid
Plants.
U Phosphate Fertilizer Industry:
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry:
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry:
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry:
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants......... X
Z Ferroalloy Production Facilities
AA Steel Plants: Electric Arc X
Furnaces Constructed After
October 21, 1974 and On or
Before August 17, 1983.
AAa Steel Plants: Electric Arc X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7,
1983.
BB Kraft pulp Mills................
CC Glass Manufacturing Plants......
DD Grain Elevators.................
EE Surface Coating of Metal
Furniture.
FF (Reserved)......................
GG Stationary Gas Turbines......... X
HH Lime Manufacturing Plants.......
KK Lead-Acid Battery Manufacturing
Plants.
LL Metallic Mineral Processing
Plants.
MM Automobile and Light Duty Trucks
Surface Coating Operations.
NN Phosphate Rock Plants...........
PP Ammonium Sulfate Manufacture....
QQ Graphic Arts Industry:
Publication Rotogravure
Printing.
RR Pressure Sensitive Tape and
Label Surface Coating
Operations.
SS Industrial Surface Coating:
Large Appliances.
TT Metal Coil Surface Coating......
UU Asphalt Processing and Asphalt
Roofing Manufacture.
VV Equipment Leaks of VOC in the X
Synthetic Organic Chemicals
Manufacturing Industry.
VVa Equipment Leaks of VOC in the
Synthetic Organic Chemicals
Manufacturing Industry for
Which Construction,
Reconstruction, or Modification
Commenced After November 7,
2006.
WW Beverage Can Surface Coating X
Industry.
XX Bulk Gasoline Terminals......... X
AAA New Residential Wool Heaters....
BBB Rubber Tire Manufacturing
Industry.
CCC (Reserved)......................
DDD Volatile Organic Compounds (VOC)
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)......................
FFF Flexible Vinyl and Urethane
Coating and Printing.
GGG Equipment Leaks of VOC in X
Petroleum Refineries.
GGGa Equipment Leaks of VOC in
Petroleum Refineries for Which
Construction, Reconstruction,
or Modification Commenced After
November 7, 2006.
HHH Synthetic Fiber Production
Facilities.
III Volatile Organic Compound (VOC)
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners.......... X
KKK Equipment Leaks of VOC From
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing:
SO2 Emissions.
MMM (Reserved)......................
NNN Volatile Organic Compound (VOC) X
Emissions From Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Distillation
Operations.
OOO Nonmetallic Mineral Processing X
Plants.
PPP Wool Fiberglass Insulation
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X
Refinery Wastewater.
RRR Volatile Organic Compound
Emissions from Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Reactor
Processes.
SSS Magnetic Tape Coating Facilities
TTT Industrial Surface Coating:
Surface Coating of Plastic
Parts for Business Machines.
UUU Calciners and Dryers in Mineral X
Industries.
VVV Polymeric Coating of Supporting X
Substrates Facilities.
WWW Municipal Solid Waste Landfills. X
[[Page 48]]
AAAA Small Municipal Waste Combustion X
Units for Which Construction is
Commenced After August 30, 1999
or for Which Modification or
Reconstruction is Commenced
After June 6, 2001.
CCCC Commercial and Industrial Solid X
Waste Incineration Units for
Which Construction Is Commenced
After November 30, 1999 or for
Which Modification or
Reconstruction Is Commenced on
or After June 1, 2001.
EEEE Other Solid Waste Incineration
Units for Which Construction is
Commenced After December 9,
2004, or for Which Modification
or Reconstruction is Commenced
on or After June 16, 2006.
GGGG (Reserved)......................
IIII Stationary Compression Ignition
Internal Combustion Engines.
JJJJ Stationary Spark Ignition
Internal Combustion Engines.
KKKK Stationary Combustion Turbines..
------------------------------------------------------------------------
(4) Nevada. The following table identifies delegations for Nevada:
Delegation Status for New Source Performance Standards for Nevada
------------------------------------------------------------------------
Air pollution control agency
-----------------------------------
Subpart Clark Washoe
Nevada DEP County County
------------------------------------------------------------------------
A General Provisions..... X X X
D Fossil-Fuel Fired Steam X X X
Generators Constructed
After August 17, 1971.
Da Electric Utility Steam X X
Generating Units
Constructed After
September 18, 1978.
Db Industrial-Commercial- X X
Institutional Steam
Generating Units.
Dc Small Industrial- X X
Commercial-
Institutional Steam
Generating Units.
E Incinerators........... X X X
Ea Municipal Waste X X
Combustors Constructed
After December 20,
1989 and On or Before
September 20, 1994.
Eb Large Municipal Waste X X
Combustors Constructed
After September 20,
1994.
Ec Hospital/Medical/ X X
Infectious Waste
Incinerators for Which
Construction is
Commenced After June
20, 1996.
F Portland Cement Plants. X X X
G Nitric Acid Plants..... X X
Ga Nitric Acid Plants For .......... ..........
Which Construction,
Reconstruction or
Modification Commenced
After October 14, 2011.
H Sulfuric Acid Plant.... X X
I Hot Mix Asphalt X X X
Facilities.
J Petroleum Refineries... X X
Ja Petroleum Refineries .......... ..........
for Which
Construction,
Reconstruction, or
Modification Commenced
After May 14, 2007.
K Storage Vessels for X X X
Petroleum Liquids for
Which Construction,
Reconstruction, or
Modification Commenced
After June 11, 1973,
and Prior to May 19,
1978.
Ka Storage Vessels for X X X
Petroleum Liquids for
Which Construction,
Reconstruction, or
Modification Commenced
After May 18, 1978,
and Prior to July 23,
1984.
Kb Volatile Organic Liquid X X
Storage Vessels
(Including Petroleum
Liquid Storage
Vessels) for Which
Construction,
Reconstruction, or
Modification Commenced
After July 23, 1984.
L Secondary Lead Smelters X X X
M Secondary Brass and X X
Bronze Production
Plants.
N Primary Emissions from X X
Basic Oxygen Process
Furnaces for Which
Construction is
Commenced After June
11, 1973.
Na Secondary Emissions X X
from Basic Oxygen
Process Steelmaking
Facilities for Which
Construction is
Commenced After
January 20, 1983.
O Sewage Treatment Plants X X X
P Primary Copper Smelters X X X
Q Primary Zinc Smelters.. X X X
R Primary Lead Smelters.. X X X
S Primary Aluminum X X
Reduction Plants.
T Phosphate Fertilizer X X
Industry: Wet Process
Phosphoric Acid Plants.
U Phosphate Fertilizer X X
Industry:
Superphosphoric Acid
Plants.
V Phosphate Fertilizer X X
Industry: Diammonium
Phosphate Plants.
W Phosphate Fertilizer X X
Industry: Triple
Superphosphate Plants.
X Phosphate Fertilizer X X
Industry: Granular
Triple Superphosphate
Storage Facilities.
Y Coal Preparation and X X X
Processing Plants.
Z Ferroalloy Production X X
Facilities.
AA Steel Plants: Electric X X
Arc Furnaces
Constructed After
October 21, 1974 and
On or Before August
17, 1983.
AAa Steel Plants: Electric X X
Arc Furnaces and Argon-
Oxygen Decarburization
Vessels Constructed
After August 7, 1983.
BB Kraft Pulp Mills....... X X
[[Page 49]]
CC Glass Manufacturing X X
Plants.
DD Grain Elevators........ X X X
EE Surface Coating of X X X
Metal Furniture.
FF (Reserved)............. .......... ..........
GG Stationary Gas Turbines X X X
HH Lime Manufacturing X X X
Plants.
KK Lead-Acid Battery X X X
Manufacturing Plants.
LL Metallic Mineral X X X
Processing Plants.
MM Automobile and Light X X X
Duty Trucks Surface
Coating Operations.
NN Phosphate Rock Plants.. X X X
PP Ammonium Sulfate X X
Manufacture.
QQ Graphic Arts Industry: X X X
Publication
Rotogravure Printing.
RR Pressure Sensitive Tape X X
and Label Surface
Coating Operations.
SS Industrial Surface X X X
Coating: Large
Appliances.
TT Metal Coil Surface X X X
Coating.
UU Asphalt Processing and X X X
Asphalt Roofing
Manufacture.
VV Equipment Leaks of VOC X X X
in the Synthetic
Organic Industry
Chemicals
Manufacturing.
VVa Equipment Leaks of VOC X X
in the Synthetic
Organic Industry for
Which Construction,
Reconstruction, or
Chemicals
Manufacturing
Modification Commenced
After November 7, 2006.
WW Beverage Can Surface X X
Coating Industry.
XX Bulk Gasoline Terminals X X
AAA New Residential Wood .......... X
Heaters.
BBB Rubber Tire X X
Manufacturing Industry.
CCC (Reserved)............. .......... ..........
DDD Volatile Organic X X
Compounds (VOC)
Emissions from the
Polymer Manufacturing
Industry.
EEE (Reserved)............. .......... ..........
FFF Flexible Vinyl and X X
Urethane Coating and
Printing.
GGG Equipment Leaks of VOC X X
in Petroleum
Refineries.
GGGa Equipment Leaks of VOC X X
in Petroleum
Refineries for Which
Construction,
Reconstruction, or
Modification Commenced
After November 7, 2006.
HHH Synthetic Fiber X X
Production Facilities.
III Volatile Organic X X
Compound (VOC)
Emissions From the
Synthetic Organic
Chemical Manufacturing
Industry (SOCMI) Air
Oxidation Unit
Processes.
JJJ Petroleum Dry Cleaners. X X X
KKK Equipment Leaks of VOC X X
From Onshore Natural
Gas Processing Plants.
LLL Onshore Natural Gas X X
Processing: SO2
Emissions.
MMM (Reserved)............. .......... ..........
NNN Volatile Organic X X
Compound (VOC)
Emissions From
Synthetic Organic
Chemical Manufacturing
Industry (SOCMI)
Distillation
Operations.
OOO Nonmetallic Mineral X X
Processing Plants.
PPP Wool Fiberglass X X
Insulation
Manufacturing Plants.
QQQ VOC Emissions From X X
Petroleum Refinery
Wastewater Systems.
RRR Volatile Organic X X
Compound Emissions
from Synthetic Organic
Chemical Manufacturing
Industry (SOCMI)
Reactor Processes.
SSS Magnetic Tape Coating X X
Facilities.
TTT Industrial Surface X X X
Coating: Surface
Coating of Plastic
Parts for Business
Machines.
UUU Calciners and Dryers in X X X
Mineral Industries.
VVV Polymeric Coating of X X X
Supporting Substrates
Facilities.
WWW Municipal Solid Waste X X X
Landfills.
AAAA Small Municipal Waste X X X
Combustion Units for
Which Construction is
Commenced After August
30, 1999 or for Which
Modification or
Reconstruction is
Commended After June
6, 2001.
CCCC Commercial and X X X
Industrial Solid Waste
Incineration Units for
Which Construction Is
Commenced After
November 30, 1999 or
for Which Modification
or Reconstruction Is
Commenced on or After
June 1, 2001.
EEEE Other Solid Waste X X X
Incineration Units for
Which Construction is
Commenced After
December 9, 2004, or
for Which Modification
or Reconstruction is
Commenced on or After
June 16, 2006.
GGGG (Reserved)............. .......... ..........
HHHH (Reserved)............. .......... ..........
IIII Stationary Compression X X X
Ignition Internal
Combustion Engines.
JJJJ Stationary Spark X X X
Ignition Internal
Combustion Engines.
KKKK Stationary Combustion X X X
Turbines.
LLLL New Sewage Sludge .......... X
Incineration Units.
OOOO Crude Oil and Natural .......... ..........
Gas Production,
Transmission, and
Distribution.
------------------------------------------------------------------------
[[Page 50]]
(5) Guam. The following table identifies delegations as of June 15,
2001:
Delegation Status for New Source Performance Standards for Guam
----------------------------------------------------------------------------------------------------------------
Subpart Guam
----------------------------------------------------------------------------------------------------------------
A General Provisions................ X
D Fossil-Fuel Fired Steam Generators X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating
Units Constructed After September
18, 1978.
Db Industrial-Commercial-
Institutional Steam Generating
Units.
Dc Small Industrial Steam Generating
Units.
E Incinerators......................
Ea Municipal Waste Combustors
Constructed After December 20,
1989 and On or Before September
20, 1994.
Eb Municipal Waste Combustors
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste
Incinerators for Which
Construction is Commenced After
June 20, 1996.
F Portland Cement Plants............ X
G Nitric Acid Plants................
H Sulfuric Acid Plants..............
I Hot Mix Asphalt Facilities........ X
J Petroleum Refineries.............. X
K Storage Vessels for Petroleum X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
----------------------------------------------------------------------------------------------------------------
(e) The following lists the specific part 60 standards that have
been delegated unchanged to the air pollution control agencies in Region
6.
(1) New Mexico. The New Mexico Environment Department has been
delegated all part 60 standards promulgated by EPA, except subpart AAA--
Standards of Performance for New Residential Wood Heaters; and subpart
HHHH--Emission Guidelines and Compliance Times for Coal-Fired Electric
Steam Generating Units, as amended in the Federal Register through
September 23, 2013.
(2) Louisiana. The Louisiana Department of Environmental Quality has
been delegated all part 60 standards promulgated by EPA, except subpart
AAA--Standards of Performance for New Residential Wood Heaters, as
amended in the Federal Register through July 1, 2013.
Delegation Status for Part 60 Standards--State of Louisiana
[Excluding Indian Country]
------------------------------------------------------------------------
Subpart Source category LDEQ \1\
------------------------------------------------------------------------
A...................... General Provisions.... Yes
Ce..................... Emission Guidelines Yes
and Compliance Times
for Hospital/Medical/
Infectious Waste
Incinerators.
D...................... Fossil Fueled Steam Yes
Generators (250 MM BTU/hr).
Da..................... Electric Utility Steam Yes
Generating Units (250 MM BTU/hr).
Db..................... Industrial-Commercial- Yes
Institutional Steam
Generating Units (100
to 250 MM BTU/hr).
Dc..................... Industrial-Commercial- Yes
Institutional Small
Steam Generating
Units (10 to 100 MM
BTU/hr).
E...................... Incinerators (50 tons per day).
Ea..................... Municipal Waste Yes
Combustors.
Eb..................... Large Municipal Waste Yes
Combustors.
Ec..................... Hospital/Medical/ Yes
Infectious Waste
Incinerators.
F...................... Portland Cement Plants Yes
G...................... Nitric Acid Plants.... Yes
Ga..................... Nitric Acid Plants Yes
(after October 14,
2011).
H...................... Sulfuric Acid Plants.. Yes
I...................... Hot Mix Asphalt Yes
Facilities.
J...................... Petroleum Refineries.. Yes
Ja..................... Petroleum Refineries Yes
(After May 14, 2007).
K...................... Storage Vessels for Yes
Petroleum Liquids
(After 6/11/73 &
Before 5/19/78).
Ka..................... Storage Vessels for Yes
Petroleum Liquids
(After 6/11/73 &
Before 5/19/78).
[[Page 51]]
Kb..................... Volatile Organic Yes
Liquid Storage
Vessels (Including
Petroleum Liquid Stg/
Vessels) After 7/23/
84.
L...................... Secondary Lead Yes
Smelters Yes.
M...................... Secondary Brass and Yes
Bronze Production
Plants.
N...................... Primary Emissions from Yes
Basic Oxygen Process
Furnaces
(Construction
Commenced After June
11, 1973).
Na..................... Secondary Emissions Yes
from Basic Oxygen
Process Steelmaking
Facilities
Construction is
Commenced After
January 20, 1983.
O...................... Sewage Treatment Yes
Plants.
P...................... Primary Copper Yes
Smelters.
Q...................... Primary Zinc Smelters. Yes
R...................... Primary Lead Smelters. Yes
S...................... Primary Aluminum Yes
Reduction Plants.
T...................... Phosphate Fertilizer Yes
Industry: Wet Process
Phosphoric Plants.
U...................... Phosphate Fertilizer Yes
Industry:
Superphosphoric Acid
Plants.
V...................... Phosphate Fertilizer Yes
Industry: Diammonium
Phosphate Plants.
W...................... Phosphate Fertilizer Yes
Industry: Triple
Superphosphate Plants.
X...................... Phosphate Fertilizer Yes
Industry: Granular
Triple Superphosphate
Storage Facilities.
Y...................... Coal Preparation Yes
Plants.
Z...................... Ferroalloy Production Yes
Facilities.
AA..................... Steel Plants: Electric Yes
Arc Furnaces After 10/
21/74 & On or Before
8/17/83.
AAa.................... Steel Plants: Electric Yes
Arc Furnaces & Argon-
Oxygen
Decarburization
Vessels After 8/07/83.
BB..................... Kraft Pulp Mills...... Yes
CC..................... Glass Manufacturing Yes
Plants.
DD..................... Grain Elevators....... Yes
EE..................... Surface Coating of Yes
Metal Furniture.
GG..................... Stationary Gas Yes
Turbines.
HH..................... Lime Manufacturing Yes
Plants.
KK..................... Lead-Acid Battery Yes
Manufacturing Plants.
LL..................... Metallic Mineral Yes
Processing Plants.
MM..................... Automobile & Light Yes
Duty Truck Surface
Coating Operations.
NN..................... Phosphate Yes
Manufacturing Plants.
PP..................... Ammonium Sulfate Yes
Manufacture.
QQ..................... Graphic Arts Industry: Yes
Publication
Rotogravure Printing.
RR..................... Pressure Sensitive Yes
Tape and Label
Surface Coating
Operations.
SS..................... Industrial Surface Yes
Coating: Large
Appliances.
TT..................... Metal Coil Surface Yes
Coating.
UU..................... Asphalt Processing and Yes
Asphalt Roofing
Manufacture.
VV..................... VOC Equipment Leaks in Yes
the SOCMI Industry.
VVa.................... VOC Equipment Leaks in Yes
the SOCMI Industry
(After November 7,
2006).
XX..................... Bulk Gasoline Yes
Terminals.
AAA.................... New Residential Wood No
Heaters.
BBB.................... Rubber Tire Yes
Manufacturing
Industry.
DDD.................... Volatile Organic Yes
Compound (VOC)
Emissions from the
Polymer Manufacturing
Industry.
FFF.................... Flexible Vinyl and Yes
Urethane Coating and
Printing.
GGG.................... VOC Equipment Leaks in Yes
Petroleum Refineries.
HHH.................... Synthetic Fiber Yes
Production.
III.................... VOC Emissions from the Yes
SOCMI Air Oxidation
Unit Processes.
JJJ.................... Petroleum Dry Cleaners Yes
KKK.................... VOC Equipment Leaks Yes
From Onshore Natural
Gas Processing Plants.
LLL.................... Onshore Natural Gas Yes
Processing: SO2
Emissions.
NNN.................... VOC Emissions from Yes
SOCMI Distillation
Operations.
OOO.................... Nonmetallic Mineral Yes
Processing Plants.
PPP.................... Wool Fiberglass Yes
Insulation
Manufacturing Plants.
QQQ.................... VOC Emissions From Yes
Petroleum Refinery
Wastewater Systems.
RRR.................... VOC Emissions from Yes
SOCMI Reactor
Processes.
SSS.................... Magnetic Tape Coating Yes
Operations.
TTT.................... Industrial Surface Yes
Coating: Plastic
Parts for Business
Machines.
UUU.................... Calciners and Dryers Yes
in Mineral Industries.
VVV.................... Polymeric Coating of Yes
Supporting Substrates
Facilities.
WWW.................... Municipal Solid Waste Yes
Landfills.
AAAA................... Small Municipal Waste Yes
Combustion Units
(Construction is
Commenced After 8/30/
99 or Modification/
Reconstruction is
Commenced After 6/06/
2001).
CCCC................... Commercial & Yes
Industrial Solid
Waste Incineration
Units (Construction
is Commenced After 11/
30/1999 or
Modification/
Reconstruction is
Commenced on or After
6/01/2001).
DDDD................... Emission Guidelines & Yes
Compliance Times for
Commercial &
Industrial Solid
Waste Incineration
Units (Commenced
Construction On or
Before 11/30/1999).
EEEE................... Other Solid Waste Yes
Incineration Units
(Constructed after 12/
09/2004 or
Modification/
Reconstruction is
commenced on or after
06/16/2004).
IIII................... Stationary Compression Yes
Ignition Internal
Combustion Engines.
[[Page 52]]
JJJJ................... Stationary Spark Yes
Ignition Internal
Combustion Engines.
KKKK................... Stationary Combustion Yes
Turbines
(Construction
Commenced After 02/18/
2005).
LLLL................... New Sewage Sludge Yes
Incineration Units.
MMMM................... Emission Guidelines Yes
and Compliance Times
for Existing Sewage
Sludge Incineration
Units.
OOOO................... Crude Oil and Natural Yes
Gas Production,
Transmission and
Distribution.
------------------------------------------------------------------------
\1\ The Louisiana Department of Environmental Quality (LDEQ) has been
delegated all Part 60 standards promulgated by EPA, except subpart
AAA--Standards of Performance for New Residential Wood Heaters--as
amended in the Federal Register through July 1, 2013.
(3) Albuquerque-Bernalillo County Air Quality Control Board. The
Albuquerque-Bernalillo County Air Quality Control Board has been
delegated all part 60 standards promulgated by EPA, except subpart AAA--
Standards of Performance for New Residential Wood Heaters, as amended in
the Federal Register through September 13, 2013.
[40 FR 18169, Apr. 25, 1975]
Editorial Note: For Federal Register citations affecting Sec. 60.4,
see the List of CFR Sections Affected, which appears in the Finding Aids
section of the printed volume and at www.fdsys.gov.
Sec. 60.5 Determination of construction or modification.
(a) When requested to do so by an owner or operator, the
Administrator will make a determination of whether action taken or
intended to be taken by such owner or operator constitutes construction
(including reconstruction) or modification or the commencement thereof
within the meaning of this part.
(b) The Administrator will respond to any request for a
determination under paragraph (a) of this section within 30 days of
receipt of such request.
[40 FR 58418, Dec. 16, 1975]
Sec. 60.6 Review of plans.
(a) When requested to do so by an owner or operator, the
Administrator will review plans for construction or modification for the
purpose of providing technical advice to the owner or operator.
(b)(1) A separate request shall be submitted for each construction
or modification project.
(2) Each request shall identify the location of such project, and be
accompanied by technical information describing the proposed nature,
size, design, and method of operation of each affected facility involved
in such project, including information on any equipment to be used for
measurement or control of emissions.
(c) Neither a request for plans review nor advice furnished by the
Administrator in response to such request shall (1) relieve an owner or
operator of legal responsibility for compliance with any provision of
this part or of any applicable State or local requirement, or (2)
prevent the Administrator from implementing or enforcing any provision
of this part or taking any other action authorized by the Act.
[36 FR 24877, Dec. 23, 1971, as amended at 39 FR 9314, Mar. 8, 1974]
Sec. 60.7 Notification and record keeping.
(a) Any owner or operator subject to the provisions of this part
shall furnish the Administrator written notification or, if acceptable
to both the Administrator and the owner or operator of a source,
electronic notification, as follows:
(1) A notification of the date construction (or reconstruction as
defined under Sec. 60.15) of an affected facility is commenced
postmarked no later than 30 days after such date. This requirement shall
not apply in the case of mass-produced facilities which are purchased in
completed form.
(2) [Reserved]
(3) A notification of the actual date of initial startup of an
affected facility postmarked within 15 days after such date.
(4) A notification of any physical or operational change to an
existing facility which may increase the emission
[[Page 53]]
rate of any air pollutant to which a standard applies, unless that
change is specifically exempted under an applicable subpart or in Sec.
60.14(e). This notice shall be postmarked 60 days or as soon as
practicable before the change is commenced and shall include information
describing the precise nature of the change, present and proposed
emission control systems, productive capacity of the facility before and
after the change, and the expected completion date of the change. The
Administrator may request additional relevant information subsequent to
this notice.
(5) A notification of the date upon which demonstration of the
continuous monitoring system performance commences in accordance with
Sec. 60.13(c). Notification shall be postmarked not less than 30 days
prior to such date.
(6) A notification of the anticipated date for conducting the
opacity observations required by Sec. 60.11(e)(1) of this part. The
notification shall also include, if appropriate, a request for the
Administrator to provide a visible emissions reader during a performance
test. The notification shall be postmarked not less than 30 days prior
to such date.
(7) A notification that continuous opacity monitoring system data
results will be used to determine compliance with the applicable opacity
standard during a performance test required by Sec. 60.8 in lieu of
Method 9 observation data as allowed by Sec. 60.11(e)(5) of this part.
This notification shall be postmarked not less than 30 days prior to the
date of the performance test.
(b) Any owner or operator subject to the provisions of this part
shall maintain records of the occurrence and duration of any startup,
shutdown, or malfunction in the operation of an affected facility; any
malfunction of the air pollution control equipment; or any periods
during which a continuous monitoring system or monitoring device is
inoperative.
(c) Each owner or operator required to install a continuous
monitoring device shall submit excess emissions and monitoring systems
performance report (excess emissions are defined in applicable subparts)
and-or summary report form (see paragraph (d) of this section) to the
Administrator semiannually, except when: more frequent reporting is
specifically required by an applicable subpart; or the Administrator, on
a case-by-case basis, determines that more frequent reporting is
necessary to accurately assess the compliance status of the source. All
reports shall be postmarked by the 30th day following the end of each
six-month period. Written reports of excess emissions shall include the
following information:
(1) The magnitude of excess emissions computed in accordance with
Sec. 60.13(h), any conversion factor(s) used, and the date and time of
commencement and completion of each time period of excess emissions. The
process operating time during the reporting period.
(2) Specific identification of each period of excess emissions that
occurs during startups, shutdowns, and malfunctions of the affected
facility. The nature and cause of any malfunction (if known), the
corrective action taken or preventative measures adopted.
(3) The date and time identifying each period during which the
continuous monitoring system was inoperative except for zero and span
checks and the nature of the system repairs or adjustments.
(4) When no excess emissions have occurred or the continuous
monitoring system(s) have not been inoperative, repaired, or adjusted,
such information shall be stated in the report.
(d) The summary report form shall contain the information and be in
the format shown in figure 1 unless otherwise specified by the
Administrator. One summary report form shall be submitted for each
pollutant monitored at each affected facility.
(1) If the total duration of excess emissions for the reporting
period is less than 1 percent of the total operating time for the
reporting period and CMS downtime for the reporting period is less than
5 percent of the total operating time for the reporting period, only the
summary report form shall be submitted and the excess emission report
described in Sec. 60.7(c) need not be submitted unless requested by the
Administrator.
(2) If the total duration of excess emissions for the reporting
period is 1
[[Page 54]]
percent or greater of the total operating time for the reporting period
or the total CMS downtime for the reporting period is 5 percent or
greater of the total operating time for the reporting period, the
summary report form and the excess emission report described in Sec.
60.7(c) shall both be submitted.
Figure 1--Summary Report--Gaseous and Opacity Excess Emission and
Monitoring System Performance
Pollutant (Circle One--SO2/NOX/TRS/H2S/
CO/Opacity)
Reporting period dates: From ---------- to ----------
Company:
Emission Limitation_____________________________________________________
Address:
Monitor Manufacturer and Model No.______________________________________
Date of Latest CMS Certification or Audit_______________________________
Process Unit(s) Description:
Total source operating time in reporting period \1\_____________________
------------------------------------------------------------------------
CMS performance
Emission data summary \1\ summary \1\
------------------------------------------------------------------------
1. Duration of excess ........ 1. CMS downtime in
emissions in reporting reporting period due
period due to: to:
a. Startup/shutdown........ ........ a. Monitor equipment
malfunctions.
b. Control equipment ........ b. Non-Monitor
problems. equipment
malfunctions.
c. Process problems........ ........ c. Quality assurance
calibration.
d. Other known causes...... ........ d. Other known
causes.
e. Unknown causes.......... ........ e. Unknown causes...
2. Total duration of excess ........ 2. Total CMS Downtime
emission.
3. Total duration of excess % \2\ 3. [Total CMS % \2\
emissions x (100) [Total Downtime] x (100)
source operating time]. [Total source
operating time].
------------------------------------------------------------------------
\1\ For opacity, record all times in minutes. For gases, record all
times in hours.
\2\ For the reporting period: If the total duration of excess emissions
is 1 percent or greater of the total operating time or the total CMS
downtime is 5 percent or greater of the total operating time, both the
summary report form and the excess emission report described in Sec.
60.7(c) shall be submitted.
On a separate page, describe any changes since last quarter in CMS,
process or controls. I certify that the information contained in this
report is true, accurate, and complete.
________________________________________________________________________
Name
________________________________________________________________________
Signature
________________________________________________________________________
Title
________________________________________________________________________
Date
(e)(1) Notwithstanding the frequency of reporting requirements
specified in paragraph (c) of this section, an owner or operator who is
required by an applicable subpart to submit excess emissions and
monitoring systems performance reports (and summary reports) on a
quarterly (or more frequent) basis may reduce the frequency of reporting
for that standard to semiannual if the following conditions are met:
(i) For 1 full year (e.g., 4 quarterly or 12 monthly reporting
periods) the affected facility's excess emissions and monitoring systems
reports submitted to comply with a standard under this part continually
demonstrate that the facility is in compliance with the applicable
standard;
(ii) The owner or operator continues to comply with all
recordkeeping and monitoring requirements specified in this subpart and
the applicable standard; and
(iii) The Administrator does not object to a reduced frequency of
reporting for the affected facility, as provided in paragraph (e)(2) of
this section.
(2) The frequency of reporting of excess emissions and monitoring
systems performance (and summary) reports may be reduced only after the
owner or operator notifies the Administrator in writing of his or her
intention to make such a change and the Administrator does not object to
the intended change. In deciding whether to approve a reduced frequency
of reporting, the Administrator may review information concerning the
source's entire previous performance history during the required
recordkeeping period prior to the intended change, including performance
test results, monitoring data, and evaluations of an owner or operator's
conformance with operation and
[[Page 55]]
maintenance requirements. Such information may be used by the
Administrator to make a judgment about the source's potential for
noncompliance in the future. If the Administrator disapproves the owner
or operator's request to reduce the frequency of reporting, the
Administrator will notify the owner or operator in writing within 45
days after receiving notice of the owner or operator's intention. The
notification from the Administrator to the owner or operator will
specify the grounds on which the disapproval is based. In the absence of
a notice of disapproval within 45 days, approval is automatically
granted.
(3) As soon as monitoring data indicate that the affected facility
is not in compliance with any emission limitation or operating parameter
specified in the applicable standard, the frequency of reporting shall
revert to the frequency specified in the applicable standard, and the
owner or operator shall submit an excess emissions and monitoring
systems performance report (and summary report, if required) at the next
appropriate reporting period following the noncomplying event. After
demonstrating compliance with the applicable standard for another full
year, the owner or operator may again request approval from the
Administrator to reduce the frequency of reporting for that standard as
provided for in paragraphs (e)(1) and (e)(2) of this section.
(f) Any owner or operator subject to the provisions of this part
shall maintain a file of all measurements, including continuous
monitoring system, monitoring device, and performance testing
measurements; all continuous monitoring system performance evaluations;
all continuous monitoring system or monitoring device calibration
checks; adjustments and maintenance performed on these systems or
devices; and all other information required by this part recorded in a
permanent form suitable for inspection. The file shall be retained for
at least two years following the date of such measurements, maintenance,
reports, and records, except as follows:
(1) This paragraph applies to owners or operators required to
install a continuous emissions monitoring system (CEMS) where the CEMS
installed is automated, and where the calculated data averages do not
exclude periods of CEMS breakdown or malfunction. An automated CEMS
records and reduces the measured data to the form of the pollutant
emission standard through the use of a computerized data acquisition
system. In lieu of maintaining a file of all CEMS subhourly measurements
as required under paragraph (f) of this section, the owner or operator
shall retain the most recent consecutive three averaging periods of
subhourly measurements and a file that contains a hard copy of the data
acquisition system algorithm used to reduce the measured data into the
reportable form of the standard.
(2) This paragraph applies to owners or operators required to
install a CEMS where the measured data is manually reduced to obtain the
reportable form of the standard, and where the calculated data averages
do not exclude periods of CEMS breakdown or malfunction. In lieu of
maintaining a file of all CEMS subhourly measurements as required under
paragraph (f) of this section, the owner or operator shall retain all
subhourly measurements for the most recent reporting period. The
subhourly measurements shall be retained for 120 days from the date of
the most recent summary or excess emission report submitted to the
Administrator.
(3) The Administrator or delegated authority, upon notification to
the source, may require the owner or operator to maintain all
measurements as required by paragraph (f) of this section, if the
Administrator or the delegated authority determines these records are
required to more accurately assess the compliance status of the affected
source.
(g) If notification substantially similar to that in paragraph (a)
of this section is required by any other State or local agency, sending
the Administrator a copy of that notification will satisfy the
requirements of paragraph (a) of this section.
(h) Individual subparts of this part may include specific provisions
which
[[Page 56]]
clarify or make inapplicable the provisions set forth in this section.
[36 FR 24877, Dec. 28, 1971, as amended at 40 FR 46254, Oct. 6, 1975; 40
FR 58418, Dec. 16, 1975; 45 FR 5617, Jan. 23, 1980; 48 FR 48335, Oct.
18, 1983; 50 FR 53113, Dec. 27, 1985; 52 FR 9781, Mar. 26, 1987; 55 FR
51382, Dec. 13, 1990; 59 FR 12428, Mar. 16, 1994; 59 FR 47265, Sep. 15,
1994; 64 FR 7463, Feb. 12, 1999]
Sec. 60.8 Performance tests.
(a) Except as specified in paragraphs (a)(1),(a)(2), (a)(3), and
(a)(4) of this section, within 60 days after achieving the maximum
production rate at which the affected facility will be operated, but not
later than 180 days after initial startup of such facility, or at such
other times specified by this part, and at such other times as may be
required by the Administrator under section 114 of the Act, the owner or
operator of such facility shall conduct performance test(s) and furnish
the Administrator a written report of the results of such performance
test(s).
(1) If a force majeure is about to occur, occurs, or has occurred
for which the affected owner or operator intends to assert a claim of
force majeure, the owner or operator shall notify the Administrator, in
writing as soon as practicable following the date the owner or operator
first knew, or through due diligence should have known that the event
may cause or caused a delay in testing beyond the regulatory deadline,
but the notification must occur before the performance test deadline
unless the initial force majeure or a subsequent force majeure event
delays the notice, and in such cases, the notification shall occur as
soon as practicable.
(2) The owner or operator shall provide to the Administrator a
written description of the force majeure event and a rationale for
attributing the delay in testing beyond the regulatory deadline to the
force majeure; describe the measures taken or to be taken to minimize
the delay; and identify a date by which the owner or operator proposes
to conduct the performance test. The performance test shall be conducted
as soon as practicable after the force majeure occurs.
(3) The decision as to whether or not to grant an extension to the
performance test deadline is solely within the discretion of the
Administrator. The Administrator will notify the owner or operator in
writing of approval or disapproval of the request for an extension as
soon as practicable.
(4) Until an extension of the performance test deadline has been
approved by the Administrator under paragraphs (a)(1), (2), and (3) of
this section, the owner or operator of the affected facility remains
strictly subject to the requirements of this part.
(b) Performance tests shall be conducted and data reduced in
accordance with the test methods and procedures contained in each
applicable subpart unless the Administrator (1) specifies or approves,
in specific cases, the use of a reference method with minor changes in
methodology, (2) approves the use of an equivalent method, (3) approves
the use of an alternative method the results of which he has determined
to be adequate for indicating whether a specific source is in
compliance, (4) waives the requirement for performance tests because the
owner or operator of a source has demonstrated by other means to the
Administrator's satisfaction that the affected facility is in compliance
with the standard, or (5) approves shorter sampling times and smaller
sample volumes when necessitated by process variables or other factors.
Nothing in this paragraph shall be construed to abrogate the
Administrator's authority to require testing under section 114 of the
Act.
(c) Performance tests shall be conducted under such conditions as
the Administrator shall specify to the plant operator based on
representative performance of the affected facility. The owner or
operator shall make available to the Administrator such records as may
be necessary to determine the conditions of the performance tests.
Operations during periods of startup, shutdown, and malfunction shall
not constitute representative conditions for the purpose of a
performance test nor shall emissions in excess of the level of the
applicable emission limit during periods of startup, shutdown, and
malfunction be considered a violation of the applicable emission limit
unless otherwise specified in the applicable standard.
[[Page 57]]
(d) The owner or operator of an affected facility shall provide the
Administrator at least 30 days prior notice of any performance test,
except as specified under other subparts, to afford the Administrator
the opportunity to have an observer present. If after 30 days notice for
an initially scheduled performance test, there is a delay (due to
operational problems, etc.) in conducting the scheduled performance
test, the owner or operator of an affected facility shall notify the
Administrator (or delegated State or local agency) as soon as possible
of any delay in the original test date, either by providing at least 7
days prior notice of the rescheduled date of the performance test, or by
arranging a rescheduled date with the Administrator (or delegated State
or local agency) by mutual agreement.
(e) The owner or operator of an affected facility shall provide, or
cause to be provided, performance testing facilities as follows:
(1) Sampling ports adequate for test methods applicable to such
facility. This includes (i) constructing the air pollution control
system such that volumetric flow rates and pollutant emission rates can
be accurately determined by applicable test methods and procedures and
(ii) providing a stack or duct free of cyclonic flow during performance
tests, as demonstrated by applicable test methods and procedures.
(2) Safe sampling platform(s).
(3) Safe access to sampling platform(s).
(4) Utilities for sampling and testing equipment.
(f) Unless otherwise specified in the applicable subpart, each
performance test shall consist of three separate runs using the
applicable test method. Each run shall be conducted for the time and
under the conditions specified in the applicable standard. For the
purpose of determining compliance with an applicable standard, the
arithmetic means of results of the three runs shall apply. In the event
that a sample is accidentally lost or conditions occur in which one of
the three runs must be discontinued because of forced shutdown, failure
of an irreplaceable portion of the sample train, extreme meteorological
conditions, or other circumstances, beyond the owner or operator's
control, compliance may, upon the Administrator's approval, be
determined using the arithmetic mean of the results of the two other
runs.
(g) The performance testing shall include a test method performance
audit (PA) during the performance test. The PAs consist of blind audit
samples supplied by an accredited audit sample provider and analyzed
during the performance test in order to provide a measure of test data
bias. Gaseous audit samples are designed to audit the performance of the
sampling system as well as the analytical system and must be collected
by the sampling system during the compliance test just as the compliance
samples are collected. If a liquid or solid audit sample is designed to
audit the sampling system, it must also be collected by the sampling
system during the compliance test. If multiple sampling systems or
sampling trains are used during the compliance test for any of the test
methods, the tester is only required to use one of the sampling systems
per method to collect the audit sample. The audit sample must be
analyzed by the same analyst using the same analytical reagents and
analytical system and at the same time as the compliance samples.
Retests are required when there is a failure to produce acceptable
results for an audit sample. However, if the audit results do not affect
the compliance or noncompliance status of the affected facility, the
compliance authority may waive the reanalysis requirement, further
audits, or retests and accept the results of the compliance test.
Acceptance of the test results shall constitute a waiver of the
reanalysis requirement, further audits, or retests. The compliance
authority may also use the audit sample failure and the compliance test
results as evidence to determine the compliance or noncompliance status
of the affected facility. A blind audit sample is a sample whose value
is known only to the sample provider and is not revealed to the tested
facility until after they report the measured value of the audit sample.
For pollutants that exist in the gas phase at ambient temperature, the
audit sample shall consist of an appropriate concentration of the
pollutant
[[Page 58]]
in air or nitrogen that can be introduced into the sampling system of
the test method at or near the same entry point as a sample from the
emission source. If no gas phase audit samples are available, an
acceptable alternative is a sample of the pollutant in the same matrix
that would be produced when the sample is recovered from the sampling
system as required by the test method. For samples that exist only in a
liquid or solid form at ambient temperature, the audit sample shall
consist of an appropriate concentration of the pollutant in the same
matrix that would be produced when the sample is recovered from the
sampling system as required by the test method. An accredited audit
sample provider (AASP) is an organization that has been accredited to
prepare audit samples by an independent, third party accrediting body.
(1) The source owner, operator, or representative of the tested
facility shall obtain an audit sample, if commercially available, from
an AASP for each test method used for regulatory compliance purposes. No
audit samples are required for the following test methods: Methods 3A
and 3C of appendix A-3 of part 60, Methods 6C, 7E, 9, and 10 of appendix
A-4 of part 60, Methods 18 and 19 of appendix A-6 of part 60, Methods
20, 22, and 25A of appendix A-7 of part 60, Methods 30A and 30B of
appendix A-8 of part 60, and Methods 303, 318, 320, and 321 of appendix
A of part 63 of this chapter. If multiple sources at a single facility
are tested during a compliance test event, only one audit sample is
required for each method used during a compliance test. The compliance
authority responsible for the compliance test may waive the requirement
to include an audit sample if they believe that an audit sample is not
necessary. ``Commercially available'' means that two or more independent
AASPs have blind audit samples available for purchase. If the source
owner, operator, or representative cannot find an audit sample for a
specific method, the owner, operator, or representative shall consult
the EPA Web site at the following URL, www.epa.gov/ttn/emc, to confirm
whether there is a source that can supply an audit sample for that
method. If the EPA Web site does not list an available audit sample at
least 60 days prior to the beginning of the compliance test, the source
owner, operator, or representative shall not be required to include an
audit sample as part of the quality assurance program for the compliance
test. When ordering an audit sample, the source owner, operator, or
representative shall give the sample provider an estimate for the
concentration of each pollutant that is emitted by the source or the
estimated concentration of each pollutant based on the permitted level
and the name, address, and phone number of the compliance authority. The
source owner, operator, or representative shall report the results for
the audit sample along with a summary of the emission test results for
the audited pollutant to the compliance authority and shall report the
results of the audit sample to the AASP. The source owner, operator, or
representative shall make both reports at the same time and in the same
manner or shall report to the compliance authority first and then report
to the AASP. If the method being audited is a method that allows the
samples to be analyzed in the field and the tester plans to analyze the
samples in the field, the tester may analyze the audit samples prior to
collecting the emission samples provided a representative of the
compliance authority is present at the testing site. The tester may
request and the compliance authority may grant a waiver to the
requirement that a representative of the compliance authority must be
present at the testing site during the field analysis of an audit
sample. The source owner, operator, or representative may report the
results of the audit sample to the compliance authority and report the
results of the audit sample to the AASP prior to collecting any emission
samples. The test protocol and final test report shall document whether
an audit sample was ordered and utilized and the pass/fail results as
applicable.
(2) An AASP shall have and shall prepare, analyze, and report the
true value of audit samples in accordance with a written technical
criteria document that describes how audit samples will be prepared and
distributed in a manner that will ensure the integrity of
[[Page 59]]
the audit sample program. An acceptable technical criteria document
shall contain standard operating procedures for all of the following
operations:
(i) Preparing the sample;
(ii) Confirming the true concentration of the sample;
(iii) Defining the acceptance limits for the results from a well
qualified tester. This procedure must use well established statistical
methods to analyze historical results from well qualified testers. The
acceptance limits shall be set so that there is 95 percent confidence
that 90 percent of well qualified labs will produce future results that
are within the acceptance limit range.
(iv) Providing the opportunity for the compliance authority to
comment on the selected concentration level for an audit sample;
(v) Distributing the sample to the user in a manner that guarantees
that the true value of the sample is unknown to the user;
(vi) Recording the measured concentration reported by the user and
determining if the measured value is within acceptable limits;
(vii) The AASP shall report the results from each audit sample in a
timely manner to the compliance authority and then to the source owner,
operator, or representative. The AASP shall make both reports at the
same time and in the same manner or shall report to the compliance
authority first and then report to the source owner, operator, or
representative. The results shall include the name of the facility
tested, the date on which the compliance test was conducted, the name of
the company performing the sample collection, the name of the company
that analyzed the compliance samples including the audit sample, the
measured result for the audit sample, and whether the testing company
passed or failed the audit. The AASP shall report the true value of the
audit sample to the compliance authority. The AASP may report the true
value to the source owner, operator, or representative if the AASP's
operating plan ensures that no laboratory will receive the same audit
sample twice.
(viii) Evaluating the acceptance limits of samples at least once
every two years to determine in cooperation with the voluntary consensus
standard body if they should be changed;
(ix) Maintaining a database, accessible to the compliance
authorities, of results from the audit that shall include the name of
the facility tested, the date on which the compliance test was
conducted, the name of the company performing the sample collection, the
name of the company that analyzed the compliance samples including the
audit sample, the measured result for the audit sample, the true value
of the audit sample, the acceptance range for the measured value, and
whether the testing company passed or failed the audit.
(3) The accrediting body shall have a written technical criteria
document that describes how it will ensure that the AASP is operating in
accordance with the AASP technical criteria document that describes how
audit samples are to be prepared and distributed. This document shall
contain standard operating procedures for all of the following
operations:
(i) Checking audit samples to confirm their true value as reported
by the AASP;
(ii) Performing technical systems audits of the AASP's facilities
and operating procedures at least once every two years;
(iii) Providing standards for use by the voluntary consensus
standard body to approve the accrediting body that will accredit the
audit sample providers.
(4) The technical criteria documents for the accredited sample
providers and the accrediting body shall be developed through a public
process guided by a voluntary consensus standards body (VCSB). The VCSB
shall operate in accordance with the procedures and requirements in the
Office of Management and Budget Circular A-119. A copy of Circular A-119
is available upon request by writing the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street,
NW., Washington, DC 20503, by calling (202) 395-6880 or downloading
online at http://standards.gov/standards--gov/a119.cfm. The VCSB shall
approve all accrediting bodies. The Administrator will review all
technical
[[Page 60]]
criteria documents. If the technical criteria documents do not meet the
minimum technical requirements in paragraphs (g)(2) through (4)of this
section, the technical criteria documents are not acceptable and the
proposed audit sample program is not capable of producing audit samples
of sufficient quality to be used in a compliance test. All acceptable
technical criteria documents shall be posted on the EPA Web site at the
following URL, http://www.epa.gov/ttn/emc.
(h) Unless otherwise specified in the applicable subpart, each test
location must be verified to be free of cyclonic flow and evaluated for
the existence of emission gas stratification and the required number of
sampling traverse points. If other procedures are not specified in the
applicable subpart to the regulations, use the appropriate procedures in
Method 1 to check for cyclonic flow and Method 7E to evaluate emission
gas stratification and selection of sampling points.
(i) Whenever the use of multiple calibration gases is required by a
test method, performance specification, or quality assurance procedure
in a part 60 standard or appendix, Method 205 of 40 CFR part 51,
appendix M of this chapter, ``Verification of Gas Dilution Systems for
Field Instrument Calibrations,'' may be used.
[36 FR 24877, Dec. 23, 1971, as amended at 39 FR 9314, Mar. 8, 1974; 42
FR 57126, Nov. 1, 1977; 44 FR 33612, June 11, 1979; 54 FR 6662, Feb. 14,
1989; 54 FR 21344, May 17, 1989; 64 FR 7463, Feb. 12, 1999; 72 FR 27442,
May 16, 2007; 75 FR 55646, Sept. 13, 2010; 79 FR 11241, Feb. 27, 2014]
Sec. 60.9 Availability of information.
The availability to the public of information provided to, or
otherwise obtained by, the Administrator under this part shall be
governed by part 2 of this chapter. (Information submitted voluntarily
to the Administrator for the purposes of Sec. Sec. 60.5 and 60.6 is
governed by Sec. Sec. 2.201 through 2.213 of this chapter and not by
Sec. 2.301 of this chapter.)
Sec. 60.10 State authority.
The provisions of this part shall not be construed in any manner to
preclude any State or political subdivision thereof from:
(a) Adopting and enforcing any emission standard or limitation
applicable to an affected facility, provided that such emission standard
or limitation is not less stringent than the standard applicable to such
facility.
(b) Requiring the owner or operator of an affected facility to
obtain permits, licenses, or approvals prior to initiating construction,
modification, or operation of such facility.
Sec. 60.11 Compliance with standards and maintenance requirements.
(a) Compliance with standards in this part, other than opacity
standards, shall be determined in accordance with performance tests
established by Sec. 60.8, unless otherwise specified in the applicable
standard.
(b) Compliance with opacity standards in this part shall be
determined by conducting observations in accordance with Method 9 in
appendix A of this part, any alternative method that is approved by the
Administrator, or as provided in paragraph (e)(5) of this section. For
purposes of determining initial compliance, the minimum total time of
observations shall be 3 hours (30 6-minute averages) for the performance
test or other set of observations (meaning those fugitive-type emission
sources subject only to an opacity standard).
(c) The opacity standards set forth in this part shall apply at all
times except during periods of startup, shutdown, malfunction, and as
otherwise provided in the applicable standard.
(d) At all times, including periods of startup, shutdown, and
malfunction, owners and operators shall, to the extent practicable,
maintain and operate any affected facility including associated air
pollution control equipment in a manner consistent with good air
pollution control practice for minimizing emissions. Determination of
whether acceptable operating and maintenance procedures are being used
will be based on information available to the Administrator which may
include, but is not limited to, monitoring results, opacity
observations, review of operating and maintenance procedures, and
inspection of the source.
(e)(1) For the purpose of demonstrating initial compliance, opacity
[[Page 61]]
observations shall be conducted concurrently with the initial
performance test required in Sec. 60.8 unless one of the following
conditions apply. If no performance test under Sec. 60.8 is required,
then opacity observations shall be conducted within 60 days after
achieving the maximum production rate at which the affected facility
will be operated but no later than 180 days after initial startup of the
facility. If visibility or other conditions prevent the opacity
observations from being conducted concurrently with the initial
performance test required under Sec. 60.8, the source owner or operator
shall reschedule the opacity observations as soon after the initial
performance test as possible, but not later than 30 days thereafter, and
shall advise the Administrator of the rescheduled date. In these cases,
the 30-day prior notification to the Administrator required in Sec.
60.7(a)(6) shall be waived. The rescheduled opacity observations shall
be conducted (to the extent possible) under the same operating
conditions that existed during the initial performance test conducted
under Sec. 60.8. The visible emissions observer shall determine whether
visibility or other conditions prevent the opacity observations from
being made concurrently with the initial performance test in accordance
with procedures contained in Method 9 of appendix B of this part.
Opacity readings of portions of plumes which contain condensed,
uncombined water vapor shall not be used for purposes of determing
compliance with opacity standards. The owner or operator of an affected
facility shall make available, upon request by the Administrator, such
records as may be necessary to determine the conditions under which the
visual observations were made and shall provide evidence indicating
proof of current visible observer emission certification. Except as
provided in paragraph (e)(5) of this section, the results of continuous
monitoring by transmissometer which indicate that the opacity at the
time visual observations were made was not in excess of the standard are
probative but not conclusive evidence of the actual opacity of an
emission, provided that the source shall meet the burden of proving that
the instrument used meets (at the time of the alleged violation)
Performance Specification 1 in appendix B of this part, has been
properly maintained and (at the time of the alleged violation) that the
resulting data have not been altered in any way.
(2) Except as provided in paragraph (e)(3) of this section, the
owner or operator of an affected facility to which an opacity standard
in this part applies shall conduct opacity observations in accordance
with paragraph (b) of this section, shall record the opacity of
emissions, and shall report to the Administrator the opacity results
along with the results of the initial performance test required under
Sec. 60.8. The inability of an owner or operator to secure a visible
emissions observer shall not be considered a reason for not conducting
the opacity observations concurrent with the initial performance test.
(3) The owner or operator of an affected facility to which an
opacity standard in this part applies may request the Administrator to
determine and to record the opacity of emissions from the affected
facility during the initial performance test and at such times as may be
required. The owner or operator of the affected facility shall report
the opacity results. Any request to the Administrator to determine and
to record the opacity of emissions from an affected facility shall be
included in the notification required in Sec. 60.7(a)(6). If, for some
reason, the Administrator cannot determine and record the opacity of
emissions from the affected facility during the performance test, then
the provisions of paragraph (e)(1) of this section shall apply.
(4) An owner or operator of an affected facility using a continuous
opacity monitor (transmissometer) shall record the monitoring data
produced during the initial performance test required by Sec. 60.8 and
shall furnish the Administrator a written report of the monitoring
results along with Method 9 and Sec. 60.8 performance test results.
(5) An owner or operator of an affected facility subject to an
opacity standard may submit, for compliance purposes, continuous opacity
monitoring system (COMS) data results produced during any performance
test required under Sec. 60.8 in lieu of Method 9
[[Page 62]]
observation data. If an owner or operator elects to submit COMS data for
compliance with the opacity standard, he shall notify the Administrator
of that decision, in writing, at least 30 days before any performance
test required under Sec. 60.8 is conducted. Once the owner or operator
of an affected facility has notified the Administrator to that effect,
the COMS data results will be used to determine opacity compliance
during subsequent tests required under Sec. 60.8 until the owner or
operator notifies the Administrator, in writing, to the contrary. For
the purpose of determining compliance with the opacity standard during a
performance test required under Sec. 60.8 using COMS data, the minimum
total time of COMS data collection shall be averages of all 6-minute
continuous periods within the duration of the mass emission performance
test. Results of the COMS opacity determinations shall be submitted
along with the results of the performance test required under Sec.
60.8. The owner or operator of an affected facility using a COMS for
compliance purposes is responsible for demonstrating that the COMS meets
the requirements specified in Sec. 60.13(c) of this part, that the COMS
has been properly maintained and operated, and that the resulting data
have not been altered in any way. If COMS data results are submitted for
compliance with the opacity standard for a period of time during which
Method 9 data indicates noncompliance, the Method 9 data will be used to
determine compliance with the opacity standard.
(6) Upon receipt from an owner or operator of the written reports of
the results of the performance tests required by Sec. 60.8, the opacity
observation results and observer certification required by Sec.
60.11(e)(1), and the COMS results, if applicable, the Administrator will
make a finding concerning compliance with opacity and other applicable
standards. If COMS data results are used to comply with an opacity
standard, only those results are required to be submitted along with the
performance test results required by Sec. 60.8. If the Administrator
finds that an affected facility is in compliance with all applicable
standards for which performance tests are conducted in accordance with
Sec. 60.8 of this part but during the time such performance tests are
being conducted fails to meet any applicable opacity standard, he shall
notify the owner or operator and advise him that he may petition the
Administrator within 10 days of receipt of notification to make
appropriate adjustment to the opacity standard for the affected
facility.
(7) The Administrator will grant such a petition upon a
demonstration by the owner or operator that the affected facility and
associated air pollution control equipment was operated and maintained
in a manner to minimize the opacity of emissions during the performance
tests; that the performance tests were performed under the conditions
established by the Administrator; and that the affected facility and
associated air pollution control equipment were incapable of being
adjusted or operated to meet the applicable opacity standard.
(8) The Administrator will establish an opacity standard for the
affected facility meeting the above requirements at a level at which the
source will be able, as indicated by the performance and opacity tests,
to meet the opacity standard at all times during which the source is
meeting the mass or concentration emission standard. The Administrator
will promulgate the new opacity standard in the Federal Register.
(f) Special provisions set forth under an applicable subpart shall
supersede any conflicting provisions in paragraphs (a) through (e) of
this section.
(g) For the purpose of submitting compliance certifications or
establishing whether or not a person has violated or is in violation of
any standard in this part, nothing in this part shall preclude the use,
including the exclusive use, of any credible evidence or information,
relevant to whether a source would have been in compliance
[[Page 63]]
with applicable requirements if the appropriate performance or
compliance test or procedure had been performed.
[38 FR 28565, Oct. 15, 1973, as amended at 39 FR 39873, Nov. 12, 1974;
43 FR 8800, Mar. 3, 1978; 45 FR 23379, Apr. 4, 1980; 48 FR 48335, Oct.
18, 1983; 50 FR 53113, Dec. 27, 1985; 51 FR 1790, Jan. 15, 1986; 52 FR
9781, Mar. 26, 1987; 62 FR 8328, Feb. 24, 1997; 65 FR 61749, Oct. 17,
2000]
Sec. 60.12 Circumvention.
No owner or operator subject to the provisions of this part shall
build, erect, install, or use any article, machine, equipment or
process, the use of which conceals an emission which would otherwise
constitute a violation of an applicable standard. Such concealment
includes, but is not limited to, the use of gaseous diluents to achieve
compliance with an opacity standard or with a standard which is based on
the concentration of a pollutant in the gases discharged to the
atmosphere.
[39 FR 9314, Mar. 8, 1974]
Sec. 60.13 Monitoring requirements.
(a) For the purposes of this section, all continuous monitoring
systems required under applicable subparts shall be subject to the
provisions of this section upon promulgation of performance
specifications for continuous monitoring systems under appendix B to
this part and, if the continuous monitoring system is used to
demonstrate compliance with emission limits on a continuous basis,
appendix F to this part, unless otherwise specified in an applicable
subpart or by the Administrator. Appendix F is applicable December 4,
1987.
(b) All continuous monitoring systems and monitoring devices shall
be installed and operational prior to conducting performance tests under
Sec. 60.8. Verification of operational status shall, as a minimum,
include completion of the manufacturer's written requirements or
recommendations for installation, operation, and calibration of the
device.
(c) If the owner or operator of an affected facility elects to
submit continous opacity monitoring system (COMS) data for compliance
with the opacity standard as provided under Sec. 60.11(e)(5), he shall
conduct a performance evaluation of the COMS as specified in Performance
Specification 1, appendix B, of this part before the performance test
required under Sec. 60.8 is conducted. Otherwise, the owner or operator
of an affected facility shall conduct a performance evaluation of the
COMS or continuous emission monitoring system (CEMS) during any
performance test required under Sec. 60.8 or within 30 days thereafter
in accordance with the applicable performance specification in appendix
B of this part, The owner or operator of an affected facility shall
conduct COMS or CEMS performance evaluations at such other times as may
be required by the Administrator under section 114 of the Act.
(1) The owner or operator of an affected facility using a COMS to
determine opacity compliance during any performance test required under
Sec. 60.8 and as described in Sec. 60.11(e)(5) shall furnish the
Administrator two or, upon request, more copies of a written report of
the results of the COMS performance evaluation described in paragraph
(c) of this section at least 10 days before the performance test
required under Sec. 60.8 is conducted.
(2) Except as provided in paragraph (c)(1) of this section, the
owner or operator of an affected facility shall furnish the
Administrator within 60 days of completion two or, upon request, more
copies of a written report of the results of the performance evaluation.
(d)(1) Owners and operators of a CEMS installed in accordance with
the provisions of this part, must check the zero (or low level value
between 0 and 20 percent of span value) and span (50 to 100 percent of
span value) calibration drifts at least once each operating day in
accordance with a written procedure. The zero and span must, at a
minimum, be adjusted whenever either the 24-hour zero drift or the 24-
hour span drift exceeds two times the limit of the applicable
performance specification in appendix B of this part. The system must
allow the amount of the excess zero and span drift to be recorded and
quantified whenever specified. Owners and operators of a COMS installed
in accordance with the provisions of this part must check the zero
[[Page 64]]
and upscale (span) calibration drifts at least once daily. For a
particular COMS, the acceptable range of zero and upscale calibration
materials is defined in the applicable version of PS-1 in appendix B of
this part. For a COMS, the optical surfaces, exposed to the effluent
gases, must be cleaned before performing the zero and upscale drift
adjustments, except for systems using automatic zero adjustments. The
optical surfaces must be cleaned when the cumulative automatic zero
compensation exceeds 4 percent opacity.
(2) Unless otherwise approved by the Administrator, the following
procedures must be followed for a COMS. Minimum procedures must include
an automated method for producing a simulated zero opacity condition and
an upscale opacity condition using a certified neutral density filter or
other related technique to produce a known obstruction of the light
beam. Such procedures must provide a system check of all active analyzer
internal optics with power or curvature, all active electronic circuitry
including the light source and photodetector assembly, and electronic or
electro-mechanical systems and hardware and or software used during
normal measurement operation.
(e) Except for system breakdowns, repairs, calibration checks, and
zero and span adjustments required under paragraph (d) of this section,
all continuous monitoring systems shall be in continuous operation and
shall meet minimum frequency of operation requirements as follows:
(1) All continuous monitoring systems referenced by paragraph (c) of
this section for measuring opacity of emissions shall complete a minimum
of one cycle of sampling and analyzing for each successive 10-second
period and one cycle of data recording for each successive 6-minute
period.
(2) All continuous monitoring systems referenced by paragraph (c) of
this section for measuring emissions, except opacity, shall complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period.
(f) All continuous monitoring systems or monitoring devices shall be
installed such that representative measurements of emissions or process
parameters from the affected facility are obtained. Additional
procedures for location of continuous monitoring systems contained in
the applicable Performance Specifications of appendix B of this part
shall be used.
(g) When the effluents from a single affected facility or two or
more affected facilities subject to the same emission standards are
combined before being released to the atmosphere, the owner or operator
may install applicable continuous monitoring systems on each effluent or
on the combined effluent. When the affected facilities are not subject
to the same emission standards, separate continuous monitoring systems
shall be installed on each effluent. When the effluent from one affected
facility is released to the atmosphere through more than one point, the
owner or operator shall install an applicable continuous monitoring
system on each separate effluent unless the installation of fewer
systems is approved by the Administrator. When more than one continuous
monitoring system is used to measure the emissions from one affected
facility (e.g., multiple breechings, multiple outlets), the owner or
operator shall report the results as required from each continuous
monitoring system.
(h)(1) Owners or operators of all continuous monitoring systems for
measurement of opacity shall reduce all data to 6-minute averages and
for continuous monitoring systems other than opacity to 1-hour averages
for time periods as defined in Sec. 60.2. Six-minute opacity averages
shall be calculated from 36 or more data points equally spaced over each
6-minute period.
(2) For continuous monitoring systems other than opacity, 1-hour
averages shall be computed as follows, except that the provisions
pertaining to the validation of partial operating hours are only
applicable for affected facilities that are required by the applicable
subpart to include partial hours in the emission calculations:
(i) Except as provided under paragraph (h)(2)(iii) of this section,
for a full operating hour (any clock hour with 60 minutes of unit
operation), at least four valid data points are required to calculate
the hourly average,
[[Page 65]]
i.e., one data point in each of the 15-minute quadrants of the hour.
(ii) Except as provided under paragraph (h)(2)(iii) of this section,
for a partial operating hour (any clock hour with less than 60 minutes
of unit operation), at least one valid data point in each 15-minute
quadrant of the hour in which the unit operates is required to calculate
the hourly average.
(iii) For any operating hour in which required maintenance or
quality-assurance activities are performed:
(A) If the unit operates in two or more quadrants of the hour, a
minimum of two valid data points, separated by at least 15 minutes, is
required to calculate the hourly average; or
(B) If the unit operates in only one quadrant of the hour, at least
one valid data point is required to calculate the hourly average.
(iv) If a daily calibration error check is failed during any
operating hour, all data for that hour shall be invalidated, unless a
subsequent calibration error test is passed in the same hour and the
requirements of paragraph (h)(2)(iii) of this section are met, based
solely on valid data recorded after the successful calibration.
(v) For each full or partial operating hour, all valid data points
shall be used to calculate the hourly average.
(vi) Except as provided under paragraph (h)(2)(vii) of this section,
data recorded during periods of continuous monitoring system breakdown,
repair, calibration checks, and zero and span adjustments shall not be
included in the data averages computed under this paragraph.
(vii) Owners and operators complying with the requirements of Sec.
60.7(f)(1) or (2) must include any data recorded during periods of
monitor breakdown or malfunction in the data averages.
(viii) When specified in an applicable subpart, hourly averages for
certain partial operating hours shall not be computed or included in the
emission averages (e.g., hours with < 30 minutes of unit operation under
Sec. 60.47b(d)).
(ix) Either arithmetic or integrated averaging of all data may be
used to calculate the hourly averages. The data may be recorded in
reduced or nonreduced form (e.g., ppm pollutant and percent
O2 or ng/J of pollutant).
(3) All excess emissions shall be converted into units of the
standard using the applicable conversion procedures specified in the
applicable subpart. After conversion into units of the standard, the
data may be rounded to the same number of significant digits used in the
applicable subpart to specify the emission limit.
(i) After receipt and consideration of written application, the
Administrator may approve alternatives to any monitoring procedures or
requirements of this part including, but not limited to the following:
(1) Alternative monitoring requirements when installation of a
continuous monitoring system or monitoring device specified by this part
would not provide accurate measurements due to liquid water or other
interferences caused by substances in the effluent gases.
(2) Alternative monitoring requirements when the affected facility
is infrequently operated.
(3) Alternative monitoring requirements to accommodate continuous
monitoring systems that require additional measurements to correct for
stack moisture conditions.
(4) Alternative locations for installing continuous monitoring
systems or monitoring devices when the owner or operator can demonstrate
that installation at alternate locations will enable accurate and
representative measurements.
(5) Alternative methods of converting pollutant concentration
measurements to units of the standards.
(6) Alternative procedures for performing daily checks of zero and
span drift that do not involve use of span gases or test cells.
(7) Alternatives to the A.S.T.M. test methods or sampling procedures
specified by any subpart.
(8) Alternative continuous monitoring systems that do not meet the
design or performance requirements in Performance Specification 1,
appendix
[[Page 66]]
B, but adequately demonstrate a definite and consistent relationship
between its measurements and the measurements of opacity by a system
complying with the requirements in Performance Specification 1. The
Administrator may require that such demonstration be performed for each
affected facility.
(9) Alternative monitoring requirements when the effluent from a
single affected facility or the combined effluent from two or more
affected facilities is released to the atmosphere through more than one
point.
(j) An alternative to the relative accuracy (RA) test specified in
Performance Specification 2 of appendix B may be requested as follows:
(1) An alternative to the reference method tests for determining RA
is available for sources with emission rates demonstrated to be less
than 50 percent of the applicable standard. A source owner or operator
may petition the Administrator to waive the RA test in Section 8.4 of
Performance Specification 2 and substitute the procedures in Section
16.0 if the results of a performance test conducted according to the
requirements in Sec. 60.8 of this subpart or other tests performed
following the criteria in Sec. 60.8 demonstrate that the emission rate
of the pollutant of interest in the units of the applicable standard is
less than 50 percent of the applicable standard. For sources subject to
standards expressed as control efficiency levels, a source owner or
operator may petition the Administrator to waive the RA test and
substitute the procedures in Section 16.0 of Performance Specification 2
if the control device exhaust emission rate is less than 50 percent of
the level needed to meet the control efficiency requirement. The
alternative procedures do not apply if the continuous emission
monitoring system is used to determine compliance continuously with the
applicable standard. The petition to waive the RA test shall include a
detailed description of the procedures to be applied. Included shall be
location and procedure for conducting the alternative, the concentration
or response levels of the alternative RA materials, and the other
equipment checks included in the alternative procedure. The
Administrator will review the petition for completeness and
applicability. The determination to grant a waiver will depend on the
intended use of the CEMS data (e.g., data collection purposes other than
NSPS) and may require specifications more stringent than in Performance
Specification 2 (e.g., the applicable emission limit is more stringent
than NSPS).
(2) The waiver of a CEMS RA test will be reviewed and may be
rescinded at such time, following successful completion of the
alternative RA procedure, that the CEMS data indicate that the source
emissions are approaching the level. The criterion for reviewing the
waiver is the collection of CEMS data showing that emissions have
exceeded 70 percent of the applicable standard for seven, consecutive,
averaging periods as specified by the applicable regulation(s). For
sources subject to standards expressed as control efficiency levels, the
criterion for reviewing the waiver is the collection of CEMS data
showing that exhaust emissions have exceeded 70 percent of the level
needed to meet the control efficiency requirement for seven,
consecutive, averaging periods as specified by the applicable
regulation(s) [e.g., Sec. Sec. 60.45(g) (2) and (3), 60.73(e), and
60.84(e)]. It is the responsibility of the source operator to maintain
records and determine the level of emissions relative to the criterion
on the waiver of RA testing. If this criterion is exceeded, the owner or
operator must notify the Administrator within 10 days of such occurrence
and include a description of the nature and cause of the increasing
emissions. The Administrator will review the notification and may
rescind the waiver and require the owner or operator to conduct a RA
test of the CEMS as specified in Section 8.4 of Performance
Specification 2.
[40 FR 46255, Oct. 6, 1975]
Editorial Note: For Federal Register citations affecting Sec.
60.13, see the List of CFR Sections Affected, which appears in the
Finding Aids section of the printed volume and at www.fdsys.gov.
Sec. 60.14 Modification.
(a) Except as provided under paragraphs (e) and (f) of this section,
any physical or operational change to an
[[Page 67]]
existing facility which results in an increase in the emission rate to
the atmosphere of any pollutant to which a standard applies shall be
considered a modification within the meaning of section 111 of the Act.
Upon modification, an existing facility shall become an affected
facility for each pollutant to which a standard applies and for which
there is an increase in the emission rate to the atmosphere.
(b) Emission rate shall be expressed as kg/hr of any pollutant
discharged into the atmosphere for which a standard is applicable. The
Administrator shall use the following to determine emission rate:
(1) Emission factors as specified in the latest issue of
``Compilation of Air Pollutant Emission Factors,'' EPA Publication No.
AP-42, or other emission factors determined by the Administrator to be
superior to AP-42 emission factors, in cases where utilization of
emission factors demonstrates that the emission level resulting from the
physical or operational change will either clearly increase or clearly
not increase.
(2) Material balances, continuous monitor data, or manual emission
tests in cases where utilization of emission factors as referenced in
paragraph (b)(1) of this section does not demonstrate to the
Administrator's satisfaction whether the emission level resulting from
the physical or operational change will either clearly increase or
clearly not increase, or where an owner or operator demonstrates to the
Administrator's satisfaction that there are reasonable grounds to
dispute the result obtained by the Administrator utilizing emission
factors as referenced in paragraph (b)(1) of this section. When the
emission rate is based on results from manual emission tests or
continuous monitoring systems, the procedures specified in appendix C of
this part shall be used to determine whether an increase in emission
rate has occurred. Tests shall be conducted under such conditions as the
Administrator shall specify to the owner or operator based on
representative performance of the facility. At least three valid test
runs must be conducted before and at least three after the physical or
operational change. All operating parameters which may affect emissions
must be held constant to the maximum feasible degree for all test runs.
(c) The addition of an affected facility to a stationary source as
an expansion to that source or as a replacement for an existing facility
shall not by itself bring within the applicability of this part any
other facility within that source.
(d) [Reserved]
(e) The following shall not, by themselves, be considered
modifications under this part:
(1) Maintenance, repair, and replacement which the Administrator
determines to be routine for a source category, subject to the
provisions of paragraph (c) of this section and Sec. 60.15.
(2) An increase in production rate of an existing facility, if that
increase can be accomplished without a capital expenditure on that
facility.
(3) An increase in the hours of operation.
(4) Use of an alternative fuel or raw material if, prior to the date
any standard under this part becomes applicable to that source type, as
provided by Sec. 60.1, the existing facility was designed to
accommodate that alternative use. A facility shall be considered to be
designed to accommodate an alternative fuel or raw material if that use
could be accomplished under the facility's construction specifications
as amended prior to the change. Conversion to coal required for energy
considerations, as specified in section 111(a)(8) of the Act, shall not
be considered a modification.
(5) The addition or use of any system or device whose primary
function is the reduction of air pollutants, except when an emission
control system is removed or is replaced by a system which the
Administrator determines to be less environmentally beneficial.
(6) The relocation or change in ownership of an existing facility.
(f) Special provisions set forth under an applicable subpart of this
part shall supersede any conflicting provisions of this section.
(g) Within 180 days of the completion of any physical or operational
change subject to the control measures specified in paragraph (a) of
this section,
[[Page 68]]
compliance with all applicable standards must be achieved.
(h) No physical change, or change in the method of operation, at an
existing electric utility steam generating unit shall be treated as a
modification for the purposes of this section provided that such change
does not increase the maximum hourly emissions of any pollutant
regulated under this section above the maximum hourly emissions
achievable at that unit during the 5 years prior to the change.
(i) Repowering projects that are awarded funding from the Department
of Energy as permanent clean coal technology demonstration projects (or
similar projects funded by EPA) are exempt from the requirements of this
section provided that such change does not increase the maximum hourly
emissions of any pollutant regulated under this section above the
maximum hourly emissions achievable at that unit during the five years
prior to the change.
(j)(1) Repowering projects that qualify for an extension under
section 409(b) of the Clean Air Act are exempt from the requirements of
this section, provided that such change does not increase the actual
hourly emissions of any pollutant regulated under this section above the
actual hourly emissions achievable at that unit during the 5 years prior
to the change.
(2) This exemption shall not apply to any new unit that:
(i) Is designated as a replacement for an existing unit;
(ii) Qualifies under section 409(b) of the Clean Air Act for an
extension of an emission limitation compliance date under section 405 of
the Clean Air Act; and
(iii) Is located at a different site than the existing unit.
(k) The installation, operation, cessation, or removal of a
temporary clean coal technology demonstration project is exempt from the
requirements of this section. A temporary clean coal control technology
demonstration project, for the purposes of this section is a clean coal
technology demonstration project that is operated for a period of 5
years or less, and which complies with the State implementation plan for
the State in which the project is located and other requirements
necessary to attain and maintain the national ambient air quality
standards during the project and after it is terminated.
(l) The reactivation of a very clean coal-fired electric utility
steam generating unit is exempt from the requirements of this section.
[40 FR 58419, Dec. 16, 1975, as amended at 43 FR 34347, Aug. 3, 1978; 45
FR 5617, Jan. 23, 1980; 57 FR 32339, July 21, 1992; 65 FR 61750, Oct.
17, 2000]
Sec. 60.15 Reconstruction.
(a) An existing facility, upon reconstruction, becomes an affected
facility, irrespective of any change in emission rate.
(b) ``Reconstruction'' means the replacement of components of an
existing facility to such an extent that:
(1) The fixed capital cost of the new components exceeds 50 percent
of the fixed capital cost that would be required to construct a
comparable entirely new facility, and
(2) It is technologically and economically feasible to meet the
applicable standards set forth in this part.
(c) ``Fixed capital cost'' means the capital needed to provide all
the depreciable components.
(d) If an owner or operator of an existing facility proposes to
replace components, and the fixed capital cost of the new components
exceeds 50 percent of the fixed capital cost that would be required to
construct a comparable entirely new facility, he shall notify the
Administrator of the proposed replacements. The notice must be
postmarked 60 days (or as soon as practicable) before construction of
the replacements is commenced and must include the following
information:
(1) Name and address of the owner or operator.
(2) The location of the existing facility.
(3) A brief description of the existing facility and the components
which are to be replaced.
(4) A description of the existing air pollution control equipment
and the proposed air pollution control equipment.
[[Page 69]]
(5) An estimate of the fixed capital cost of the replacements and of
constructing a comparable entirely new facility.
(6) The estimated life of the existing facility after the
replacements.
(7) A discussion of any economic or technical limitations the
facility may have in complying with the applicable standards of
performance after the proposed replacements.
(e) The Administrator will determine, within 30 days of the receipt
of the notice required by paragraph (d) of this section and any
additional information he may reasonably require, whether the proposed
replacement constitutes reconstruction.
(f) The Administrator's determination under paragraph (e) shall be
based on:
(1) The fixed capital cost of the replacements in comparison to the
fixed capital cost that would be required to construct a comparable
entirely new facility;
(2) The estimated life of the facility after the replacements
compared to the life of a comparable entirely new facility;
(3) The extent to which the components being replaced cause or
contribute to the emissions from the facility; and
(4) Any economic or technical limitations on compliance with
applicable standards of performance which are inherent in the proposed
replacements.
(g) Individual subparts of this part may include specific provisions
which refine and delimit the concept of reconstruction set forth in this
section.
[40 FR 58420, Dec. 16, 1975]
Sec. 60.16 Priority list.
Prioritized Major Source Categories
------------------------------------------------------------------------
Priority Number \1\ Source Category
------------------------------------------------------------------------
1. Synthetic Organic Chemical Manufacturing
Industry (SOCMI) and Volatile Organic
Liquid Storage Vessels and Handling
Equipment
(a) SOCMI unit processes
(b) Volatile organic liquid (VOL) storage
vessels and handling equipment
(c) SOCMI fugitive sources
(d) SOCMI secondary sources
2. Industrial Surface Coating: Cans
3. Petroleum Refineries: Fugitive Sources
4. Industrial Surface Coating: Paper
5. Dry Cleaning
(a) Perchloroethylene
(b) Petroleum solvent
6. Graphic Arts
7. Polymers and Resins: Acrylic Resins
8. Mineral Wool (Deleted)
9. Stationary Internal Combustion Engines
10. Industrial Surface Coating: Fabric
11. Industrial-Commercial-Institutional Steam
Generating Units.
12. Incineration: Non-Municipal (Deleted)
13. Non-Metallic Mineral Processing
14. Metallic Mineral Processing
15. Secondary Copper (Deleted)
16. Phosphate Rock Preparation
17. Foundries: Steel and Gray Iron
18. Polymers and Resins: Polyethylene
19. Charcoal Production
20. Synthetic Rubber
(a) Tire manufacture
(b) SBR production
21. Vegetable Oil
22. Industrial Surface Coating: Metal Coil
23. Petroleum Transportation and Marketing
24. By-Product Coke Ovens
25. Synthetic Fibers
26. Plywood Manufacture
27. Industrial Surface Coating: Automobiles
28. Industrial Surface Coating: Large
Appliances
29. Crude Oil and Natural Gas Production
30. Secondary Aluminum
31. Potash (Deleted)
32. Lightweight Aggregate Industry: Clay,
Shale, and Slate \2\
33. Glass
34. Gypsum
35. Sodium Carbonate
36. Secondary Zinc (Deleted)
37. Polymers and Resins: Phenolic
38. Polymers and Resins: Urea-Melamine
39. Ammonia (Deleted)
40. Polymers and Resins: Polystyrene
41. Polymers and Resins: ABS-SAN Resins
42. Fiberglass
43. Polymers and Resins: Polypropylene
44. Textile Processing
45. Asphalt Processing and Asphalt Roofing
Manufacture
46. Brick and Related Clay Products
47. Ceramic Clay Manufacturing (Deleted)
48. Ammonium Nitrate Fertilizer
49. Castable Refractories (Deleted)
50. Borax and Boric Acid (Deleted)
51. Polymers and Resins: Polyester Resins
52. Ammonium Sulfate
53. Starch
54. Perlite
55. Phosphoric Acid: Thermal Process
(Deleted)
56. Uranium Refining
57. Animal Feed Defluorination (Deleted)
58. Urea (for fertilizer and polymers)
59. Detergent (Deleted)
Other Source Categories
Lead acid battery manufacture \3\
Organic solvent cleaning \3\
Industrial surface coating: metal furniture \3\
Stationary gas turbines \4\
Municipal solid waste landfills \4\
[[Page 70]]
------------------------------------------------------------------------
\1\ Low numbers have highest priority, e.g., No. 1 is high priority,
No. 59 is low priority.
\2\ Formerly titled ``Sintering: Clay and Fly Ash''.
\3\ Minor source category, but included on list since an NSPS is being
developed for that source category.
\4\ Not prioritized, since an NSPS for this major source category has
already been promulgated.
[47 FR 951, Jan. 8, 1982, as amended at 47 FR 31876, July 23, 1982; 51
FR 42796, Nov. 25, 1986; 52 FR 11428, Apr. 8, 1987; 61 FR 9919, Mar. 12,
1996]
Sec. 60.17 Incorporations by reference.
(a) Certain material is incorporated by reference into this part
with the approval of the Director of the Federal Register under 5 U.S.C.
552(a) and 1 CFR part 51. To enforce any edition other than that
specified in this section, the EPA must publish notice of change in the
Federal Register and the material must be available to the public. All
approved material is available for inspection at the EPA Docket Center,
Public Reading Room, EPA WJC West, Room 3334, 1301 Constitution Ave.
NW., Washington, DC, telephone number 202-566-1744, and is available
from the sources listed below. It is also available for inspection at
the National Archives and Records Administration (NARA). For information
on the availability of this material at NARA, call (202) 741-6030 or go
to http://www.archives.gov/federal--register/code--of--federal--
regulations/ibr--locations.html.
(b) American Gas Association, available through ILI Infodisk, 610
Winters Avenue, Paramus, New Jersey 07652:
(1) American Gas Association Report No. 3: Orifice Metering for
Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General
Equations and Uncertainty Guidelines (1990), IBR approved for Sec.
60.107a(d).
(2) American Gas Association Report No. 3: Orifice Metering for
Natural Gas and Other Related Hydrocarbon Fluids, Part 2: Specification
and Installation Requirements (2000), IBR approved for Sec. 60.107a(d).
(3) American Gas Association Report No. 11: Measurement of Natural
Gas by Coriolis Meter (2003), IBR approved for Sec. 60.107a(d).
(4) American Gas Association Transmission Measurement Committee
Report No. 7: Measurement of Gas by Turbine Meters (Revised February
2006), IBR approved for Sec. 60.107a(d).
(c) American Hospital Association (AHA) Service, Inc., Post Office
Box 92683, Chicago, Illinois 60675-2683. You may inspect a copy at the
EPA's Air and Radiation Docket and Information Center (Docket A-91-61,
Item IV-J-124), Room M-1500, 1200 Pennsylvania Ave. NW., Washington, DC
20460.
(1) An Ounce of Prevention: Waste Reduction Strategies for Health
Care Facilities. American Society for Health Care Environmental Services
of the American Hospital Association. Chicago, Illinois. 1993. AHA
Catalog No. 057007. ISBN 0-87258-673-5. IBR approved for Sec. Sec.
60.35e and 60.55c.
(2) [Reserved]
(d) The following material is available for purchase from the
American National Standards Institute (ANSI), 25 W. 43rd Street, 4th
Floor, New York, NY 10036, Telephone (212) 642-4980, and is also
available at the following Web site: http://www.ansi.org.
(1) ANSI No. C12.20-2010 American National Standard for Electricity
Meters--0.2 and 0.5 Accuracy Classes (Approved August 31, 2010), IBR
approved for Sec. 60.5535(d).
(2) [Reserved]
(e) American Petroleum Institute (API), 1220 L Street NW.,
Washington, DC 20005.
(1) API Publication 2517, Evaporation Loss from External Floating
Roof Tanks, Second Edition, February 1980, IBR approved for Sec. Sec.
60.111(i), 60.111a(f), and 60.116b(e).
(2) API Manual of Petroleum Measurement Standards, Chapter 22--
Testing Protocol, Section 2--Differential Pressure Flow Measurement
Devices, First Edition, August 2005, IBR approved for Sec. 60.107a(d).
(f) American Public Health Association, 1015 18th Street NW.,
Washington, DC 20036.
(1) ``Standard Methods for the Examination of Water and
Wastewater,'' 16th
[[Page 71]]
edition, 1985. Method 303F: ``Determination of Mercury by the Cold Vapor
Technique.'' Incorporated by reference for appendix A-8 to part 60,
Method 29, Sec. Sec. 9.2.3, 10.3, and 11.1.3.
(2) 2540 G. Total, Fixed, and Volatile Solids in Solid and Semisolid
Samples, in Standard Methods for the Examination of Water and
Wastewater, 20th Edition, 1998, IBR approved for Sec. 60.154(b).
(g) The following material is available for purchase from the
American Society of Mechanical Engineers (ASME), Two Park Avenue, New
York, NY 10016-5990, Telephone (800) 843-2763, and is also available at
the following Web site: http://www.asme.org.
(1) ASME Interim Supplement 19.5 on Instruments and Apparatus:
Application, Part II of Fluid Meters, 6th Edition (1971), IBR approved
for Sec. Sec. 60.58a(h), 60.58b(i), 60.1320(a), and 60.1810(a).
(2) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi, IBR approved for Sec. 60.107a(d).
(3) ASME/ANSI MFC-4M-1986 (Reaffirmed 2008), Measurement of Gas Flow
by Turbine Meters, IBR approved for Sec. 60.107a(d).
(4) ASME/ANSI MFC-5M-1985 (Reaffirmed 2006), Measurement of Liquid
Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, IBR
approved for Sec. 60.107a(d).
(5) ASME MFC-6M-1998 (Reaffirmed 2005), Measurement of Fluid Flow in
Pipes Using Vortex Flowmeters, IBR approved for Sec. 60.107a(d).
(6) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement of Gas Flow
by Means of Critical Flow Venturi Nozzles, IBR approved for Sec.
60.107a(d).
(7) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement of Liquid
Flow in Closed Conduits by Weighing Method, IBR approved for Sec.
60.107a(d).
(8) ASME MFC-11M-2006, Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters, IBR approved for Sec. 60.107a(d).
(9) ASME MFC-14M-2003, Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters, IBR approved for Sec. 60.107a(d).
(10) ASME MFC-16-2007, Measurement of Liquid Flow in Closed Conduits
with Electromagnetic Flowmeters, IBR approved for Sec. 60.107a(d).
(11) ASME MFC-18M-2001, Measurement of Fluid Flow Using Variable
Area Meters, IBR approved for Sec. 60.107a(d).
(12) ASME MFC-22-2007, Measurement of Liquid by Turbine Flowmeters,
IBR approved for Sec. 60.107a(d).
(13) ASME PTC 4.1-1964 (Reaffirmed 1991), Power Test Codes: Test
Code for Steam Generating Units (with 1968 and 1969 Addenda), IBR
approved for Sec. Sec. 60.46b, 60.58a(h), 60.58b(i), 60.1320(a), and
60.1810(a).
(14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved
for Sec. Sec. 60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i), and
(j), 60.105a(d), (f), and (g), Sec. 60.106a(a), Sec. 60.107a(a), (c),
and (d), tables 1 and 3 to subpart EEEE, tables 2 and 4 to subpart FFFF,
table 2 to subpart JJJJ, Sec. 60.285a(f), Sec. Sec. 60.4415(a),
60.2145(s) and (t), 60.2710(s) (t), and (w), 60.2730(q), 60.4900(b),
60.5220(b), tables 1 and 2 to subpart LLLL, tables 2 and 3 to subpart
MMMM, Sec. Sec. 60.5406(c) and 60.5413(b).
(15) ASME PTC 22-2014, Gas Turbines: Performance Test Codes, (Issued
December 31, 2014), IBR approved for Sec. 60.5580.
(16) ASME PTC 46-1996, Performance Test Code on Overall Plant
Performance, (Issued October 15, 1997), IBR approved for Sec. 60.5580.
(17) ASME QRO-1-1994, Standard for the Qualification and
Certification of Resource Recovery Facility Operators, IBR approved for
Sec. Sec. 60.54b(a) and (b), 60.56a, 60.1185(a) and (c), and 60.1675(a)
and (c).
(h) The following material is available for purchase from ASTM
International, 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken,
Pennsylvania 19428-2959, (800) 262-1373, http://www.astm.org.
(1) ASTM A99-76, Standard Specification for Ferromanganese, IBR
approved for Sec. 60.261.
(2) ASTM A99-82 (Reapproved 1987), Standard Specification for
Ferromanganese, IBR approved for Sec. 60.261.
[[Page 72]]
(3) ASTM A100-69, Standard Specification for Ferrosilicon, IBR
approved for Sec. 60.261.
(4) ASTM A100-74, Standard Specification for Ferrosilicon, IBR
approved for Sec. 60.261.
(5) ASTM A100-93, Standard Specification for Ferrosilicon, IBR
approved for Sec. 60.261.
(6) ASTM A101-73, Standard Specification for Ferrochromium, IBR
approved for Sec. 60.261.
(7) ASTM A101-93, Standard Specification for Ferrochromium, IBR
approved for Sec. 60.261.
(8) ASTM A482-76, Standard Specification for Ferrochromesilicon, IBR
approved for Sec. 60.261.
(9) ASTM A482-93, Standard Specification for Ferrochromesilicon, IBR
approved for Sec. 60.261.
(10) ASTM A483-64, Standard Specification for Silicomanganese, IBR
approved for Sec. 60.261.
(11) ASTM A483-74 (Reapproved 1988), Standard Specification for
Silicomanganese, IBR approved for Sec. 60.261.
(12) ASTM A495-76, Standard Specification for Calcium-Silicon and
Calcium Manganese-Silicon, IBR approved for Sec. 60.261.
(13) ASTM A495-94, Standard Specification for Calcium-Silicon and
Calcium Manganese-Silicon, IBR approved for Sec. 60.261.
(14) ASTM D86-78, Distillation of Petroleum Products, IBR approved
for Sec. Sec. 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).
(15) ASTM D86-82, Distillation of Petroleum Products, IBR approved
for Sec. Sec. 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).
(16) ASTM D86-90, Distillation of Petroleum Products, IBR approved
for Sec. Sec. 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).
(17) ASTM D86-93, Distillation of Petroleum Products, IBR approved
for Sec. Sec. 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).
(18) ASTM D86-95, Distillation of Petroleum Products, IBR approved
for Sec. Sec. 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).
(19) ASTM D86-96, Distillation of Petroleum Products, (Approved
April 10, 1996), IBR approved for Sec. Sec. 60.562-2(d), 60.593(d),
60.593a(d), 60.633(h), and 60.5401(f).
(20) ASTM D129-64, Standard Test Method for Sulfur in Petroleum
Products (General Bomb Method), IBR approved for Sec. Sec. 60.106(j)
and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
(21) ASTM D129-78, Standard Test Method for Sulfur in Petroleum
Products (General Bomb Method), IBR approved for Sec. Sec. 60.106(j)
and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
(22) ASTM D129-95, Standard Test Method for Sulfur in Petroleum
Products (General Bomb Method), IBR approved for Sec. Sec. 60.106(j)
and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
(23) ASTM D129-00, Standard Test Method for Sulfur in Petroleum
Products (General Bomb Method), IBR approved for Sec. 60.335(b).
(24) ASTM D129-00 (Reapproved 2005), Standard Test Method for Sulfur
in Petroleum Products (General Bomb Method), IBR approved for Sec.
60.4415(a).
(25) ASTM D240-76, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for
Sec. Sec. 60.46(c), 60.296(b), and appendix A-7 to part 60: Method 19,
Section 12.5.2.2.3.
(26) ASTM D240-92, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for
Sec. Sec. 60.46(c), 60.296(b), and appendix A-7: Method 19, Section
12.5.2.2.3.
(27) ASTM D240-02 (Reapproved 2007), Standard Test Method for Heat
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, (Approved
May 1, 2007), IBR approved for Sec. 60.107a(d).
(28) ASTM D270-65, Standard Method of Sampling Petroleum and
Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.2.1.
(29) ASTM D270-75, Standard Method of Sampling Petroleum and
Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.2.1.
(30) ASTM D323-82, Test Method for Vapor Pressure of Petroleum
Products (Reid Method), IBR approved for Sec. Sec. 60.111(l),
60.111a(g), 60.111b, and 60.116b(f).
(31) ASTM D323-94, Test Method for Vapor Pressure of Petroleum
Products
[[Page 73]]
(Reid Method), IBR approved for Sec. Sec. 60.111(l), 60.111a(g),
60.111b, and 60.116b(f).
(32) ASTM D388-77, Standard Specification for Classification of
Coals by Rank, IBR approved for Sec. Sec. 60.41, 60.45(f), 60.41Da,
60.41b, 60.41c, and 60.251.
(33) ASTM D388-90, Standard Specification for Classification of
Coals by Rank, IBR approved for Sec. Sec. 60.41, 60.45(f), 60.41Da,
60.41b, 60.41c, and 60.251.
(34) ASTM D388-91, Standard Specification for Classification of
Coals by Rank, IBR approved for Sec. Sec. 60.41, 60.45(f), 60.41Da,
60.41b, 60.41c, and 60.251.
(35) ASTM D388-95, Standard Specification for Classification of
Coals by Rank, IBR approved for Sec. Sec. 60.41, 60.45(f), 60.41Da,
60.41b, 60.41c, and 60.251.
(36) ASTM D388-98a, Standard Specification for Classification of
Coals by Rank, IBR approved for Sec. Sec. 60.41, 60.45(f), 60.41Da,
60.41b, 60.41c, and 60.251.
(37) ASTM D388-99 (Reapproved 2004) [epsiv]1 Standard Classification
of Coals by Rank, IBR approved for Sec. Sec. 60.41, 60.45(f), 60.41Da,
60.41b, 60.41c, 60.251, and 60.5580.
(38) ASTM D396-78, Standard Specification for Fuel Oils, IBR
approved for Sec. Sec. 60.41b, 60.41c, 60.111(b), and 60.111a(b).
(39) ASTM D396-89, Standard Specification for Fuel Oils, IBR
approved for Sec. Sec. 60.41b, 60.41c, 60.111(b), and 60.111a(b).
(40) ASTM D396-90, Standard Specification for Fuel Oils, IBR
approved for Sec. Sec. 60.41b, 60.41c, 60.111(b), and 60.111a(b).
(41) ASTM D396-92, Standard Specification for Fuel Oils, IBR
approved for Sec. Sec. 60.41b, 60.41c, 60.111(b), and 60.111a(b).
(42) ASTM D396-98, Standard Specification for Fuel Oils, IBR
approved for Sec. Sec. 60.41b, 60.41c, 60.111(b), 60.111a(b), and
60.5580.
(43) ASTM D975-78, Standard Specification for Diesel Fuel Oils, IBR
approved for Sec. Sec. 60.111(b) and 60.111a(b).
(44) ASTM D975-96, Standard Specification for Diesel Fuel Oils, IBR
approved for Sec. Sec. 60.111(b) and 60.111a(b).
(45) ASTM D975-98a, Standard Specification for Diesel Fuel Oils, IBR
approved for Sec. Sec. 60.111(b) and 60.111a(b).
(46) ASTM D975-08a, Standard Specification for Diesel Fuel Oils, IBR
approved for Sec. Sec. 60.41b 60.41c, and 60.5580.
(47) ASTM D1072-80, Standard Test Method for Total Sulfur in Fuel
Gases, IBR approved for Sec. 60.335(b).
(48) ASTM D1072-90 (Reapproved 1994), Standard Test Method for Total
Sulfur in Fuel Gases, IBR approved for Sec. 60.335(b).
(49) ASTM D1072-90 (Reapproved 1999), Standard Test Method for Total
Sulfur in Fuel Gases, IBR approved for Sec. 60.4415(a).
(50) ASTM D1137-53, Standard Method for Analysis of Natural Gases
and Related Types of Gaseous Mixtures by the Mass Spectrometer, IBR
approved for Sec. 60.45(f).
(51) ASTM D1137-75, Standard Method for Analysis of Natural Gases
and Related Types of Gaseous Mixtures by the Mass Spectrometer, IBR
approved for Sec. 60.45(f).
(52) ASTM D1193-77, Standard Specification for Reagent Water, IBR
approved for appendix A-3 to part 60: Method 5, Section 7.1.3; Method
5E, Section 7.2.1; Method 5F, Section 7.2.1; appendix A-4 to part 60:
Method 6, Section 7.1.1; Method 7, Section 7.1.1; Method 7C, Section
7.1.1; Method 7D, Section 7.1.1; Method 10A, Section 7.1.1; appendix A-5
to part 60: Method 11, Section 7.1.3; Method 12, Section 7.1.3; Method
13A, Section 7.1.2; appendix A-8 to part 60: Method 26, Section 7.1.2;
Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.
(53) ASTM D1193-91, Standard Specification for Reagent Water, IBR
approved for appendix A-3 to part 60: Method 5, Section 7.1.3; Method
5E, Section 7.2.1; Method 5F, Section 7.2.1; appendix A-4 to part 60:
Method 6, Section 7.1.1; Method 7, Section 7.1.1; Method 7C, Section
7.1.1; Method 7D, Section 7.1.1; Method 10A, Section 7.1.1; appendix A-5
to part 60: Method 11, Section 7.1.3; Method 12, Section 7.1.3; Method
13A, Section 7.1.2; appendix A-8 to part 60: Method 26, Section 7.1.2;
Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.
(54) ASTM D1266-87, Standard Test Method for Sulfur in Petroleum
Products (Lamp Method), IBR approved for Sec. Sec. 60.106(j) and
60.335(b).
(55) ASTM D1266-91, Standard Test Method for Sulfur in Petroleum
Products (Lamp Method), IBR approved for Sec. Sec. 60.106(j) and
60.335(b).
[[Page 74]]
(56) ASTM D1266-98, Standard Test Method for Sulfur in Petroleum
Products (Lamp Method), IBR approved for Sec. Sec. 60.106(j) and
60.335(b).
(57) ASTM D1266-98 (Reapproved 2003) [egr],\1\ Standard
Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved
for Sec. 60.4415(a).
(58) ASTM D1475-60 (Reapproved 1980), Standard Test Method for
Density of Paint, Varnish Lacquer, and Related Products, IBR approved
for Sec. 60.435(d), appendix A-8 to part 60: Method 24, Section 6.1;
and Method 24A, Sections 6.5 and 7.1.
(59) ASTM D1475-90, Standard Test Method for Density of Paint,
Varnish Lacquer, and Related Products, IBR approved for Sec. 60.435(d),
appendix A-8 to part 60: Method 24, Section 6.1; and Method 24A,
Sec. Sec. 6.5 and 7.1.
(60) ASTM D1552-83, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method), IBR approved for Sec. Sec.
60.106(j), 60.335(b), and appendix A-7 to part 60: Method 19, Section
12.5.2.2.3.
(61) ASTM D1552-95, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method), IBR approved for Sec. Sec.
60.106(j), 60.335(b), and appendix A-7 to part 60: Method 19, Section
12.5.2.2.3.
(62) ASTM D1552-01, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method), IBR approved for Sec. Sec.
60.106(j), 60.335(b), and appendix A-7 to part 60: Method 19, Section
12.5.2.2.3.
(63) ASTM D1552-03, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method), IBR approved for Sec. 60.4415(a).
(64) ASTM D1826-77, Standard Test Method for Calorific Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR
approved for Sec. Sec. 60.45(f), 60.46(c), 60.296(b), and appendix A-7
to part 60: Method 19, Section 12.3.2.4.
(65) ASTM D1826-94, Standard Test Method for Calorific Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR
approved for Sec. Sec. 60.45(f), 60.46(c), 60.296(b), and appendix A-7
to part 60: Method 19, Section 12.3.2.4.
(66) ASTM D1826-94 (Reapproved 2003), Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter, (Approved May 10, 2003), IBR approved for Sec.
60.107a(d).
(67) ASTM D1835-87, Standard Specification for Liquefied Petroleum
(LP) Gases, IBR approved for Sec. Sec. 60.41Da, 60.41b, and 60.41c.
(68) ASTM D1835-91, Standard Specification for Liquefied Petroleum
(LP) Gases, IBR approved for Sec. Sec. 60.41Da, 60.41b, and 60.41c.
(69) ASTM D1835-97, Standard Specification for Liquefied Petroleum
(LP) Gases, IBR approved for Sec. Sec. 60.41Da, 60.41b, and 60.41c.
(70) ASTM D1835-03a, Standard Specification for Liquefied Petroleum
(LP) Gases, IBR approved for Sec. Sec. 60.41Da, 60.41b, and 60.41c.
(71) ASTM D1945-64, Standard Method for Analysis of Natural Gas by
Gas Chromatography, IBR approved for Sec. 60.45(f).
(72) ASTM D1945-76, Standard Method for Analysis of Natural Gas by
Gas Chromatography, IBR approved for Sec. 60.45(f).
(73) ASTM D1945-91, Standard Method for Analysis of Natural Gas by
Gas Chromatography, IBR approved for Sec. 60.45(f).
(74) ASTM D1945-96, Standard Method for Analysis of Natural Gas by
Gas Chromatography, IBR approved for Sec. 60.45(f).
(75) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis
of Natural Gas by Gas Chromatography, (Approved January 1, 2010), IBR
approved for Sec. Sec. 60.107a(d) and 60.5413(d).
(76) ASTM D1946-77, Standard Method for Analysis of Reformed Gas by
Gas Chromatography, IBR approved for Sec. Sec. 60.18(f), 60.45(f),
60.564(f), 60.614(e), 60.664(e), and 60.704(d).
(77) ASTM D1946-90 (Reapproved 1994), Standard Method for Analysis
of Reformed Gas by Gas Chromatography, IBR approved for Sec. Sec.
60.18(f), 60.45(f), 60.564(f), 60.614(e), 60.664(e), and 60.704(d).
(78) ASTM D1946-90 (Reapproved 2006), Standard Method for Analysis
of Reformed Gas by Gas Chromatography, (Approved June 1, 2006), IBR
approved for Sec. 60.107a(d).
[[Page 75]]
(79) ASTM D2013-72, Standard Method of Preparing Coal Samples for
Analysis, IBR approved for appendix A-7 to part 60: Method 19, Section
12.5.2.1.3.
(80) ASTM D2013-86, Standard Method of Preparing Coal Samples for
Analysis, IBR approved for appendix A-7 to part 60: Method 19, Section
12.5.2.1.3.
(81) ASTM D2015-77 (Reapproved 1978), Standard Test Method for Gross
Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter, IBR
approved for Sec. Sec. 60.45(f), 60.46(c), and appendix A-7 to part 60:
Method 19, Section 12.5.2.1.3.
(82) ASTM D2015-96, Standard Test Method for Gross Calorific Value
of Solid Fuel by the Adiabatic Bomb Calorimeter, IBR approved for
Sec. Sec. 60.45(f), 60.46(c), and appendix A-7 to part 60: Method 19,
Section 12.5.2.1.3.
(83) ASTM D2016-74, Standard Test Methods for Moisture Content of
Wood, IBR approved for appendix A-8 to part 60: Method 28, Section
16.1.1.
(84) ASTM D2016-83, Standard Test Methods for Moisture Content of
Wood, IBR approved for appendix A-8 to part 60: Method 28, Section
16.1.1.
(85) ASTM D2234-76, Standard Methods for Collection of a Gross
Sample of Coal, IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.1.
(86) ASTM D2234-96, Standard Methods for Collection of a Gross
Sample of Coal, IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.1.
(87) ASTM D2234-97b, Standard Methods for Collection of a Gross
Sample of Coal, IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.1.
(88) ASTM D2234-98, Standard Methods for Collection of a Gross
Sample of Coal, IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.1.
(89) ASTM D2369-81, Standard Test Method for Volatile Content of
Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section
6.2.
(90) ASTM D2369-87, Standard Test Method for Volatile Content of
Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section
6.2.
(91) ASTM D2369-90, Standard Test Method for Volatile Content of
Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section
6.2.
(92) ASTM D2369-92, Standard Test Method for Volatile Content of
Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section
6.2.
(93) ASTM D2369-93, Standard Test Method for Volatile Content of
Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section
6.2.
(94) ASTM D2369-95, Standard Test Method for Volatile Content of
Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section
6.2.
(95) ASTM D2382-76, Heat of Combustion of Hydrocarbon Fuels by Bomb
Calorimeter (High-Precision Method), IBR approved for Sec. Sec.
60.18(f), 60.485(g), 60.485a(g), 60.564(f), 60.614(e), 60.664(e), and
60.704(d).
(96) ASTM D2382-88, Heat of Combustion of Hydrocarbon Fuels by Bomb
Calorimeter (High-Precision Method), IBR approved for Sec. Sec.
60.18(f), 60.485(g), 60.485a(g), 60.564(f), 60.614(e), 60.664(e), and
60.704(d).
(97) ASTM D2504-67, Noncondensable Gases in C3 and Lighter
Hydrocarbon Products by Gas Chromatography, IBR approved for Sec. Sec.
60.485(g) and 60.485a(g).
(98) ASTM D2504-77, Noncondensable Gases in C3 and Lighter
Hydrocarbon Products by Gas Chromatography, IBR approved for Sec. Sec.
60.485(g) and 60.485a(g).
(99) ASTM D2504-88 (Reapproved 1993), Noncondensable Gases in C3 and
Lighter Hydrocarbon Products by Gas Chromatography, IBR approved for
Sec. Sec. 60.485(g) and 60.485a(g).
(100) ASTM D2584-68(Reapproved 1985), Standard Test Method for
Ignition Loss of Cured Reinforced Resins, IBR approved for Sec.
60.685(c).
(101) ASTM D2584-94, Standard Test Method for Ignition Loss of Cured
Reinforced Resins, IBR approved for Sec. 60.685(c).
(102) ASTM D2597-94 (Reapproved 1999), Standard Test Method for
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen
and Carbon Dioxide by Gas Chromatography, IBR approved for Sec.
60.335(b).
(103) ASTM D2622-87, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR
approved for Sec. Sec. 60.106(j) and 60.335(b).
(104) ASTM D2622-94, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR
approved for Sec. Sec. 60.106(j) and 60.335(b).
[[Page 76]]
(105) ASTM D2622-98, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR
approved for Sec. Sec. 60.106(j) and 60.335(b).
(106) ASTM D2622-05, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR
approved for Sec. 60.4415(a).
(107) ASTM D2879-83Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope, IBR approved for Sec. Sec. 60.111b(f)(3), 60.116b(e),
60.116b(f), 60.485(e), and 60.485a(e).
(108) ASTM D2879-96, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope, IBR approved for Sec. Sec. 60.111b(f)(3), 60.116b(e),
60.116b(f), 60.485(e), and 60.485a(e).
(109) ASTM D2879-97, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope, IBR approved for Sec. Sec. 60.111b(f)(3), 60.116b(e),
60.116b(f), 60.485(e), and 60.485a(e).
(110) ASTM D2880-78, Standard Specification for Gas Turbine Fuel
Oils, IBR approved for Sec. Sec. 60.111(b), 60.111a(b), and 60.335(d).
(111) ASTM D2880-96, Standard Specification for Gas Turbine Fuel
Oils, IBR approved for Sec. Sec. 60.111(b), 60.111a(b), and 60.335(d).
(112) ASTM D2908-74, Standard Practice for Measuring Volatile
Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR
approved for Sec. 60.564(j).
(113) ASTM D2908-91, Standard Practice for Measuring Volatile
Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR
approved for Sec. 60.564(j).
(114) ASTM D2986-71, Standard Method for Evaluation of Air, Assay
Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR
approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix
A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section
7.1.1.2.
(115) ASTM D2986-78, Standard Method for Evaluation of Air, Assay
Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR
approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix
A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section
7.1.1.2.
(116) ASTM D2986-95a, Standard Method for Evaluation of Air, Assay
Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR
approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix
A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section
7.1.1.2.
(117) ASTM D3173-73, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.1.3.
(118) ASTM D3173-87, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.1.3.
(119) ASTM D3176-74, Standard Method for Ultimate Analysis of Coal
and Coke, IBR approved for Sec. 60.45(f)(5)(i) and appendix A-7 to part
60: Method 19, Section 12.3.2.3.
(120) ASTM D3176-89, Standard Method for Ultimate Analysis of Coal
and Coke, IBR approved for Sec. 60.45(f)(5)(i) and appendix A-7 to part
60: Method 19, Section 12.3.2.3.
(121) ASTM D3177-75, Standard Test Method for Total Sulfur in the
Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.1.3.
(122) ASTM D3177-89, Standard Test Method for Total Sulfur in the
Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.1.3.
(123) ASTM D3178-73 (Reapproved 1979), Standard Test Methods for
Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR
approved for Sec. 60.45(f).
(124) ASTM D3178-89, Standard Test Methods for Carbon and Hydrogen
in the Analysis Sample of Coal and Coke, IBR approved for Sec.
60.45(f).
(125) ASTM D3246-81, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry, IBR approved for Sec. 60.335(b).
(126) ASTM D3246-92, Standard Test Method for Sulfur in Petroleum
Gas by
[[Page 77]]
Oxidative Microcoulometry, IBR approved for Sec. 60.335(b).
(127) ASTM D3246-96, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry, IBR approved for Sec. 60.335(b).
(128) ASTM D3246-05, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry, IBR approved for Sec. 60.4415(a)(1).
(129) ASTM D3270-73T, Standard Test Methods for Analysis for
Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated
Method), IBR approved for appendix A-5 to part 60: Method 13A, Section
16.1.
(130) ASTM D3270-80, Standard Test Methods for Analysis for Fluoride
Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR
approved for appendix A-5 to part 60: Method 13A, Section 16.1.
(131) ASTM D3270-91, Standard Test Methods for Analysis for Fluoride
Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR
approved for appendix A-5 to part 60: Method 13A, Section 16.1.
(132) ASTM D3270-95, Standard Test Methods for Analysis for Fluoride
Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR
approved for appendix A-5 to part 60: Method 13A, Section 16.1.
(133) ASTM D3286-85, Standard Test Method for Gross Calorific Value
of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved for
appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
(134) ASTM D3286-96, Standard Test Method for Gross Calorific Value
of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved for
appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
(135) ASTM D3370-76, Standard Practices for Sampling Water, IBR
approved for Sec. 60.564(j).
(136) ASTM D3370-95a, Standard Practices for Sampling Water, IBR
approved for Sec. 60.564(j).
(137) ASTM D3588-98 (Reapproved 2003), Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels, (Approved May 10, 2003), IBR approved for Sec. Sec.
60.107a(d) and 60.5413(d).
(138) ASTM D3699-08, Standard Specification for Kerosine, including
Appendix X1, (Approved September 1, 2008), IBR approved for Sec. Sec.
60.41b, 60.41c, and 60.5580.
(139) ASTM D3792-79, Standard Test Method for Water Content of
Water-Reducible Paints by Direct Injection into a Gas Chromatograph, IBR
approved for appendix A-7 to part 60: Method 24, Section 6.3.
(140) ASTM D3792-91, Standard Test Method for Water Content of
Water-Reducible Paints by Direct Injection into a Gas Chromatograph, IBR
approved for appendix A-7 to part 60: Method 24, Section 6.3.
(141) ASTM D4017-81, Standard Test Method for Water in Paints and
Paint Materials by the Karl Fischer Titration Method, IBR approved for
appendix A-7 to part 60: Method 24, Section 6.4.
(142) ASTM D4017-90, Standard Test Method for Water in Paints and
Paint Materials by the Karl Fischer Titration Method, IBR approved for
appendix A-7 to part 60: Method 24, Section 6.4.
(143) ASTM D4017-96a, Standard Test Method for Water in Paints and
Paint Materials by the Karl Fischer Titration Method, IBR approved for
appendix A-7 to part 60: Method 24, Section 6.4.
(144) ASTM D4057-81, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products, IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.2.3.
(145) ASTM D4057-95, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products, IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.2.3.
(146) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, IBR approved for Sec.
60.4415(a).
(147) ASTM D4084-82, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR
approved for Sec. 60.334(h).
(148) ASTM D4084-94, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR
approved for Sec. 60.334(h).
[[Page 78]]
(149) ASTM D4084-05, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR
approved for Sec. Sec. 60.4360 and 60.4415(a).
(150) ASTM D4177-95, Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products, IBR approved for appendix A-7 to part
60: Method 19, Section 12.5.2.2.1.
(151) ASTM D4177-95 (Reapproved 2000), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, IBR approved for
Sec. 60.4415(a).
(152) ASTM D4239-85, Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube Furnace
Combustion Methods, IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.3.
(153) ASTM D4239-94, Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube Furnace
Combustion Methods, IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.3.
(154) ASTM D4239-97, Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube Furnace
Combustion Methods, IBR approved for appendix A-7 to part 60: Method 19,
Section 12.5.2.1.3.
(155) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec. 60.335(b).
(156) ASTM D4294-03, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec. 60.4415(a).
(157) ASTM D4442-84, Standard Test Methods for Direct Moisture
Content Measurement in Wood and Wood-base Materials, IBR approved for
appendix A-8 to part 60: Method 28, Section 16.1.1.
(158) ASTM D4442-92, Standard Test Methods for Direct Moisture
Content Measurement in Wood and Wood-base Materials, IBR approved for
appendix A-8 to part 60: Method 28, Section 16.1.1.
(159) ASTM D4444-92, Standard Test Methods for Use and Calibration
of Hand-Held Moisture Meters, IBR approved for appendix A-8 to part 60:
Method 28, Section 16.1.1.
(160) ASTM D4457-85 (Reapproved 1991), Test Method for Determination
of Dichloromethane and 1,1,1-Trichloroethane in Paints and Coatings by
Direct Injection into a Gas Chromatograph, IBR approved for appendix A-7
to part 60: Method 24, Section 6.5.
(161) ASTM D4468-85 (Reapproved 2000), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, IBR approved for Sec. Sec. 60.335(b) and 60.4415(a).
(162) ASTM D4468-85 (Reapproved 2006), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, (Approved June 1, 2006), IBR approved for Sec. 60.107a(e).
(163) ASTM D4629-02, Standard Test Method for Trace Nitrogen in
Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and
Chemiluminescence Detection, IBR approved for Sec. Sec. 60.49b(e) and
60.335(b).
(164) ASTM D4809-95, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for Sec. Sec. 60.18(f), 60.485(g), 60.485a(g), 60.564(f),
60.614(d), 60.664(e), and 60.704(d).
(165) ASTM D4809-06, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method),
(Approved December 1, 2006), IBR approved for Sec. 60.107a(d).
(166) ASTM D4810-88 (Reapproved 1999), Standard Test Method for
Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes,
IBR approved for Sec. Sec. 60.4360 and 60.4415(a).
(167) ASTM D4891-89 (Reapproved 2006) Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion, (Approved June 1, 2006), IBR approved for Sec. Sec.
60.107a(d) and 60.5413(d).
(168) ASTM D5287-97 (Reapproved 2002), Standard Practice for
Automatic Sampling of Gaseous Fuels, IBR approved for Sec. 60.4415(a).
(169) ASTM D5403-93, Standard Test Methods for Volatile Content of
Radiation Curable Materials, IBR approved
[[Page 79]]
for appendix A-7 to part 60: Method 24, Section 6.6.
(170) ASTM D5453-00, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec. 60.335(b).
(171) ASTM D5453-05, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec. 60.4415(a).
(172) ASTM D5504-01, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, IBR approved for Sec. Sec. 60.334(h) and
60.4360.
(173) ASTM D5504-08, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, (Approved June 15, 2008), IBR approved for
Sec. Sec. 60.107a(e) and 60.5413(d).
(174) ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum
and Petroleum Products by Boat-Inlet Chemiluminescence, IBR approved for
Sec. 60.335(b).
(175) ASTM D5865-98, Standard Test Method for Gross Calorific Value
of Coal and Coke, IBR approved for Sec. Sec. 60.45(f) and 60.46(c), and
appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
(176) ASTM D5865-10, Standard Test Method for Gross Calorific Value
of Coal and Coke, (Approved January 1, 2010), IBR approved for
Sec. Sec. 60.45(f), 60.46(c), and appendix A-7 to part 60: Method 19,
section 12.5.2.1.3.
(177) ASTM D6216-98, Standard Practice for Opacity Monitor
Manufacturers to Certify Conformance with Design and Performance
Specifications, IBR approved for appendix B to part 60: Performance
Specification 1.
(178) ASTM D6228-98, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Flame Photometric Detection, IBR approved for Sec. 60.334(h).
(179) ASTM D6228-98 (Reapproved 2003), Standard Test Method for
Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by
Gas Chromatography and Flame Photometric Detection, IBR approved for
Sec. Sec. 60.4360 and 60.4415.
(180) ASTM D6348-03, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, (Approved October 1, 2003), IBR approved
for Sec. 60.73a(b), table 7 to subpart IIII, and table 2 to subpart
JJJJ.
(181) ASTM D6366-99, Standard Test Method for Total Trace Nitrogen
and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative
Combustion and Electrochemical Detection, IBR approved for Sec.
60.335(b)(9).
(182) ASTM D6420-99 (Reapproved 2004), Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry, (Approved October 1, 2004), IBR
approved for Sec. 60.107a(d) and table 2 to subpart JJJJ.
(183) ASTM D6522-00, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions
from Natural Gas-Fired Reciprocating Engines, Combustion Turbines,
Boilers, and Process Heaters Using Portable Analyzers, IBR approved for
Sec. 60.335(a).
(184) ASTM D6522-00 (Reapproved 2005), Standard Test Method for
Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen
Concentrations in Emissions from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers, and Process Heaters Using
Portable Analyzers, (Approved October 1, 2005), IBR approved for table 2
to subpart JJJJ, and Sec. Sec. 60.5413(b) and (d).
(185) ASTM D6667-01, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by
Ultraviolet Fluorescence, IBR approved for Sec. 60.335(b).
(186) ASTM D6667-04, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by
Ultraviolet Fluorescence, IBR approved for Sec. 60.4415(a).
(187) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1
[[Page 80]]
through X3, (Approved July 15, 2011), IBR approved for Sec. Sec.
60.41b, 60.41c, and 60.5580.
(188) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), IBR approved for Sec.
60.56c(b) and appendix B to part 60: Performance Specification 12A,
Section 8.6.2.
(189) ASTM D6784-02 (Reapproved 2008) Standard Test Method for
Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary Sources (Ontario Hydro Method),
(Approved April 1, 2008), IBR approved for Sec. Sec. 60.2165(j) and
60.2730(j), tables 1, 5, 6 and 8 to subpart CCCC, and tables 2, 6, 7,
and 9 to subpart DDDD, Sec. Sec. 60.4900(b), 60.5220(b), tables 1 and 2
to subpart LLLL, and tables 2 and 3 to subpart MMMM.
(190) ASTM D7467-10, Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including Appendices X1 through X3,
(Approved August 1, 2010), IBR approved for Sec. Sec. 60.41b, 60.41c,
and 60.5580.
(191) ASTM E168-67, General Techniques of Infrared Quantitative
Analysis, IBR approved for Sec. Sec. 60.485a(d), 60.593(b), 60.593a(b),
and 60.632(f).
(192) ASTM E168-77, General Techniques of Infrared Quantitative
Analysis, IBR approved for Sec. Sec. 60.485a(d), 60.593(b), 60.593a(b),
and 60.632(f).
(193) ASTM E168-92, General Techniques of Infrared Quantitative
Analysis, IBR approved for Sec. Sec. 60.485a(d)(1), 60.593(b)(2),
60.593a(b)(2), 60.632(f), and 60.5400.
(194) ASTM E169-63, General Techniques of Ultraviolet Quantitative
Analysis, IBR approved for Sec. Sec. 60.485a(d), 60.593(b), 60.593a(b),
and 60.632(f) .
(195) ASTM E169-77, General Techniques of Ultraviolet Quantitative
Analysis, IBR approved for Sec. Sec. 60.485a(d), 60.593(b), and
60.593a(b), 60.632(f).
(196) ASTM E169-93, General Techniques of Ultraviolet Quantitative
Analysis, (Approved May 15, 1993), IBR approved for Sec. Sec.
60.485a(d), 60.593(b), 60.593a(b), 60.632(f), and 60.5400(f).
(197) ASTM E260-73, General Gas Chromatography Procedures, IBR
approved for Sec. Sec. 60.485a(d), 60.593(b), 60.593a(b), and
60.632(f).
(198) ASTM E260-91, General Gas Chromatography Procedures, (IBR
approved for Sec. Sec. 60.485a(d), 60.593(b), 60.593a(b), and
60.632(f).
(199) ASTM E260-96, General Gas Chromatography Procedures, (Approved
April 10, 1996), IBR approved for Sec. Sec. 60.485a(d), 60.593(b),
60.593a(b), 60.632(f), 60.5400(f), and 60.5406(b).
(200) ASTM E1584-11, Standard Test Method for Assay of Nitric Acid,
(Approved August 1, 2011), IBR approved for Sec. 60.73a(c).
(201) ASTM UOP539-97, Refinery Gas Analysis by Gas Chromatography,
(Copyright 1997), IBR approved for Sec. 60.107a(d).
(202) ASTM E871-82 (Reapproved 2013), Standard Test Method for
Moisture Analysis of Particulate Wood Fuels, (Approved August 15, 2013),
IBR approved for appendix A-8: method 28R.
(203) ASTM E2515-11, Standard Test Method for Determination of
Particulate Matter Emissions Collected by a Dilution Tunnel, (Approved
November 1, 2011), IBR approved for Sec. 60.534 and Sec. 60.5476.
(204) ASTM E2779-10, Standard Test Method for Determining
Particulate Matter Emissions from Pellet Heaters, (Approved October 1,
2010), IBR approved for Sec. 60.534.
(205) ASTM E2618-13 Standard Test Method for Measurement of
Particulate Matter Emissions and Heating Efficiency of Outdoor Solid
Fuel-Fired Hydronic Heating Appliances, (Approved September 1, 2013),
IBR approved for Sec. 60.5476.
(206) ASTM E2780-10, Standard Test Method for Determining
Particulate Matter Emissions from Wood Heaters, (Approved October 1,
2010), IBR approved for appendix A: method 28R.
(i) Association of Official Analytical Chemists, 1111 North 19th
Street, Suite 210, Arlington, VA 22209.
(1) AOAC Method 9, Official Methods of Analysis of the Association
of Official Analytical Chemists (AOAC), 11th edition, 1970, pp. 11-12,
IBR approved for Sec. Sec. 60.204(b), 60.214(b), 60.224(b), and
60.234(b).
(2) [Reserved]
(j) U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue
[[Page 81]]
NW., Washington, DC 20460, (202) 272-0167, http://www.epa.gov.
(1) EPA-454/R-98-015, Office of Air Quality Planning and Standards
(OAQPS) Fabric Filter Bag Leak Detection Guidance, September 1997, IBR
approved for Sec. Sec. 60.2145(r), 60.2710(r), 60.4905(b), and
60.5225(b).
(2) [Reserved]
(k) The Gas Processors Association, 6526 East 60th Street, Tulsa, OK
74145; also available through Information Handling Services, 15
Inverness Way East, PO Box 1154, Englewood, CO 80150-1154. You may
inspect a copy at the EPA's Air and Radiation Docket and Information
Center, Room 3334, 1301 Constitution Ave. NW., Washington, DC 20460.
(1) Gas Processors Association Standard 2172-09, Calculation of
Gross Heating Value, Relative Density, Compressibility and Theoretical
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer
(2009), IBR approved for Sec. 60.107a(d).
(2) Gas Processors Association Standard 2261-00, Analysis for
Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (2000),
IBR approved for Sec. 60.107a(d).
(3) Gas Processors Association Standard 2377-86, Test for Hydrogen
Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,
1986 Revision, IBR approved for Sec. Sec. 60.105(b), 60.107a(b),
60.334(h), 60.4360, and 60.4415(a).
(l) International Organization for Standardization (ISO) available
through IHS Inc., 15 Inverness Way East, Englewood, CO 80112.
(1) ISO 8178-4: 1996(E), Reciprocating Internal Combustion Engines--
Exhaust Emission Measurement--part 4: Test Cycles for Different Engine
Applications, IBR approved for Sec. 60.4241(b).
(2) [Reserved]
(m) International Organization for Standardization (ISO), 1, ch. de
la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland, + 41 22
749 01 11, http://www.iso.org/iso/home.htm.
(1) ISO 2314:2009(E), Gas turbines-Acceptance tests, Third edition
(December 15, 2009), IBR approved for Sec. 60.5580.
(2) ISO 8316: Measurement of Liquid Flow in Closed Conduits--Method
by Collection of the Liquid in a Volumetric Tank (1987-10-01)--First
Edition, IBR approved for Sec. 60.107a(d).
(n) This material is available for purchase from the National
Technical Information Services (NTIS), 5285 Port Royal Road,
Springfield, Virginia 22161. You may inspect a copy at the EPA's Air and
Radiation Docket and Information Center (Docket A-91-61, Item IV-J-125),
Room M-1500, 1200 Pennsylvania Ave. NW., Washington, DC 20460.
(1) OMB Bulletin No. 93-17: Revised Statistical Definitions for
Metropolitan Areas. Office of Management and Budget, June 30, 1993. NTIS
No. PB 93-192-664. IBR approved for Sec. 60.31e.
(2) [Reserved]
(o) North American Electric Reliability Corporation, 1325 G Street
NW., Suite 600, Washington, DC 20005-3801, http://www.nerc.com.
(1) North American Electric Reliability Corporation Reliability
Standard EOP-002-3, Capacity and Energy Emergencies, updated November
19, 2012, IBR approved for Sec. Sec. 60.4211(f) and 60.4243(d). Also
available online: http://www.nerc.com/files/EOP-002-3--1.pdf.
(2) [Reserved]
(p) The following material is available for purchase from the
Technical Association of the Pulp and Paper Industry (TAPPI), 15
Technology Parkway South, Suite 115, Peachtree Corners, GA 30092,
Telephone (800) 332-8686, and is also available at the following Web
site: http://www.tappi.org.
(1) TAPPI Method T 624 cm-11, (Copyright 2011), IBR approved, for
Sec. Sec. 60.285(d) and 60.285a(d).
(2) [Reserved]
(q) Underwriter's Laboratories, Inc. (UL), 333 Pfingsten Road,
Northbrook, IL 60062.
(1) UL 103, Sixth Edition revised as of September 3, 1986, Standard
for Chimneys, Factory-built, Residential Type and Building Heating
Appliance, IBR approved for appendix A-8 to part 60.
(2) [Reserved]
(r) Water Pollution Control Federation (WPCF), 2626 Pennsylvania
Avenue NW., Washington, DC 20037.
(1) Method 209A, Total Residue Dried at 103-105 [deg]C, in Standard
Methods for the Examination of Water and Wastewater, 15th Edition, 1980,
IBR approved for Sec. 60.683(b).
(2) [Reserved]
[[Page 82]]
(s) West Coast Lumber Inspection Bureau, 6980 SW. Barnes Road,
Portland, OR 97223.
(1) West Coast Lumber Standard Grading Rules No. 16, pages 5-21, 90
and 91, September 3, 1970, revised 1984, IBR approved for appendix A-8
to part 60.
(2) [Reserved]
(t) This material is available for purchase from the Canadian
Standards Association (CSA), 5060 Spectrum Way, Suite 100, Mississauga,
Ontario, Canada L4W 5N6, Telephone: 800-463-6727.
(1) CSA B415.1-10, Performance Testing of Solid-fuel-burning Heating
Appliances, (March 2010), IBR approved for Sec. 60.534 and Sec.
60.5476. (The standard is also available at http://shop.csa.ca/en/
canada/fuel-burning-equipment/b4151-10/invt/27013322010)
(2) [Reserved]
(u) This European National (EN) standards material is available for
purchase at European Committee for Standardization, Management Centre,
Avenue Marnix 17, B-1000 Brussels, Belgium, Telephone: + 32 2 550 08 11.
(1) DIN EN 303-5:2012E (EN 303-5), Heating boilers--Part 5: Heating
boilers for solid fuels, manually and automatically stoked, nominal heat
output of up to 500 kW--Terminology, requirements, testing and marking,
(October 2012), IBR approved for Sec. 60.5476. (The standard is also
available at http://www.en-standard.eu/csn-en-303-5-heating-boilers-
part-5-heating-boilers-for-solid-fuels-manually-and-automatically-
stoked-nominal-heat-output-of-up-to-500-kw-terminology-requirements-
testing-and-marking/?gclid = CJXI2P--97MMCFdccgQodan8ATA)
(2) [Reserved]
[79 FR 11242, Feb. 27, 2014, as amended at 79 FR 18965, Apr. 4, 2014; 80
FR 13701, Mar. 16, 2015; 80 FR 64648, Oct. 23, 2015]
Effective Date Note: At 81 FR 35895, June 3, 2016, Sec. 60.17 was
amended by revising paragraphs (g)(14), (h)(19), (75), (137), (167),
(184), (193), (196), and (199), and by adding paragraph (j)(2),
effective Aug. 2, 2016. For the convenience of the user, the added and
revised text is set forth as follows:
Sec. 60.17 Incorporations by reference.
* * * * *
(g) * * *
(14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved
for Sec. Sec. 60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i), and
(j), 60.105a(d), (f), and (g), Sec. 60.106a(a), Sec. 60.107a(a), (c),
and (d), tables 1 and 3 to subpart EEEE, tables 2 and 4 to subpart FFFF,
table 2 to subpart JJJJ, Sec. 60.285a(f), Sec. Sec. 60.4415(a),
60.2145(s) and (t), 60.2710(s), (t), and (w), 60.2730(q), 60.4900(b),
60.5220(b), tables 1 and 2 to subpart LLLL, tables 2 and 3 to subpart
MMMM, 60.5406(c), 60.5406a(c), 60.5407a(g), 60.5413(b), 60.5413a(b) and
60.5413a(d).
* * * * *
(h) * * *
(19) ASTM D86-96, Distillation of Petroleum Products, (Approved
April 10, 1996), IBR approved for Sec. Sec. 60.562-2(d), 60.593(d),
60.593a(d), 60.633(h), 60.5401(f), 60.5401a(f).
* * * * *
(75) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis
of Natural Gas by Gas Chromatography, (Approved January 1, 2010), IBR
approved for Sec. Sec. 60.107a(d), 60.5413(d), 60.5413a(d).
* * * * *
(137) ASTM D3588-98 (Reapproved 2003), Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels, (Approved May 10, 2003), IBR approved for Sec. Sec.
60.107a(d), 60.5413(d), and 60.5413a(d).
* * * * *
(167) ASTM D4891-89 (Reapproved 2006) Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion, (Approved June 1, 2006), IBR approved for Sec. Sec.
60.107a(d), 60.5413(d), and 60.5413a(d).
* * * * *
(184) ASTM D6522-00 (Reapproved 2005), Standard Test Method for
Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen
Concentrations in Emissions from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers, and Process Heaters Using
Portable Analyzers, (Approved October 1, 2005), IBR approved for table 2
to subpart JJJJ, Sec. Sec. 60.5413(b) and (d), and 60.5413a(b).
* * * * *
[[Page 83]]
(193) ASTM E168-92, General Techniques of Infrared Quantitative
Analysis, IBR approved for Sec. Sec. 60.485a(d), 60.593(b), 60.593a(b),
60.632(f), 60.5400, 60.5400a(f).
* * * * *
(196) ASTM E169-93, General Techniques of Ultraviolet Quantitative
Analysis, (Approved May 15, 1993), IBR approved for Sec. Sec.
60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f), and
60.5400a(f).
* * * * *
(199) ASTM E260-96, General Gas Chromatography Procedures, (Approved
April 10, 1996), IBR approved for Sec. Sec. 60.485a(d), 60.593(b),
60.593a(b), 60.632(f), 60.5400(f), 60.5400a(f) 60.5406(b), and
60.5406a(b)(3).
* * * * *
(j) * * *
(2) EPA-600/R-12/531, EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration Standards, May 2012, IBR approved
for Sec. Sec. 60.5413(d) and 60.5413a(d).
* * * * *
Sec. 60.18 General control device and work practice requirements.
(a) Introduction. (1) This section contains requirements for control
devices used to comply with applicable subparts of 40 CFR parts 60 and
61. The requirements are placed here for administrative convenience and
apply only to facilities covered by subparts referring to this section.
(2) This section also contains requirements for an alternative work
practice used to identify leaking equipment. This alternative work
practice is placed here for administrative convenience and is available
to all subparts in 40 CFR parts 60, 61, 63, and 65 that require
monitoring of equipment with a 40 CFR part 60, appendix A-7, Method 21
monitor.
(b) Flares. Paragraphs (c) through (f) apply to flares.
(c)(1) Flares shall be designed for and operated with no visible
emissions as determined by the methods specified in paragraph (f),
except for periods not to exceed a total of 5 minutes during any 2
consecutive hours.
(2) Flares shall be operated with a flame present at all times, as
determined by the methods specified in paragraph (f).
(3) An owner/operator has the choice of adhering to either the heat
content specifications in paragraph (c)(3)(ii) of this section and the
maximum tip velocity specifications in paragraph (c)(4) of this section,
or adhering to the requirements in paragraph (c)(3)(i) of this section.
(i)(A) Flares shall be used that have a diameter of 3 inches or
greater, are nonassisted, have a hydrogen content of 8.0 percent (by
volume), or greater, and are designed for and operated with an exit
velocity less than 37.2 m/sec (122 ft/sec) and less than the velocity,
Vmax, as determined by the following equation:
Vmax = (XH2-K1)* K2
Where:
Vmax = Maximum permitted velocity, m/sec.
K1 = Constant, 6.0 volume-percent hydrogen.
K2 = Constant, 3.9(m/sec)/volume-percent hydrogen.
XH2 = The volume-percent of hydrogen, on a wet basis, as
calculated by using the American Society for Testing and
Materials (ASTM) Method D1946-77. (Incorporated by reference
as specified in Sec. 60.17).
(B) The actual exit velocity of a flare shall be determined by the
method specified in paragraph (f)(4) of this section.
(ii) Flares shall be used only with the net heating value of the gas
being combusted being 11.2 MJ/scm (300 Btu/scf) or greater if the flare
is steam-assisted or air-assisted; or with the net heating value of the
gas being combusted being 7.45 MJ/scm (200 Btu/scf) or greater if the
flare is nonassisted. The net heating value of the gas being combusted
shall be determined by the methods specified in paragraph (f)(3) of this
section.
(4)(i) Steam-assisted and nonassisted flares shall be designed for
and operated with an exit velocity, as determined by the methods
specified in paragraph (f)(4) of this section, less than 18.3 m/sec (60
ft/sec), except as provided in paragraphs (c)(4) (ii) and (iii) of this
section.
(ii) Steam-assisted and nonassisted flares designed for and operated
with an exit velocity, as determined by the methods specified in
paragraph (f)(4),
[[Page 84]]
equal to or greater than 18.3 m/sec (60 ft/sec) but less than 122 m/sec
(400 ft/sec) are allowed if the net heating value of the gas being
combusted is greater than 37.3 MJ/scm (1,000 Btu/scf).
(iii) Steam-assisted and nonassisted flares designed for and
operated with an exit velocity, as determined by the methods specified
in paragraph (f)(4), less than the velocity, Vmax, as
determined by the method specified in paragraph (f)(5), and less than
122 m/sec (400 ft/sec) are allowed.
(5) Air-assisted flares shall be designed and operated with an exit
velocity less than the velocity, Vmax, as determined by the
method specified in paragraph (f)(6).
(6) Flares used to comply with this section shall be steam-assisted,
air-assisted, or nonassisted.
(d) Owners or operators of flares used to comply with the provisions
of this subpart shall monitor these control devices to ensure that they
are operated and maintained in conformance with their designs.
Applicable subparts will provide provisions stating how owners or
operators of flares shall monitor these control devices.
(e) Flares used to comply with provisions of this subpart shall be
operated at all times when emissions may be vented to them.
(f)(1) Method 22 of appendix A to this part shall be used to
determine the compliance of flares with the visible emission provisions
of this subpart. The observation period is 2 hours and shall be used
according to Method 22.
(2) The presence of a flare pilot flame shall be monitored using a
thermocouple or any other equivalent device to detect the presence of a
flame.
(3) The net heating value of the gas being combusted in a flare
shall be calculated using the following equation:
[GRAPHIC] [TIFF OMITTED] TC01JN92.008
where:
HT = Net heating value of the sample, MJ/scm; where the net
enthalpy per mole of offgas is based on combustion at 25
[deg]C and 760 mm Hg, but the standard temperature for
determining the volume corresponding to one mole is 20 [deg]C;
[GRAPHIC] [TIFF OMITTED] TC01JN92.009
Ci = Concentration of sample component i in ppm on a wet
basis, as measured for organics by Reference Method 18 and
measured for hydrogen and carbon monoxide by ASTM D1946-77 or
90 (Reapproved 1994) (Incorporated by reference as specified
in Sec. 60.17); and
Hi = Net heat of combustion of sample component i, kcal/g
mole at 25 [deg]C and 760 mm Hg. The heats of combustion may
be determined using ASTM D2382-76 or 88 or D4809-95
(incorporated by reference as specified in Sec. 60.17) if
published values are not available or cannot be calculated.
(4) The actual exit velocity of a flare shall be determined by
dividing the volumetric flowrate (in units of standard temperature and
pressure), as determined by Reference Methods 2, 2A, 2C, or 2D as
appropriate; by the unobstructed (free) cross sectional area of the
flare tip.
(5) The maximum permitted velocity, Vmax, for flares
complying with paragraph (c)(4)(iii) shall be determined by the
following equation.
Log10 (Vmax) = (HT + 28.8)/31.7
Vmax = Maximum permitted velocity, M/sec
28.8 = Constant
31.7 = Constant
HT = The net heating value as determined in paragraph (f)(3).
(6) The maximum permitted velocity, Vmax, for air-
assisted flares shall be determined by the following equation.
Vmax = 8.706 + 0.7084 (HT)
Vmax = Maximum permitted velocity, m/sec
[[Page 85]]
8.706 = Constant
0.7084 = Constant
HT = The net heating value as determined in paragraph (f)(3).
(g) Alternative work practice for monitoring equipment for leaks.
Paragraphs (g), (h), and (i) of this section apply to all equipment for
which the applicable subpart requires monitoring with a 40 CFR part 60,
appendix A-7, Method 21 monitor, except for closed vent systems,
equipment designated as leakless, and equipment identified in the
applicable subpart as having no detectable emissions, as indicated by an
instrument reading of less than 500 ppm above background. An owner or
operator may use an optical gas imaging instrument instead of a 40 CFR
part 60, appendix A-7, Method 21 monitor. Requirements in the existing
subparts that are specific to the Method 21 instrument do not apply
under this section. All other requirements in the applicable subpart
that are not addressed in paragraphs (g), (h), and (i) of this section
apply to this standard. For example, equipment specification
requirements, and non-Method 21 instrument recordkeeping and reporting
requirements in the applicable subpart continue to apply. The terms
defined in paragraphs (g)(1) through (5) of this section have meanings
that are specific to the alternative work practice standard in
paragraphs (g), (h), and (i) of this section.
(1) Applicable subpart means the subpart in 40 CFR parts 60, 61, 63,
or 65 that requires monitoring of equipment with a 40 CFR part 60,
appendix A-7, Method 21 monitor.
(2) Equipment means pumps, valves, pressure relief valves,
compressors, open-ended lines, flanges, connectors, and other equipment
covered by the applicable subpart that require monitoring with a 40 CFR
part 60, appendix A-7, Method 21 monitor.
(3) Imaging means making visible emissions that may otherwise be
invisible to the naked eye.
(4) Optical gas imaging instrument means an instrument that makes
visible emissions that may otherwise be invisible to the naked eye.
(5) Repair means that equipment is adjusted, or otherwise altered,
in order to eliminate a leak.
(6) Leak means:
(i) Any emissions imaged by the optical gas instrument;
(ii) Indications of liquids dripping;
(iii) Indications by a sensor that a seal or barrier fluid system
has failed; or
(iv) Screening results using a 40 CFR part 60, appendix A-7, Method
21 monitor that exceed the leak definition in the applicable subpart to
which the equipment is subject.
(h) The alternative work practice standard for monitoring equipment
for leaks is available to all subparts in 40 CFR parts 60, 61, 63, and
65 that require monitoring of equipment with a 40 CFR part 60, appendix
A-7, Method 21 monitor.
(1) An owner or operator of an affected source subject to CFR parts
60, 61, 63, or 65 can choose to comply with the alternative work
practice requirements in paragraph (i) of this section instead of using
the 40 CFR part 60, appendix A-7, Method 21 monitor to identify leaking
equipment. The owner or operator must document the equipment, process
units, and facilities for which the alternative work practice will be
used to identify leaks.
(2) Any leak detected when following the leak survey procedure in
paragraph (i)(3) of this section must be identified for repair as
required in the applicable subpart.
(3) If the alternative work practice is used to identify leaks, re-
screening after an attempted repair of leaking equipment must be
conducted using either the alternative work practice or the 40 CFR part
60, appendix A-7, Method 21 monitor at the leak definition required in
the applicable subpart to which the equipment is subject.
(4) The schedule for repair is as required in the applicable
subpart.
(5) When this alternative work practice is used for detecting
leaking equipment, choose one of the monitoring frequencies listed in
Table 1 to subpart A of this part in lieu of the monitoring frequency
specified for regulated equipment in the applicable subpart. Reduced
monitoring frequencies for good performance are not applicable when
using the alternative work practice.
[[Page 86]]
(6) When this alternative work practice is used for detecting
leaking equipment the following are not applicable for the equipment
being monitored:
(i) Skip period leak detection and repair;
(ii) Quality improvement plans; or
(iii) Complying with standards for allowable percentage of valves
and pumps to leak.
(7) When the alternative work practice is used to detect leaking
equipment, the regulated equipment in paragraph (h)(1)(i) of this
section must also be monitored annually using a 40 CFR part 60, appendix
A-7, Method 21 monitor at the leak definition required in the applicable
subpart. The owner or operator may choose the specific monitoring period
(for example, first quarter) to conduct the annual monitoring.
Subsequent monitoring must be conducted every 12 months from the initial
period. Owners or operators must keep records of the annual Method 21
screening results, as specified in paragraph (i)(4)(vii) of this
section.
(i) An owner or operator of an affected source who chooses to use
the alternative work practice must comply with the requirements of
paragraphs (i)(1) through (i)(5) of this section.
(1) Instrument Specifications. The optical gas imaging instrument
must comply with the requirements in (i)(1)(i) and (i)(1)(ii) of this
section.
(i) Provide the operator with an image of the potential leak points
for each piece of equipment at both the detection sensitivity level and
within the distance used in the daily instrument check described in
paragraph (i)(2) of this section. The detection sensitivity level
depends upon the frequency at which leak monitoring is to be performed.
(ii) Provide a date and time stamp for video records of every
monitoring event.
(2) Daily Instrument Check. On a daily basis, and prior to beginning
any leak monitoring work, test the optical gas imaging instrument at the
mass flow rate determined in paragraph (i)(2)(i) of this section in
accordance with the procedure specified in paragraphs (i)(2)(ii) through
(i)(2)(iv) of this section for each camera configuration used during
monitoring (for example, different lenses used), unless an alternative
method to demonstrate daily instrument checks has been approved in
accordance with paragraph (i)(2)(v) of this section.
(i) Calculate the mass flow rate to be used in the daily instrument
check by following the procedures in paragraphs (i)(2)(i)(A) and
(i)(2)(i)(B) of this section.
(A) For a specified population of equipment to be imaged by the
instrument, determine the piece of equipment in contact with the lowest
mass fraction of chemicals that are detectable, within the distance to
be used in paragraph (i)(2)(iv)(B) of this section, at or below the
standard detection sensitivity level.
(B) Multiply the standard detection sensitivity level, corresponding
to the selected monitoring frequency in Table 1 of subpart A of this
part, by the mass fraction of detectable chemicals from the stream
identified in paragraph (i)(2)(i)(A) of this section to determine the
mass flow rate to be used in the daily instrument check, using the
following equation.
[GRAPHIC] [TIFF OMITTED] TR22DE08.007
Where:
Edic = Mass flow rate for the daily instrument check, grams
per hour
xi = Mass fraction of detectable chemical(s) i seen by the
optical gas imaging instrument, within the distance to be used
in paragraph (i)(2)(iv)(B) of this section, at or below the
standard detection sensitivity level, Esds.
Esds = Standard detection sensitivity level from Table 1 to
subpart A, grams per hour
k = Total number of detectable chemicals emitted from the leaking
equipment and seen by the optical gas imaging instrument.
(ii) Start the optical gas imaging instrument according to the
manufacturer's instructions, ensuring that all appropriate settings
conform to the manufacturer's instructions.
(iii) Use any gas chosen by the user that can be viewed by the
optical gas imaging instrument and that has a purity of no less than 98
percent.
(iv) Establish a mass flow rate by using the following procedures:
[[Page 87]]
(A) Provide a source of gas where it will be in the field of view of
the optical gas imaging instrument.
(B) Set up the optical gas imaging instrument at a recorded distance
from the outlet or leak orifice of the flow meter that will not be
exceeded in the actual performance of the leak survey. Do not exceed the
operating parameters of the flow meter.
(C) Open the valve on the flow meter to set a flow rate that will
create a mass emission rate equal to the mass rate specified in
paragraph (i)(2)(i) of this section while observing the gas flow through
the optical gas imaging instrument viewfinder. When an image of the gas
emission is seen through the viewfinder at the required emission rate,
make a record of the reading on the flow meter.
(v) Repeat the procedures specified in paragraphs (i)(2)(ii) through
(i)(2)(iv) of this section for each configuration of the optical gas
imaging instrument used during the leak survey.
(vi) To use an alternative method to demonstrate daily instrument
checks, apply to the Administrator for approval of the alternative under
Sec. 60.13(i).
(3) Leak Survey Procedure. Operate the optical gas imaging
instrument to image every regulated piece of equipment selected for this
work practice in accordance with the instrument manufacturer's operating
parameters. All emissions imaged by the optical gas imaging instrument
are considered to be leaks and are subject to repair. All emissions
visible to the naked eye are also considered to be leaks and are subject
to repair.
(4) Recordkeeping. You must keep the records described in paragraphs
(i)(4)(i) through (i)(4)(vii) of this section:
(i) The equipment, processes, and facilities for which the owner or
operator chooses to use the alternative work practice.
(ii) The detection sensitivity level selected from Table 1 to
subpart A of this part for the optical gas imaging instrument.
(iii) The analysis to determine the piece of equipment in contact
with the lowest mass fraction of chemicals that are detectable, as
specified in paragraph (i)(2)(i)(A) of this section.
(iv) The technical basis for the mass fraction of detectable
chemicals used in the equation in paragraph (i)(2)(i)(B) of this
section.
(v) The daily instrument check. Record the distance, per paragraph
(i)(2)(iv)(B) of this section, and the flow meter reading, per paragraph
(i)(2)(iv)(C) of this section, at which the leak was imaged. Keep a
video record of the daily instrument check for each configuration of the
optical gas imaging instrument used during the leak survey (for example,
the daily instrument check must be conducted for each lens used). The
video record must include a time and date stamp for each daily
instrument check. The video record must be kept for 5 years.
(vi) Recordkeeping requirements in the applicable subpart. A video
record must be used to document the leak survey results. The video
record must include a time and date stamp for each monitoring event. A
video record can be used to meet the recordkeeping requirements of the
applicable subparts if each piece of regulated equipment selected for
this work practice can be identified in the video record. The video
record must be kept for 5 years.
(vii) The results of the annual Method 21 screening required in
paragraph (h)(7) of this section. Records must be kept for all regulated
equipment specified in paragraph (h)(1) of this section. Records must
identify the equipment screened, the screening value measured by Method
21, the time and date of the screening, and calibration information
required in the existing applicable subpart.
(5) Reporting. Submit the reports required in the applicable
subpart. Submit the records of the annual Method 21 screening required
in paragraph (h)(7) of this section to the Administrator via e-mail to
[email protected].
[51 FR 2701, Jan. 21, 1986, as amended at 63 FR 24444, May 4, 1998; 65
FR 61752, Oct. 17, 2000; 73 FR 78209, Dec. 22, 2008]
Sec. 60.19 General notification and reporting requirements.
(a) For the purposes of this part, time periods specified in days
shall be
[[Page 88]]
measured in calendar days, even if the word ``calendar'' is absent,
unless otherwise specified in an applicable requirement.
(b) For the purposes of this part, if an explicit postmark deadline
is not specified in an applicable requirement for the submittal of a
notification, application, report, or other written communication to the
Administrator, the owner or operator shall postmark the submittal on or
before the number of days specified in the applicable requirement. For
example, if a notification must be submitted 15 days before a particular
event is scheduled to take place, the notification shall be postmarked
on or before 15 days preceding the event; likewise, if a notification
must be submitted 15 days after a particular event takes place, the
notification shall be delivered or postmarked on or before 15 days
following the end of the event. The use of reliable non-Government mail
carriers that provide indications of verifiable delivery of information
required to be submitted to the Administrator, similar to the postmark
provided by the U.S. Postal Service, or alternative means of delivery,
including the use of electronic media, agreed to by the permitting
authority, is acceptable.
(c) Notwithstanding time periods or postmark deadlines specified in
this part for the submittal of information to the Administrator by an
owner or operator, or the review of such information by the
Administrator, such time periods or deadlines may be changed by mutual
agreement between the owner or operator and the Administrator.
Procedures governing the implementation of this provision are specified
in paragraph (f) of this section.
(d) If an owner or operator of an affected facility in a State with
delegated authority is required to submit periodic reports under this
part to the State, and if the State has an established timeline for the
submission of periodic reports that is consistent with the reporting
frequency(ies) specified for such facility under this part, the owner or
operator may change the dates by which periodic reports under this part
shall be submitted (without changing the frequency of reporting) to be
consistent with the State's schedule by mutual agreement between the
owner or operator and the State. The allowance in the previous sentence
applies in each State beginning 1 year after the affected facility is
required to be in compliance with the applicable subpart in this part.
Procedures governing the implementation of this provision are specified
in paragraph (f) of this section.
(e) If an owner or operator supervises one or more stationary
sources affected by standards set under this part and standards set
under part 61, part 63, or both such parts of this chapter, he/she may
arrange by mutual agreement between the owner or operator and the
Administrator (or the State with an approved permit program) a common
schedule on which periodic reports required by each applicable standard
shall be submitted throughout the year. The allowance in the previous
sentence applies in each State beginning 1 year after the stationary
source is required to be in compliance with the applicable subpart in
this part, or 1 year after the stationary source is required to be in
compliance with the applicable 40 CFR part 61 or part 63 of this chapter
standard, whichever is latest. Procedures governing the implementation
of this provision are specified in paragraph (f) of this section.
(f)(1)(i) Until an adjustment of a time period or postmark deadline
has been approved by the Administrator under paragraphs (f)(2) and
(f)(3) of this section, the owner or operator of an affected facility
remains strictly subject to the requirements of this part.
(ii) An owner or operator shall request the adjustment provided for
in paragraphs (f)(2) and (f)(3) of this section each time he or she
wishes to change an applicable time period or postmark deadline
specified in this part.
(2) Notwithstanding time periods or postmark deadlines specified in
this part for the submittal of information to the Administrator by an
owner or operator, or the review of such information by the
Administrator, such time periods or deadlines may be changed by mutual
agreement between
[[Page 89]]
the owner or operator and the Administrator. An owner or operator who
wishes to request a change in a time period or postmark deadline for a
particular requirement shall request the adjustment in writing as soon
as practicable before the subject activity is required to take place.
The owner or operator shall include in the request whatever information
he or she considers useful to convince the Administrator that an
adjustment is warranted.
(3) If, in the Administrator's judgment, an owner or operator's
request for an adjustment to a particular time period or postmark
deadline is warranted, the Administrator will approve the adjustment.
The Administrator will notify the owner or operator in writing of
approval or disapproval of the request for an adjustment within 15
calendar days of receiving sufficient information to evaluate the
request.
(4) If the Administrator is unable to meet a specified deadline, he
or she will notify the owner or operator of any significant delay and
inform the owner or operator of the amended schedule.
[59 FR 12428, Mar. 16, 1994, as amended at 64 FR 7463, Feb. 12, 1998]
Sec. Table 1 to Subpart A of Part 60--Detection Sensitivity Levels
(grams per hour)
------------------------------------------------------------------------
Detection
Monitoring frequency per subpart \a\ sensitivity
level
------------------------------------------------------------------------
Bi-Monthly.............................................. 60
Semi-Quarterly.......................................... 85
Monthly................................................. 100
------------------------------------------------------------------------
\a\ When this alternative work practice is used to identify leaking
equipment, the owner or operator must choose one of the monitoring
frequencies listed in this table in lieu of the monitoring frequency
specified in the applicable subpart. Bi-monthly means every other
month. Semi-quarterly means twice per quarter. Monthly means once per
month.
[73 FR 78211, Dec. 22, 2008]
Subpart B_Adoption and Submittal of State Plans for Designated
Facilities
Source: 40 FR 53346, Nov. 17, 1975, unless otherwise noted.
Sec. 60.20 Applicability.
The provisions of this subpart apply to States upon publication of a
final guideline document under Sec. 60.22(a).
Sec. 60.21 Definitions.
Terms used but not defined in this subpart shall have the meaning
given them in the Act and in subpart A:
(a) Designated pollutant means any air pollutant, the emissions of
which are subject to a standard of performance for new stationary
sources, but for which air quality criteria have not been issued and
that is not included on a list published under section 108(a) or section
112(b)(1)(A) of the Act.
(b) Designated facility means any existing facility (see Sec.
60.2(aa)) which emits a designated pollutant and which would be subject
to a standard of performance for that pollutant if the existing facility
were an affected facility (see Sec. 60.2(e)).
(c) Plan means a plan under section 111(d) of the Act which
establishes emission standards for designated pollutants from designated
facilities and provides for the implementation and enforcement of such
emission standards.
(d) Applicable plan means the plan, or most recent revision thereof,
which has been approved under Sec. 60.27(b) or promulgated under Sec.
60.27(d).
(e) Emission guideline means a guideline set forth in subpart C of
this part, or in a final guideline document published under Sec.
60.22(a), which reflects the degree of emission reduction achievable
through the application of the best system of emission reduction which
(taking into account the cost of such reduction) the Administrator has
determined has been adequately demonstrated for designated facilities.
(f) Emission standard means a legally enforceable regulation setting
forth an allowable rate of emissions into the atmosphere, establishing
an allowance system, or prescribing equipment specifications for control
of air pollution emissions.
(g) Compliance schedule means a legally enforceable schedule
specifying a date or dates by which a source or category of sources must
comply with specific emission standards contained in a plan or with any
increments of progress to achieve such compliance.
(h) Increments of progress means steps to achieve compliance which
must be taken by an owner or operator of a designated facility,
including:
[[Page 90]]
(1) Submittal of a final control plan for the designated facility to
the appropriate air pollution control agency;
(2) Awarding of contracts for emission control systems or for
process modifications, or issuance of orders for the purchase of
component parts to accomplish emission control or process modification;
(3) Initiation of on-site construction or installation of emission
control equipment or process change;
(4) Completion of on-site construction or installation of emission
control equipment or process change; and
(5) Final compliance.
(i) Region means an air quality control region designated under
section 107 of the Act and described in part 81 of this chapter.
(j) Local agency means any local governmental agency.
[40 FR 53346, Nov. 17, 1975, as amended at 70 FR 28649, May 18, 2005; 77
FR 9447, Feb. 16, 2012]
Sec. 60.22 Publication of guideline documents, emission guidelines,
and final compliance times.
(a) Concurrently upon or after proposal of standards of performance
for the control of a designated pollutant from affected facilities, the
Administrator will publish a draft guideline document containing
information pertinent to control of the designated pollutant form
designated facilities. Notice of the availability of the draft guideline
document will be published in the Federal Register and public comments
on its contents will be invited. After consideration of public comments
and upon or after promulgation of standards of performance for control
of a designated pollutant from affected facilities, a final guideline
document will be published and notice of its availability will be
published in the Federal Register.
(b) Guideline documents published under this section will provide
information for the development of State plans, such as:
(1) Information concerning known or suspected endangerment of public
health or welfare caused, or contributed to, by the designated
pollutant.
(2) A description of systems of emission reduction which, in the
judgment of the Administrator, have been adequately demonstrated.
(3) Information on the degree of emission reduction which is
achievable with each system, together with information on the costs and
environmental effects of applying each system to designated facilities.
(4) Incremental periods of time normally expected to be necessary
for the design, installation, and startup of identified control systems.
(5) An emission guideline that reflects the application of the best
system of emission reduction (considering the cost of such reduction)
that has been adequately demonstrated for designated facilities, and the
time within which compliance with emission standards of equivalent
stringency can be achieved. The Administrator will specify different
emission guidelines or compliance times or both for different sizes,
types, and classes of designated facilities when costs of control,
physical limitations, geographical location, or similar factors make
subcategorization appropriate. (6) Such other available information as
the Administrator determines may contribute to the formulation of State
plans.
(c) Except as provided in paragraph (d)(1) of this section, the
emission guidelines and compliance times referred to in paragraph (b)(5)
of this section will be proposed for comment upon publication of the
draft guideline document, and after consideration of comments will be
promulgated in subpart C of this part with such modifications as may be
appropriate.
(d)(1) If the Administrator determines that a designated pollutant
may cause or contribute to endangerment of public welfare, but that
adverse effects on public health have not been demonstrated, he will
include the determination in the draft guideline document and in the
Federal Register notice of its availability. Except as provided in
paragraph (d)(2) of this section, paragraph (c) of this section shall be
inapplicable in such cases.
(2) If the Administrator determines at any time on the basis of new
information that a prior determination under paragraph (d)(1) of this
section is incorrect or no longer correct, he will publish notice of the
determination in
[[Page 91]]
the Federal Register, revise the guideline document as necessary under
paragraph (a) of this section, and propose and promulgate emission
guidelines and compliance times under paragraph (c) of this section.
[40 FR 53346, Nov. 17, 1975, as amended at 54 FR 52189, Dec. 20, 1989]
Sec. 60.23 Adoption and submittal of State plans; public hearings.
(a)(1) Unless otherwise specified in the applicable subpart, within
9 months after notice of the availability of a final guideline document
is published under Sec. 60.22(a), each State shall adopt and submit to
the Administrator, in accordance with Sec. 60.4 of subpart A of this
part, a plan for the control of the designated pollutant to which the
guideline document applies.
(2) Within nine months after notice of the availability of a final
revised guideline document is published as provided in Sec.
60.22(d)(2), each State shall adopt and submit to the Administrator any
plan revision necessary to meet the requirements of this subpart.
(b) If no designated facility is located within a State, the State
shall submit a letter of certification to that effect to the
Administrator within the time specified in paragraph (a) of this
section. Such certification shall exempt the State from the requirements
of this subpart for that designated pollutant.
(c)(1) Except as provided in paragraphs (c)(2) and (c)(3) of this
section, the State shall, prior to the adoption of any plan or revision
thereof, conduct one or more public hearings within the State on such
plan or plan revision.
(2) No hearing shall be required for any change to an increment of
progress in an approved compliance schedule unless the change is likely
to cause the facility to be unable to comply with the final compliance
date in the schedule.
(3) No hearing shall be required on an emission standard in effect
prior to the effective date of this subpart if it was adopted after a
public hearing and is at least as stringent as the corresponding
emission guideline specified in the applicable guideline document
published under Sec. 60.22(a).
(d) Any hearing required by paragraph (c) of this section shall be
held only after reasonable notice. Notice shall be given at least 30
days prior to the date of such hearing and shall include:
(1) Notification to the public by prominently advertising the date,
time, and place of such hearing in each region affected;
(2) Availability, at the time of public announcement, of each
proposed plan or revision thereof for public inspection in at least one
location in each region to which it will apply;
(3) Notification to the Administrator;
(4) Notification to each local air pollution control agency in each
region to which the plan or revision will apply; and
(5) In the case of an interstate region, notification to any other
State included in the region.
(e) The State shall prepare and retain, for a minimum of 2 years, a
record of each hearing for inspection by any interested party. The
record shall contain, as a minimum, a list of witnesses together with
the text of each presentation.
(f) The State shall submit with the plan or revision:
(1) Certification that each hearing required by paragraph (c) of
this section was held in accordance with the notice required by
paragraph (d) of this section; and
(2) A list of witnesses and their organizational affiliations, if
any, appearing at the hearing and a brief written summary of each
presentation or written submission.
(g) Upon written application by a State agency (through the
appropriate Regional Office), the Administrator may approve State
procedures designed to insure public participation in the matters for
which hearings are required and public notification of the opportunity
to participate if, in the judgment of the Administrator, the procedures,
although different from the requirements of this subpart, in fact
provide for adequate notice to and participation of the public. The
Administrator may impose such conditions on his approval as he deems
necessary. Procedures approved under this section
[[Page 92]]
shall be deemed to satisfy the requirements of this subpart regarding
procedures for public hearings.
[40 FR 53346, Nov. 17, 1975, as amended at 60 FR 65414, Dec. 19, 1995]
Sec. 60.24 Emission standards and compliance schedules.
(a) Each plan shall include emission standards and compliance
schedules.
(b) (1) Emission standards shall either be based on an allowance
system or prescribe allowable rates of emissions except when it is
clearly impracticable. Such cases will be identified in the guideline
documents issued under Sec. 60.22. Where emission standards prescribing
equipment specifications are established, the plan shall, to the degree
possible, set forth the emission reductions achievable by implementation
of such specifications, and may permit compliance by the use of
equipment determined by the State to be equivalent to that prescribed.
(2) Test methods and procedures for determining compliance with the
emission standards shall be specified in the plan. Methods other than
those specified in appendix A to this part may be specified in the plan
if shown to be equivalent or alternative methods as defined in Sec.
60.2 (t) and (u).
(3) Emission standards shall apply to all designated facilities
within the State. A plan may contain emission standards adopted by local
jurisdictions provided that the standards are enforceable by the State.
(c) Except as provided in paragraph (f) of this section, where the
Administrator has determined that a designated pollutant may cause or
contribute to endangerment of public health, emission standards shall be
no less stringent than the corresponding emission guideline(s) specified
in subpart C of this part, and final compliance shall be required as
expeditiously as practicable but no later than the compliance times
specified in subpart C of this part.
(d) Where the Administrator has determined that a designated
pollutant may cause or contribute to endangerment of public welfare but
that adverse effects on public health have not been demonstrated, States
may balance the emission guidelines, compliance times, and other
information provided in the applicable guideline document against other
factors of public concern in establishing emission standards, compliance
schedules, and variances. Appropriate consideration shall be given to
the factors specified in Sec. 60.22(b) and to information presented at
the public hearing(s) conducted under Sec. 60.23(c).
(e)(1) Any compliance schedule extending more than 12 months from
the date required for submittal of the plan must include legally
enforceable increments of progress to achieve compliance for each
designated facility or category of facilities. Unless otherwise
specified in the applicable subpart, increments of progress must
include, where practicable, each increment of progress specified in
Sec. 60.21(h) and must include such additional increments of progress
as may be necessary to permit close and effective supervision of
progress toward final compliance.
(2) A plan may provide that compliance schedules for individual
sources or categories of sources will be formulated after plan
submittal. Any such schedule shall be the subject of a public hearing
held according to Sec. 60.23 and shall be submitted to the
Administrator within 60 days after the date of adoption of the schedule
but in no case later than the date prescribed for submittal of the first
semiannual report required by Sec. 60.25(e).
(f) Unless otherwise specified in the applicable subpart on a case-
by-case basis for particular designated facilities or classes of
facilities, States may provide for the application of less stringent
emissions standards or longer compliance schedules than those otherwise
required by paragraph (c) of this section, provided that the State
demonstrates with respect to each such facility (or class of
facilities):
(1) Unreasonable cost of control resulting from plant age, location,
or basic process design;
(2) Physical impossibility of installing necessary control
equipment; or
(3) Other factors specific to the facility (or class of facilities)
that make application of a less stringent standard or final compliance
time significantly more reasonable.
[[Page 93]]
(g) Nothing in this subpart shall be construed to preclude any State
or political subdivision thereof from adopting or enforcing (1) emission
standards more stringent than emission guidelines specified in subpart C
of this part or in applicable guideline documents or (2) compliance
schedules requiring final compliance at earlier times than those
specified in subpart C or in applicable guideline documents.
[40 FR 53346, Nov. 17, 1975, as amended at 60 FR 65414, Dec. 19, 1995;
65 FR 76384, Dec. 6, 2000; 70 FR 28649, May 18, 2005; 71 FR 33398, June
9, 2006; 72 FR 59204, Oct. 19, 2007; 77 FR 9447, Feb. 16, 2012]
Sec. 60.25 Emission inventories, source surveillance, reports.
(a) Each plan shall include an inventory of all designated
facilities, including emission data for the designated pollutants and
information related to emissions as specified in appendix D to this
part. Such data shall be summarized in the plan, and emission rates of
designated pollutants from designated facilities shall be correlated
with applicable emission standards. As used in this subpart,
``correlated'' means presented in such a manner as to show the
relationship between measured or estimated amounts of emissions and the
amounts of such emissions allowable under applicable emission standards.
(b) Each plan shall provide for monitoring the status of compliance
with applicable emission standards. Each plan shall, as a minimum,
provide for:
(1) Legally enforceable procedures for requiring owners or operators
of designated facilities to maintain records and periodically report to
the State information on the nature and amount of emissions from such
facilities, and/or such other information as may be necessary to enable
the State to determine whether such facilities are in compliance with
applicable portions of the plan. Submission of electronic documents
shall comply with the requirements of 40 CFR part 3--(Electronic
reporting).
(2) Periodic inspection and, when applicable, testing of designated
facilities.
(c) Each plan shall provide that information obtained by the State
under paragraph (b) of this section shall be correlated with applicable
emission standards (see Sec. 60.25(a)) and made available to the
general public.
(d) The provisions referred to in paragraphs (b) and (c) of this
section shall be specifically identified. Copies of such provisions
shall be submitted with the plan unless:
(1) They have been approved as portions of a preceding plan
submitted under this subpart or as portions of an implementation plan
submitted under section 110 of the Act, and
(2) The State demonstrates:
(i) That the provisions are applicable to the designated
pollutant(s) for which the plan is submitted, and
(ii) That the requirements of Sec. 60.26 are met.
(e) The State shall submit reports on progress in plan enforcement
to the Administrator on an annual (calendar year) basis, commencing with
the first full report period after approval of a plan or after
promulgation of a plan by the Administrator. Information required under
this paragraph must be included in the annual report required by Sec.
51.321 of this chapter.
(f) Each progress report shall include:
(1) Enforcement actions initiated against designated facilities
during the reporting period, under any emission standard or compliance
schedule of the plan.
(2) Identification of the achievement of any increment of progress
required by the applicable plan during the reporting period.
(3) Identification of designated facilities that have ceased
operation during the reporting period.
(4) Submission of emission inventory data as described in paragraph
(a) of this section for designated facilities that were not in operation
at the time of plan development but began operation during the reporting
period.
(5) Submission of additional data as necessary to update the
information submitted under paragraph (a) of this section or in previous
progress reports.
(6) Submission of copies of technical reports on all performance
testing on designated facilities conducted under
[[Page 94]]
paragraph (b)(2) of this section, complete with concurrently recorded
process data.
[40 FR 53346, Nov. 17, 1975, as amended at 44 FR 65071, Nov. 9, 1979; 70
FR 59887, Oct. 13, 2005]
Sec. 60.26 Legal authority.
(a) Each plan shall show that the State has legal authority to carry
out the plan, including authority to:
(1) Adopt emission standards and compliance schedules applicable to
designated facilities.
(2) Enforce applicable laws, regulations, standards, and compliance
schedules, and seek injunctive relief.
(3) Obtain information necessary to determine whether designated
facilities are in compliance with applicable laws, regulations,
standards, and compliance schedules, including authority to require
recordkeeping and to make inspections and conduct tests of designated
facilities.
(4) Require owners or operators of designated facilities to install,
maintain, and use emission monitoring devices and to make periodic
reports to the State on the nature and amounts of emissions from such
facilities; also authority for the State to make such data available to
the public as reported and as correlated with applicable emission
standards.
(b) The provisions of law or regulations which the State determines
provide the authorities required by this section shall be specifically
identified. Copies of such laws or regulations shall be submitted with
the plan unless:
(1) They have been approved as portions of a preceding plan
submitted under this subpart or as portions of an implementation plan
submitted under section 110 of the Act, and
(2) The State demonstrates that the laws or regulations are
applicable to the designated pollutant(s) for which the plan is
submitted.
(c) The plan shall show that the legal authorities specified in this
section are available to the State at the time of submission of the
plan. Legal authority adequate to meet the requirements of paragraphs
(a)(3) and (4) of this section may be delegated to the State under
section 114 of the Act.
(d) A State governmental agency other than the State air pollution
control agency may be assigned responsibility for carrying out a portion
of a plan if the plan demonstrates to the Administrator's satisfaction
that the State governmental agency has the legal authority necessary to
carry out that portion of the plan.
(e) The State may authorize a local agency to carry out a plan, or
portion thereof, within the local agency's jurisdiction if the plan
demonstrates to the Administrator's satisfaction that the local agency
has the legal authority necessary to implement the plan or portion
thereof, and that the authorization does not relieve the State of
responsibility under the Act for carrying out the plan or portion
thereof.
Sec. 60.27 Actions by the Administrator.
(a) The Administrator may, whenever he determines necessary, extend
the period for submission of any plan or plan revision or portion
thereof.
(b) After receipt of a plan or plan revision, the Administrator will
propose the plan or revision for approval or disapproval. The
Administrator will, within four months after the date required for
submission of a plan or plan revision, approve or disapprove such plan
or revision or each portion thereof.
(c) The Administrator will, after consideration of any State hearing
record, promptly prepare and publish proposed regulations setting forth
a plan, or portion thereof, for a State if:
(1) The State fails to submit a plan within the time prescribed;
(2) The State fails to submit a plan revision required by Sec.
60.23(a)(2) within the time prescribed; or
(3) The Administrator disapproves the State plan or plan revision or
any portion thereof, as unsatisfactory because the requirements of this
subpart have not been met.
(d) The Administrator will, within six months after the date
required for submission of a plan or plan revision, promulgate the
regulations proposed under paragraph (c) of this section with such
modifications as may be appropriate unless, prior to such promulgation,
the State has adopted and submitted a plan or plan revision which
[[Page 95]]
the Administrator determines to be approvable.
(e)(1) Except as provided in paragraph (e)(2) of this section,
regulations proposed and promulgated by the Administrator under this
section will prescribe emission standards of the same stringency as the
corresponding emission guideline(s) specified in the final guideline
document published under Sec. 60.22(a) and will require final
compliance with such standards as expeditiously as practicable but no
later than the times specified in the guideline document.
(2) Upon application by the owner or operator of a designated
facility to which regulations proposed and promulgated under this
section will apply, the Administrator may provide for the application of
less stringent emission standards or longer compliance schedules than
those otherwise required by this section in accordance with the criteria
specified in Sec. 60.24(f).
(f) Prior to promulgation of a plan under paragraph (d) of this
section, the Administrator will provide the opportunity for at least one
public hearing in either:
(1) Each State that failed to hold a public hearing as required by
Sec. 60.23(c); or
(2) Washington, DC or an alternate location specified in the Federal
Register.
[40 FR 53346, Nov. 17, 1975, as amended at 65 FR 76384, Dec. 6, 2000]
Sec. 60.28 Plan revisions by the State.
(a) Plan revisions which have the effect of delaying compliance with
applicable emission standards or increments of progress or of
establishing less stringent emission standards shall be submitted to the
Administrator within 60 days after adoption in accordance with the
procedures and requirements applicable to development and submission of
the original plan.
(b) More stringent emission standards, or orders which have the
effect of accelerating compliance, may be submitted to the Administrator
as plan revisions in accordance with the procedures and requirements
applicable to development and submission of the original plan.
(c) A revision of a plan, or any portion thereof, shall not be
considered part of an applicable plan until approved by the
Administrator in accordance with this subpart.
Sec. 60.29 Plan revisions by the Administrator.
After notice and opportunity for public hearing in each affected
State, the Administrator may revise any provision of an applicable plan
if:
(a) The provision was promulgated by the Administrator, and
(b) The plan, as revised, will be consistent with the Act and with
the requirements of this subpart.
Subpart C_Emission Guidelines and Compliance Times
Sec. 60.30 Scope.
The following subparts contain emission guidelines and compliance
times for the control of certain designated pollutants in accordance
with section 111(d) and section 129 of the Clean Air Act and subpart B
of this part.
(a) Subpart Ca [Reserved]
(b) Subpart Cb--Municipal Waste Combustors.
(c) Subpart Cc--Municipal Solid Waste Landfills.
(d) Subpart Cd--Sulfuric Acid Production Plants.
(e) Subpart Ce--Hospital/Medical/Infectious Waste Incinerators.
[62 FR 48379, Sept. 15, 1997]
Sec. 60.31 Definitions.
Terms used but not defined in this subpart have the meaning given
them in the Act and in subparts A and B of this part.
[42 FR 55797, Oct. 18, 1977]
Subpart Ca [Reserved]
Subpart Cb_Emissions Guidelines and Compliance Times for Large Municipal
Waste Combustors That are Constructed on or Before September 20, 1994
Source: 60 FR 65415, Dec. 19, 1995, unless otherwise noted.
[[Page 96]]
Sec. 60.30b Scope and delegation of authority.
(a) This subpart contains emission guidelines and compliance
schedules for the control of certain designated pollutants from certain
municipal waste combustors in accordance with section 111(d) and section
129 of the Clean Air Act and subpart B of this part. The provisions in
these emission guidelines apply instead of the provisions of Sec.
60.24(f) of subpart B of this part.
(b) The following authorities are retained by EPA:
(1) Approval of exemption claims in Sec. 60.32b(b)(1), (d), (e),
(f)(1), (i)(1);
(2) Approval of a nitrogen oxides trading program under Sec.
60.33b(d)(2);
(3) Approval of major alternatives to test methods;
(4) Approval of major alternatives to monitoring;
(5) Waiver of recordkeeping; and
(6) Performance test and data reduction waivers under Sec. 608(b).
[71 FR 27332, May 10, 2006]
Sec. 60.31b Definitions.
Terms used but not defined in this subpart have the meaning given
them in the Clean Air Act and subparts A, B, and Eb of this part.
EPA means the Administrator of the U.S. EPA or employee of the U.S.
EPA who is delegated to perform the specified task.
Municipal waste combustor plant means one or more designated
facilities (as defined in Sec. 60.32b) at the same location.
Semi-suspension refuse-derived fuel-fired combustor/wet refuse-
derived fuel process conversion means a combustion unit that was
converted from a wet refuse-derived fuel process to a dry refuse-derived
fuel process, and because of constraints in the design of the system,
includes a low furnace height (less than 60 feet between the grate and
the roof) and a high waste capacity-to-undergrate air zone ratio
(greater than 300 tons of waste per day (tpd) fuel per each undergrate
air zone).
Spreader stoker fixed floor refuse-derived fuel-fired combustor/100
percent coal capable means a spreader stoker type combustor with a fixed
floor grate design that typically fires 100 percent refuse-derived fuel
but is equipped to burn 100 percent coal instead of refuse-derived fuel
to fulfill 100 percent steam or energy demand.
[60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45119, 45125, Aug. 25,
1997; 71 FR 27332, May 10, 2006]
Sec. 60.32b Designated facilities.
(a) The designated facility to which these guidelines apply is each
municipal waste combustor unit with a combustion capacity greater than
250 tons per day of municipal solid waste for which construction was
commenced on or before September 20, 1994.
(b) Any municipal waste combustion unit that is capable of
combusting more than 250 tons per day of municipal solid waste and is
subject to a federally enforceable permit limiting the maximum amount of
municipal solid waste that may be combusted in the unit to less than or
equal to 11 tons per day is not subject to this subpart if the owner or
operator:
(1) Notifies EPA of an exemption claim,
(2) Provides a copy of the federally enforceable permit that limits
the firing of municipal solid waste to less than 11 tons per day, and
(3) Keeps records of the amount of municipal solid waste fired on a
daily basis.
(c) Physical or operational changes made to an existing municipal
waste combustor unit primarily for the purpose of complying with
emission guidelines under this subpart are not considered in determining
whether the unit is a modified or reconstructed facility under subpart
Ea or subpart Eb of this part.
(d) A qualifying small power production facility, as defined in
section 3(17)(C) of the Federal Power Act (16 U.S.C. 796(17)(C)), that
burns homogeneous waste (such as automotive tires or used oil, but not
including refuse-derived fuel) for the production of electric energy is
not subject to this subpart if the owner or operator of the facility
notifies EPA of this exemption and provides data documenting that the
facility qualifies for this exemption.
[[Page 97]]
(e) A qualifying cogeneration facility, as defined in section
3(18)(B) of the Federal Power Act (16 U.S.C. 796(18)(B)), that burns
homogeneous waste (such as automotive tires or used oil, but not
including refuse-derived fuel) for the production of electric energy and
steam or forms of useful energy (such as heat) that are used for
industrial, commercial, heating, or cooling purposes, is not subject to
this subpart if the owner or operator of the facility notifies EPA of
this exemption and provides data documenting that the facility qualifies
for this exemption.
(f) Any unit combusting a single-item waste stream of tires is not
subject to this subpart if the owner or operator of the unit:
(1) Notifies EPA of an exemption claim, and
(2) Provides data documenting that the unit qualifies for this
exemption.
(g) Any unit required to have a permit under section 3005 of the
Solid Waste Disposal Act is not subject to this subpart.
(h) Any materials recovery facility (including primary or secondary
smelters) that combusts waste for the primary purpose of recovering
metals is not subject to this subpart.
(i) Any cofired combustor, as defined under Sec. 60.51b of subpart
Eb of this part, that meets the capacity specifications in paragraph (a)
of this section is not subject to this subpart if the owner or operator
of the cofired combustor:
(1) Notifies EPA of an exemption claim,
(2) Provides a copy of the federally enforceable permit (specified
in the definition of cofired combustor in this section), and
(3) Keeps a record on a calendar quarter basis of the weight of
municipal solid waste combusted at the cofired combustor and the weight
of all other fuels combusted at the cofired combustor.
(j) Air curtain incinerators, as defined under Sec. 60.51b of
subpart Eb of this part, that meet the capacity specifications in
paragraph (a) of this section, and that combust a fuel stream composed
of 100 percent yard waste are exempt from all provisions of this subpart
except the opacity standard under Sec. 60.37b, the testing procedures
under Sec. 60.38b, and the reporting and recordkeeping provisions under
Sec. 60.39b.
(k) Air curtain incinerators that meet the capacity specifications
in paragraph (a) of this section and that combust municipal solid waste
other than yard waste are subject to all provisions of this subpart.
(l) Pyrolysis/combustion units that are an integrated part of a
plastics/rubber recycling unit (as defined in Sec. 60.51b) are not
subject to this subpart if the owner or operator of the plastics/rubber
recycling unit keeps records of the weight of plastics, rubber, and/or
rubber tires processed on a calendar quarter basis; the weight of
chemical plant feedstocks and petroleum refinery feedstocks produced and
marketed on a calendar quarter basis; and the name and address of the
purchaser of the feedstocks. The combustion of gasoline, diesel fuel,
jet fuel, fuel oils, residual oil, refinery gas, petroleum coke,
liquified petroleum gas, propane, or butane produced by chemical plants
or petroleum refineries that use feedstocks produced by plastics/rubber
recycling units are not subject to this subpart.
(m) Cement kilns firing municipal solid waste are not subject to
this subpart.
(n) Any affected facility meeting the applicability requirements
under this section is not subject to subpart E of this part.
[60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45119, 45125, Aug. 25,
1997; 71 FR 27332, May 10, 2006]
Sec. 60.33b Emission guidelines for municipal waste combustor metals,
acid gases, organics, and nitrogen oxides.
(a) The emission limits for municipal waste combustor metals are
specified in paragraphs (a)(1) through (a)(3) of this section.
(1) For approval, a State plan shall include emission limits for
particulate matter and opacity at least as protective as the emission
limits for particulate matter and opacity specified in paragraphs
(a)(1)(i) through (a)(1)(iii) of this section.
(i) Before April 28, 2009, the emission limit for particulate matter
contained
[[Page 98]]
in the gases discharged to the atmosphere from a designated facility is
27 milligrams per dry standard cubic meter, corrected to 7 percent
oxygen. On and after April 28, 2009, the emission limit for particulate
matter contained in the gases discharged to the atmosphere from a
designated facility is 25 milligrams per dry standard cubic meter,
corrected to 7 percent oxygen.
(ii) [Reserved]
(iii) The emission limit for opacity exhibited by the gases
discharged to the atmosphere from a designated facility is 10 percent
(6-minute average).
(2) For approval, a State plan shall include emission limits for
cadmium at least as protective as the emission limits for cadmium
specified in paragraphs (a)(2)(i) through (a)(2)(iv) of this section.
(i) Before April 28, 2009, the emission limit for cadmium contained
in the gases discharged to the atmosphere from a designated facility is
40 micrograms per dry standard cubic meter, corrected to 7 percent
oxygen. On and after April 28, 2009, the emission limit for cadmium
contained in the gases discharged to the atmosphere from a designated
facility is 35 micrograms per dry standard cubic meter, corrected to 7
percent oxygen.
(ii) [Reserved]
(3) For approval, a State plan shall include emission limits for
mercury at least as protective as the emission limits specified in this
paragraph. Before April 28, 2009, the emission limit for mercury
contained in the gases discharged to the atmosphere from a designated
facility is 80 micrograms per dry standard cubic meter or 15 percent of
the potential mercury emission concentration (85-percent reduction by
weight), corrected to 7 percent oxygen, whichever is less stringent. On
and after April 28, 2009, the emission limit for mercury contained in
the gases discharged to the atmosphere from a designated facility is 50
micrograms per dry standard cubic meter or 15 percent of the potential
mercury emission concentration (85-percent reduction by weight),
corrected to 7 percent oxygen, whichever is less stringent.
(4) For approval, a State plan shall include an emission limit for
lead at least as protective as the emission limit for lead specified in
this paragraph. Before April 28, 2009, the emission limit for lead
contained in the gases discharged to the atmosphere from a designated
facility is 440 micrograms per dry standard cubic meter, corrected to 7
percent oxygen. On and after April 28, 2009, the emission limit for lead
contained in the gases discharged to the atmosphere from a designated
facility is 400 micrograms per dry standard cubic meter, corrected to 7
percent oxygen.
(b) The emission limits for municipal waste combustor acid gases,
expressed as sulfur dioxide and hydrogen chloride, are specified in
paragraphs (b)(1) and (b)(2) of this section.
(1) For approval, a State plan shall include emission limits for
sulfur dioxide at least as protective as the emission limits for sulfur
dioxide specified in paragraphs (b)(1)(i) and (b)(1)(ii) of this
section.
(i) The emission limit for sulfur dioxide contained in the gases
discharged to the atmosphere from a designated facility is 31 parts per
million by volume or 25 percent of the potential sulfur dioxide emission
concentration (75-percent reduction by weight or volume), corrected to 7
percent oxygen (dry basis), whichever is less stringent. Compliance with
this emission limit is based on a 24-hour daily geometric mean.
(ii) [Reserved]
(2) For approval, a State plan shall include emission limits for
hydrogen chloride at least as protective as the emission limits for
hydrogen chloride specified in paragraphs (b)(2)(i) and (b)(2)(ii) of
this section.
(i) The emission limit for hydrogen chloride contained in the gases
discharged to the atmosphere from a designated facility is 31 parts per
million by volume or 5 percent of the potential hydrogen chloride
emission concentration (95-percent reduction by weight or volume),
corrected to 7 percent oxygen (dry basis), whichever is less stringent.
(ii) [Reserved]
(3) For approval, a State plan shall be submitted by August 25, 1998
and shall include emission limits for sulfur dioxide and hydrogen
chloride at least as
[[Page 99]]
protective as the emission limits specified in paragraphs (b)(3)(i) and
(b)(3)(ii) of this section.
(i) The emission limit for sulfur dioxide contained in the gases
discharged to the atmosphere from a designated facility is 29 parts per
million by volume or 25 percent of the potential sulfur dioxide emission
concentration (75-percent reduction by weight or volume), corrected to 7
percent oxygen (dry basis), whichever is less stringent. Compliance with
this emission limit is based on a 24-hour daily geometric mean.
(ii) The emission limit for hydrogen chloride contained in the gases
discharged to the atmosphere from a designated facility is 29 parts per
million by volume or 5 percent of the potential hydrogen chloride
emission concentration (95-percent reduction by weight or volume),
corrected to 7 percent oxygen (dry basis), whichever is less stringent.
(c) The emission limits for municipal waste combustor organics,
expressed as total mass dioxin/furan, are specified in paragraphs (c)(1)
and (c)(2) of this section.
(1) For approval, a State plan shall include an emission limit for
dioxin/furan contained in the gases discharged to the atmosphere from a
designated facility at least as protective as the emission limit for
dioxin/furan specified in paragraphs (c)(1)(i), (c)(1)(ii), and
(c)(1)(iii) of this section, as applicable.
(i) Before April 28, 2009, the emission limit for designated
facilities that employ an electrostatic precipitator-based emission
control system is 60 nanograms per dry standard cubic meter (total
mass), corrected to 7 percent oxygen.
(ii) On and after April 28, 2009, the emission limit for designated
facilities that employ an electrostatic precipitator-based emission
control system is 35 nanograms per dry standard cubic meter (total
mass), corrected to 7 percent oxygen.
(iii) The emission limit for designated facilities that do not
employ an electrostatic precipitator-based emission control system is 30
nanograms per dry standard cubic meter (total mass), corrected to 7
percent oxygen.
(d) For approval, a State plan shall include emission limits for
nitrogen oxides at least as protective as the emission limits listed in
table 1 of this subpart for designated facilities. table 1 provides
emission limits for the nitrogen oxides concentration level for each
type of designated facility.
(1) A State plan may allow nitrogen oxides emissions averaging as
specified in paragraphs (d)(1)(i) through (d)(1)(v) of this section.
(i) The owner or operator of a municipal waste combustor plant may
elect to implement a nitrogen oxides emissions averaging plan for the
designated facilities that are located at that plant and that are
subject to subpart Cb, except as specified in paragraphs (d)(1)(i)(A)
and (d)(1)(i)(B) of this section.
(A) Municipal waste combustor units subject to subpart Ea or Eb
cannot be included in the emissions averaging plan.
(B) Mass burn refractory municipal waste combustor units and other
municipal waste combustor technologies not listed in paragraph
(d)(1)(iii) of this section may not be included in the emissions
averaging plan.
(ii) The designated facilities included in the nitrogen oxides
emissions averaging plan must be identified in the initial compliance
report specified in Sec. 60.59b(f) or in the annual report specified in
Sec. 60.59b(g), as applicable, prior to implementing the averaging
plan. The designated facilities being included in the averaging plan may
be redesignated each calendar year. Partial year redesignation is
allowable with State approval.
(iii) To implement the emissions averaging plan, the average daily
(24-hour) nitrogen oxides emission concentration level for gases
discharged from the designated facilities being included in the
emissions averaging plan must be no greater than the levels specified in
table 2 of this subpart. table 2 provides emission limits for the
nitrogen oxides concentration level for each type of designated
facility.
(iv) Under the emissions averaging plan, the average daily nitrogen
oxides emissions specified in paragraph (d)(1)(iii) of this section
shall be calculated using equation (1). Designated
[[Page 100]]
facilities that are offline shall not be included in calculating the
average daily nitrogen oxides emission level.
[GRAPHIC] [TIFF OMITTED] TR19DE95.000
where:
NOX 24-hr = 24-hr daily average nitrogen oxides emission
concentration level for the emissions averaging plan (parts
per million by volume corrected to 7 percent oxygen).
NOX i-hr = 24-hr daily average nitrogen oxides emission
concentration level for designated facility i (parts per
million by volume, corrected to 7 percent oxygen), calculated
according to the procedures in Sec. 60.58b(h) of this
subpart.
Si = maximum demonstrated municipal waste combustor unit load
for designated facility i (pounds per hour steam or feedwater
flow as determined in the most recent dioxin/furan performance
test).
h = total number of designated facilities being included in the daily
emissions average.
(v) For any day in which any designated facility included in the
emissions averaging plan is offline, the owner or operator of the
municipal waste combustor plant must demonstrate compliance according to
either paragraph (d)(1)(v)(A) of this section or both paragraphs
(d)(1)(v)(B) and (d)(1)(v)(C) of this section.
(A) Compliance with the applicable limits specified in table 2 of
this subpart shall be demonstrated using the averaging procedure
specified in paragraph (d)(1)(iv) of this section for the designated
facilities that are online.
(B) For each of the designated facilities included in the emissions
averaging plan, the nitrogen oxides emissions on a daily average basis
shall be calculated and shall be equal to or less than the maximum daily
nitrogen oxides emission level achieved by that designated facility on
any of the days during which the emissions averaging plan was achieved
with all designated facilities online during the most recent calendar
quarter. The requirements of this paragraph do not apply during the
first quarter of operation under the emissions averaging plan.
(C) The average nitrogen oxides emissions (kilograms per day)
calculated according to paragraph (d)(1)(v)(C)(2) of this section shall
not exceed the average nitrogen oxides emissions (kilograms per day)
calculated according to paragraph (d)(1)(v)(C)(1) of this section.
(1) For all days during which the emissions averaging plan was
implemented and achieved and during which all designated facilities were
online, the average nitrogen oxides emissions shall be calculated. The
average nitrogen oxides emissions (kilograms per day) shall be
calculated on a calendar year basis according to paragraphs
(d)(1)(v)(C)(1)(i) through (d)(1)(v)(C)(1)(iii) of this section.
(i) For each designated facility included in the emissions averaging
plan, the daily amount of nitrogen oxides emitted (kilograms per day)
shall be calculated based on the hourly nitrogen oxides data required
under Sec. 60.38b(a) and specified under Sec. 60.58b(h)(5) of subpart
Eb of this part, the flue gas flow rate determined using table 19-1 of
EPA Reference Method 19 or a State-approved method, and the hourly
average steam or feedwater flow rate.
(ii) The daily total nitrogen oxides emissions shall be calculated
as the sum of the daily nitrogen oxides emissions from each designated
facility calculated under paragraph (d)(1)(v)(C)(1)(i) of this section.
(iii) The average nitrogen oxides emissions (kilograms per day) on a
calendar year basis shall be calculated as the sum of all daily total
nitrogen oxides emissions calculated under paragraph (d)(1)(v)(C)(1)(ii)
of this section divided by the number of calendar days for which a daily
total was calculated.
(2) For all days during which one or more of the designated
facilities under the emissions averaging plan was offline, the average
nitrogen oxides emissions shall be calculated. The average nitrogen
oxides emissions (kilograms per day) shall be calculated on a calendar
year basis according to paragraphs (d)(1)(v)(C)(2)(i) through
(d)(1)(v)(C)(2)(iii) of this section.
(i) For each designated facility included in the emissions averaging
plan, the daily amount of nitrogen oxides emitted (kilograms per day)
shall be
[[Page 101]]
calculated based on the hourly nitrogen oxides data required under Sec.
60.38b(a) and specified under Sec. 60.58b(h)(5) of subpart Eb of this
part, the flue gas flow rate determined using table 19-1 of EPA
Reference Method 19 or a State-approved method, and the hourly average
steam or feedwater flow rate.
(ii) The daily total nitrogen oxides emissions shall be calculated
as the sum of the daily nitrogen oxides emissions from each designated
facility calculated under paragraph (d)(1)(v)(C)(2)(i) of this section.
(iii) The average nitrogen oxides emissions (kilograms per day) on a
calendar year basis shall be calculated as the sum of all daily total
nitrogen oxides emissions calculated under paragraph (d)(1)(v)(C)(2)(ii)
of this section divided by the number of calendar days for which a daily
total was calculated.
(2) A State plan may establish a program to allow owners or
operators of municipal waste combustor plants to engage in trading of
nitrogen oxides emission credits. A trading program must be approved by
EPA before implementation.
(3) For approval, a State plan shall include emission limits for
nitrogen oxides from fluidized bed combustors at least as protective as
the emission limits listed in paragraphs (d)(3)(i) and (d)(3)(ii) of
this section.
(i) The emission limit for nitrogen oxides contained in the gases
discharged to the atmosphere from a designated facility that is a
fluidized bed combustor is 180 parts per million by volume, corrected to
7 percent oxygen.
(ii) If a State plan allows nitrogen oxides emissions averaging as
specified in paragraphs (d)(1)(i) through (d)(1)(v) of this section, the
emission limit for nitrogen oxides contained in the gases discharged to
the atmosphere from a designated facility that is a fluidized bed
combustor is 165 parts per million by volume, corrected to 7 percent
oxygen.
[60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45119, 45125, Aug. 25,
1997; 71 FR 27333, May 10, 2006]
Sec. 60.34b Emission guidelines for municipal waste combustor operating
practices.
(a) For approval, a State plan shall include emission limits for
carbon monoxide at least as protective as the emission limits for carbon
monoxide listed in table 3 of this subpart. table 3 provides emission
limits for the carbon monoxide concentration level for each type of
designated facility.
(b) For approval, a State plan shall include requirements for
municipal waste combustor operating practices at least as protective as
those requirements listed in Sec. 60.53b(b) and (c) of subpart Eb of
this part.
[60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45120, 45125, Aug. 25,
1997; 69 FR 42121, July 14, 2004; 71 FR 27333, May 10, 2006]
Sec. 60.35b Emission guidelines for municipal waste combustor operator
training and certification.
For approval, a State plan shall include requirements for designated
facilities for municipal waste combustor operator training and
certification at least as protective as those requirements listed in
Sec. 60.54b of subpart Eb of this part. The State plan shall require
compliance with these requirements according to the schedule specified
in Sec. 60.39b(c)(4).
[60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45120, Aug. 25, 1997]
Sec. 60.36b Emission guidelines for municipal waste combustor fugitive
ash emissions.
For approval, a State plan shall include requirements for municipal
waste combustor fugitive ash emissions at least as protective as those
requirements listed in Sec. 60.55b of subpart Eb of this part.
Sec. 60.37b Emission guidelines for air curtain incinerators.
For approval, a State plan shall include emission limits for opacity
for air curtain incinerators at least as protective as those listed in
Sec. 60.56b of subpart Eb of this part.
[[Page 102]]
Sec. 60.38b Compliance and performance testing.
(a) For approval, a State plan shall include the performance testing
methods listed in Sec. 60.58b of subpart Eb of this part, as
applicable, except as provided for under Sec. 60.24(b)(2) of subpart B
of this part and paragraphs (b) and (c) of this section.
(b) For approval, a State plan shall include for designated
facilities the alternative performance testing schedule for dioxins/
furans specified in Sec. 60.58b(g)(5)(iii) of subpart Eb of this part,
as applicable, for those designated facilities that achieve a dioxin/
furan emission level less than or equal to 15 nanograms per dry standard
cubic meter total mass, corrected to 7 percent oxygen.
(c) [Reserved]
[60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45120, Aug. 25, 1997]
Sec. 60.39b Reporting and recordkeeping guidelines and compliance
schedules.
(a) For approval, a State plan shall include the reporting and
recordkeeping provisions listed in Sec. 60.59b of subpart Eb of this
part, as applicable, except for the siting requirements under Sec.
60.59b(a), (b)(5), and (d)(11) of subpart Eb of this part.
(b) Except as provided in paragraph (e) of this section, not later
than December 19, 1996, each State in which a designated facility is
located shall submit to EPA a plan to implement and enforce all
provisions of this subpart except the revised April 28, 2009 emission
limits in Sec. 60.33b(a), (c), and (d). Not later than April 28, 2007,
each State in which a designated facility is located shall submit to EPA
a plan to implement and enforce all provisions of this subpart, as
amended on May 10, 2006. The submittal schedule specified in this
paragraph is in accordance with section 129(b)(2) of the Clean Air Act
and applies instead of the schedule provided in Sec. 60.23(a)(1) of
subpart B of this part.
(c) For approval, a State plan that is submitted prior to May 10,
2006 shall include the compliance schedules specified in paragraphs
(c)(1) through (c)(5) of this section.
(1) A State plan shall allow designated facilities to comply with
all requirements of a State plan (or close) within 1 year after approval
of the State plan, except as provided by paragraph (c)(1)(i) and
(c)(1)(ii) of this section.
(i) A State plan that allows designated facilities more than 1 year
but less than 3 years following the date of issuance of a revised
construction or operation permit, if a permit modification is required,
or more than 1 year but less than 3 years following approval of the
State plan, if a permit modification is not required, shall include
measurable and enforceable incremental steps of progress toward
compliance. Suggested measurable and enforceable activities are
specified in paragraphs (c)(1)(i)(A) through (c)(1)(i)(J) of this
section.
(A) Date for obtaining services of an architectural and engineering
firm regarding the air pollution control device(s);
(B) Date for obtaining design drawings of the air pollution control
device(s);
(C) Date for submittal of permit modifications, if necessary;
(D) Date for submittal of the final control plan to the
Administrator. [Sec. 60.21 (h)(1) of subpart B of this part.];
(E) Date for ordering the air pollution control device(s);
(F) Date for obtaining the major components of the air pollution
control device(s);
(G) Date for initiation of site preparation for installation of the
air pollution control device(s);
(H) Date for initiation of installation of the air pollution control
device(s);
(I) Date for initial startup of the air pollution control device(s);
and
(J) Date for initial performance test(s) of the air pollution
control device(s).
(ii) A State plan that allows designated facilities more than 1 year
but up to 3 years after State plan approval to close shall require a
closure agreement. The closure agreement must include the date of plant
closure.
(2) If the State plan requirements for a designated facility include
a compliance schedule longer than 1 year after
[[Page 103]]
approval of the State plan in accordance with paragraph (c)(1)(i) or
(c)(1)(ii) of this section, the State plan submittal (for approval)
shall include performance test results for dioxin/furan emissions for
each designated facility that has a compliance schedule longer than 1
year following the approval of the State plan, and the performance test
results shall have been conducted during or after 1990. The performance
test shall be conducted according to the procedures in Sec. 60.38b.
(3) [Reserved]
(4) A State plan shall require compliance with the municipal waste
combustor operator training and certification requirements under Sec.
60.35b according to the schedule specified in paragraphs (c)(4)(i)
through (c)(4)(iii) of this section.
(i) [Reserved]
(ii) For designated facilities, the State plan shall require
compliance with the municipal waste combustor operator training and
certification requirements specified under Sec. 60.54b (a) through (c)
of subpart Eb of this part by the date 6 months after the date of
startup or 12 months after State plan approval, whichever is later.
(iii) For designated facilities, the State plan shall require
compliance with the requirements specified in Sec. 60.54b (d), (f), and
(g) of subpart Eb of this part no later than 6 months after startup or
12 months after State plan approval, whichever is later.
(A) The requirement specified in Sec. 60.54b(d) of subpart Eb of
this part does not apply to chief facility operators, shift supervisors,
and control room operators who have obtained full certification from the
American Society of Mechanical Engineers on or before the date of State
plan approval.
(B) The owner or operator of a designated facility may request that
the Administrator waive the requirement specified in Sec. 60.54b(d) of
subpart Eb of this part for chief facility operators, shift supervisors,
and control room operators who have obtained provisional certification
from the American Society of Mechanical Engineers on or before the
initial date of State plan approval.
(C) The initial training requirements specified in Sec.
60.54b(f)(1) of subpart Eb of this part shall be completed no later than
the date specified in paragraph (c)(4)(iii)(C)(1), (c)(4)(iii)(C)(2), or
(c)(4)(iii)(C)(3), of this section whichever is later.
(1) The date 6 months after the date of startup of the affected
facility;
(2) Twelve months after State plan approval; or
(3) The date prior to the day when the person assumes
responsibilities affecting municipal waste combustor unit operation.
(5) A State plan shall require all designated facilities for which
construction, modification, or reconstruction is commenced after June
26, 1987 to comply with the emission limit for mercury specified in
Sec. 60.33b(a)(3) and the emission limit for dioxins/furans specified
in Sec. 60.33b(c)(1) within 1 year following issuance of a revised
construction or operation permit, if a permit modification is required,
or within 1 year following approval of the State plan, whichever is
later.
(d) In the event no plan for implementing the emission guidelines is
approved by EPA, all designated facilities meeting the applicability
requirements under Sec. 60.32b shall be in compliance with all of the
guidelines, except those specified under Sec. 60.33b (a)(4), (b)(3),
and (d)(3), no later than December 19, 2000.
(e) Not later than August 25, 1998, each State in which a designated
facility is operating shall submit to EPA a plan to implement and
enforce all provisions of this subpart specified in Sec. 60.33b(b)(3)
and (d)(3) and the emission limit in paragraph (a)(4) that applies
before April 28, 2009.
(f) In the event no plan for implementing the emission guidelines is
approved by EPA, all designated facilities meeting the applicability
requirements under Sec. 60.32b shall be in compliance with all of the
guidelines, including those specified under Sec. 60.33b (a)(4), (b)(3),
and (d)(3), no later than August 26, 2002.
(g) For approval, a revised State plan submitted not later than
April 28, 2007 in accordance with paragraph (b) of this section, shall
include compliance schedules for meeting the revised April 28, 2009
emission limits in Sec. 60.33b(a), (c), and (d) and the revised testing
provisions in Sec. 60.38b(b).
[[Page 104]]
(1) Compliance with the revised April 28, 2009 emission limits is
required as expeditiously as practicable, but no later than April 28,
2009, except as provided in paragraph (g)(2) of this section.
(2) The owner or operator of an affected facility who is planning an
extensive emission control system upgrade may petition the Administrator
for a longer compliance schedule and must demonstrate to the
satisfaction of the Administrator the need for the additional time. If
approved, the schedule may exceed the schedule in paragraph (g)(1) of
this section, but cannot exceed May 10, 2011.
(h) In the event no plan for implementing the emission guidelines is
approved by EPA, all designated facilities meeting the applicability
requirements under Sec. 60.32b shall be in compliance with all of the
guidelines, including the revised April 28, 2009 emission limits in
Sec. Sec. 60.33b(a), (b), (c), (d), and 60.34b(a), and the revised
testing provisions in Sec. 60.38b(b), no later than May 10, 2011.
[60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45120, 45125, Aug. 25,
1997; 71 FR 27333, May 10, 2006]
Sec. Table 1 to Subpart Cb of Part 60--Nitrogen Oxides Guidelines for
Designated Facilities
------------------------------------------------------------------------
Before April 28, On and after April
2009, nitrogen 28, 2009, nitrogen
Municipal waste combustor oxides emission oxides emission
technology limit (parts per limit (parts per
million by volume) million by volume)
\a\ \a\
------------------------------------------------------------------------
Mass burn waterwall............. 205............... 205.
Mass burn rotary waterwall...... 250............... 210.
Refuse-derived fuel combustor... 250............... 250.
Fluidized bed combustor......... 180............... 180.
Mass burn refractory combustors. No limit.......... No limit.
------------------------------------------------------------------------
\a\ Corrected to 7 percent oxygen, dry basis.
[71 FR 27334, May 10, 2006]
Sec. Table 2 to Subpart Cb of Part 60--Nitrogen Oxides Limits for
Existing Designated Facilities Included in an Emissions Averaging Plan
at a Municipal Waste Combustor Plant \b\
------------------------------------------------------------------------
Before April 28, On and after April
2009, nitrogen 28, 2009, nitrogen
Municipal waste combustor oxides emission oxides emission
technology limit (parts per limit (parts per
million by volume) million by volume)
\b\ \a\
------------------------------------------------------------------------
Mass burn waterwall............. 185............... 185
Mass burn rotary waterwall...... 220............... 190
Refuse-derived fuel combustor... 230............... 230
Fluidized bed combustor......... 165............... 165
------------------------------------------------------------------------
\a\ Mass burn refractory municipal waste combustors and other MWC
technologies not listed above may not be included in an emissions
averaging plan.
\b\ Corrected to 7 percent oxygen, dry basis.
[71 FR 27334, May 10, 2006]
Sec. Table 3 to Subpart Cb of Part 60--Municipal Waste Combustor
Operating Guidelines
------------------------------------------------------------------------
Carbon monoxide
emissions levels
Municipal waste combustor (parts per Averaging time
technology million by (hrs) \b\
volume) \a\
------------------------------------------------------------------------
Mass burn waterwall............... 100 4
Mass burn refractory.............. 100 4
Mass burn rotary refractory....... 100 24
Mass burn rotary waterwall........ 250 24
Modular starved air............... 50 4
Modular excess air................ 50 4
Refuse-derived fuel stoker........ 200 24
Fluidized bed, mixed fuel (wood/ 200 \c\ 24
refuse-derived fuel).............
Bubbling fluidized bed combustor.. 100 4
Circulating fluidized bed 100 4
combustor........................
[[Page 105]]
Pulverized coal/refuse-derived 150 4
fuel mixed fuel-fired combustor..
Spreader stoker coal/refuse- 200 24
derived fuel mixed fuel-fired
combustor........................
Semi-suspension refuse-derived 250 \c\ 24
fuel-fired combustor/wet refuse-
derived fuel process conversion..
Spreader stoker fixed floor refuse- 250 \c\ 24
derived fuel-fired combustor/100
percent coal capable.............
------------------------------------------------------------------------
\a\ Measured at the combustor outlet in conjunction with a measurement
of oxygen concentration, corrected to 7 percent oxygen, dry basis.
Calculated as an arithmetic average.
\b\ Averaging times are 4-hour or 24-hour block averages.
\c\ 24-hour block average, geometric mean.
[71 FR 27334, May 10, 2006]
Subpart Cc_Emission Guidelines and Compliance Times for Municipal Solid
Waste Landfills
Source: 61 FR 9919, Mar. 12, 1996, unless otherwise noted.
Sec. 60.30c Scope.
This subpart contains emission guidelines and compliance times for
the control of certain designated pollutants from certain designated
municipal solid waste landfills in accordance with section 111(d) of the
Act and subpart B.
Sec. 60.31c Definitions.
Terms used but not defined in this subpart have the meaning given
them in the Act and in subparts A, B, and WWW of this part.
Municipal solid waste landfill or MSW landfill means an entire
disposal facility in a contiguous geographical space where household
waste is placed in or on land. An MSW landfill may also receive other
types of RCRA Subtitle D wastes such as commercial solid waste,
nonhazardous sludge, conditionally exempt small quantity generator
waste, and industrial solid waste. Portions of an MSW landfill may be
separated by access roads. An MSW landfill may be publicly or privately
owned. An MSW landfill may be a new MSW landfill, an existing MSW
landfill or a lateral expansion.
Sec. 60.32c Designated facilities.
(a) The designated facility to which the guidelines apply is each
existing MSW landfill for which construction, reconstruction or
modification was commenced before May 30, 1991.
(b) Physical or operational changes made to an existing MSW landfill
solely to comply with an emission guideline are not considered a
modification or reconstruction and would not subject an existing MSW
landfill to the requirements of subpart WWW [see Sec. 60.750 of subpart
WWW].
(c) For purposes of obtaining an operating permit under title V of
the Act, the owner or operator of a MSW landfill subject to this subpart
with a design capacity less than 2.5 million megagrams or 2.5 million
cubic meters is not subject to the requirement to obtain an operating
permit for the landfill under part 70 or 71 of this chapter, unless the
landfill is otherwise subject to either part 70 or 71. For purposes of
submitting a timely application for an operating permit under part 70 or
71, the owner or operator of a MSW landfill subject to this subpart with
a design capacity greater than or equal to 2.5 million megagrams and 2.5
million cubic meters on the effective date of EPA approval of the
State's program under section 111(d) of the Act, and not otherwise
subject to either part 70 or 71, becomes subject to the requirements of
Sec. Sec. 70.5(a)(1)(i) or 71.5(a)(1)(i) of this chapter 90 days after
the effective date of such 111(d) program approval, even if the design
capacity report is submitted earlier.
(d) When a MSW landfill subject to this subpart is closed, the owner
or operator is no longer subject to the requirement to maintain an
operating permit under part 70 or 71 of this chapter for the landfill if
the landfill is not otherwise subject to the requirements
[[Page 106]]
of either part 70 or 71 and if either of the following conditions are
met.
(1) The landfill was never subject to the requirement for a control
system under Sec. 60.33c(c) of this subpart; or
(2) The owner or operator meets the conditions for control system
removal specified in Sec. 60.752(b)(2)(v) of subpart WWW.
[61 FR 9919, Mar. 12, 1996, as amended at 63 FR 32750, June 16, 1998]
Sec. 60.33c Emission guidelines for municipal solid waste landfill
emissions.
(a) For approval, a State plan shall include control of MSW landfill
emissions at each MSW landfill meeting the following three conditions:
(1) The landfill has accepted waste at any time since November 8,
1987, or has additional design capacity available for future waste
deposition;
(2) The landfill has a design capacity greater than or equal to 2.5
million megagrams and 2.5 million cubic meters. The landfill may
calculate design capacity in either megagrams or cubic meters for
comparison with the exemption values. Any density conversions shall be
documented and submitted with the design capacity report; and
(3) The landfill has a nonmethane organic compound emission rate of
50 megagrams per year or more.
(b) For approval, a State plan shall include the installation of a
collection and control system meeting the conditions provided in Sec.
60.752(b)(2)(ii) of this part at each MSW landfill meeting the
conditions in paragraph (a) of this section. The State plan shall
include a process for State review and approval of the site-specific
design plans for the gas collection and control system(s).
(c) For approval, a State plan shall include provisions for the
control of collected MSW landfill emissions through the use of control
devices meeting the requirements of paragraph (c)(1), (2), or (3) of
this section, except as provided in Sec. 60.24.
(1) An open flare designed and operated in accordance with the
parameters established in Sec. 60.18; or
(2) A control system designed and operated to reduce NMOC by 98
weight percent; or
(3) An enclosed combustor designed and operated to reduce the outlet
NMOC concentration to 20 parts per million as hexane by volume, dry
basis at 3 percent oxygen, or less.
(d) For approval, a State plan shall require each owner or operator
of an MSW landfill having a design capacity less than 2.5 million
megagrams by mass or 2.5 million cubic meters by volume to submit an
initial design capacity report to the Administrator as provided in Sec.
60.757(a)(2) of subpart WWW by the date specified in Sec. 60.35c of
this subpart. The landfill may calculate design capacity in either
megagrams or cubic meters for comparison with the exemption values. Any
density conversions shall be documented and submitted with the report.
Submittal of the initial design capacity report shall fulfill the
requirements of this subpart except as provided in paragraph (d)(1) and
(d)(2) of this section.
(1) The owner or operator shall submit an amended design capacity
report as provided in Sec. 60.757(a)(3) of subpart WWW. [Guidance: Note
that if the design capacity increase is the result of a modification, as
defined in Sec. 60.751 of subpart WWW, that was commenced on or after
May 30, 1991, the landfill will become subject to subpart WWW instead of
this subpart. If the design capacity increase is the result of a change
in operating practices, density, or some other change that is not a
modification, the landfill remains subject to this subpart.]
(2) When an increase in the maximum design capacity of a landfill
with an initial design capacity less than 2.5 million megagrams or 2.5
million cubic meters results in a revised maximum design capacity equal
to or greater than 2.5 million megagrams and 2.5 million cubic meters,
the owner or operator shall comply with paragraph (e) of this section.
(e) For approval, a State plan shall require each owner or operator
of an MSW landfill having a design capacity equal to or greater than 2.5
million megagrams and 2.5 million cubic meters to either install a
collection and control system as provided in paragraph (b) of this
section and Sec. 60.752(b)(2) of subpart WWW or calculate an initial
NMOC emission rate
[[Page 107]]
for the landfill using the procedures specified in Sec. 60.34c of this
subpart and Sec. 60.754 of subpart WWW. The NMOC emission rate shall be
recalculated annually, except as provided in Sec. 60.757(b)(1)(ii) of
subpart WWW.
(1) If the calculated NMOC emission rate is less than 50 megagrams
per year, the owner or operator shall:
(i) Submit an annual emission report, except as provided for in
Sec. 60.757(b)(1)(ii); and
(ii) Recalculate the NMOC emission rate annually using the
procedures specified in Sec. 60.754(a)(1) of subpart WWW until such
time as the calculated NMOC emission rate is equal to or greater than 50
megagrams per year, or the landfill is closed.
(2)(i) If the NMOC emission rate, upon initial calculation or annual
recalculation required in paragraph (e)(1)(ii) of this section, is equal
to or greater than 50 megagrams per year, the owner or operator shall
install a collection and control system as provided in paragraph (b) of
this section and Sec. 60.752(b)(2) of subpart WWW.
(ii) If the landfill is permanently closed, a closure notification
shall be submitted to the Administrator as provided in Sec. 60.35c of
this subpart and Sec. 60.757(d) of subpart WWW.
[61 FR 9919, Mar. 12, 1996, as amended at 63 FR 32750, June 16, 1998; 64
FR 9261, Feb. 24, 1999]
Sec. 60.34c Test methods and procedures.
For approval, a State plan shall include provisions for: the
calculation of the landfill NMOC emission rate listed in Sec. 60.754,
as applicable, to determine whether the landfill meets the condition in
Sec. 60.33c(a)(3); the operational standards in Sec. 60.753; the
compliance provisions in Sec. 60.755; and the monitoring provisions in
Sec. 60.756.
Sec. 60.35c Reporting and recordkeeping guidelines.
For approval, a State plan shall include the recordkeeping and
reporting provisions listed in Sec. Sec. 60.757 and 60.758, as
applicable, except as provided under Sec. 60.24.
(a) For existing MSW landfills subject to this subpart the initial
design capacity report shall be submitted no later than 90 days after
the effective date of EPA approval of the State's plan under section
111(d) of the Act.
(b) For existing MSW landfills covered by this subpart with a design
capacity equal to or greater than 2.5 million megagrams and 2.5 million
cubic meters, the initial NMOC emission rate report shall be submitted
no later than 90 days after the effective date of EPA approval of the
State's plan under section 111(d) of the Act.
[61 FR 9919, Mar. 12, 1996, as amended at 64 FR 9262, Feb. 24, 1999]
Sec. 60.36c Compliance times.
(a) Except as provided for under paragraph (b) of this section,
planning, awarding of contracts, and installation of MSW landfill air
emission collection and control equipment capable of meeting the
emission guidelines established under Sec. 60.33c shall be accomplished
within 30 months after the date the initial NMOC emission rate report
shows NMOC emissions equal or exceed 50 megagrams per year.
(b) For each existing MSW landfill meeting the conditions in Sec.
60.33c(a)(1) and Sec. 60.33c(a)(2) whose NMOC emission rate is less
than 50 megagrams per year on the effective date of the State emission
standard, installation of collection and control systems capable of
meeting emission guidelines in Sec. 60.33c shall be accomplished within
30 months of the date when the condition in Sec. 60.33c(a)(3) is met
(i.e., the date of the first annual nonmethane organic compounds
emission rate which equals or exceeds 50 megagrams per year).
[61 FR 9919, Mar. 12, 1996, as amended at 63 FR 32750, June 16, 1998]
Subpart Cd_Emissions Guidelines and Compliance Times for Sulfuric Acid
Production Units
Source: 60 FR 65414, Dec. 19, 1995, unless otherwise noted.
Sec. 60.30d Designated facilities.
Sulfuric acid production units. The designated facility to which
Sec. Sec. 60.31d and 60.32d apply is each existing ``sulfuric acid
production unit'' as defined in Sec. 60.81(a) of subpart H of this
part.
[[Page 108]]
Sec. 60.31d Emissions guidelines.
Sulfuric acid production units. The emission guideline for
designated facilities is 0.25 grams sulfuric acid mist (as measured by
EPA Reference Method 8 of appendix A of this part) per kilogram (0.5
pounds per ton) of sulfuric acid produced, the production being
expressed as 100 percent sulfuric acid.
Sec. 60.32d Compliance times.
Sulfuric acid production units. Planning, awarding of contracts, and
installation of equipment capable of attaining the level of the emission
guideline established under Sec. 60.31d can be accomplished within 17
months after the effective date of a State emission standard for
sulfuric acid mist.
Subpart Ce_Emission Guidelines and Compliance Times for Hospital/
Medical/Infectious Waste Incinerators
Source: 62 FR 48379, Sept. 15, 1997, unless otherwise noted.
Sec. 60.30e Scope.
This subpart contains emission guidelines and compliance times for
the control of certain designated pollutants from hospital/medical/
infectious waste incinerator(s) (HMIWI) in accordance with sections 111
and 129 of the Clean Air Act and subpart B of this part. The provisions
in these emission guidelines supersede the provisions of Sec. 60.24(f)
of subpart B of this part.
Sec. 60.31e Definitions.
Terms used but not defined in this subpart have the meaning given
them in the Clean Air Act and in subparts A, B, and Ec of this part.
Standard Metropolitan Statistical Area or SMSA means any areas
listed in OMB Bulletin No. 93-17 entitled ``Revised Statistical
Definitions for Metropolitan Areas'' dated June 30, 1993 (incorporated
by reference, see Sec. 60.17).
Sec. 60.32e Designated facilities.
(a) Except as provided in paragraphs (b) through (h) of this
section, the designated facility to which the guidelines apply is each
individual HMIWI:
(1) For which construction was commenced on or before June 20, 1996,
or for which modification was commenced on or before March 16, 1998.
(2) For which construction was commenced after June 20, 1996 but no
later than December 1, 2008, or for which modification is commenced
after March 16, 1998 but no later than April 6, 2010.
(b) A combustor is not subject to this subpart during periods when
only pathological waste, low-level radioactive waste, and/or
chemotherapeutic waste (all defined in Sec. 60.51c) is burned, provided
the owner or operator of the combustor:
(1) Notifies the Administrator of an exemption claim; and
(2) Keeps records on a calendar quarter basis of the periods of time
when only pathological waste, low-level radioactive waste, and/or
chemotherapeutic waste is burned.
(c) Any co-fired combustor (defined in Sec. 60.51c) is not subject
to this subpart if the owner or operator of the co-fired combustor:
(1) Notifies the Administrator of an exemption claim;
(2) Provides an estimate of the relative weight of hospital waste,
medical/infectious waste, and other fuels and/or wastes to be combusted;
and
(3) Keeps records on a calendar quarter basis of the weight of
hospital waste and medical/infectious waste combusted, and the weight of
all other fuels and wastes combusted at the co-fired combustor.
(d) Any combustor required to have a permit under Section 3005 of
the Solid Waste Disposal Act is not subject to this subpart.
(e) Any combustor which meets the applicability requirements under
subpart Cb, Ea, or Eb of this part (standards or guidelines for certain
municipal waste combustors) is not subject to this subpart.
(f) Any pyrolysis unit (defined in Sec. 60.51c) is not subject to
this subpart.
(g) Cement kilns firing hospital waste and/or medical/infectious
waste are not subject to this subpart.
(h) Physical or operational changes made to an existing HMIWI unit
solely for the purpose of complying with emission guidelines under this
subpart
[[Page 109]]
are not considered a modification and do not result in an existing HMIWI
unit becoming subject to the provisions of subpart Ec (see Sec.
60.50c).
(i) Beginning September 15, 2000, or on the effective date of an EPA
approved operating permit program under Clean Air Act title V and the
implementing regulations under 40 CFR part 70 in the State in which the
unit is located, whichever date is later, designated facilities subject
to this subpart shall operate pursuant to a permit issued under the EPA-
approved operating permit program.
(j) The requirements of this subpart as promulgated on September 15,
1997, shall apply to the designated facilities defined in paragraph
(a)(1) of this section until the applicable compliance date of the
requirements of this subpart, as amended on October 6, 2009. Upon the
compliance date of the requirements of this subpart, designated
facilities as defined in paragraph (a)(1) of this section are no longer
subject to the requirements of this subpart, as promulgated on September
15, 1997, but are subject to the requirements of this subpart, as
amended on October 6, 2009.
(k) The authorities listed under Sec. 60.50c(i) shall be retained
by the Administrator and not be transferred to a state.
[60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51402, Oct. 6, 2009; 76
FR 18412, Apr. 4, 2011]
Sec. 60.33e Emissions guidelines.
(a) For approval, a State plan shall include the requirements for
emissions limits at least as protective as the following requirements,
as applicable:
(1) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions guidelines as promulgated on September 15,
1997, the requirements listed in Table 1A of this subpart, except as
provided in paragraph (b) of this section.
(2) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions guidelines as amended on October 6, 2009, the
requirements listed in Table 1B of this subpart, except as provided in
paragraph (b) of this section.
(3) For a designated facility as defined in Sec. 60.32e(a)(2), the
more stringent of the requirements listed in Table 1B of this subpart
and Table 1A of subpart Ec of this part.
(b) For approval, a State plan shall include the requirements for
emissions limits for any small HMIWI constructed on or before June 20,
1996, which is located more than 50 miles from the boundary of the
nearest Standard Metropolitan Statistical Area (defined in Sec. 60.31e)
and which burns less than 2,000 pounds per week of hospital waste and
medical/infectious waste that are at least as protective as the
requirements in paragraphs (b)(1) and (b)(2) of this section, as
applicable. The 2,000 lb/week limitation does not apply during
performance tests.
(1) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions guidelines as promulgated on September 15,
1997, the requirements listed in Table 2A of this subpart.
(2) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions guidelines as amended on October 6, 2009, the
requirements listed in Table 2B of this subpart.
(c) For approval, a State plan shall include the requirements for
stack opacity at least as protective as the following, as applicable:
(1) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions guidelines as promulgated on September 15,
1997, the requirements in Sec. 60.52c(b)(1) of subpart Ec of this part.
(2) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions guidelines as amended on October 6, 2009 and a
designated facility as defined in Sec. 60.32e(a)(2), the requirements
in Sec. 60.52c(b)(2) of subpart Ec of this part.
[74 FR 51403, Oct. 6, 2009]
Sec. 60.34e Operator training and qualification guidelines.
For approval, a State plan shall include the requirements for
operator training and qualification at least as protective as those
requirements listed in Sec. 60.53c of subpart Ec of this part. The
State plan shall require compliance with these requirements according to
the schedule specified in Sec. 60.39e(e).
[[Page 110]]
Sec. 60.35e Waste management guidelines.
For approval, a State plan shall include the requirements for a
waste management plan at least as protective as those requirements
listed in Sec. 60.55c of subpart Ec of this part.
Sec. 60.36e Inspection guidelines.
(a) For approval, a State plan shall require each small HMIWI
subject to the emissions limits under Sec. 60.33e(b) and each HMIWI
subject to the emissions limits under Sec. 60.33e(a)(2) and (a)(3) to
undergo an initial equipment inspection that is at least as protective
as the following within 1 year following approval of the State plan:
(1) At a minimum, an inspection shall include the following:
(i) Inspect all burners, pilot assemblies, and pilot sensing devices
for proper operation; clean pilot flame sensor, as necessary;
(ii) Ensure proper adjustment of primary and secondary chamber
combustion air, and adjust as necessary;
(iii) Inspect hinges and door latches, and lubricate as necessary;
(iv) Inspect dampers, fans, and blowers for proper operation;
(v) Inspect HMIWI door and door gaskets for proper sealing;
(vi) Inspect motors for proper operation;
(vii) Inspect primary chamber refractory lining; clean and repair/
replace lining as necessary;
(viii) Inspect incinerator shell for corrosion and/or hot spots;
(ix) Inspect secondary/tertiary chamber and stack, clean as
necessary;
(x) Inspect mechanical loader, including limit switches, for proper
operation, if applicable;
(xi) Visually inspect waste bed (grates), and repair/seal, as
appropriate;
(xii) For the burn cycle that follows the inspection, document that
the incinerator is operating properly and make any necessary
adjustments;
(xiii) Inspect air pollution control device(s) for proper operation,
if applicable;
(xiv) Inspect waste heat boiler systems to ensure proper operation,
if applicable;
(xv) Inspect bypass stack components;
(xvi) Ensure proper calibration of thermocouples, sorbent feed
systems and any other monitoring equipment; and
(xvii) Generally observe that the equipment is maintained in good
operating condition.
(2) Within 10 operating days following an equipment inspection all
necessary repairs shall be completed unless the owner or operator
obtains written approval from the State agency establishing a date
whereby all necessary repairs of the designated facility shall be
completed.
(b) For approval, a State plan shall require each small HMIWI
subject to the emissions limits under Sec. 60.33e(b) and each HMIWI
subject to the emissions limits under Sec. 60.33e(a)(2) and (a)(3) to
undergo an equipment inspection annually (no more than 12 months
following the previous annual equipment inspection), as outlined in
paragraph (a) of this section.
(c) For approval, a State plan shall require each small HMIWI
subject to the emissions limits under Sec. 60.33e(b)(2) and each HMIWI
subject to the emissions limits under Sec. 60.33e(a)(2) and (a)(3) to
undergo an initial air pollution control device inspection, as
applicable, that is at least as protective as the following within 1
year following approval of the State plan:
(1) At a minimum, an inspection shall include the following:
(i) Inspect air pollution control device(s) for proper operation, if
applicable;
(ii) Ensure proper calibration of thermocouples, sorbent feed
systems, and any other monitoring equipment; and
(iii) Generally observe that the equipment is maintained in good
operating condition.
(2) Within 10 operating days following an air pollution control
device inspection, all necessary repairs shall be completed unless the
owner or operator obtains written approval from the State agency
establishing a date whereby all necessary repairs of the designated
facility shall be completed.
(d) For approval, a State plan shall require each small HMIWI
subject to the emissions limits under Sec. 60.33e(b)(2)
[[Page 111]]
and each HMIWI subject to the emissions limits under Sec. 60.33e(a)(2)
and (a)(3) to undergo an air pollution control device inspection, as
applicable, annually (no more than 12 months following the previous
annual air pollution control device inspection), as outlined in
paragraph (c) of this section.
[60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51403, Oct. 6, 2009]
Sec. 60.37e Compliance, performance testing, and monitoring guidelines.
(a) Except as provided in paragraph (b) of this section, for
approval, a State plan shall include the requirements for compliance and
performance testing listed in Sec. 60.56c of subpart Ec of this part,
with the following exclusions:
(1) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions limits in Sec. 60.33e(a)(1), the test methods
listed in Sec. 60.56c(b)(7) and (8), the fugitive emissions testing
requirements under Sec. 60.56c(b)(14) and (c)(3), the CO CEMS
requirements under Sec. 60.56c(c)(4), and the compliance requirements
for monitoring listed in Sec. 60.56c(c)(5)(ii) through (v), (c)(6),
(c)(7), (e)(6) through (10), (f)(7) through (10), (g)(6) through (10),
and (h).
(2) For a designated facility as defined in Sec. 60.32e(a)(1) and
(a)(2) subject to the emissions limits in Sec. 60.33e(a)(2) and (a)(3),
the annual fugitive emissions testing requirements under Sec.
60.56c(c)(3), the CO CEMS requirements under Sec. 60.56c(c)(4), and the
compliance requirements for monitoring listed in Sec. 60.56c(c)(5)(ii)
through (v), (c)(6), (c)(7), (e)(6) through (10), (f)(7) through (10),
and (g)(6) through (10). Sources subject to the emissions limits under
Sec. 60.33e(a)(2) and (a)(3) may, however, elect to use CO CEMS as
specified under Sec. 60.56c(c)(4) or bag leak detection systems as
specified under Sec. 60.57c(h).
(b) Except as provided in paragraphs (b)(1) and (b)(2) of this
section, for approval, a State plan shall require each small HMIWI
subject to the emissions limits under Sec. 60.33e(b) to meet the
performance testing requirements listed in Sec. 60.56c of subpart Ec of
this part. The 2,000 lb/week limitation under Sec. 60.33e(b) does not
apply during performance tests.
(1) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions limits under Sec. 60.33e(b)(1), the test
methods listed in Sec. 60.56c(b)(7), (8), (12), (13) (Pb and Cd), and
(14), the annual PM, CO, and HCl emissions testing requirements under
Sec. 60.56c(c)(2), the annual fugitive emissions testing requirements
under Sec. 60.56c(c)(3), the CO CEMS requirements under Sec.
60.56c(c)(4), and the compliance requirements for monitoring listed in
Sec. 60.56c(c)(5) through (7), and (d) through (k) do not apply.
(2) For a designated facility as defined in Sec. 60.32e(a)(2)
subject to the emissions limits under Sec. 60.33e(b)(2), the annual
fugitive emissions testing requirements under Sec. 60.56c(c)(3), the CO
CEMS requirements under Sec. 60.56c(c)(4), and the compliance
requirements for monitoring listed in Sec. 60.56c(c)(5)(ii) through
(v), (c)(6), (c)(7), (e)(6) through (10), (f)(7) through (10), and
(g)(6) through (10) do not apply. Sources subject to the emissions
limits under Sec. 60.33e(b)(2) may, however, elect to use CO CEMS as
specified under Sec. 60.56c(c)(4) or bag leak detection systems as
specified under Sec. 60.57c(h).
(c) For approval, a State plan shall require each small HMIWI
subject to the emissions limits under Sec. 60.33e(b) that is not
equipped with an air pollution control device to meet the following
compliance and performance testing requirements:
(1) Establish maximum charge rate and minimum secondary chamber
temperature as site-specific operating parameters during the initial
performance test to determine compliance with applicable emission
limits.
(2) Following the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, ensure that the designated facility does not operate
above the maximum charge rate or below the minimum secondary chamber
temperature measured as 3-hour rolling averages (calculated each hour as
the average of the previous 3 operating hours) at all times. Operating
parameter limits do not apply during performance tests. Operation above
the maximum charge rate or
[[Page 112]]
below the minimum secondary chamber temperature shall constitute a
violation of the established operating parameter(s).
(3) Except as provided in paragraph (c)(4) of this section,
operation of the designated facility above the maximum charge rate and
below the minimum secondary chamber temperature (each measured on a 3-
hour rolling average) simultaneously shall constitute a violation of the
PM, CO, and dioxin/furan emissions limits.
(4) The owner or operator of a designated facility may conduct a
repeat performance test within 30 days of violation of applicable
operating parameter(s) to demonstrate that the designated facility is
not in violation of the applicable emissions limit(s). Repeat
performance tests conducted pursuant to this paragraph must be conducted
under process and control device operating conditions duplicating as
nearly as possible those that indicated a violation under paragraph
(c)(3) of this section.
(d) For approval, a State plan shall include the requirements for
monitoring listed in Sec. 60.57c of subpart Ec of this part for HMIWI
subject to the emissions limits under Sec. 60.33e(a) and (b), except as
provided for under paragraph (e) of this section.
(e) For approval, a State plan shall require small HMIWI subject to
the emissions limits under Sec. 60.33e(b) that are not equipped with an
air pollution control device to meet the following monitoring
requirements:
(1) Install, calibrate (to manufacturers' specifications), maintain,
and operate a device for measuring and recording the temperature of the
secondary chamber on a continuous basis, the output of which shall be
recorded, at a minimum, once every minute throughout operation.
(2) Install, calibrate (to manufacturers' specifications), maintain,
and operate a device which automatically measures and records the date,
time, and weight of each charge fed into the HMIWI.
(3) The owner or operator of a designated facility shall obtain
monitoring data at all times during HMIWI operation except during
periods of monitoring equipment malfunction, calibration, or repair. At
a minimum, valid monitoring data shall be obtained for 75 percent of the
operating hours per day for 90 percent of the operating hours per
calendar quarter that the designated facility is combusting hospital
waste and/or medical/infectious waste.
(f) The owner or operator of a designated facility as defined in
Sec. 60.32e(a)(1) or (a)(2) subject to emissions limits under Sec.
60.33e(a)(2), (a)(3), or (b)(2) may use the results of previous
emissions tests to demonstrate compliance with the emissions limits,
provided that the conditions in paragraphs (f)(1) through (f)(3) of this
section are met:
(1) The designated facility's previous emissions tests must have
been conducted using the applicable procedures and test methods listed
in Sec. 60.56c(b) of subpart Ec of this part. Previous emissions test
results obtained using EPA-accepted voluntary consensus standards are
also acceptable.
(2) The HMIWI at the designated facility shall currently be operated
in a manner (e.g., with charge rate, secondary chamber temperature,
etc.) that would be expected to result in the same or lower emissions
than observed during the previous emissions test(s), and the HMIWI may
not have been modified such that emissions would be expected to exceed
(notwithstanding normal test-to-test variability) the results from
previous emissions test(s).
(3) The previous emissions test(s) must have been conducted in 1996
or later.
[60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51403, Oct. 6, 2009]
Sec. 60.38e Reporting and recordkeeping guidelines.
(a) Except as provided in paragraphs (a)(1) and (a)(2) of this
section, for approval, a State plan shall include the reporting and
recordkeeping requirements listed in Sec. 60.58c(b) through (g) of
subpart Ec of this part.
(1) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to emissions limits under Sec. 60.33e(a)(1) or (b)(1),
excluding Sec. 60.58c(b)(2)(ii) (fugitive emissions), (b)(2)(viii)
(NOX reagent), (b)(2)(xvii) (air pollution control device
[[Page 113]]
inspections), (b)(2)(xviii) (bag leak detection system alarms),
(b)(2)(xix) (CO CEMS data), and (b)(7) (siting documentation).
(2) For a designated facility as defined in Sec. 60.32e(a)(1) or
(a)(2) subject to emissions limits under Sec. 60.33e(a)(2), (a)(3), or
(b)(2), excluding Sec. 60.58c(b)(2)(xviii) (bag leak detection system
alarms), (b)(2)(xix) (CO CEMS data), and (b)(7) (siting documentation).
(b) For approval, a State plan shall require the owner or operator
of each HMIWI subject to the emissions limits under Sec. 60.33e to:
(1) As specified in Sec. 60.36e, maintain records of the annual
equipment inspections that are required for each HMIWI subject to the
emissions limits under Sec. 60.33e(a)(2), (a)(3), and (b), and the
annual air pollution control device inspections that are required for
each HMIWI subject to the emissions limits under Sec. 60.33e(a)(2),
(a)(3), and (b)(2), any required maintenance, and any repairs not
completed within 10 days of an inspection or the timeframe established
by the State regulatory agency; and
(2) Submit an annual report containing information recorded under
paragraph (b)(1) of this section no later than 60 days following the
year in which data were collected. Subsequent reports shall be sent no
later than 12 calendar months following the previous report (once the
unit is subject to permitting requirements under Title V of the Act, the
owner or operator must submit these reports semiannually). The report
shall be signed by the facilities manager.
[60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51404, Oct. 6, 2009]
Sec. 60.39e Compliance times.
(a) Each State in which a designated facility is operating shall
submit to the Administrator a plan to implement and enforce the
emissions guidelines as specified in paragraphs (a)(1) and (a)(2) of
this section:
(1) Not later than September 15, 1998, for the emissions guidelines
as promulgated on September 15, 1997.
(2) Not later than October 6, 2010, for the emissions guidelines as
amended on October 6, 2009.
(b) Except as provided in paragraphs (c) and (d) of this section,
State plans shall provide that designated facilities comply with all
requirements of the State plan on or before the date 1 year after EPA
approval of the State plan, regardless of whether a designated facility
is identified in the State plan inventory required by Sec. 60.25(a) of
subpart B of this part.
(c) State plans that specify measurable and enforceable incremental
steps of progress towards compliance for designated facilities planning
to install the necessary air pollution control equipment may allow
compliance on or before the date 3 years after EPA approval of the State
plan (but not later than September 16, 2002), for the emissions
guidelines as promulgated on September 15, 1997, and on or before the
date 3 years after approval of an amended State plan (but not later than
October 6, 2014), for the emissions guidelines as amended on October 6,
2009). Suggested measurable and enforceable activities to be included in
State plans are:
(1) Date for submitting a petition for site-specific operating
parameters under Sec. 60.56c(j) of subpart Ec of this part.
(2) Date for obtaining services of an architectural and engineering
firm regarding the air pollution control device(s);
(3) Date for obtaining design drawings of the air pollution control
device(s);
(4) Date for ordering the air pollution control device(s);
(5) Date for obtaining the major components of the air pollution
control device(s);
(6) Date for initiation of site preparation for installation of the
air pollution control device(s);
(7) Date for initiation of installation of the air pollution control
device(s);
(8) Date for initial startup of the air pollution control device(s);
and
(9) Date for initial compliance test(s) of the air pollution control
device(s).
(d) State plans that include provisions allowing designated
facilities to petition the State for extensions beyond the compliance
times required in paragraph (b) of this section shall:
[[Page 114]]
(1) Require that the designated facility requesting an extension
submit the following information in time to allow the State adequate
time to grant or deny the extension within 1 year after EPA approval of
the State plan:
(i) Documentation of the analyses undertaken to support the need for
an extension, including an explanation of why up to 3 years after EPA
approval of the State plan is sufficient time to comply with the State
plan while 1 year after EPA approval of the State plan is not
sufficient. The documentation shall also include an evaluation of the
option to transport the waste offsite to a commercial medical waste
treatment and disposal facility on a temporary or permanent basis; and
(ii) Documentation of measurable and enforceable incremental steps
of progress to be taken towards compliance with the emission guidelines.
(2) Include procedures for granting or denying the extension; and
(3) If an extension is granted, require expeditious compliance with
the emissions guidelines on or before the date 3 years after EPA
approval of the state plan (but not later than September 16, 2002), for
the emissions guidelines as promulgated on September 15, 1997, and on or
before the date 3 years after EPA approval of an amended state plan (but
not later than October 6, 2014), for the emissions guidelines as amended
on October 6, 2009.
(e) For approval, a State plan shall require compliance with Sec.
60.34e--Operator training and qualification guidelines and Sec.
60.36e--Inspection guidelines by the date 1 year after EPA approval of a
State plan.
(f) The Administrator shall develop, implement, and enforce a plan
for existing HMIWI located in any State that has not submitted an
approvable plan within 2 years after September 15, 1997, for the
emissions guidelines as promulgated on September 15, 1997, and within 2
years after October 6, 2009 for the emissions guidelines as amended on
October 6, 2009. Such plans shall ensure that each designated facility
is in compliance with the provisions of this subpart no later than 5
years after September 15, 1997, for the emissions guidelines as
promulgated on September 15, 1997, and no later than 5 years after
October 6, 2009 for the emissions guidelines as amended on October 6,
2009.
[60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51404, Oct. 6, 2009; 76
FR 18412, Apr. 4, 2011]
Sec. Table 1A to Subpart Ce of Part 60--Emissions Limits for Small,
Medium, and Large HMIWI at Designated Facilities as Defined in Sec.
60.32e(a)(1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions limits
--------------------------------------------------------------- Method for
Pollutant Units (7 percent HMIWI size Averaging time demonstrating
oxygen, dry basis) --------------------------------------------------------------- \1\ compliance \2\
Small Medium Large
--------------------------------------------------------------------------------------------------------------------------------------------------------
Particulate matter............. Milligrams per dry 115 (0.05)......... 69 (0.03)......... 34 (0.015).......... 3-run average (1- EPA Reference
standard cubic hour minimum Method 5 of
meter (mg/dscm) sample time per appendix A-3 of
(grains per dry run). part 60, or EPA
standard cubic Reference Method
foot (gr/dscf)). 26A or 29 of
appendix A-8 of
part 60.
Carbon monoxide................ Parts per million 40................. 40................ 40.................. 3-run average (1- EPA Reference
by volume (ppmv). hour minimum Method 10 or 10B
sample time per of appendix A-4
run). of part 60.
[[Page 115]]
Dioxins/furans................. Nanograms per dry 125 (55) or 2.3 125 (55) or 2.3 125 (55) or 2.3 3-run average (4- EPA Reference
standard cubic (1.0). (1.0). (1.0). hour minimum Method 23 of
meter total sample time per appendix A-7 of
dioxins/furans run). part 60.
(ng/dscm) (grains
per billion dry
standard cubic
feet (gr/10\9\
dscf)) or ng/dscm
TEQ (gr/10\9\
dscf).
Hydrogen chloride.............. ppmv or percent 100 or 93%......... 100 or 93%........ 100 or 93%.......... 3-run average (1- EPA Reference
reduction. hour minimum Method 26 or 26A
sample time per of appendix A-8
run). of part 60.
Sulfur dioxide................. ppmv.............. 55................. 55................ 55.................. 3-run average (1- EPA Reference
hour minimum Method 6 or 6C
sample time per of appendix A-4
run). of part 60.
Nitrogen oxides................ ppmv.............. 250................ 250............... 250................. 3-run average (1- EPA Reference
hour minimum Method 7 or 7E
sample time per of appendix A-4
run). of part 60.
Lead........................... mg/dscm (grains 1.2 (0.52) or 70%.. 1.2 (0.52) or 70%. 1.2 (0.52) or 70%... 3-run average (1- EPA Reference
per thousand dry hour minimum Method 29 of
standard cubic sample time per appendix A-8 of
feet (gr/10\3\ run). part 60.
dscf)) or percent
reduction.
Cadmium........................ mg/dscm (gr/10\3\ 0.16 (0.07) or 65%. 0.16 (0.07) or 65% 0.16 (0.07) or 65%.. 3-run average (1- EPA Reference
dscf) or percent hour minimum Method 29 of
reduction. sample time per appendix A-8 of
run). part 60.
Mercury........................ mg/dscm (gr/10\3\ 0.55 (0.24) or 85%. 0.55 (0.24) or 85% 0.55 (0.24) or 85%.. 3-run average (1- EPA Reference
dscf) or percent hour minimum Method 29 of
reduction. sample time per appendix A-8 of
run). part 60.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Except as allowed under Sec. 60.56c(c) for HMIWI equipped with CEMS.
\2\ Does not include CEMS and approved alternative non-EPA test methods allowed under Sec. 60.56c(b).
[60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51405, Oct. 6, 2009; 76
FR 18412, Apr. 4, 2011]
[[Page 116]]
Sec. Table 1B to Subpart Ce of Part 60--Emissions Limits for Small,
Medium, and Large HMIWI at Designated Facilities as Defined in Sec.
60.32e(a)(1) and (a)(2)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions limits
--------------------------------------------------------------- Method for
Pollutant Units (7 percent HMIWI size Averaging time demonstrating
oxygen, dry basis) --------------------------------------------------------------- \1\ compliance \2\
Small Medium Large
--------------------------------------------------------------------------------------------------------------------------------------------------------
Particulate matter............. Milligrams per dry 66 (0.029)......... 46 (0.020)......... 25 (0.011)......... 3-run average (1- EPA Reference
standard cubic hour minimum Method 5 of
meter (mg/dscm) sample time per appendix A-3 of
(grains per dry run). part 60, or EPA
standard cubic Reference Method
foot (gr/dscf)). 26A or 29 of
appendix A-8 of
part 60.
Carbon monoxide................ Parts per million 20................. 5.5................ 11................. 3-run average (1- EPA Reference
by volume (ppmv). hour minimum Method 10 or 10B
sample time per of appendix A-4
run). of part 60.
Dioxins/furans................. Nanograms per dry 16 (7.0) or 0.013 0.85 (0.37) or 9.3 (4.1) or 0.054 3-run average (4- EPA Reference
standard cubic (0.0057). 0.020 (0.0087). (0.024). hour minimum Method 23 of
meter total sample time per appendix A-7 of
dioxins/furans run). part 60.
(ng/dscm) (grains
per billion dry
standard cubic
feet (gr/10\9\
dscf)) or ng/dscm
TEQ (gr/10\9\
dscf).
Hydrogen chloride.............. ppmv.............. 44................. 7.7................ 6.6................ 3-run average (1- EPA Reference
hour minimum Method 26 or 26A
sample time per of appendix A-8
run). of part 60.
Sulfur dioxide................. ppmv.............. 4.2................ 4.2................ 9.0................ 3-run average (1- EPA Reference
hour minimum Method 6 or 6C
sample time per of appendix A-4
run). of part 60.
Nitrogen oxides................ ppmv.............. 190................ 190................ 140................ 3-run average (1- EPA Reference
hour minimum Method 7 or 7E
sample time per of appendix A-4
run). of part 60.
Lead........................... mg/dscm (grains 0.31 (0.14)........ 0.018 (0.0079)..... 0.036 (0.016)...... 3-run average (1- EPA Reference
per thousand dry hour minimum Method 29 of
standard cubic sample time per appendix A-8 of
feet (gr/10\3\ run). part 60.
dscf)).
Cadmium........................ mg/dscm (gr/10\3\ 0.017 (0.0074)..... 0.013 (0.0057)..... 0.0092 (0.0040).... 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
[[Page 117]]
Mercury........................ mg/dscm (gr/10\3\ 0.014 (0.0061)..... 0.025 (0.011)...... 0.018 (0.0079)..... 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Except as allowed under Sec. 60.56c(c) for HMIWI equipped with CEMS.
\2\ Does not include CEMS and approved alternative non-EPA test methods allowed under Sec. 60.56c(b).
[74 FR 51406, Oct. 6, 2009]
Sec. Table 2A to Subpart Ce of Part 60--Emissions Limits for Small HMIWI
Which Meet the Criteria Under Sec. 60.33e(b)(1)
----------------------------------------------------------------------------------------------------------------
Units (7 percent Method for
Pollutant oxygen, dry HMIWI emissions limits Averaging time demonstrating
basis) \1\ compliance \2\
----------------------------------------------------------------------------------------------------------------
Particulate matter............ mg/dscm (gr/dscf) 197 (0.086)............ 3-run average (1- EPA Reference
hour minimum Method 5 of
sample time per appendix A-3 of
run). part 60, or EPA
Reference Method
26A or 29 of
appendix A-8 of
part 60.
Carbon monoxide............... ppmv............. 40..................... 3-run average (1- EPA Reference
hour minimum Method 10 or 10B
sample time per of appendix A-4
run). of part 60.
Dioxins/furans................ ng/dscm total 800 (350) or 15 (6.6).. 3-run average (4- EPA Reference
dioxins/furans hour minimum Method 23 of
(gr/10\9\ dscf) sample time per appendix A-7 of
or ng/dscm TEQ run). part 60.
(gr/10\9\ dscf).
Hydrogen chloride............. ppmv............. 3,100.................. 3-run average (1- EPA Reference
hour minimum Method 26 or 26A
sample time per of appendix A-8
run). of part 60.
Sulfur dioxide................ ppmv............. 55..................... 3-run average (1- EPA Reference
hour minimum Method 6 or 6C
sample time per of appendix A-4
run). of part 60.
Nitrogen oxides............... ppmv............. 250.................... 3-run average (1- EPA Reference
hour minimum Method 7 or 7E
sample time per of appendix A-4
run). of part 60.
Lead.......................... mg/dscm (gr/10\3\ 10 (4.4)............... 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
Cadmium....................... mg/dscm (gr/10\3\ 4 (1.7)................ 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
Mercury....................... mg/dscm (gr/10\3\ 7.5 (3.3).............. 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
----------------------------------------------------------------------------------------------------------------
\1\ Except as allowed under Sec. 60.56c(c) for HMIWI equipped with CEMS.
\2\ Does not include CEMS and approved alternative non-EPA test methods allowed under Sec. 60.56c(b).
[74 FR 51407, Oct. 6, 2009]
Sec. Table 2B to Subpart Ce of Part 60--Emissions Limits for Small HMIWI
Which Meet the Criteria Under Sec. 60.33e(b)(2)
----------------------------------------------------------------------------------------------------------------
Units (7 percent Method for
Pollutant oxygen, dry HMIWI Emissions limits Averaging time demonstrating
basis) \1\ compliance \2\
----------------------------------------------------------------------------------------------------------------
Particulate matter............ mg/dscm (gr/dscf) 87 (0.038)............. 3-run average (1- EPA Reference
hour minimum Method 5 of
sample time per appendix A-3 of
run). part 60, or EPA
Reference Method
26A or 29 of
appendix A-8 of
part 60.
Carbon monoxide............... ppmv............. 20..................... 3-run average (1- EPA Reference
hour minimum Method 10 or 10B
sample time per of appendix A-4
run). of part 60.
[[Page 118]]
Dioxins/furans................ ng/dscm total 240 (100) or 5.1 (2.2). 3-run average (4- EPA Reference
dioxins/furans hour minimum Method 23 of
(gr/10\9\ dscf) sample time per appendix A-7 of
or ng/dscm TEQ run). part 60.
(gr/10\9\ dscf).
Hydrogen chloride............. ppmv............. 810.................... 3-run average (1- EPA Reference
hour minimum Method 26 or 26A
sample time per of appendix A-8
run). of part 60.
Sulfur dioxide................ ppmv............. 55..................... 3-run average (1- EPA Reference
hour minimum Method 6 or 6C
sample time per of appendix A-4
run). of part 60.
Nitrogen oxides............... ppmv............. 130.................... 3-run average (1- EPA Reference
hour minimum Method 7 or 7E
sample time per of appendix A-4
run). of part 60.
Lead.......................... mg/dscm (gr/10\3\ 0.50 (0.22)............ 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
Cadmium....................... mg/dscm (gr/10\3\ 0.11 (0.048)........... 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
Mercury....................... mg/dscm (gr/10\3\ 0.0051 (0.0022)........ 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
----------------------------------------------------------------------------------------------------------------
\1\ Except as allowed under Sec. 60.56c(c) for HMIWI equipped with CEMS.
\2\ Does not include CEMS and approved alternative non-EPA test methods allowed under Sec. 60.56c(b).
[74 FR 51407, Oct. 6, 2009]
Subpart D_Standards of Performance for Fossil-Fuel-Fired Steam
Generators
Source: 72 FR 32717, June 13, 2007, unless otherwise noted.
Sec. 60.40 Applicability and designation of affected facility.
(a) The affected facilities to which the provisions of this subpart
apply are:
(1) Each fossil-fuel-fired steam generating unit of more than 73
megawatts (MW) heat input rate (250 million British thermal units per
hour (MMBtu/hr)).
(2) Each fossil-fuel and wood-residue-fired steam generating unit
capable of firing fossil fuel at a heat input rate of more than 73 MW
(250 MMBtu/hr).
(b) Any change to an existing fossil-fuel-fired steam generating
unit to accommodate the use of combustible materials, other than fossil
fuels as defined in this subpart, shall not bring that unit under the
applicability of this subpart.
(c) Except as provided in paragraph (d) of this section, any
facility under paragraph (a) of this section that commenced construction
or modification after August 17, 1971, is subject to the requirements of
this subpart.
(d) The requirements of Sec. Sec. 60.44 (a)(4), (a)(5), (b) and
(d), and 60.45(f)(4)(vi) are applicable to lignite-fired steam
generating units that commenced construction or modification after
December 22, 1976.
(e) Any facility subject to either subpart Da or KKKK of this part
is not subject to this subpart.
[72 FR 32717, June 13, 2007, as amended at 77 FR 9447, Feb. 16, 2012]
Sec. 60.41 Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Act, and in subpart A of this part.
Boiler operating day means a 24-hour period between 12 midnight and
the following midnight during which any fuel is combusted at any time in
the steam-generating unit. It is not necessary for fuel to be combusted
the entire 24-hour period.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by ASTM D388 (incorporated by reference, see
Sec. 60.17).
Coal refuse means waste-products of coal mining, cleaning, and coal
preparation operations (e.g. culm, gob, etc.) containing coal, matrix
material, clay,
[[Page 119]]
and other organic and inorganic material.
Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such materials for the
purpose of creating useful heat.
Fossil fuel and wood residue-fired steam generating unit means a
furnace or boiler used in the process of burning fossil fuel and wood
residue for the purpose of producing steam by heat transfer.
Fossil-fuel-fired steam generating unit means a furnace or boiler
used in the process of burning fossil fuel for the purpose of producing
steam by heat transfer.
Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In addition,
natural gas contains 20.0 grains or less of total sulfur per 100
standard cubic feet. Finally, natural gas does not include the following
gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast
furnace gas, coal-derived gas, producer gas, coke oven gas, or any
gaseous fuel produced in a process which might result in highly variable
sulfur content or heating value.
Wood residue means bark, sawdust, slabs, chips, shavings, mill trim,
and other wood products derived from wood processing and forest
management operations.
[72 FR 32717, June 13, 2007, as amended at 77 FR 9447, Feb. 16, 2012]
Sec. 60.42 Standard for particulate matter (PM).
(a) Except as provided under paragraphs (b), (c), (d), and (e) of
this section, on and after the date on which the performance test
required to be conducted by Sec. 60.8 is completed, no owner or
operator subject to the provisions of this subpart shall cause to be
discharged into the atmosphere from any affected facility any gases
that:
(1) Contain PM in excess of 43 nanograms per joule (ng/J) heat input
(0.10 lb/MMBtu) derived from fossil fuel or fossil fuel and wood
residue.
(2) Exhibit greater than 20 percent opacity except for one six-
minute period per hour of not more than 27 percent opacity.
(b)(1) On or after December 28, 1979, no owner or operator shall
cause to be discharged into the atmosphere from the Southwestern Public
Service Company's Harrington Station 1, in Amarillo, TX, any gases
which exhibit greater than 35 percent opacity, except that a maximum or
42 percent opacity shall be permitted for not more than 6 minutes in any
hour.
(2) Interstate Power Company shall not cause to be discharged into
the atmosphere from its Lansing Station Unit No. 4 in Lansing, IA, any
gases which exhibit greater than 32 percent opacity, except that a
maximum of 39 percent opacity shall be permitted for not more than six
minutes in any hour.
(c) As an alternate to meeting the requirements of paragraph (a) of
this section, an owner or operator that elects to install, calibrate,
maintain, and operate a continuous emissions monitoring systems (CEMS)
for measuring PM emissions can petition the Administrator (in writing)
to comply with Sec. 60.42Da(a) of subpart Da of this part. If the
Administrator grants the petition, the source will from then on (unless
the unit is modified or reconstructed in the future) have to comply with
the requirements in Sec. 60.42Da(a) of subpart Da of this part.
(d) An owner or operator of an affected facility that combusts only
natural gas is exempt from the PM and opacity standards specified in
paragraph (a) of this section.
(e) An owner or operator of an affected facility that combusts only
gaseous or liquid fossil fuel (excluding residual oil) with potential
SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and
that does not use post-combustion technology to reduce emissions of
SO2 or PM is exempt from the PM standards specified in
paragraph (a) of this section.
[60 FR 65415, Dec. 19, 1995, as amended at 76 FR 3522, Jan. 20, 2011; 74
FR 5077, Jan. 28, 2009; 77 FR 9447, Feb. 16, 2012]
[[Page 120]]
Sec. 60.43 Standard for sulfur dioxide (SO[bdi2]).
(a) Except as provided under paragraph (d) of this section, on and
after the date on which the performance test required to be conducted by
Sec. 60.8 is completed, no owner or operator subject to the provisions
of this subpart shall cause to be discharged into the atmosphere from
any affected facility any gases that contain SO2 in excess
of:
(1) 340 ng/J heat input (0.80 lb/MMBtu) derived from liquid fossil
fuel or liquid fossil fuel and wood residue.
(2) 520 ng/J heat input (1.2 lb/MMBtu) derived from solid fossil
fuel or solid fossil fuel and wood residue, except as provided in
paragraph (e) of this section.
(b) Except as provided under paragraph (d) of this section, when
different fossil fuels are burned simultaneously in any combination, the
applicable standard (in ng/J) shall be determined by proration using the
following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.000
Where:
PSSO2 = Prorated standard for SO2 when burning
different fuels simultaneously, in ng/J heat input derived
from all fossil fuels or from all fossil fuels and wood
residue fired;
y = Percentage of total heat input derived from liquid fossil fuel; and
z = Percentage of total heat input derived from solid fossil fuel.
(c) Compliance shall be based on the total heat input from all
fossil fuels burned, including gaseous fuels.
(d) As an alternate to meeting the requirements of paragraphs (a)
and (b) of this section, an owner or operator can petition the
Administrator (in writing) to comply with Sec. 60.43Da(i)(3) of subpart
Da of this part or comply with Sec. 60.42b(k)(4) of subpart Db of this
part, as applicable to the affected source. If the Administrator grants
the petition, the source will from then on (unless the unit is modified
or reconstructed in the future) have to comply with the requirements in
Sec. 60.43Da(i)(3) of subpart Da of this part or Sec. 60.42b(k)(4) of
subpart Db of this part, as applicable to the affected source.
(e) Units 1 and 2 (as defined in appendix G of this part) at the
Newton Power Station owned or operated by the Central Illinois Public
Service Company will be in compliance with paragraph (a)(2) of this
section if Unit 1 and Unit 2 individually comply with paragraph (a)(2)
of this section or if the combined emission rate from Units 1 and 2 does
not exceed 470 ng/J (1.1 lb/MMBtu) combined heat input to Units 1 and 2.
[60 FR 65415, Dec. 19, 1995, as amended at 74 FR 5077, Jan. 28, 2009]
Sec. 60.44 Standard for nitrogen oxides (NOX).
(a) Except as provided under paragraph (e) of this section, on and
after the date on which the performance test required to be conducted by
Sec. 60.8 is completed, no owner or operator subject to the provisions
of this subpart shall cause to be discharged into the atmosphere from
any affected facility any gases that contain NOX, expressed
as NO2 in excess of:
(1) 86 ng/J heat input (0.20 lb/MMBtu) derived from gaseous fossil
fuel.
(2) 129 ng/J heat input (0.30 lb/MMBtu) derived from liquid fossil
fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and
wood residue.
(3) 300 ng/J heat input (0.70 lb/MMBtu) derived from solid fossil
fuel or solid fossil fuel and wood residue (except lignite or a solid
fossil fuel containing 25 percent, by weight, or more of coal refuse).
(4) 260 ng/J heat input (0.60 lb MMBtu) derived from lignite or
lignite and wood residue (except as provided under paragraph (a)(5) of
this section).
(5) 340 ng/J heat input (0.80 lb MMBtu) derived from lignite which
is mined in North Dakota, South Dakota, or Montana and which is burned
in a cyclone-fired unit.
(b) Except as provided under paragraphs (c), (d), and (e) of this
section, when different fossil fuels are burned simultaneously in any
combination, the applicable standard (in ng/J) is determined by
proration using the following formula:
[[Page 121]]
[GRAPHIC] [TIFF OMITTED] TR13JN07.001
Where:
PSNOX = Prorated standard for NOX when
burning different fuels simultaneously, in ng/J heat input
derived from all fossil fuels fired or from all fossil fuels
and wood residue fired;
w = Percentage of total heat input derived from lignite;
x = Percentage of total heat input derived from gaseous fossil fuel;
y = Percentage of total heat input derived from liquid fossil fuel; and
z = Percentage of total heat input derived from solid fossil fuel
(except lignite).
(c) When a fossil fuel containing at least 25 percent, by weight, of
coal refuse is burned in combination with gaseous, liquid, or other
solid fossil fuel or wood residue, the standard for NOX does
not apply.
(d) Except as provided under paragraph (e) of this section, cyclone-
fired units which burn fuels containing at least 25 percent of lignite
that is mined in North Dakota, South Dakota, or Montana remain subject
to paragraph (a)(5) of this section regardless of the types of fuel
combusted in combination with that lignite.
(e) As an alternate to meeting the requirements of paragraphs (a),
(b), and (d) of this section, an owner or operator can petition the
Administrator (in writing) to comply with Sec. 60.44Da(e)(3) of subpart
Da of this part. If the Administrator grants the petition, the source
will from then on (unless the unit is modified or reconstructed in the
future) have to comply with the requirements in Sec. 60.44Da(e)(3) of
subpart Da of this part.
Sec. 60.45 Emissions and fuel monitoring.
(a) Each owner or operator of an affected facility subject to the
applicable emissions standard shall install, calibrate, maintain, and
operate continuous opacity monitoring system (COMS) for measuring
opacity and a continuous emissions monitoring system (CEMS) for
measuring SO2 emissions, NOX emissions, and either
oxygen (O2) or carbon dioxide (CO2) except as
provided in paragraph (b) of this section.
(b) Certain of the CEMS and COMS requirements under paragraph (a) of
this section do not apply to owners or operators under the following
conditions:
(1) For a fossil-fuel-fired steam generator that combusts only
gaseous or liquid fossil fuel (excluding residual oil) with potential
SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and
that does not use post-combustion technology to reduce emissions of
SO2 or PM, COMS for measuring the opacity of emissions and
CEMS for measuring SO2 emissions are not required if the
owner or operator monitors SO2 emissions by fuel sampling and
analysis or fuel receipts.
(2) For a fossil-fuel-fired steam generator that does not use a flue
gas desulfurization device, a CEMS for measuring SO2
emissions is not required if the owner or operator monitors
SO2 emissions by fuel sampling and analysis.
(3) Notwithstanding Sec. 60.13(b), installation of a CEMS for
NOX may be delayed until after the initial performance tests
under Sec. 60.8 have been conducted. If the owner or operator
demonstrates during the performance test that emissions of
NOX are less than 70 percent of the applicable standards in
Sec. 60.44, a CEMS for measuring NOX emissions is not
required. If the initial performance test results show that
NOX emissions are greater than 70 percent of the applicable
standard, the owner or operator shall install a CEMS for NOX
within one year after the date of the initial performance tests under
Sec. 60.8 and comply with all other applicable monitoring requirements
under this part.
(4) If an owner or operator is not required to and elects not to
install any CEMS for either SO2 or NOX, a CEMS for
measuring either O2 or CO2 is not required.
(5) For affected facilities using a PM CEMS, a bag leak detection
system to
[[Page 122]]
monitor the performance of a fabric filter (baghouse) according to the
most current requirements in Sec. 60.48Da of this part, or an ESP
predictive model to monitor the performance of the ESP developed in
accordance and operated according to the most current requirements in
section Sec. 60.48Da of this part a COMS is not required.
(6) A COMS for measuring the opacity of emissions is not required
for an affected facility that does not use post-combustion technology
(except a wet scrubber) for reducing PM, SO2, or carbon
monoxide (CO) emissions, burns only gaseous fuels or fuel oils that
contain less than or equal to 0.30 weight percent sulfur, and is
operated such that emissions of CO to the atmosphere from the affected
source are maintained at levels less than or equal to 0.15 lb/MMBtu on a
boiler operating day average basis. Owners and operators of affected
sources electing to comply with this paragraph must demonstrate
compliance according to the procedures specified in paragraphs (b)(6)(i)
through (iv) of this section.
(i) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (b)(6)(i)(A) through (D) of this
section.
(A) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec. 60.58b(i)(3) of subpart Eb
of this part.
(B) Each 1-hour CO emissions average is calculated using the data
points generated by the CO CEMS expressed in parts per million by volume
corrected to 3 percent oxygen (dry basis).
(C) At a minimum, valid 1-hour CO emissions averages must be
obtained for at least 90 percent of the operating hours on a 30-day
rolling average basis. The 1-hour averages are calculated using the data
points required in Sec. 60.13(h)(2).
(D) Quarterly accuracy determinations and daily calibration drift
tests for the CO CEMS must be performed in accordance with procedure 1
in appendix F of this part.
(ii) You must calculate the 1-hour average CO emissions levels for
each boiler operating day by multiplying the average hourly CO output
concentration measured by the CO CEMS times the corresponding average
hourly flue gas flow rate and divided by the corresponding average
hourly heat input to the affected source. The 24-hour average CO
emission level is determined by calculating the arithmetic average of
the hourly CO emission levels computed for each boiler operating day.
(iii) You must evaluate the preceding 24-hour average CO emission
level each boiler operating day excluding periods of affected source
startup, shutdown, or malfunction. If the 24-hour average CO emission
level is greater than 0.15 lb/MMBtu, you must initiate investigation of
the relevant equipment and control systems within 24 hours of the first
discovery of the high emission incident and, take the appropriate
corrective action as soon as practicable to adjust control settings or
repair equipment to reduce the 24-hour average CO emission level to 0.15
lb/MMBtu or less.
(iv) You must record the CO measurements and calculations performed
according to paragraph (b)(6) of this section and any corrective actions
taken. The record of corrective action taken must include the date and
time during which the 24-hour average CO emission level was greater than
0.15 lb/MMBtu, and the date, time, and description of the corrective
action.
(7) An owner or operator of an affected facility subject to an
opacity standard under Sec. 60.42 that elects to not use a COMS because
the affected facility burns only fuels as specified under paragraph
(b)(1) of this section, monitors PM emissions as specified under
paragraph (b)(5) of this section, or monitors CO emissions as specified
under paragraph (b)(6) of this section, shall conduct a performance test
using Method 9 of appendix A-4 of this part and the procedures in Sec.
60.11 to demonstrate compliance with the applicable limit in Sec. 60.42
by April 29, 2011 or within 45 days after stopping use of an existing
COMS, whichever is later, and shall comply with either paragraph
(b)(7)(i), (b)(7)(ii), or (b)(7)(iii) of this section. The observation
period for Method 9 of appendix A-4 of this part performance tests may
be reduced from 3 hours to 60 minutes if all 6-minute averages are less
than 10 percent and all individual 15-second observations
[[Page 123]]
are less than or equal to 20 percent during the initial 60 minutes of
observation. The permitting authority may exempt owners or operators of
affected facilities burning only natural gas from the opacity monitoring
requirements.
(i) Except as provided in paragraph (b)(7)(ii) or (b)(7)(iii) of
this section, the owner or operator shall conduct subsequent Method 9 of
appendix A-4 of this part performance tests using the procedures in
paragraph (b)(7) of this section according to the applicable schedule in
paragraphs (b)(7)(i)(A) through (b)(7)(i)(D) of this section, as
determined by the most recent Method 9 of appendix A-4 of this part
performance test results.
(A) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later;
(B) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed within
6 calendar months from the date that the most recent performance test
was conducted or within 45 days of the next day that fuel with an
opacity standard is combusted, whichever is later;
(C) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later; or
(D) If the maximum 6-minute average opacity is greater than 10
percent, a subsequent Method 9 of appendix A-4 of this part performance
test must be completed within 45 calendar days from the date that the
most recent performance test was conducted.
(ii) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 of this part performance test, elect to perform
subsequent monitoring using Method 22 of appendix A-7 of this part
according to the procedures specified in paragraphs (b)(7)(ii)(A) and
(B) of this section.
(A) The owner or operator shall conduct 10 minute observations
(during normal operation) each operating day the affected facility fires
fuel for which an opacity standard is applicable using Method 22 of
appendix A-7 of this part and demonstrate that the sum of the
occurrences of any visible emissions is not in excess of 5 percent of
the observation period (i.e., 30 seconds per 10 minute period). If the
sum of the occurrence of any visible emissions is greater than 30
seconds during the initial 10 minute observation, immediately conduct a
30 minute observation. If the sum of the occurrence of visible emissions
is greater than 5 percent of the observation period (i.e., 90 seconds
per 30 minute period), the owner or operator shall either document and
adjust the operation of the facility and demonstrate within 24 hours
that the sum of the occurrence of visible emissions is equal to or less
than 5 percent during a 30 minute observation (i.e., 90 seconds) or
conduct a new Method 9 of appendix A-4 of this part performance test
using the procedures in paragraph (b)(7) of this section within 45
calendar days according to the requirements in Sec. 60.46(b)(3).
(B) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily observations
shall be resumed.
(iii) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 performance tests,
[[Page 124]]
elect to perform subsequent monitoring using a digital opacity
compliance system according to a site-specific monitoring plan approved
by the Administrator. The observations shall be similar, but not
necessarily identical, to the requirements in paragraph (b)(7)(ii) of
this section. For reference purposes in preparing the monitoring plan,
see OAQPS ``Determination of Visible Emission Opacity from Stationary
Sources Using Computer-Based Photographic Analysis Systems.'' This
document is available from the U.S. Environmental Protection Agency
(U.S. EPA); Office of Air Quality and Planning Standards; Sector
Policies and Programs Division; Measurement Policy Group (D243-02),
Research Triangle Park, NC 27711. This document is also available on the
Technology Transfer Network (TTN) under Emission Measurement Center
Preliminary Methods.
(8) A COMS for measuring the opacity of emissions is not required
for an affected facility at which the owner or operator installs,
calibrates, operates, and maintains a particulate matter continuous
parametric monitoring system (PM CPMS) according to the requirements
specified in subpart UUUUU of part 63.
(c) For performance evaluations under Sec. 60.13(c) and calibration
checks under Sec. 60.13(d), the following procedures shall be used:
(1) Methods 6, 7, and 3B of appendix A of this part, as applicable,
shall be used for the performance evaluations of SO2 and
NOX continuous monitoring systems. Acceptable alternative
methods for Methods 6, 7, and 3B of appendix A of this part are given in
Sec. 60.46(d).
(2) Sulfur dioxide or nitric oxide, as applicable, shall be used for
preparing calibration gas mixtures under Performance Specification 2 of
appendix B to this part.
(3) For affected facilities burning fossil fuel(s), the span value
for a continuous monitoring system measuring the opacity of emissions
shall be 80, 90, or 100 percent. For a continuous monitoring system
measuring sulfur oxides or NOX the span value shall be
determined using one of the following procedures:
(i) Except as provided under paragraph (c)(3)(ii) of this section,
SO2 and NOX span values shall be determined as
follows:
----------------------------------------------------------------------------------------------------------------
In parts per million
Fossil fuel ---------------------------------------------------------------------------
Span value for SO2 Span value for NOX
----------------------------------------------------------------------------------------------------------------
Gas................................. (\1\)............................... 500.
Liquid.............................. 1,000............................... 500.
Solid............................... 1,500............................... 1,000.
Combinations........................ 1,000y + 1,500z..................... 500 (x + y) + 1,000z.
----------------------------------------------------------------------------------------------------------------
\1\ Not applicable.
Where:
x = Fraction of total heat input derived from gaseous fossil fuel;
y = Fraction of total heat input derived from liquid fossil fuel; and
z = Fraction of total heat input derived from solid fossil fuel.
(ii) As an alternative to meeting the requirements of paragraph
(c)(3)(i) of this section, the owner or operator of an affected facility
may elect to use the SO2 and NOX span values
determined according to sections 2.1.1 and 2.1.2 in appendix A to part
75 of this chapter.
(4) All span values computed under paragraph (c)(3)(i) of this
section for burning combinations of fossil fuels shall be rounded to the
nearest 500 ppm. Span values that are computed under paragraph
(c)(3)(ii) of this section shall be rounded off according to the
applicable procedures in section 2 of appendix A to part 75 of this
chapter.
(5) For a fossil-fuel-fired steam generator that simultaneously
burns fossil fuel and nonfossil fuel, the span value of all CEMS shall
be subject to the Administrator's approval.
(d) [Reserved]
(e) For any CEMS installed under paragraph (a) of this section, the
following conversion procedures shall be used to convert the continuous
monitoring data into units of the applicable standards (ng/J, lb/MMBtu):
[[Page 125]]
(1) When a CEMS for measuring O2 is selected, the
measurement of the pollutant concentration and O2
concentration shall each be on a consistent basis (wet or dry).
Alternative procedures approved by the Administrator shall be used when
measurements are on a wet basis. When measurements are on a dry basis,
the following conversion procedure shall be used:
[GRAPHIC] [TIFF OMITTED] TR13JN07.002
Where E, C, F, and %O2 are determined under paragraph (f) of
this section.
(2) When a CEMS for measuring CO2 is selected, the
measurement of the pollutant concentration and CO2
concentration shall each be on a consistent basis (wet or dry) and the
following conversion procedure shall be used:
[GRAPHIC] [TIFF OMITTED] TR13JN07.003
Where E, C, Fc and %CO2 are determined under
paragraph (f) of this section.
(f) The values used in the equations under paragraphs (e)(1) and (2)
of this section are derived as follows:
(1) E = pollutant emissions, ng/J (lb/MMBtu).
(2) C = pollutant concentration, ng/dscm (lb/dscf), determined by
multiplying the average concentration (ppm) for each one-hour period by
4.15 x 10\4\ M ng/dscm per ppm (2.59 x 10-9 M lb/dscf per
ppm) where M = pollutant molecular weight, g/g-mole (lb/lb-mole). M =
64.07 for SO2 and 46.01 for NOX.
(3) %O2, %CO2 = O2 or
CO2 volume (expressed as percent), determined with equipment
specified under paragraph (a) of this section.
(4) F, Fc = a factor representing a ratio of the volume
of dry flue gases generated to the calorific value of the fuel combusted
(F), and a factor representing a ratio of the volume of CO2
generated to the calorific value of the fuel combusted (Fc),
respectively. Values of F and Fc are given as follows:
(i) For anthracite coal as classified according to ASTM D388
(incorporated by reference, see Sec. 60.17), F = 2,723 x
10-17 dscm/J (10,140 dscf/MMBtu) and Fc = 0.532 x
10-17 scm CO2/J (1,980 scf CO2/MMBtu).
(ii) For subbituminous and bituminous coal as classified according
to ASTM D388 (incorporated by reference, see Sec. 60.17), F = 2.637 x
10-7 dscm/J (9,820 dscf/MMBtu) and Fc = 0.486 x
10-7 scm CO2/J (1,810 scf CO2/MMBtu).
(iii) For liquid fossil fuels including crude, residual, and
distillate oils, F = 2.476 x 10-7 dscm/J (9,220 dscf/MMBtu)
and Fc = 0.384 x 10-7 scm CO2/J (1,430
scf CO2/MMBtu).
(iv) For gaseous fossil fuels, F = 2.347 x 10-7 dscm/J
(8,740 dscf/MMBtu). For natural gas, propane, and butane fuels,
Fc = 0.279 x 10-7 scm CO2/J (1,040 scf
CO2/MMBtu) for natural gas, 0.322 x 10-7 scm
CO2/J (1,200 scf CO2/MMBtu) for propane, and 0.338
x 10-7 scm CO2/J (1,260 scf CO2/MMBtu)
for butane.
(v) For bark F = 2.589 x 10-7 dscm/J (9,640 dscf/MMBtu)
and Fc = 0.500 x 10-7 scm CO2/J (1,840
scf CO2/MMBtu). For wood residue other than bark F = 2.492 x
10-7 dscm/J (9,280 dscf/MMBtu) and Fc = 0.494 x
10-7 scm CO2/J (1,860 scf CO2/MMBtu).
(vi) For lignite coal as classified according to ASTM D388
(incorporated by reference, see Sec. 60.17), F = 2.659 x
10-7 dscm/J (9,900 dscf/MMBtu) and Fc = 0.516 x
10-7 scm CO2/J (1,920 scf CO2/MMBtu).
(5) The owner or operator may use the following equation to
determine an F factor (dscm/J or dscf/MMBtu) on a dry basis (if it is
desired to calculate F on a wet basis, consult the Administrator) or Fc
factor (scm CO2/J, or scf CO2/MMBtu) on either
basis in lieu of the F or Fc factors specified in paragraph
(f)(4) of this section:
[[Page 126]]
[GRAPHIC] [TIFF OMITTED] TR13JN07.004
(i) %H, %C, %S, %N, and %O are content by weight of hydrogen,
carbon, sulfur, nitrogen, and O2 (expressed as percent),
respectively, as determined on the same basis as GCV by ultimate
analysis of the fuel fired, using ASTM D3178 or D3176 (solid fuels), or
computed from results using ASTM D1137, D1945, or D1946 (gaseous fuels)
as applicable. (These five methods are incorporated by reference, see
Sec. 60.17.)
(ii) GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel
combusted determined by the ASTM test methods D2015 or D5865 for solid
fuels and D1826 for gaseous fuels as applicable. (These three methods
are incorporated by reference, see Sec. 60.17.)
(iii) For affected facilities which fire both fossil fuels and
nonfossil fuels, the F or Fc value shall be subject to the
Administrator's approval.
(6) For affected facilities firing combinations of fossil fuels or
fossil fuels and wood residue, the F or Fc factors determined by
paragraphs (f)(4) or (f)(5) of this section shall be prorated in
accordance with the applicable formula as follows:
[GRAPHIC] [TIFF OMITTED] TR13JN07.005
Where:
Xi = Fraction of total heat input derived from each type of
fuel (e.g. natural gas, bituminous coal, wood residue, etc.);
Fi or (Fc)i = Applicable F or
Fc factor for each fuel type determined in
accordance with paragraphs (f)(4) and (f)(5) of this section;
and
n = Number of fuels being burned in combination.
(g) Excess emission and monitoring system performance reports shall
be submitted to the Administrator semiannually for each six-month period
in the calendar year. All semiannual reports shall be postmarked by the
30th day following the end of each six-month period. Each excess
emission and MSP report shall include the information required in Sec.
60.7(c). Periods of excess emissions and monitoring systems (MS)
downtime that shall be reported are defined as follows:
(1) Opacity. Excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 20 percent
opacity, except that one six-minute average per hour of up to 27 percent
opacity need not be reported.
(i) For sources subject to the opacity standard of Sec.
60.42(b)(1), excess emissions are defined as any six-minute period
during which the average opacity
[[Page 127]]
of emissions exceeds 35 percent opacity, except that one six-minute
average per hour of up to 42 percent opacity need not be reported.
(ii) For sources subject to the opacity standard of Sec.
60.42(b)(2), excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 32 percent
opacity, except that one six-minute average per hour of up to 39 percent
opacity need not be reported.
(2) Sulfur dioxide. Excess emissions for affected facilities are
defined as:
(i) For affected facilities electing not to comply with Sec.
60.43(d), any three-hour period during which the average emissions
(arithmetic average of three contiguous one-hour periods) of
SO2 as measured by a CEMS exceed the applicable standard in
Sec. 60.43; or
(ii) For affected facilities electing to comply with Sec. 60.43(d),
any 30 operating day period during which the average emissions
(arithmetic average of all one-hour periods during the 30 operating
days) of SO2 as measured by a CEMS exceed the applicable
standard in Sec. 60.43. Facilities complying with the 30-day
SO2 standard shall use the most current associated
SO2 compliance and monitoring requirements in Sec. Sec.
60.48Da and 60.49Da of subpart Da of this part or Sec. Sec. 60.45b and
60.47b of subpart Db of this part, as applicable.
(3) Nitrogen oxides. Excess emissions for affected facilities using
a CEMS for measuring NOX are defined as:
(i) For affected facilities electing not to comply with Sec.
60.44(e), any three-hour period during which the average emissions
(arithmetic average of three contiguous one-hour periods) exceed the
applicable standards in Sec. 60.44; or
(ii) For affected facilities electing to comply with Sec. 60.44(e),
any 30 operating day period during which the average emissions
(arithmetic average of all one-hour periods during the 30 operating
days) of NOX as measured by a CEMS exceed the applicable
standard in Sec. 60.44. Facilities complying with the 30-day
NOX standard shall use the most current associated
NOX compliance and monitoring requirements in Sec. Sec.
60.48Da and 60.49Da of subpart Da of this part.
(4) Particulate matter. Excess emissions for affected facilities
using a CEMS for measuring PM are defined as any boiler operating day
period during which the average emissions (arithmetic average of all
operating one-hour periods) exceed the applicable standards in Sec.
60.42. Affected facilities using PM CEMS must follow the most current
applicable compliance and monitoring provisions in Sec. Sec. 60.48Da
and 60.49Da of subpart Da of this part.
(h) The owner or operator of an affected facility subject to the
opacity limits in Sec. 60.42 that elects to monitor emissions according
to the requirements in Sec. 60.45(b)(7) shall maintain records
according to the requirements specified in paragraphs (h)(1) through (3)
of this section, as applicable to the visible emissions monitoring
method used.
(1) For each performance test conducted using Method 9 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (h)(1)(i) through (iii) of this
section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission reading
certification for each visible emission observer participating in the
performance test; and
(iii) Copies of all visible emission observer opacity field data
sheets;
(2) For each performance test conducted using Method 22 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (h)(2)(i) through (iv) of this
section.
(i) Dates and time intervals of all visible emissions observation
periods;
(ii) Name and affiliation for each visible emission observer
participating in the performance test;
(iii) Copies of all visible emission observer opacity field data
sheets; and
(iv) Documentation of any adjustments made and the time the
adjustments were completed to the affected facility operation by the
owner or operator to demonstrate compliance with the applicable
monitoring requirements.
(3) For each digital opacity compliance system, the owner or
operator shall maintain records and submit reports according to the
requirements
[[Page 128]]
specified in the site-specific monitoring plan approved by the
Administrator.
[60 FR 65415, Dec. 19, 1995, as amended at 74 FR 5077, Jan. 28, 2009; 76
FR 3522, Jan. 20, 2011; 77 FR 9447, Feb. 16, 2012]
Sec. 60.46 Test methods and procedures.
(a) In conducting the performance tests required in Sec. 60.8, and
subsequent performance tests as requested by the EPA Administrator, the
owner or operator shall use as reference methods and procedures the test
methods in appendix A of this part or other methods and procedures as
specified in this section, except as provided in Sec. 60.8(b).
Acceptable alternative methods and procedures are given in paragraph (d)
of this section.
(b) The owner or operator shall determine compliance with the PM,
SO2, and NOX standards in Sec. Sec. 60.42, 60.43,
and 60.44 as follows:
(1) The emission rate (E) of PM, SO2, or NOX
shall be computed for each run using the following equation:
[GRAPHIC] [TIFF OMITTED] TR13JN07.006
Where:
E = Emission rate of pollutant, ng/J (1b/million Btu);
C = Concentration of pollutant, ng/dscm (1b/dscf);
%O2 = O2 concentration, percent dry basis; and
Fd = Factor as determined from Method 19 of appendix A of
this part.
(2) Method 5 of appendix A of this part shall be used to determine
the PM concentration (C) at affected facilities without wet flue-gas-
desulfurization (FGD) systems and Method 5B of appendix A of this part
shall be used to determine the PM concentration (C) after FGD systems.
(i) The sampling time and sample volume for each run shall be at
least 60 minutes and 0.85 dscm (30 dscf). The probe and filter holder
heating systems in the sampling train shall be set to provide an average
gas temperature of 16014 [deg]C (32025 [deg]F).
(ii) The emission rate correction factor, integrated or grab
sampling and analysis procedure of Method 3B of appendix A of this part
shall be used to determine the O2 concentration
(%O2). The O2 sample shall be obtained
simultaneously with, and at the same traverse points as, the particulate
sample. If the grab sampling procedure is used, the O2
concentration for the run shall be the arithmetic mean of the sample
O2 concentrations at all traverse points.
(iii) If the particulate run has more than 12 traverse points, the
O2 traverse points may be reduced to 12 provided that Method
1 of appendix A of this part is used to locate the 12 O2
traverse points.
(3) Method 9 of appendix A of this part and the procedures in Sec.
60.11 shall be used to determine opacity.
(4) Method 6 of appendix A of this part shall be used to determine
the SO2 concentration.
(i) The sampling site shall be the same as that selected for the
particulate sample. The sampling location in the duct shall be at the
centroid of the cross section or at a point no closer to the walls than
1 m (3.28 ft). The sampling time and sample volume for each sample run
shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples
shall be taken during a 1-hour period, with each sample taken within a
30-minute interval.
(ii) The emission rate correction factor, integrated sampling and
analysis procedure of Method 3B of appendix A of this part shall be used
to determine the O2 concentration (%O2). The
O2 sample shall be taken simultaneously with, and at the same
point as, the SO2 sample. The SO2 emission rate
shall be computed for each pair of SO2 and O2
samples. The SO2 emission rate (E) for each run shall be the
arithmetic mean of the results of the two pairs of samples.
(5) Method 7 of appendix A of this part shall be used to determine
the NOX concentration.
(i) The sampling site and location shall be the same as for the
SO2 sample. Each run shall consist of four grab samples, with
each sample taken at about 15-minute intervals.
(ii) For each NOX sample, the emission rate correction
factor, grab sampling and analysis procedure of Method 3B of appendix A
of this part shall be
[[Page 129]]
used to determine the O2 concentration (%O2). The
sample shall be taken simultaneously with, and at the same point as, the
NOX sample.
(iii) The NOX emission rate shall be computed for each
pair of NOX and O2 samples. The NOX
emission rate (E) for each run shall be the arithmetic mean of the
results of the four pairs of samples.
(c) When combinations of fossil fuels or fossil fuel and wood
residue are fired, the owner or operator (in order to compute the
prorated standard as shown in Sec. Sec. 60.43(b) and 60.44(b)) shall
determine the percentage (w, x, y, or z) of the total heat input derived
from each type of fuel as follows:
(1) The heat input rate of each fuel shall be determined by
multiplying the gross calorific value of each fuel fired by the rate of
each fuel burned.
(2) ASTM Methods D2015, or D5865 (solid fuels), D240 (liquid fuels),
or D1826 (gaseous fuels) (all of these methods are incorporated by
reference, see Sec. 60.17) shall be used to determine the gross
calorific values of the fuels. The method used to determine the
calorific value of wood residue must be approved by the Administrator.
(3) Suitable methods shall be used to determine the rate of each
fuel burned during each test period, and a material balance over the
steam generating system shall be used to confirm the rate.
(d) The owner or operator may use the following as alternatives to
the reference methods and procedures in this section or in other
sections as specified:
(1) The emission rate (E) of PM, SO2 and NOX
may be determined by using the Fc factor, provided that the following
procedure is used:
(i) The emission rate (E) shall be computed using the following
equation:
[GRAPHIC] [TIFF OMITTED] TR13JN07.007
Where:
E = Emission rate of pollutant, ng/J (lb/MMBtu);
C = Concentration of pollutant, ng/dscm (lb/dscf);
%CO2 = CO2 concentration, percent dry basis; and
Fc = Factor as determined in appropriate sections of Method
19 of appendix A of this part.
(ii) If and only if the average Fc factor in Method 19 of appendix A
of this part is used to calculate E and either E is from 0.97 to 1.00 of
the emission standard or the relative accuracy of a continuous emission
monitoring system is from 17 to 20 percent, then three runs of Method 3B
of appendix A of this part shall be used to determine the O2
and CO2 concentration according to the procedures in
paragraph (b)(2)(ii), (4)(ii), or (5)(ii) of this section. Then if
Fo (average of three runs), as calculated from the equation
in Method 3B of appendix A of this part, is more than 3 percent than the average Fo value, as
determined from the average values of Fd and Fc in
Method 19 of appendix A of this part, i.e., Foa = 0.209
(Fda/Fca), then the following procedure shall be
followed:
(A) When Fo is less than 0.97 Foa, then E
shall be increased by that proportion under 0.97 Foa, e.g.,
if Fo is 0.95 Foa, E shall be increased by 2
percent. This recalculated value shall be used to determine compliance
with the emission standard.
(B) When Fo is less than 0.97 Foa and when the
average difference (d) between the continuous monitor minus the
reference methods is negative, then E shall be increased by that
proportion under 0.97 Foa, e.g., if Fo is 0.95
Foa, E shall be increased by 2 percent. This recalculated
value shall be used to determine compliance with the relative accuracy
specification.
(C) When Fo is greater than 1.03 Foa and when
the average difference d is positive, then E shall be decreased by that
proportion over 1.03 Foa, e.g., if Fo is 1.05
Foa, E shall be decreased by 2 percent. This recalculated
value shall be used to determine compliance with the relative accuracy
specification.
(2) For Method 5 or 5B of appendix A-3 of this part, Method 17 of
appendix A-6 of this part may be used at facilities with or without wet
FGD systems if the stack gas temperature at the sampling location does
not exceed an average temperature of 160 [deg]C (320 [deg]F). The
procedures of sections 8.1 and 11.1 of Method 5B of appendix A-3 of this
part
[[Page 130]]
may be used with Method 17 of appendix A-6 of this part only if it is
used after wet FGD systems. Method 17 of appendix A-6 of this part shall
not be used after wet FGD systems if the effluent gas is saturated or
laden with water droplets.
(3) Particulate matter and SO2 may be determined
simultaneously with the Method 5 of appendix A of this part train
provided that the following changes are made:
(i) The filter and impinger apparatus in sections 2.1.5 and 2.1.6 of
Method 8 of appendix A of this part is used in place of the condenser
(section 2.1.7) of Method 5 of appendix A of this part.
(ii) All applicable procedures in Method 8 of appendix A of this
part for the determination of SO2 (including moisture) are
used:
(4) For Method 6 of appendix A of this part, Method 6C of appendix A
of this part may be used. Method 6A of appendix A of this part may also
be used whenever Methods 6 and 3B of appendix A of this part data are
specified to determine the SO2 emission rate, under the
conditions in paragraph (d)(1) of this section.
(5) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or
7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of
appendix A of this part is used, the sampling time for each run shall be
at least 1 hour and the integrated sampling approach shall be used to
determine the O2 concentration (%O2) for the
emission rate correction factor.
(6) For Method 3 of appendix A of this part, Method 3A or 3B of
appendix A of this part may be used.
(7) For Method 3B of appendix A of this part, Method 3A of appendix
A of this part may be used.
[60 FR 65415, Dec. 19, 1995, as amended at 74 FR 5078, Jan. 28, 2009]
Subpart Da_Standards of Performance for Electric Utility Steam
Generating Units
Source: 72 FR 32722, June 13, 2007, unless otherwise noted.
Sec. 60.40Da Applicability and designation of affected facility.
(a) Except as specified in paragraph (e) of this section, the
affected facility to which this subpart applies is each electric utility
steam generating unit:
(1) That is capable of combusting more than 73 megawatts (MW) (250
million British thermal units per hour (MMBtu/hr)) heat input of fossil
fuel (either alone or in combination with any other fuel); and
(2) For which construction, modification, or reconstruction is
commenced after September 18, 1978.
(b) An IGCC electric utility steam generating unit (both the
stationary combustion turbine and any associated duct burners) is
subject to this part and is not subject to subpart GG or KKKK of this
part if both of the conditions specified in paragraphs (b)(1) and (2) of
this section are met.
(1) The IGCC electric utility steam generating unit is capable of
combusting more than 73 MW (250 MMBtu/h) heat input of fossil fuel
(either alone or in combination with any other fuel) in the combustion
turbine engine and associated heat recovery steam generator; and
(2) The IGCC electric utility steam generating unit commenced
construction, modification, or reconstruction after February 28, 2005.
(c) Any change to an existing fossil-fuel-fired steam generating
unit to accommodate the use of combustible materials, other than fossil
fuels, shall not bring that unit under the applicability of this
subpart.
(d) Any change to an existing steam generating unit originally
designed to fire gaseous or liquid fossil fuels, to accommodate the use
of any other fuel (fossil or nonfossil) shall not bring that unit under
the applicability of this subpart.
(e) Applicability of this subpart to an electric utility combined
cycle gas turbine other than an IGCC electric utility steam generating
unit is as specified in paragraphs (e)(1) through (3) of this section.
(1) Affected facilities (i.e. heat recovery steam generators used
with duct burners) associated with a stationary combustion turbine that
are capable of combusting more than 73 MW (250
[[Page 131]]
MMBtu/h) heat input of fossil fuel are subject to this subpart except in
cases when the affected facility (i.e. heat recovery steam generator)
meets the applicability requirements of and is subject to subpart KKKK
of this part.
(2) For heat recovery steam generators use with duct burners subject
to this subpart, only emissions resulting from the combustion of fuels
in the steam generating unit (i.e. duct burners) are subject to the
standards under this subpart. (The emissions resulting from the
combustion of fuels in the stationary combustion turbine engine are
subject to subpart GG or KKKK, as applicable, of this part.)
(3) Any affected facility that meets the applicability requirements
and is subject to subpart Eb or subpart CCCC of this part is not subject
to the emission standards under subpart Da.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5078, Jan. 28, 2009; 77
FR 9448, Feb. 16, 2012]
Sec. 60.41Da Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Act and in subpart A of this part.
Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which are
independently and objectively evaluated in a judicial or administrative
proceeding.
Anthracite means coal that is classified as anthracite according to
the American Society of Testing and Materials in ASTM D388 (incorporated
by reference, see Sec. 60.17).
Available system capacity means the capacity determined by
subtracting the system load and the system emergency reserves from the
net system capacity.
Biomass means plant materials and animal waste.
Bituminous coal means coal that is classified as bituminous
according to the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec. 60.17).
Boiler operating day for units constructed, reconstructed, or
modified before March 1, 2005, means a 24-hour period during which
fossil fuel is combusted in a steam-generating unit for the entire 24
hours. For units constructed, reconstructed, or modified after February
28, 2005, boiler operating day means a 24-hour period between 12
midnight and the following midnight during which any fuel is combusted
at any time in the steam-generating unit. It is not necessary for fuel
to be combusted the entire 24-hour period.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec. 60.17) and
coal refuse. Synthetic fuels derived from coal for the purpose of
creating useful heat, including but not limited to solvent-refined coal,
gasified coal, coal-oil mixtures, and coal-water mixtures are included
in this definition for the purposes of this subpart.
Coal-fired electric utility steam generating unit means an electric
utility steam generating unit that burns coal, coal refuse, or a
synthetic gas derived from coal either exclusively, in any combination
together, or in any combination with other fuels in any amount.
Coal refuse means waste products of coal mining, physical coal
cleaning, and coal preparation operations (e.g. culm, gob, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material.
Combined cycle gas turbine means a stationary turbine combustion
system where heat from the turbine exhaust gases is recovered by a steam
generating unit.
Combined heat and power, also known as ``cogeneration,'' means a
steam-generating unit that simultaneously produces both electric (and
mechanical) and useful thermal energy from the same primary energy
source.
Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source, such as a stationary gas turbine,
internal combustion engine, kiln, etc., to allow the firing of
additional fuel to heat the exhaust gases before the exhaust gases enter
a heat recovery steam generating unit.
[[Page 132]]
Electric utility combined cycle gas turbine means any combined cycle
gas turbine used for electric generation that is constructed for the
purpose of supplying more than one-third of its potential electric
output capacity and more than 25 MW net-electrical output to any utility
power distribution system for sale. Any steam distribution system that
is constructed for the purpose of providing steam to a steam electric
generator that would produce electrical power for sale is also
considered in determining the electrical energy output capacity of the
affected facility.
Electric utility steam-generating unit means any steam electric
generating unit that is constructed for the purpose of supplying more
than one-third of its potential electric output capacity and more than
25 MW net-electrical output to any utility power distribution system for
sale. Also, any steam supplied to a steam distribution system for the
purpose of providing steam to a steam-electric generator that would
produce electrical energy for sale is considered in determining the
electrical energy output capacity of the affected facility.
Electrostatic precipitator or ESP means an add-on air pollution
control device used to capture particulate matter (PM) by charging the
particles using an electrostatic field, collecting the particles using a
grounded collecting surface, and transporting the particles into a
hopper.
Emission limitation means any emissions limit or operating limit.
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State implementation
plan, and any permit requirements established under 40 CFR 52.21 or
under 40 CFR 51.18 and 51.24.
Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such material for the
purpose of creating useful heat.
Gaseous fuel means any fuel that is present as a gas at standard
conditions and includes, but is not limited to, natural gas, refinery
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
Gross energy output means:
(1) For facilities constructed, reconstructed, or modified before
May 4, 2011, the gross electrical or mechanical output from the affected
facility plus 75 percent of the useful thermal output measured relative
to ISO conditions that is not used to generate additional electrical or
mechanical output or to enhance the performance of the unit (i.e., steam
delivered to an industrial process);
(2) For facilities constructed, reconstructed, or modified after May
3, 2011, the gross electrical or mechanical output from the affected
facility minus any electricity used to power the feedwater pumps and any
associated gas compressors (air separation unit main compressor, oxygen
compressor, and nitrogen compressor) plus 75 percent of the useful
thermal output measured relative to ISO conditions that is not used to
generate additional electrical or mechanical output or to enhance the
performance of the unit (i.e., steam delivered to an industrial
process);
(3) For combined heat and power facilities constructed,
reconstructed, or modified after May 3, 2011, the gross electrical or
mechanical output from the affected facility divided by 0.95 minus any
electricity used to power the feedwater pumps and any associated gas
compressors (air separation unit main compressor, oxygen compressor, and
nitrogen compressor) plus 75 percent of the useful thermal output
measured relative to ISO conditions that is not used to generate
additional electrical or mechanical output or to enhance the performance
of the unit (i.e., steam delivered to an industrial process);
(4) For a IGCC electric utility generating unit that coproduces
chemicals constructed, reconstructed, or modified after May 3, 2011, the
gross useful work performed is the gross electrical or mechanical output
from the unit minus electricity used to power the feedwater pumps and
any associated gas compressors (air separation unit main compressor,
oxygen compressor, and nitrogen compressor) that are associated with
power production plus 75 percent
[[Page 133]]
of the useful thermal output measured relative to ISO conditions that is
not used to generate additional electrical or mechanical output or to
enhance the performance of the unit (i.e., steam delivered to an
industrial process). Auxiliary loads that are associated with power
production are determined based on the energy in the coproduced
chemicals compared to the energy of the syngas combusted in combustion
turbine engine and associated duct burners.
24-hour period means the period of time between 12:01 a.m. and 12:00
midnight.
Integrated gasification combined cycle electric utility steam
generating unit or IGCC electric utility steam generating unit means an
electric utility combined cycle gas turbine that is designed to burn
fuels containing 50 percent (by heat input) or more solid-derived fuel
not meeting the definition of natural gas. The Administrator may waive
the 50 percent solid-derived fuel requirement during periods of the
gasification system construction, startup and commissioning, shutdown,
or repair. No solid fuel is directly burned in the unit during
operation.
ISO conditions means a temperature of 288 Kelvin, a relative
humidity of 60 percent, and a pressure of 101.3 kilopascals.
Lignite means coal that is classified as lignite A or B according to
the American Society of Testing and Materials in ASTM D388 (incorporated
by reference, see Sec. 60.17).
Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In addition,
natural gas contains 20.0 grains or less of total sulfur per 100
standard cubic feet. Finally, natural gas does not include the following
gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast
furnace gas, coal-derived gas, producer gas, coke oven gas, or any
gaseous fuel produced in a process which might result in highly variable
sulfur content or heating value.
Neighboring company means any one of those electric utility
companies with one or more electric power interconnections to the
principal company and which have geographically adjoining service areas.
Net-electric output means the gross electric sales to the utility
power distribution system minus purchased power on a calendar year
basis.
Net energy output means the gross energy output minus the parasitic
load associated with power production. Parasitic load includes, but is
not limited to, the power required to operate the equipment used for
fuel delivery systems, air pollution control systems, wastewater
treatment systems, ash handling and disposal systems, and other controls
(i.e., pumps, fans, compressors, motors, instrumentation, and other
ancillary equipment required to operate the affected facility).
Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
Out-of-control period means any period beginning with the quadrant
corresponding to the completion of a daily calibration error, linearity
check, or quality assurance audit that indicates that the instrument is
not measuring and recording within the applicable performance
specifications and ending with the quadrant corresponding to the
completion of an additional calibration error, linearity check, or
quality assurance audit following corrective action that demonstrates
that the instrument is measuring and recording within the applicable
performance specifications.
Petroleum for facilities constructed, reconstructed, or modified
before May 4, 2011, means crude oil or a fuel derived from crude oil,
including, but not limited to, distillate oil, and residual oil. For
units constructed, reconstructed, or modified after May 3, 2011,
petroleum means crude oil or a fuel derived from crude oil, including,
but not limited to, distillate oil, residual oil, and petroleum coke.
Petroleum coke, also known as ``petcoke,'' means a carbonization
product of high-boiling hydrocarbon fractions obtained in petroleum
processing (heavy residues). Petroleum coke
[[Page 134]]
is typically derived from oil refinery coker units or other cracking
processes.
Potential combustion concentration means the theoretical emissions
(nanograms per joule (ng/J), lb/MMBtu heat input) that would result from
combustion of a fuel in an uncleaned state without emission control
systems. For sulfur dioxide (SO2) the potential combustion
concentration is determined under Sec. 60.50Da(c).
Potential electrical output capacity means 33 percent of the maximum
design heat input capacity of the steam generating unit, divided by
3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr
(e.g., a steam generating unit with a 100 MW (340 MMBtu/hr) fossil-fuel
heat input capacity would have a 289,080 MWh 12 month potential
electrical output capacity). For electric utility combined cycle gas
turbines the potential electrical output capacity is determined on the
basis of the fossil-fuel firing capacity of the steam generator
exclusive of the heat input and electrical power contribution by the gas
turbine.
Resource recovery unit means a facility that combusts more than 75
percent non-fossil fuel on a quarterly (calendar) heat input basis.
Solid-derived fuel means any solid, liquid, or gaseous fuel derived
from solid fuel for the purpose of creating useful heat and includes,
but is not limited to, solvent refined coal, liquified coal, synthetic
gas, gasified coal, gasified petroleum coke, gasified biomass, and
gasified tire derived fuel.
Steam generating unit for facilities constructed, reconstructed, or
modified before May 4, 2011, means any furnace, boiler, or other device
used for combusting fuel for the purpose of producing steam (including
fossil-fuel-fired steam generators associated with combined cycle gas
turbines; nuclear steam generators are not included). For units
constructed, reconstructed, or modified after May 3, 2011, steam
generating unit means any furnace, boiler, or other device used for
combusting fuel for the purpose of producing steam (including fossil-
fuel-fired steam generators associated with combined cycle gas turbines;
nuclear steam generators are not included) plus any integrated
combustion turbines and fuel cells.
Subbituminous coal means coal that is classified as subbituminous A,
B, or C according to the American Society of Testing and Materials in
ASTM D388 (incorporated by reference, see Sec. 60.17).
Wet flue gas desulfurization technology or wet FGD means a
SO2 control system that is located downstream of the steam
generating unit and removes sulfur oxides from the combustion gases of
the steam generating unit by contacting the combustion gases with an
alkaline slurry or solution and forming a liquid material. This
definition applies to devices where the aqueous liquid material product
of this contact is subsequently converted to other forms. Alkaline
reagents used in wet FGD technology include, but are not limited to,
lime, limestone, and sodium.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5079, Jan. 28, 2009; 77
FR 9448, Feb. 16, 2012; 77 FR 23402, Apr. 19, 2012; 78 FR 24082, Apr.
24, 2013]
Sec. 60.42Da Standards for particulate matter (PM).
(a) Except as provided in paragraph (f) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
an owner or operator of an affected facility shall not cause to be
discharged into the atmosphere from any affected facility for which
construction, reconstruction, or modification commenced before March 1,
2005, any gases that contain PM in excess of 13 ng/J (0.03 lb/MMBtu)
heat input.
(b) Except as provided in paragraphs (b)(1) and (b)(2) of this
section, on and after the date the initial PM performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, an owner or operator of an affected facility shall not
cause to be discharged into the atmosphere any gases which exhibit
greater than 20 percent opacity (6-minute average), except for one 6-
minute period per hour of not more than 27 percent opacity.
(1) An owner or operator of an affected facility that elects to
install, calibrate, maintain, and operate a continuous emissions
monitoring system (CEMS) for measuring PM emissions
[[Page 135]]
according to the requirements of this subpart is exempt from the opacity
standard specified in this paragraph (b) of this section.
(2) An owner or operator of an affected facility that combusts only
natural gas and/or synthetic natural gas that chemically meets the
definition of natural gas is exempt from the opacity standard specified
in paragraph (b) of this section.
(c) Except as provided in paragraphs (d) and (f) of this section, on
and after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that commenced
construction, reconstruction, or modification after February 28, 2005,
but before May 4, 2011, shall cause to be discharged into the atmosphere
from that affected facility any gases that contain PM in excess of
either:
(1) 18 ng/J (0.14 lb/MWh) gross energy output; or
(2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the combustion
of solid, liquid, or gaseous fuel.
(d) As an alternative to meeting the requirements of paragraph (c)
of this section, the owner or operator of an affected facility for which
construction, reconstruction, or modification commenced after February
28, 2005, but before May 4, 2011, may elect to meet the requirements of
this paragraph. On and after the date on which the initial performance
test is completed or required to be completed under Sec. 60.8,
whichever date comes first, no owner or operator of an affected facility
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain PM in excess of:
(1) 13 ng/J (0.030 lb/MMBtu) heat input derived from the combustion
of solid, liquid, or gaseous fuel, and
(2) For an affected facility that commenced construction or
reconstruction, 0.1 percent of the combustion concentration determined
according to the procedure in Sec. 60.48Da(o)(5) (99.9 percent
reduction) when combusting solid, liquid, or gaseous fuel, or
(3) For an affected facility that commenced modification, 0.2
percent of the combustion concentration determined according to the
procedure in Sec. 60.48Da(o)(5) (99.8 percent reduction) when
combusting solid, liquid, or gaseous fuel.
(e) Except as provided in paragraph (f) of this section, the owner
or operator of an affected facility that commenced construction,
reconstruction, or modification commenced after May 3, 2011, shall meet
the requirements specified in paragraphs (e)(1) and (2) of this section.
(1) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, the owner or operator shall not cause to be discharged into
the atmosphere from that affected facility any gases that contain PM in
excess of the applicable emissions limit specified in paragraphs
(e)(1)(i) or (ii) of this section.
(i) For an affected facility which commenced construction or
reconstruction:
(A) 11 ng/J (0.090 lb/MWh) gross energy output; or
(B) 12 ng/J (0.097 lb/MWh) net energy output.
(ii) For an affected facility which commenced modification, the
emission limits specified in paragraphs (c) or (d) of this section.
(2) During startup periods and shutdown periods, owners or operators
of facilities subject to subpart UUUUU of part 63 of this chapter shall
meet the work practice standards specified in Table 3 to subpart UUUUU
of part 63 and use the relevant definitions in Sec. 63.10042, and
owners or operators of facilities subject to subpart DDDDD of part 63
shall meet the work practice standards specified in Table 3 to subpart
DDDDD of part 63 and use the relevant definition used in Sec. 63.7575.
(f) An owner or operator of an affected facility that meets the
conditions in either paragraphs (f)(1) or (2) of this section is exempt
from the PM emissions limits in this section.
(1) The affected facility combusts only gaseous or liquid fuels
(excluding residual oil) with potential SO2 emissions rates
of 26 ng/J (0.060 lb/MMBtu) or less, and that does not use a post-
combustion technology to reduce emissions of SO2 or PM.
(2) The affected facility is operated under a PM commercial
demonstration
[[Page 136]]
permit issued by the Administrator according to the provisions of Sec.
60.47Da.
[77 FR 9450, Feb. 16, 2012, as amended at 78 FR 24083, Apr. 24, 2013; 79
FR 68788, Nov. 19, 2014]
Sec. 60.43Da Standards for sulfur dioxide (SO[bdi2]).
(a) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility which combusts solid fuel or solid-derived fuel and
for which construction, reconstruction, or modification commenced before
or on February 28, 2005, except as provided under paragraphs (c), (d),
(f) or (h) of this section, any gases that contain SO2 in
excess of:
(1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the
potential combustion concentration (90 percent reduction);
(2) 30 percent of the potential combustion concentration (70 percent
reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat
input;
(3) 180 ng/J (1.4 lb/MWh) gross energy output; or
(4) 65 ng/J (0.15 lb/MMBtu) heat input.
(b) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility which combusts liquid or gaseous fuels (except for
liquid or gaseous fuels derived from solid fuels and as provided under
paragraphs (e) or (h) of this section) and for which construction,
reconstruction, or modification commenced before or on February 28,
2005, any gases that contain SO2 in excess of:
(1) 340 ng/J (0.80 lb/MMBtu) heat input and 10 percent of the
potential combustion concentration (90 percent reduction); or
(2) 100 percent of the potential combustion concentration (zero
percent reduction) when emissions are less than 86 ng/J (0.20 lb/MMBtu)
heat input.
(c) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility which combusts solid solvent refined coal (SRC-I) any
gases that contain SO2 in excess of 520 ng/J (1.20 lb/MMBtu)
heat input and 15 percent of the potential combustion concentration (85
percent reduction) except as provided under paragraph (f) of this
section; compliance with the emission limitation is determined on a 30-
day rolling average basis and compliance with the percent reduction
requirement is determined on a 24-hour basis.
(d) Sulfur dioxide emissions are limited to 520 ng/J (1.20 lb/MMBtu)
heat input from any affected facility which:
(1) Combusts 100 percent anthracite;
(2) Is classified as a resource recovery unit; or
(3) Is located in a noncontinental area and combusts solid fuel or
solid-derived fuel.
(e) Sulfur dioxide emissions are limited to 340 ng/J (0.80 lb/MMBtu)
heat input from any affected facility which is located in a
noncontinental area and combusts liquid or gaseous fuels (excluding
solid-derived fuels).
(f) The SO2 standards under this section do not apply to
an owner or operator of an affected facility that is operated under an
SO2 commercial demonstration permit issued by the
Administrator in accordance with the provisions of Sec. 60.47Da.
(g) Compliance with the emission limitation and percent reduction
requirements under this section are both determined on a 30-day rolling
average basis except as provided under paragraph (c) of this section.
(h) When different fuels are combusted simultaneously, the
applicable standard is determined by proration using the following
formula:
(1) If emissions of SO2 to the atmosphere are greater
than 260 ng/J (0.60 lb/MMBtu) heat input
[GRAPHIC] [TIFF OMITTED] TR13JN07.008
[[Page 137]]
(2) If emissions of SO2 to the atmosphere are equal to or
less than 260 ng/J (0.60 lb/MMBtu) heat input:
[GRAPHIC] [TIFF OMITTED] TR13JN07.009
Where:
Es = Prorated SO2 emission limit (ng/J heat
input);
%Ps = Percentage of potential SO2 emission
allowed;
x = Percentage of total heat input derived from the combustion of liquid
or gaseous fuels (excluding solid-derived fuels); and
y = Percentage of total heat input derived from the combustion of solid
fuel (including solid-derived fuels).
(i) Except as provided in paragraphs (j) and (k) of this section, on
and after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility for which construction,
reconstruction, or modification commenced after February 28, 2005, but
before May 4, 2011, shall cause to be discharged into the atmosphere
from that affected facility, any gases that contain SO2 in
excess of the applicable emissions limit specified in paragraphs (i)(1)
through (3) of this section.
(1) For an affected facility which commenced construction, any gases
that contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output; or
(ii) 5 percent of the potential combustion concentration (95 percent
reduction).
(2) For an affected facility which commenced reconstruction, any
gases that contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
(iii) 5 percent of the potential combustion concentration (95
percent reduction).
(3) For an affected facility which commenced modification, any gases
that contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
(iii) 10 percent of the potential combustion concentration (90
percent reduction).
(j) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification commenced after February
28, 2005, and that burns 75 percent or more (by heat input) coal refuse
on a 12-month rolling average basis, shall caused to be discharged into
the atmosphere from that affected facility any gases that contain
SO2 in excess of the applicable emission limitation specified
in paragraphs (j)(1) through (3) of this section.
(1) For an affected facility for which construction commenced after
February 28, 2005, any gases that contain SO2 in excess of
either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis; or
(ii) 6 percent of the potential combustion concentration (94 percent
reduction) on a 30-day rolling average basis.
(2) For an affected facility for which reconstruction commenced
after February 28, 2005, any gases that contain SO2 in excess
of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis; or
(iii) 6 percent of the potential combustion concentration (94
percent reduction) on a 30-day rolling average basis.
(3) For an affected facility for which modification commenced after
February 28, 2005, any gases that contain SO2 in excess of
either:
[[Page 138]]
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis; or
(iii) 10 percent of the potential combustion concentration (90
percent reduction) on a 30-day rolling average basis.
(k) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility located in a
noncontinental area for which construction, reconstruction, or
modification commenced after February 28, 2005, but before May 4, 2011,
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of the
applicable emissions limit specified in paragraphs (k)(1) and (2) of
this section.
(1) For an affected facility that burns solid or solid-derived fuel,
the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 520 ng/J
(1.2 lb/MMBtu) heat input.
(2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged
into the atmosphere any gases that contain SO2 in excess of
230 ng/J (0.54 lb/MMBtu) heat input.
(l) Except as provided in paragraphs (j) and (m) of this section, on
and after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility for which construction,
reconstruction, or modification commenced after May 3, 2011, shall cause
to be discharged into the atmosphere from that affected facility, any
gases that contain SO2 in excess of the applicable emissions
limit specified in paragraphs (l)(1) and (2) of this section.
(1) For an affected facility which commenced construction or
reconstruction, any gases that contain SO2 in excess of
either:
(i) 130 ng/J (1.0 lb/MWh) gross energy output; or
(ii) 140 ng/J (1.2 lb/MWh) net energy output; or
(iii) 3 percent of the potential combustion concentration (97
percent reduction).
(2) For an affected facility which commenced modification, any gases
that contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output; or
(ii) 10 percent of the potential combustion concentration (90
percent reduction).
(m) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility located in a
noncontinental area for which construction, reconstruction, or
modification commenced after May 3, 2011, shall cause to be discharged
into the atmosphere from that affected facility any gases that contain
SO2 in excess of the applicable emissions limit specified in
paragraphs (m)(1) and (2) of this section.
(1) For an affected facility that burns solid or solid-derived fuel,
the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 520 ng/J
(1.2 lb/MMBtu) heat input.
(2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged
into the atmosphere any gases that contain SO2 in excess of
230 ng/J (0.54 lb/MMBtu) heat input.
[72 FR 32722, June 13, 2007, as amended at 77 FR 9450, Feb. 16, 2012]
Sec. 60.44Da Standards for nitrogen oxides (NOX).
(a) Except as provided in paragraph (h) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator subject to the provisions of this subpart shall
cause to be discharged into the atmosphere from any affected facility
for which construction, reconstruction, or modification commenced before
July 10, 1997 any gases that contain NOX (expressed as
NO2) in excess of the applicable emissions limit in
paragraphs (a)(1) and (2) of this section.
[[Page 139]]
(1) The owner or operator shall not cause to be discharged into the
atmosphere any gases that contain NOX in excess of the
emissions limit listed in the following table as applicable to the fuel
type combusted and as determined on a 30-boiler operating day rolling
average basis.
------------------------------------------------------------------------
Emission limit for heat
input
Fuel type -------------------------
ng/J lb/MMBtu
------------------------------------------------------------------------
Gaseous fuels:
Coal-derived fuels........................ 210 0.50
All other fuels........................... 86 0.20
Liquid fuels:
Coal-derived fuels........................ 210 0.50
Shale oil................................. 210 0.50
All other fuels........................... 130 0.30
Solid fuels:
Coal-derived fuels........................ 210 0.50
Any fuel containing more than 25%, by (\1\) (\1\)
weight, coal refuse......................
Any fuel containing more than 25%, by weight, 340 0.80
lignite if the lignite is mined in North
Dakota, South Dakota, or Montana, and is
combusted in a slag tap furnace \2\..........
Any fuel containing more than 25%, by weight, 260 0.60
lignite not subject to the 340 ng/J heat
input emission limit \2\.....................
Subbituminous coal............................ 210 0.50
Bituminous coal............................... 260 0.60
Anthracite coal............................... 260 0.60
All other fuels............................... 260 0.60
------------------------------------------------------------------------
\1\ Exempt from NOX standards and NOX monitoring requirements.
\2\ Any fuel containing less than 25%, by weight, lignite is not
prorated but its percentage is added to the percentage of the
predominant fuel.
(2) When two or more fuels are combusted simultaneously in an
affected facility, the applicable emissions limit (En) is
determined by proration using the following formula:
[GRAPHIC] [TIFF OMITTED] TR16FE12.019
Where:
En = Applicable NOX emissions limit when multiple fuels are
combusted simultaneously (ng/J heat input);
w = Percentage of total heat input derived from the combustion of fuels
subject to the 86 ng/J heat input standard;
x = Percentage of total heat input derived from the combustion of fuels
subject to the 130 ng/J heat input standard;
y = Percentage of total heat input derived from the combustion of fuels
subject to the 210 ng/J heat input standard;
z = Percentage of total heat input derived from the combustion of fuels
subject to the 260 ng/J heat input standard; and
v = Percentage of total heat input delivered from the combustion of
fuels subject to the 340 ng/J heat input standard.
(b)-(c) [Reserved]
(d) Except as provided in paragraph (h) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that commenced
construction, reconstruction, or modification after July 9, 1997, but
before March 1, 2005, shall cause to be discharged into the atmosphere
from that affected facility any gases that contain NOX
(expressed as NO2) in excess of the applicable emissions
limit specified in paragraphs (d)(1) and (2) of this section as
determined on a 30-boiler operating day rolling average basis.
(1) For an affected facility which commenced construction, any gases
that contain NOX in excess of 200 ng/J (1.6 lb/MWh) gross
energy output.
(2) For an affected facility which commenced reconstruction, any
gases that contain NOX in excess of 65 ng/J (0.15 lb/MMBtu)
heat input.
[[Page 140]]
(e) Except as provided in paragraphs (f) and (h) of this section, on
and after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that commenced
construction, reconstruction, or modification after February 28, 2005
but before May 4, 2011, shall cause to be discharged into the atmosphere
from that affected facility any gases that contain NOX
(expressed as NO2) in excess of the applicable emissions
limit specified in paragraphs (e)(1) through (3) of this section as
determined on a 30-boiler operating day rolling average basis.
(1) For an affected facility which commenced construction, any gases
that contain NOX in excess of 130 ng/J (1.0 lb/MWh) gross
energy output.
(2) For an affected facility which commenced reconstruction, any
gases that contain NOX in excess of either:
(i) 130 ng/J (1.0 lb/MWh) gross energy output; or
(ii) 47 ng/J (0.11 lb/MMBtu) heat input.
(3) For an affected facility which commenced modification, any gases
that contain NOX in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output; or
(ii) 65 ng/J (0.15 lb/MMBtu) heat input.
(f) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, the owner or operator of an IGCC electric utility steam
generating unit subject to the provisions of this subpart and for which
construction, reconstruction, or modification commenced after February
28, 2005 but before May 4, 2011, shall meet the requirements specified
in paragraphs (f)(1) through (3) of this section.
(1) Except as provided for in paragraphs (f)(2) and (3) of this
section, the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain NOX (expressed as
NO2) in excess of 130 ng/J (1.0 lb/MWh) gross energy output.
(2) When burning liquid fuel exclusively or in combination with
solid-derived fuel such that the liquid fuel contributes 50 percent or
more of the total heat input to the combined cycle combustion turbine,
the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain NOX (expressed as
NO2) in excess of 190 ng/J (1.5 lb/MWh) gross energy output.
(3) In cases when during a 30-boiler operating day rolling average
compliance period liquid fuel is burned in such a manner to meet the
conditions in paragraph (f)(2) of this section for only a portion of the
clock hours in the 30-day compliance period, the owner or operator shall
not cause to be discharged into the atmosphere any gases that contain
NOX (expressed as NO2) in excess of the computed
weighted-average emissions limit based on the proportion of gross energy
output (in MWh) generated during the compliance period for each of
emissions limits in paragraphs (f)(1) and (2) of this section.
(g) Except as provided in paragraphs (h) of this section and Sec.
60.45Da, on and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification after May 3, 2011, shall
cause to be discharged into the atmosphere from that affected facility
any gases that contain NOX (expressed as NO2) in
excess of the applicable emissions limit specified in paragraphs (g)(1)
through (3) of this section.
(1) For an affected facility which commenced construction or
reconstruction, any gases that contain NOX in excess of
either:
(i) 88 ng/J (0.70 lb/MWh) gross energy output; or
(ii) 95 ng/J (0.76 lb/MWh) net energy output.
(2) For an affected facility which commenced construction or
reconstruction and that burns 75 percent or more coal refuse (by heat
input) on a 12-month rolling average basis, any gases that contain
NOX in excess of either:
(i) 110 ng/J (0.85 lb/MWh) gross energy output; or
(ii) 120 ng/J (0.92 lb/MWh) net energy output.
(3) For an affected facility which commenced modification, any gases
[[Page 141]]
that contain NOX in excess of 140 ng/J (1.1 lb/MWh) gross
energy output.
(h) The NOX emissions limits under this section do not
apply to an owner or operator of an affected facility which is operating
under a commercial demonstration permit issued by the Administrator in
accordance with the provisions of Sec. 60.47Da.
[77 FR 9451, Feb. 16, 2012]
Sec. 60.45Da Alternative standards for combined nitrogen oxides (NOX)
and carbon monoxide (CO).
(a) The owner or operator of an affected facility that commenced
construction, reconstruction, or modification after May 3, 2011 as
alternate to meeting the applicable NOX emissions limits
specified in Sec. 60.44Da may elect to meet the applicable standards
for combined NOX and CO specified in paragraph (b) of this
section.
(b) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8 no owner or
operator of an affected facility that commenced construction,
reconstruction, or modification after May 3, 2011, shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain NOX (expressed as NO2) plus CO in
excess of the applicable emissions limit specified in paragraphs (b)(1)
through (3) of this section as determined on a 30-boiler operating day
rolling average basis.
(1) For an affected facility which commenced construction or
reconstruction, any gases that contain NOX plus CO in excess
of either:
(i) 140 ng/J (1.1 lb/MWh) gross energy output; or
(ii) 150 ng/J (1.2 lb/MWh) net energy output.
(2) For an affected facility which commenced construction or
reconstruction and that burns 75 percent or more coal refuse (by heat
input) on a 12-month rolling average basis, any gases that contain
NOX plus CO in excess of either:
(i) 160 ng/J (1.3 lb/MWh) gross energy output; or
(ii) 170 ng/J (1.4 lb/MWh) net energy output.
(3) For an affected facility which commenced modification, any gases
that contain NOX plus CO in excess of 190 ng/J (1.5 lb/MWh)
gross energy output.
[77 FR 9453, Feb. 16, 2012]
Sec. 60.46Da [Reserved]
Sec. 60.47Da Commercial demonstration permit.
(a) An owner or operator of an affected facility proposing to
demonstrate an emerging technology may apply to the Administrator for a
commercial demonstration permit. The Administrator will issue a
commercial demonstration permit in accordance with paragraph (e) of this
section. Commercial demonstration permits may be issued only by the
Administrator, and this authority will not be delegated.
(b) An owner or operator of an affected facility that combusts solid
solvent refined coal (SRC-I) and who is issued a commercial
demonstration permit by the Administrator is not subject to the
SO2 emission reduction requirements under Sec. 60.43Da(c)
but must, as a minimum, reduce SO2 emissions to 20 percent of
the potential combustion concentration (80 percent reduction) for each
24-hour period of steam generator operation and to less than 520 ng/J
(1.20 lb/MMBtu) heat input on a 30-day rolling average basis.
(c) An owner or operator of an affected facility that uses fluidized
bed combustion (atmospheric or pressurized) and who is issued a
commercial demonstration permit by the Administrator is not subject to
the SO2 emission reduction requirements under Sec.
60.43Da(a) but must, as a minimum, reduce SO2 emissions to 15
percent of the potential combustion concentration (85 percent reduction)
on a 30-day rolling average basis and to less than 520 ng/J (1.20 lb/
MMBtu) heat input on a 30-day rolling average basis.
(d) The owner or operator of an affected facility that combusts
coal-derived liquid fuel and who is issued a commercial demonstration
permit by the Administrator is not subject to the applicable
NOX emission limitation and percent reduction under Sec.
60.44Da(a) but must, as a minimum, reduce emissions to less than 300 ng/
J (0.70 lb/MMBtu)
[[Page 142]]
heat input on a 30-day rolling average basis.
(e) Commercial demonstration permits may not exceed the following
equivalent MW electrical generation capacity for any one technology
category, and the total equivalent MW electrical generation capacity for
all commercial demonstration plants may not exceed 15,000 MW.
------------------------------------------------------------------------
Equivalent
electrical
Technology Pollutant capacity (MW
electrical output)
------------------------------------------------------------------------
Solid solvent refined coal (SCR SO2............... 6,000-10,000
I).
Fluidized bed combustion SO2............... 400-3,000
(atmospheric).
Fluidized bed combustion SO2............... 400-1,200
(pressurized).
Coal liquification.............. NOX............... 750-10,000
---------------------------------------
Total allowable for all .................. 15,000
technologies.
------------------------------------------------------------------------
(f) An owner or operator of an affected facility that uses a
pressurized fluidized bed or a multi-pollutant emissions controls system
who is issued a commercial demonstration permit by the Administrator is
not subject to the total PM emission reduction requirements under Sec.
60.42Da but must, as a minimum, reduce PM emissions to less than 6.4 ng/
J (0.015 lb/MMBtu) heat input.
(g) An owner or operator of an affected facility that uses a
pressurized fluidized bed or a multi-pollutant emissions controls system
who is issued a commercial demonstration permit by the Administrator is
not subject to the SO2 standards or emission reduction
requirements under Sec. 60.43Da but must, as a minimum, reduce
SO2 emissions to 5 percent of the potential combustion
concentration (95 percent reduction) or to less than 180 ng/J (1.4 lb/
MWh) gross energy output on a 30-boiler operating day rolling average
basis.
(h) An owner or operator of an affected facility that uses a
pressurized fluidized bed or a multi-pollutant emissions control system
or advanced combustion controls who is issued a commercial demonstration
permit by the Administrator is not subject to the NOX
standards or emission reduction requirements under Sec. 60.44Da but
must, as a minimum, reduce NOX emissions to less than 130 ng/
J (1.0 lb/MWh) or the combined NOX plus CO emissions to less
than 180 ng/J (1.4 lb/MWh) gross energy output on a 30-boiler operating
day rolling average basis.
(i) Commercial demonstration permits may not exceed the following
equivalent MW electrical generation capacity for any one technology
category listed in the following table.
------------------------------------------------------------------------
Equivalent
electrical
Technology Pollutant capacity (MW
electrical output)
------------------------------------------------------------------------
Multi-pollutant Emission Control SO2............... 1,000
Multi-pollutant Emission Control NOX............... 1,000
Multi-pollutant Emission Control PM................ 1,000
Pressurized Fluidized Bed SO2............... 1,000
Combustion.
Pressurized Fluidized Bed NOX............... 1,000
Combustion.
Pressurized Fluidized Bed PM................ 1,000
Combustion.
Advanced Combustion Controls.... NOX............... 1,000
------------------------------------------------------------------------
[72 FR 32722, June 13, 2007, as amended at 77 FR 9450, Feb. 16, 2012]
Sec. 60.48Da Compliance provisions.
(a) For affected facilities for which construction, modification, or
reconstruction commenced before May 4, 2011, the applicable PM emissions
limit and opacity standard under Sec. 60.42Da, SO2 emissions
limit under Sec. 60.43Da, and NOX emissions limit under
Sec. 60.44Da apply at all times except during periods of startup,
shutdown, or malfunction. For affected facilities for which
construction, modification, or reconstruction commenced after May 3,
2011, the applicable SO2 emissions limit under Sec. 60.43Da,
NOX emissions limit
[[Page 143]]
under Sec. 60.44Da, and NOX plus CO emissions limit under
Sec. 60.45Da apply at all times. The applicable PM emissions limit and
opacity standard under Sec. 60.42Da apply at all times except during
periods of startup and shutdown.
(b) After the initial performance test required under Sec. 60.8,
compliance with the applicable SO2 emissions limit and
percentage reduction requirements under Sec. 60.43Da, NOX
emissions limit under Sec. 60.44Da, and NOX plus CO
emissions limit under Sec. 60.45Da is based on the average emission
rate for 30 successive boiler operating days. A separate performance
test is completed at the end of each boiler operating day after the
initial performance test, and a new 30-boiler operating day rolling
average emission rate for both SO2, NOX or
NOX plus CO as applicable, and a new percent reduction for
SO2 are calculated to demonstrate compliance with the
standards.
(c) For the initial performance test required under Sec. 60.8,
compliance with the applicable SO2 emissions limits and
percentage reduction requirements under Sec. 60.43Da, the
NOX emissions limits under Sec. 60.44Da, and the
NOX plus CO emissions limits under Sec. 60.45Da is based on
the average emission rates for SO2, NOX, CO, and
percent reduction for SO2 for the first 30 successive boiler
operating days. The initial performance test is the only test in which
at least 30 days prior notice is required unless otherwise specified by
the Administrator. The initial performance test is to be scheduled so
that the first boiler operating day of the 30 successive boiler
operating days is completed within 60 days after achieving the maximum
production rate at which the affected facility will be operated, but not
later than 180 days after initial startup of the facility.
(d) For affected facilities for which construction, modification, or
reconstruction commenced before May 4, 2011, compliance with applicable
30-boiler operating day rolling average SO2 and
NOX emissions limits is determined by calculating the
arithmetic average of all hourly emission rates for SO2 and
NOX for the 30 successive boiler operating days, except for
data obtained during startup, shutdown, or malfunction. For affected
facilities for which construction, modification, or reconstruction
commenced after May 3, 2011, compliance with applicable 30-boiler
operating day rolling average SO2 and NOX
emissions limits is determined by dividing the sum of the SO2
and NOX emissions for the 30 successive boiler operating days
by the sum of the gross energy output or net energy output, as
applicable, for the 30 successive boiler operating days.
(e) For affected facilities for which construction, modification, or
reconstruction commenced before May 4, 2011, compliance with applicable
SO2 percentage reduction requirements is determined based on
the average inlet and outlet SO2 emission rates for the 30
successive boiler operating days. For affected facilities for which
construction, modification, or reconstruction commenced after May 3,
2011, compliance with applicable SO2 percentage reduction
requirements is determined based on the ``as fired'' total potential
emissions and the total outlet SO2 emissions for the 30
successive boiler operating days.
(f) For affected facilities for which construction, modification, or
reconstruction commenced before May 4, 2011, compliance with the
applicable daily average PM emissions limit is determined by calculating
the arithmetic average of all hourly emission rates each boiler
operating day, except for data obtained during startup, shutdown, or
malfunction periods. Daily averages are only calculated for boiler
operating days that have non-out-of-control data for at least 18 hours
of unit operation during which the standard applies. Instead, all of the
non-out-of-control hourly emission rates of the operating day(s) not
meeting the minimum 18 hours non-out-of-control data daily average
requirement are averaged with all of the non-out-of-control hourly
emission rates of the next boiler operating day with 18 hours or more of
non-out-of-control PM CEMS data to determine compliance. For affected
facilities for which construction or reconstruction commenced after May
3, 2011 that elect to demonstrate compliance using PM CEMS, compliance
with the applicable PM emissions limit in Sec. 60.42Da is determined on
a 30-boiler operating day rolling average basis by
[[Page 144]]
calculating the arithmetic average of all hourly PM emission rates for
the 30 successive boiler operating days, except for data obtained during
periods of startup and shutdown.
(g) For affected facilities for which construction, modification, or
reconstruction commenced after May 3, 2011, compliance with applicable
30-boiler operating day rolling average NOX plus CO emissions
limit is determined by dividing the sum of the NOX plus CO
emissions for the 30 successive boiler operating days by the sum of the
gross energy output or net energy output, as applicable, for the 30
successive boiler operating days.
(h) If an owner or operator has not obtained the minimum quantity of
emission data as required under Sec. 60.49Da of this subpart,
compliance of the affected facility with the emission requirements under
Sec. Sec. 60.43Da and 60.44Da of this subpart for the day on which the
30-day period ends may be determined by the Administrator by following
the applicable procedures in section 7 of Method 19 of appendix A of
this part.
(i) Compliance provisions for sources subject to Sec.
60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), (f), or (g). The owner or
operator shall calculate NOX emissions as 1.194 x
10-7 lb/scf-ppm times the average hourly NOX
output concentration in ppm (measured according to the provisions of
Sec. 60.49Da(c)), times the average hourly flow rate (measured in scfh,
according to the provisions of Sec. 60.49Da(l) or Sec. 60.49Da(m)),
divided by the average hourly gross energy output (measured according to
the provisions of Sec. 60.49Da(k)) or the average hourly net energy
output, as applicable. Alternatively, for oil-fired and gas-fired units,
NOX emissions may be calculated by multiplying the hourly
NOX emission rate in lb/MMBtu (measured by the CEMS required
under Sec. 60.49Da(c) and (d)), by the hourly heat input rate (measured
according to the provisions of Sec. 60.49Da(n)), and dividing the
result by the average gross energy output (measured according to the
provisions of Sec. 60.49Da(k)) or the average hourly net energy output,
as applicable.
(j) Compliance provisions for duct burners subject to Sec.
60.44Da(a)(1). To determine compliance with the emissions limits for
NOX required by Sec. 60.44Da(a) for duct burners used in
combined cycle systems, either of the procedures described in paragraph
(j)(1) or (2) of this section may be used:
(1) The owner or operator of an affected duct burner shall conduct
the performance test required under Sec. 60.8 using the appropriate
methods in appendix A of this part. Compliance with the emissions limits
under Sec. 60.44Da(a)(1) is determined on the average of three (nominal
1-hour) runs for the initial and subsequent performance tests. During
the performance test, one sampling site shall be located in the exhaust
of the turbine prior to the duct burner. A second sampling site shall be
located at the outlet from the heat recovery steam generating unit.
Measurements shall be taken at both sampling sites during the
performance test; or
(2) The owner or operator of an affected duct burner may elect to
determine compliance by using the CEMS specified under Sec. 60.49Da for
measuring NOX and oxygen (O2) (or carbon dioxide
(CO2)) and meet the requirements of Sec. 60.49Da.
Alternatively, data from a NOX emission rate (i.e.,
NOX-diluent) CEMS certified according to the provisions of
Sec. 75.20(c) of this chapter and appendix A to part 75 of this
chapter, and meeting the quality assurance requirements of Sec. 75.21
of this chapter and appendix B to part 75 of this chapter, may be used,
with the following caveats. Data used to meet the requirements of Sec.
60.51Da shall not include substitute data values derived from the
missing data procedures in subpart D of part 75 of this chapter, nor
shall the data have been bias adjusted according to the procedures of
part 75 of this chapter. The sampling site shall be located at the
outlet from the steam generating unit. The NOX emission rate
at the outlet from the steam generating unit shall constitute the
NOX emission rate from the duct burner of the combined cycle
system.
(k) Compliance provisions for duct burners subject to Sec.
60.44Da(d)(1) or (e)(1). To determine compliance with the emission
limitation for NOX required by Sec. 60.44Da(d)(1) or (e)(1)
for duct burners used in combined cycle systems, either of the
procedures described in
[[Page 145]]
paragraphs (k)(1) and (2) of this section may be used:
(1) The owner or operator of an affected duct burner used in
combined cycle systems shall determine compliance with the applicable
NOX emission limitation in Sec. 60.44Da(d)(1) or (e)(1) as
follows:
(i) The emission rate (E) of NOX shall be computed using
Equation 2 in this section:
[GRAPHIC] [TIFF OMITTED] TR16FE12.000
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/MWh)
gross energy output;
Csg = Average hourly concentration of NOX exiting
the steam generating unit, ng/dscm (lb/dscf);
Cte = Average hourly concentration of NOX in the
turbine exhaust upstream from duct burner, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas from
steam generating unit, dscm/h (dscf/h);
Qte = Average hourly volumetric flow rate of exhaust gas from
combustion turbine, dscm/h (dscf/h);
Osg = Average hourly gross energy output from steam
generating unit, J/h (MW); and
h = Average hourly fraction of the total heat input to the steam
generating unit derived from the combustion of fuel in the
affected duct burner.
(ii) Method 7E of appendix A of this part shall be used to determine
the NOX concentrations (Csg and Cte).
Method 2, 2F or 2G of appendix A of this part, as appropriate, shall be
used to determine the volumetric flow rates (Qsg and
Qte) of the exhaust gases. The volumetric flow rate
measurements shall be taken at the same time as the concentration
measurements.
(iii) The owner or operator shall develop, demonstrate, and provide
information satisfactory to the Administrator to determine the average
hourly gross energy output from the steam generating unit, and the
average hourly percentage of the total heat input to the steam
generating unit derived from the combustion of fuel in the affected duct
burner.
(iv) Compliance with the applicable NOX emission
limitation in Sec. 60.44Da(d)(1) or (e)(1) is determined by the three-
run average (nominal 1-hour runs) for the initial and subsequent
performance tests.
(2) The owner or operator of an affected duct burner used in a
combined cycle system may elect to determine compliance with the
applicable NOX emission limitation in Sec. 60.44Da(d)(1) or
(e)(1) on a 30-day rolling average basis as indicated in paragraphs
(k)(2)(i) through (iv) of this section.
(i) The emission rate (E) of NOX shall be computed using
Equation 3 in this section:
[GRAPHIC] [TIFF OMITTED] TR16FE12.001
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/MWh)
gross energy output;
Csg = Average hourly concentration of NOX exiting
the steam generating unit, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas from
steam generating unit, dscm/h (dscf/h); and
Occ = Average hourly gross energy output from entire combined
cycle unit, J/h (MW).
(ii) The CEMS specified under Sec. 60.49Da for measuring
NOX and O2 (or
[[Page 146]]
CO2) shall be used to determine the average hourly
NOX concentrations (Csg). The continuous flow
monitoring system specified in Sec. 60.49Da(l) or Sec. 60.49Da(m)
shall be used to determine the volumetric flow rate (Qsg) of
the exhaust gas. If the option to use the flow monitoring system in
Sec. 60.49Da(m) is selected, the flow rate data used to meet the
requirements of Sec. 60.51Da shall not include substitute data values
derived from the missing data procedures in subpart D of part 75 of this
chapter, nor shall the data have been bias adjusted according to the
procedures of part 75 of this chapter. The sampling site shall be
located at the outlet from the steam generating unit.
(iii) The continuous monitoring system specified under Sec.
60.49Da(k) for measuring and determining gross energy output shall be
used to determine the average hourly gross energy output from the entire
combined cycle unit (Occ), which is the combined output from
the combustion turbine and the steam generating unit.
(iv) The owner or operator may, in lieu of installing, operating,
and recording data from the continuous flow monitoring system specified
in Sec. 60.49Da(l), determine the mass rate (lb/h) of NOX
emissions by installing, operating, and maintaining continuous fuel
flowmeters following the appropriate measurements procedures specified
in appendix D of part 75 of this chapter. If this compliance option is
selected, the emission rate (E) of NOX shall be computed
using Equation 4 in this section:
[GRAPHIC] [TIFF OMITTED] TR16FE12.002
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/MWh)
gross energy output;
ERsg = Average hourly emission rate of NOX exiting
the steam generating unit heat input calculated using
appropriate F factor as described in Method 19 of appendix A
of this part, ng/J (lb/MMBtu);
Hcc = Average hourly heat input rate of entire combined cycle
unit, J/h (MMBtu/h); and
Occ = Average hourly gross energy output from entire combined
cycle unit, J/h (MW).
(3) When an affected duct burner steam generating unit utilizes a
common steam turbine with one or more affected duct burner steam
generating units, the owner or operator shall either:
(i) Determine compliance with the applicable NOX
emissions limits by measuring the emissions combined with the emissions
from the other unit(s) utilizing the common steam turbine; or
(ii) Develop, demonstrate, and provide information satisfactory to
the Administrator on methods for apportioning the combined gross energy
output from the steam turbine for each of the affected duct burners. The
Administrator may approve such demonstrated substitute methods for
apportioning the combined gross energy output measured at the steam
turbine whenever the demonstration ensures accurate estimation of
emissions regulated under this part.
(l) [Reserved]
(m) Compliance provisions for sources subject to Sec.
60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), (j)(3)(i),
(l)(1)(i), (l)(1)(ii), or (l)(2). The owner or operator shall calculate
SO2 emissions as 1.660 x 10-7 lb/scf-ppm times the
average hourly SO2 output concentration in ppm (measured
according to the provisions of Sec. 60.49Da(b)), times the average
hourly flow rate (measured according to the provisions of Sec.
60.49Da(l) or Sec. 60.49Da(m)), divided by the average hourly gross
energy output (measured according to the provisions of Sec. 60.49Da(k))
or the average hourly net energy output, as applicable. Alternatively,
for oil-fired and gas-fired units, SO2 emissions may be
calculated by multiplying the hourly SO2 emission rate (in
lb/MMBtu), measured by the CEMS required under Sec. 60.49Da, by
[[Page 147]]
the hourly heat input rate (measured according to the provisions of
Sec. 60.49Da(n)), and dividing the result by the average gross energy
output (measured according to the provisions of Sec. 60.49Da(k)) or the
average hourly net energy output, as applicable.
(n) Compliance provisions for sources subject to Sec. 60.42Da(c)(1)
or (e)(1)(i). The owner or operator shall calculate PM emissions by
multiplying the average hourly PM output concentration (measured
according to the provisions of Sec. 60.49Da(t)), by the average hourly
flow rate (measured according to the provisions of Sec. 60.49Da(l) or
Sec. 60.49Da(m)), and dividing by the average hourly gross energy
output (measured according to the provisions of Sec. 60.49Da(k)) or the
average hourly net energy output, as applicable.
(o) Compliance provisions for sources subject to Sec.
60.42Da(c)(2), (d), or (e)(1)(ii). Except as provided for in paragraph
(p) of this section, the owner or operator must demonstrate compliance
with each applicable emissions limit according to the requirements in
paragraphs (o)(1) through (o)(5) of this section.
(1) You must conduct a performance test to demonstrate initial
compliance with the applicable PM emissions limit in Sec. 60.42Da by
the applicable date specified in Sec. 60.8(a). Thereafter, you must
conduct each subsequent performance test within 12 calendar months
following the date the previous performance test was required to be
conducted. You must conduct each performance test according to the
requirements in Sec. 60.8 using the test methods and procedures in
Sec. 60.50Da. The owner or operator of an affected facility that has
not operated for 60 consecutive calendar days prior to the date that the
subsequent performance test would have been required had the unit been
operating is not required to perform the subsequent performance test
until 30 calendar days after the next boiler operating day. Requests for
additional 30 day extensions shall be granted by the relevant air
division or office director of the appropriate Regional Office of the
U.S. EPA.
(2) You must monitor the performance of each electrostatic
precipitator or fabric filter (baghouse) operated to comply with the
applicable PM emissions limit in Sec. 60.42Da using a continuous
opacity monitoring system (COMS) according to the requirements in
paragraphs (o)(2)(i) through (vi) unless you elect to comply with one of
the alternatives provided in paragraphs (o)(3) and (o)(4) of this
section, as applicable to your control device.
(i) Each COMS must meet Performance Specification 1 in 40 CFR part
60, appendix B.
(ii) You must comply with the quality assurance requirements in
paragraphs (o)(2)(ii)(A) through (E) of this section.
(A) You must automatically (intrinsic to the opacity monitor) check
the zero and upscale (span) calibration drifts at least once daily. For
a particular COMS, the acceptable range of zero and upscale calibration
materials is as defined in the applicable version of Performance
Specification 1 in 40 CFR part 60, appendix B.
(B) You must adjust the zero and span whenever the 24-hour zero
drift or 24-hour span drift exceeds 4 percent opacity. The COMS must
allow for the amount of excess zero and span drift measured at the 24-
hour interval checks to be recorded and quantified. The optical surfaces
exposed to the effluent gases must be cleaned prior to performing the
zero and span drift adjustments, except for systems using automatic zero
adjustments. For systems using automatic zero adjustments, the optical
surfaces must be cleaned when the cumulative automatic zero compensation
exceeds 4 percent opacity.
(C) You must apply a method for producing a simulated zero opacity
condition and an upscale (span) opacity condition using a certified
neutral density filter or other related technique to produce a known
obscuration of the light beam. All procedures applied must provide a
system check of the analyzer internal optical surfaces and all
electronic circuitry including the lamp and photodetector assembly.
(D) Except during periods of system breakdowns, repairs, calibration
checks, and zero and span adjustments, the COMS must be in continuous
operation and must complete a minimum of one cycle of sampling and
analyzing for
[[Page 148]]
each successive 10 second period and one cycle of data recording for
each successive 6-minute period.
(E) You must reduce all data from the COMS to 6-minute averages.
Six-minute opacity averages must be calculated from 36 or more data
points equally spaced over each 6-minute period. Data recorded during
periods of system breakdowns, repairs, calibration checks, and zero and
span adjustments must not be included in the data averages. An
arithmetic or integrated average of all data may be used.
(iii) During each performance test conducted according to paragraph
(o)(1) of this section, you must establish an opacity baseline level.
The value of the opacity baseline level is determined by averaging all
of the 6-minute average opacity values (reported to the nearest 0.1
percent opacity) from the COMS measurements recorded during each of the
test run intervals conducted for the performance test, and then adding
2.5 percent opacity to your calculated average opacity value for all of
the test runs. If your opacity baseline level is less than 5.0 percent,
then the opacity baseline level is set at 5.0 percent.
(iv) You must evaluate the preceding 24-hour average opacity level
measured by the COMS each boiler operating day excluding periods of
affected facility startup, shutdown, or malfunction. If the measured 24-
hour average opacity emission level is greater than the baseline opacity
level determined in paragraph (o)(2)(iii) of this section, you must
initiate investigation of the relevant equipment and control systems
within 24 hours of the first discovery of the high opacity incident and
take the appropriate corrective action as soon as practicable to adjust
control settings or repair equipment to reduce the measured 24-hour
average opacity to a level below the baseline opacity level. In cases
when a wet scrubber is used in combination with another PM control
device that serves as the primary PM control device, the wet scrubber
must be maintained and operated.
(v) You must record the opacity measurements, calculations
performed, and any corrective actions taken. The record of corrective
action taken must include the date and time during which the measured
24-hour average opacity was greater than baseline opacity level, and the
date, time, and description of the corrective action.
(vi) If the measured 24-hour average opacity for your affected
facility remains at a level greater than the opacity baseline level
after 7 boiler operating days, then you must conduct a new PM
performance test according to paragraph (o)(1) of this section and
establish a new opacity baseline value according to paragraph (o)(2) of
this section. This new performance test must be conducted within 60 days
of the date that the measured 24-hour average opacity was first
determined to exceed the baseline opacity level unless a waiver is
granted by the permitting authority.
(3) As an alternative to complying with the requirements of
paragraph (o)(2) of this section, an owner or operator may elect to
monitor the performance of an electrostatic precipitator (ESP) operated
to comply with the applicable PM emissions limit in Sec. 60.42Da using
an ESP predictive model developed in accordance with the requirements in
paragraphs (o)(3)(i) through (v) of this section.
(i) You must calibrate the ESP predictive model with each PM control
device used to comply with the applicable PM emissions limit in Sec.
60.42Da operating under normal conditions. In cases when a wet scrubber
is used in combination with an ESP to comply with the PM emissions
limit, the wet scrubber must be maintained and operated.
(ii) You must develop a site-specific monitoring plan that includes
a description of the ESP predictive model used, the model input
parameters, and the procedures and criteria for establishing monitoring
parameter baseline levels indicative of compliance with the PM emissions
limit. You must submit the site-specific monitoring plan for approval by
the permitting authority. For reference purposes in preparing the
monitoring plan, see the OAQPS ``Compliance Assurance Monitoring (CAM)
Protocol for an Electrostatic Precipitator (ESP) Controlling Particulate
Matter (PM) Emissions from a Coal-Fired Boiler.'' This document is
available from the U.S. Environmental Protection Agency (U.S.
[[Page 149]]
EPA); Office of Air Quality Planning and Standards; Sector Policies and
Programs Division; Measurement Policy Group (D243-02), Research Triangle
Park, NC 27711. This document is also available on the Technology
Transfer Network (TTN) under Emission Measurement Center Continuous
Emission Monitoring.
(iii) You must run the ESP predictive model using the applicable
input data each boiler operating day and evaluate the model output for
the preceding boiler operating day excluding periods of affected
facility startup, shutdown, or malfunction. If the values for one or
more of the model parameters exceed the applicable baseline levels
determined according to your approved site-specific monitoring plan, you
must initiate investigation of the relevant equipment and control
systems within 24 hours of the first discovery of a model parameter
deviation and, take the appropriate corrective action as soon as
practicable to adjust control settings or repair equipment to return the
model output to within the applicable baseline levels.
(iv) You must record the ESP predictive model inputs and outputs and
any corrective actions taken. The record of corrective action taken must
include the date and time during which the model output values exceeded
the applicable baseline levels, and the date, time, and description of
the corrective action.
(v) If after 7 consecutive days a model parameter continues to
exceed the applicable baseline level, then you must conduct a new PM
performance test according to paragraph (o)(1) of this section. This new
performance test must be conducted within 60 calendar days of the date
that the model parameter was first determined to exceed its baseline
level unless a waiver is granted by the permitting authority.
(4) As an alternative to complying with the requirements of
paragraph (o)(2) of this section, an owner or operator may elect to
monitor the performance of a fabric filter (baghouse) operated to comply
with the applicable PM emissions limit in Sec. 60.42Da by using a bag
leak detection system according to the requirements in paragraphs
(o)(4)(i) through (v) of this section.
(i) Each bag leak detection system must meet the specifications and
requirements in paragraphs (o)(4)(i)(A) through (H) of this section.
(A) The bag leak detection system must be certified by the
manufacturer to be capable of detecting PM emissions at concentrations
of 1 milligram per actual cubic meter (0.00044 grains per actual cubic
foot) or less.
(B) The bag leak detection system sensor must provide output of
relative PM loadings. The owner or operator must continuously record the
output from the bag leak detection system using electronic or other
means (e.g., using a strip chart recorder or a data logger.)
(C) The bag leak detection system must be equipped with an alarm
system that will react when the system detects an increase in relative
particulate loading over the alarm set point established according to
paragraph (o)(4)(i)(D) of this section, and the alarm must be located
such that it can be noticed by the appropriate plant personnel.
(D) In the initial adjustment of the bag leak detection system, you
must establish, at a minimum, the baseline output by adjusting the
sensitivity (range) and the averaging period of the device, the alarm
set points, and the alarm delay time.
(E) Following initial adjustment, you must not adjust the averaging
period, alarm set point, or alarm delay time without approval from the
permitting authority except as provided in paragraph (d)(1)(vi) of this
section.
(F) Once per quarter, you may adjust the sensitivity of the bag leak
detection system to account for seasonal effects, including temperature
and humidity, according to the procedures identified in the site-
specific monitoring plan required by paragraph (o)(4)(ii) of this
section.
(G) You must install the bag leak detection sensor downstream of the
fabric filter and upstream of any wet scrubber.
(H) Where multiple detectors are required, the system's
instrumentation and alarm may be shared among detectors.
(ii) You must develop and submit to the permitting authority for
approval a
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site-specific monitoring plan for each bag leak detection system. You
must operate and maintain the bag leak detection system according to the
site-specific monitoring plan at all times. Each monitoring plan must
describe the items in paragraphs (o)(4)(ii)(A) through (F) of this
section.
(A) Installation of the bag leak detection system;
(B) Initial and periodic adjustment of the bag leak detection
system, including how the alarm set-point will be established;
(C) Operation of the bag leak detection system, including quality
assurance procedures;
(D) How the bag leak detection system will be maintained, including
a routine maintenance schedule and spare parts inventory list;
(E) How the bag leak detection system output will be recorded and
stored; and
(F) Corrective action procedures as specified in paragraph
(o)(4)(iii) of this section. In approving the site-specific monitoring
plan, the permitting authority may allow owners and operators more than
3 hours to alleviate a specific condition that causes an alarm if the
owner or operator identifies in the monitoring plan this specific
condition as one that could lead to an alarm, adequately explains why it
is not feasible to alleviate this condition within 3 hours of the time
the alarm occurs, and demonstrates that the requested time will ensure
alleviation of this condition as expeditiously as practicable.
(iii) For each bag leak detection system, you must initiate
procedures to determine the cause of every alarm within 1 hour of the
alarm. Except as provided in paragraph (o)(4)(ii)(F) of this section,
you must alleviate the cause of the alarm within 3 hours of the alarm by
taking whatever corrective action(s) are necessary. Corrective actions
may include, but are not limited to the following:
(A) Inspecting the fabric filter for air leaks, torn or broken bags
or filter media, or any other condition that may cause an increase in
particulate emissions;
(B) Sealing off defective bags or filter media;
(C) Replacing defective bags or filter media or otherwise repairing
the control device;
(D) Sealing off a defective fabric filter compartment;
(E) Cleaning the bag leak detection system probe or otherwise
repairing the bag leak detection system; or
(F) Shutting down the process producing the particulate emissions.
(iv) You must maintain records of the information specified in
paragraphs (o)(4)(iv)(A) through (C) of this section for each bag leak
detection system.
(A) Records of the bag leak detection system output;
(B) Records of bag leak detection system adjustments, including the
date and time of the adjustment, the initial bag leak detection system
settings, and the final bag leak detection system settings; and
(C) The date and time of all bag leak detection system alarms, the
time that procedures to determine the cause of the alarm were initiated,
if procedures were initiated within 1 hour of the alarm, the cause of
the alarm, an explanation of the actions taken, the date and time the
cause of the alarm was alleviated, and if the alarm was alleviated
within 3 hours of the alarm.
(v) If after any period composed of 30 boiler operating days during
which the alarm rate exceeds 5 percent of the process operating time
(excluding control device or process startup, shutdown, and
malfunction), then you must conduct a new PM performance test according
to paragraph (o)(1) of this section. This new performance test must be
conducted within 60 calendar days of the date that the alarm rate was
first determined to exceed 5 percent limit unless a waiver is granted by
the permitting authority.
(5) An owner or operator of a modified affected facility electing to
meet the emission limitations in Sec. 60.42Da(d) shall determine the
percent reduction in PM by using the emission rate for PM determined by
the performance test conducted according to the requirements in
paragraph (o)(1) of this section and the ash content on a mass basis of
the fuel burned during each performance test run as determined by
analysis of the fuel as fired.
[[Page 151]]
(p) As an alternative to meeting the compliance provisions specified
in paragraph (o) of this section, an owner or operator may elect to
install, evaluate, maintain, and operate a CEMS measuring PM emissions
discharged from the affected facility to the atmosphere and record the
output of the system as specified in paragraphs (p)(1) through (p)(8) of
this section.
(1) The owner or operator shall submit a written notification to the
Administrator of intent to demonstrate compliance with this subpart by
using a CEMS measuring PM. This notification shall be sent at least 30
calendar days before the initial startup of the monitor for compliance
determination purposes. The owner or operator may discontinue operation
of the monitor and instead return to demonstration of compliance with
this subpart according to the requirements in paragraph (o) of this
section by submitting written notification to the Administrator of such
intent at least 30 calendar days before shutdown of the monitor for
compliance determination purposes.
(2) Each CEMS shall be installed, evaluated, operated, and
maintained according to the requirements in Sec. 60.49Da(v).
(3) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of the affected
facility, as specified under Sec. 60.8 of subpart A of this part or
within 180 days of the date of notification to the Administrator
required under paragraph (p)(1) of this section, whichever is later.
(4) Compliance with the applicable emissions limit shall be
determined based on the 24-hour daily (block) average of the hourly
arithmetic average emissions concentrations using the continuous
monitoring system outlet data. The 24-hour block arithmetic average
emission concentration shall be calculated using EPA Reference Method 19
of appendix A of this part, section 4.1.
(5) At a minimum, non-out-of-control CEMS hourly averages shall be
obtained for 75 percent of all operating hours on a 30-boiler operating
day rolling average basis. Beginning on January 1, 2012, non-out-of-
control CEMS hourly averages shall be obtained for 90 percent of all
operating hours on a 30-boiler operating day rolling average basis.
(i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(ii) [Reserved]
(6) The 1-hour arithmetic averages required shall be expressed in
ng/J, MMBtu/hr, or lb/MWh and shall be used to calculate the boiler
operating day daily arithmetic average emission concentrations. The 1-
hour arithmetic averages shall be calculated using the data points
required under Sec. 60.13(e)(2) of subpart A of this part.
(7) All non-out-of-control CEMS data shall be used in calculating
average emission concentrations even if the minimum CEMS data
requirements of paragraph (j)(5) of this section are not met.
(8) When PM emissions data are not obtained because of CEMS
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained by using other monitoring systems as
approved by the Administrator or EPA Reference Method 19 of appendix A
of this part to provide, as necessary, non-out-of-control emissions data
for a minimum of 90 percent (only 75 percent is required prior to
January 1, 2012) of all operating hours per 30-boiler operating day
rolling average.
(q) Compliance provisions for sources subject to Sec. 60.42Da(b).
An owner or operator of an affected facility subject to the opacity
standard in Sec. 60.42Da(b) shall monitor the opacity of emissions
discharged from the affected facility to the atmosphere according to the
requirements in Sec. 60.49Da(a), as applicable to the affected
facility.
(r) Compliance provisions for sources subject to Sec. 60.45Da. To
determine compliance with the NOX plus CO emissions limit,
the owner or operator shall use the procedures specified in paragraphs
(r)(1) through (3) of this section.
(1) Calculate NOX emissions as 1.194 x 10-7
lb/scf-ppm times the average hourly NOX output concentration
in ppm (measured according to the provisions of Sec. 60.49Da(c)), times
the average hourly flow rate (measured in scfh, according to the
provisions of Sec. 60.49Da(l) or Sec. 60.49Da(m)), divided by the
average
[[Page 152]]
hourly gross energy output (measured according to the provisions of
Sec. 60.49Da(k)) or the average hourly net energy output, as
applicable.
(2) Calculate CO emissions by multiplying the average hourly CO
output concentration (measured according to the provisions of Sec.
60.49Da(u), by the average hourly flow rate (measured according to the
provisions of Sec. 60.49Da(l) or Sec. 60.49Da(m)), and dividing by the
average hourly gross energy output (measured according to the provisions
of Sec. 60.49Da(k)) or the average hourly net energy output, as
applicable.
(3) Calculate NOX plus CO emissions by summing the
NOX emissions results from paragraph (r)(1) of this section
plus the CO emissions results from paragraph (r)(2) of this section.
(s) Affirmative defense for exceedance of emissions limit during
malfunction. In response to an action to enforce the standards set forth
in paragraph Sec. Sec. 60.42Da, 60.43Da, 60.44Da, and 60.45Da, you may
assert an affirmative defense to a claim for civil penalties for
exceedances of such standards that are caused by malfunction, as defined
at 40 CFR 60.2. Appropriate penalties may be assessed, however, if you
fail to meet your burden of proving all of the requirements in the
affirmative defense as specified in paragraphs (s)(1) and (2) of this
section. The affirmative defense shall not be available for claims for
injunctive relief.
(1) To establish the affirmative defense in any action to enforce
such a limit, you must timely meet the notification requirements in
paragraph (s)(2) of this section, and must prove by a preponderance of
evidence that:
(i) The excess emissions:
(A) Were caused by a sudden, infrequent, and unavoidable failure of
air pollution control and monitoring equipment, process equipment, or a
process to operate in a normal or usual manner; and
(B) Could not have been prevented through careful planning, proper
design, or better operation and maintenance practices; and
(C) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
(D) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(ii) Repairs were made as expeditiously as possible when the
applicable emissions limits were being exceeded. Off-shift and overtime
labor were used, to the extent practicable to make these repairs; and
(iii) The frequency, amount, and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions; and
(iv) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage; and
(v) All possible steps were taken to minimize the impact of the
excess emissions on ambient air quality, the environment, and human
health; and
(vi) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
(vii) All of the actions in response to the excess emissions were
documented by properly signed, contemporaneous operating logs; and
(viii) At all times, the facility was operated in a manner
consistent with good practices for minimizing emissions; and
(ix) A written root cause analysis has been prepared, the purpose of
which is to determine, correct, and eliminate the primary causes of the
malfunction and the excess emissions resulting from the malfunction
event at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of excess emissions that
were the result of the malfunction.
(2) Notification. The owner or operator of the affected source
experiencing an exceedance of its emission limit(s) during a malfunction
shall notify the Administrator by telephone or facsimile (FAX)
transmission as soon as possible, but no later than two business days
after the initial occurrence of the malfunction or, if it is not
possible to determine within two business days whether the malfunction
caused or contributed to an exceedance, no later
[[Page 153]]
than two business days after the owner or operator knew or should have
known that the malfunction caused or contributed to an exceedance, but,
in no event later than two business days after the end of the averaging
period, if it wishes to avail itself of an affirmative defense to civil
penalties for that malfunction. The owner or operator seeking to assert
an affirmative defense shall also submit a written report to the
Administrator within 45 days of the initial occurrence of the exceedance
of the standard in Sec. 63.9991 to demonstrate, with all necessary
supporting documentation, that it has met the requirements set forth in
paragraph (s)(1) of this section. The owner or operator may seek an
extension of this deadline for up to 30 additional days by submitting a
written request to the Administrator before the expiration of the 45 day
period. Until a request for an extension has been approved by the
Administrator, the owner or operator is subject to the requirement to
submit such report within 45 days of the initial occurrence of the
exceedance.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5079, Jan. 28, 2009; 76
FR 3522, Jan. 20, 2011; 77 FR 9454, Feb. 16, 2012; 78 FR 24083, Apr. 24,
2013; 81 FR 20180, Apr. 6, 2016]
Sec. 60.49Da Emission monitoring.
(a) An owner or operator of an affected facility subject to the
opacity standard in Sec. 60.42Da must monitor the opacity of emissions
discharged from the affected facility to the atmosphere according to the
applicable requirements in paragraphs (a)(1) through (4) of this
section.
(1) Except as provided for in paragraphs (a)(2) and (4) of this
section, the owner or operator of an affected facility subject to an
opacity standard, shall install, calibrate, maintain, and operate a
COMS, and record the output of the system, for measuring the opacity of
emissions discharged to the atmosphere. If opacity interference due to
water droplets exists in the stack (for example, from the use of an FGD
system), the opacity is monitored upstream of the interference (at the
inlet to the FGD system). If opacity interference is experienced at all
locations (both at the inlet and outlet of the SO2 control
system), alternate parameters indicative of the PM control system's
performance and/or good combustion are monitored (subject to the
approval of the Administrator).
(2) As an alternative to the monitoring requirements in paragraph
(a)(1) of this section, an owner or operator of an affected facility
that meets the conditions in either paragraph (a)(2)(i), (ii), (iii), or
(iv) of this section may elect to monitor opacity as specified in
paragraph (a)(3) of this section.
(i) The affected facility uses a fabric filter (baghouse) to meet
the standards in Sec. 60.42Da and a bag leak detection system is
installed and operated according to the requirements in paragraphs Sec.
60.48Da(o)(4)(i) through (v);
(ii) The affected facility burns only gaseous or liquid fuels
(excluding residual oil) with potential SO2 emissions rates
of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion
technology to reduce emissions of SO2 or PM;
(iii) The affected facility meets all of the conditions specified in
paragraphs (a)(2)(iii)(A) through (C) of this section.
(A) No post-combustion technology (except a wet scrubber) is used
for reducing PM, SO2, or CO emissions;
(B) Only natural gas, gaseous fuels, or fuel oils that contain less
than or equal to 0.30 weight percent sulfur are burned; and
(C) Emissions of CO discharged to the atmosphere are maintained at
levels less than or equal to 1.4 lb/MWh on a boiler operating day
average basis as demonstrated by the use of a CEMS measuring CO
emissions according to the procedures specified in paragraph (u) of this
section; or
(iv) The affected facility uses an ESP and uses an ESP predictive
model to monitor the performance of the ESP developed in accordance and
operated according to the most current requirements in section Sec.
60.48Da of this part.
(3) The owner or operator of an affected facility that meets the
conditions in paragraph (a)(2) of this section may, as an alternative to
using a COMS, elect to monitor visible emissions using the applicable
procedures specified in paragraphs (a)(3)(i) through (iv) of this
section. The opacity performance test requirement in paragraph (a)(3)(i)
must be conducted by
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April 29, 2011, within 45 days after stopping use of an existing COMS,
or within 180 days after initial startup of the facility, whichever is
later.
(i) The owner or operator shall conduct a performance test using
Method 9 of appendix A-4 of this part and the procedures in Sec. 60.11.
If during the initial 60 minutes of the observation all the 6-minute
averages are less than 10 percent and all the individual 15-second
observations are less than or equal to 20 percent, then the observation
period may be reduced from 3 hours to 60 minutes.
(ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this
section, the owner or operator shall conduct subsequent Method 9 of
appendix A-4 of this part performance tests using the procedures in
paragraph (a)(3)(i) of this section according to the applicable schedule
in paragraphs (a)(3)(ii)(A) through (a)(3)(ii)(C) of this section, as
determined by the most recent Method 9 of appendix A-4 of this part
performance test results.
(A) If the maximum 6-minute average opacity is less than or equal to
5 percent, a subsequent Method 9 of appendix A-4 of this part
performance test must be completed within 12 calendar months from the
date that the most recent performance test was conducted or within 45
days of the next day that fuel with an opacity standard is combusted,
whichever is later;
(B) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later; or
(C) If the maximum 6-minute average opacity is greater than 10
percent, a subsequent Method 9 of appendix A-4 of this part performance
test must be completed within 45 calendar days from the date that the
most recent performance test was conducted.
(iii) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 of this part performance tests, elect to
perform subsequent monitoring using Method 22 of appendix A-7 of this
part according to the procedures specified in paragraphs (a)(3)(iii)(A)
and (B) of this section.
(A) The owner or operator shall conduct 10 minute observations
(during normal operation) each operating day the affected facility fires
fuel for which an opacity standard is applicable using Method 22 of
appendix A-7 of this part and demonstrate that the sum of the
occurrences of any visible emissions is not in excess of 5 percent of
the observation period (i.e., 30 seconds per 10 minute period). If the
sum of the occurrence of any visible emissions is greater than 30
seconds during the initial 10 minute observation, immediately conduct a
30 minute observation. If the sum of the occurrence of visible emissions
is greater than 5 percent of the observation period (i.e., 90 seconds
per 30 minute period), the owner or operator shall either document and
adjust the operation of the facility and demonstrate within 24 hours
that the sum of the occurrence of visible emissions is equal to or less
than 5 percent during a 30 minute observation (i.e., 90 seconds) or
conduct a new Method 9 of appendix A-4 of this part performance test
using the procedures in paragraph (a)(3)(i) of this section within 45
calendar days according to the requirements in Sec. 60.50Da(b)(3).
(B) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily observations
shall be resumed.
(iv) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 performance tests, elect to perform subsequent
monitoring using a digital opacity compliance system according to a
site-specific monitoring plan approved by the
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Administrator. The observations must be similar, but not necessarily
identical, to the requirements in paragraph (a)(3)(iii) of this section.
For reference purposes in preparing the monitoring plan, see OAQPS
``Determination of Visible Emission Opacity from Stationary Sources
Using Computer-Based Photographic Analysis Systems.'' This document is
available from the U.S. Environmental Protection Agency (U.S. EPA);
Office of Air Quality and Planning Standards; Sector Policies and
Programs Division; Measurement Policy Group (D243-02), Research Triangle
Park, NC 27711. This document is also available on the Technology
Transfer Network (TTN) under Emission Measurement Center Preliminary
Methods.
(4) An owner or operator of an affected facility that is subject to
an opacity standard under Sec. 60.42Da is not required to operate a
COMS provided that affected facility meets the conditions in either
paragraph (a)(4)(i) or (ii) of this section.
(i) The affected facility combusts only gaseous and/or liquid fuels
(excluding residue oil) where the potential SO2 emissions
rate of each fuel is no greater than 26 ng/J (0.060 lb/MMBtu), and the
unit operates according to a written site-specific monitoring plan
approved by the permitting authority. This monitoring plan must include
procedures and criteria for establishing and monitoring specific
parameters for the affected facility indicative of compliance with the
opacity standard. For testing performed as part of this site-specific
monitoring plan, the permitting authority may require as an alternative
to the notification and reporting requirements specified in Sec. Sec.
60.8 and 60.11 that the owner or operator submit any deviations with the
excess emissions report required under Sec. 60.51Da(d).
(ii) The owner or operator of the affected facility installs,
calibrates, operates, and maintains a particulate matter continuous
parametric monitoring system (PM CPMS) according to the requirements
specified in subpart UUUUU of part 63.
(b) The owner or operator of an affected facility must install,
calibrate, maintain, and operate a CEMS, and record the output of the
system, for measuring SO2 emissions, except where only
gaseous and/or liquid fuels (excluding residual oil) where the potential
SO2 emissions rate of each fuel is 26 ng/J (0.060 lb/MMBtu)
or less are combusted, as follows:
(1) Sulfur dioxide emissions are monitored at both the inlet and
outlet of the SO2 control device.
(2) For a facility that qualifies under the numerical limit
provisions of Sec. 60.43Da, SO2 emissions are only monitored
as discharged to the atmosphere.
(3) An ``as fired'' fuel monitoring system (upstream of coal
pulverizers) meeting the requirements of Method 19 of appendix A of this
part may be used to determine potential SO2 emissions in
place of a continuous SO2 emission monitor at the inlet to
the SO2 control device as required under paragraph (b)(1) of
this section.
(4) If the owner or operator has installed and certified a
SO2 CEMS according to the requirements of Sec. 75.20(c)(1)
of this chapter and appendix A to part 75 of this chapter, and is
continuing to meet the ongoing quality assurance requirements of Sec.
75.21 of this chapter and appendix B to part 75 of this chapter, that
CEMS may be used to meet the requirements of this section, provided
that:
(i) A CO2 or O2 continuous monitoring system
is installed, calibrated, maintained and operated at the same location,
according to paragraph (d) of this section; and
(ii) For sources subject to an SO2 emission limit in lb/
MMBtu under Sec. 60.43Da:
(A) When relative accuracy testing is conducted, SO2
concentration data and CO2 (or O2) data are
collected simultaneously; and
(B) In addition to meeting the applicable SO2 and
CO2 (or O2) relative accuracy specifications in
Figure 2 of appendix B to part 75 of this chapter, the relative accuracy
(RA) standard in section 13.2 of Performance Specification 2 in appendix
B to this part is met when the RA is calculated on a lb/MMBtu basis; and
(iii) The reporting requirements of Sec. 60.51Da are met. The
SO2 and, if required, CO2 (or O2) data
reported to meet the requirements of Sec. 60.51Da shall not include
substitute data values
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derived from the missing data procedures in subpart D of part 75 of this
chapter, nor shall the SO2 data have been bias adjusted
according to the procedures of part 75 of this chapter.
(c)(1) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a CEMS, and record the output of the
system, for measuring NOX emissions discharged to the
atmosphere; or
(2) If the owner or operator has installed a NOX emission
rate CEMS to meet the requirements of part 75 of this chapter and is
continuing to meet the ongoing requirements of part 75 of this chapter,
that CEMS may be used to meet the requirements of this section, except
that the owner or operator shall also meet the requirements of Sec.
60.51Da. Data reported to meet the requirements of Sec. 60.51Da shall
not include data substituted using the missing data procedures in
subpart D of part 75 of this chapter, nor shall the data have been bias
adjusted according to the procedures of part 75 of this chapter.
(d) The owner or operator of an affected facility not complying with
an output based limit shall install, calibrate, maintain, and operate a
CEMS, and record the output of the system, for measuring the
O2 or carbon dioxide (CO2) content of the flue
gases at each location where SO2 or NOX emissions
are monitored. For affected facilities subject to a lb/MMBtu
SO2 emission limit under Sec. 60.43Da, if the owner or
operator has installed and certified a CO2 or O2
monitoring system according to Sec. 75.20(c) of this chapter and
appendix A to part 75 of this chapter and the monitoring system
continues to meet the applicable quality-assurance provisions of Sec.
75.21 of this chapter and appendix B to part 75 of this chapter, that
CEMS may be used together with the part 75 SO2 concentration
monitoring system described in paragraph (b) of this section, to
determine the SO2 emission rate in lb/MMBtu. SO2
data used to meet the requirements of Sec. 60.51Da shall not include
substitute data values derived from the missing data procedures in
subpart D of part 75 of this chapter, nor shall the data have been bias
adjusted according to the procedures of part 75 of this chapter.
(e) The CEMS under paragraphs (b), (c), and (d) of this section are
operated and data recorded during all periods of operation of the
affected facility including periods of startup, shutdown, and
malfunction, except for CEMS breakdowns, repairs, calibration checks,
and zero and span adjustments.
(f)(1) For units that began construction, reconstruction, or
modification on or before February 28, 2005, the owner or operator shall
obtain emission data for at least 18 hours in at least 22 out of 30
successive boiler operating days. If this minimum data requirement
cannot be met with CEMS, the owner or operator shall supplement emission
data with other monitoring systems approved by the Administrator or the
reference methods and procedures as described in paragraph (h) of this
section.
(2) For units that began construction, reconstruction, or
modification after February 28, 2005, the owner or operator shall obtain
emission data for at least 90 percent of all operating hours for each 30
successive boiler operating days. If this minimum data requirement
cannot be met with a CEMS, the owner or operator shall supplement
emission data with other monitoring systems approved by the
Administrator or the reference methods and procedures as described in
paragraph (h) of this section.
(g) The 1-hour averages required under paragraph Sec. 60.13(h) are
expressed in ng/J (lb/MMBtu) heat input and used to calculate the
average emission rates under Sec. 60.48Da. The 1-hour averages are
calculated using the data points required under Sec. 60.13(h)(2).
(h) When it becomes necessary to supplement CEMS data to meet the
minimum data requirements in paragraph (f) of this section, the owner or
operator shall use the reference methods and procedures as specified in
this paragraph. Acceptable alternative methods and procedures are given
in paragraph (j) of this section.
(1) Method 6 of appendix A of this part shall be used to determine
the SO2 concentration at the same location as the
SO2 monitor. Samples shall be taken at 60-minute intervals.
The sampling time and sample volume for each sample shall be at least 20
minutes and
[[Page 157]]
0.020 dscm (0.71 dscf). Each sample represents a 1-hour average.
(2) Method 7 of appendix A of this part shall be used to determine
the NOX concentration at the same location as the
NOX monitor. Samples shall be taken at 30-minute intervals.
The arithmetic average of two consecutive samples represents a 1-hour
average.
(3) The emission rate correction factor, integrated bag sampling and
analysis procedure of Method 3B of appendix A of this part shall be used
to determine the O2 or CO2 concentration at the
same location as the O2 or CO2 monitor. Samples
shall be taken for at least 30 minutes in each hour. Each sample
represents a 1-hour average.
(4) The procedures in Method 19 of appendix A of this part shall be
used to compute each 1-hour average concentration in ng/J (lb/MMBtu)
heat input.
(i) The owner or operator shall use methods and procedures in this
paragraph to conduct monitoring system performance evaluations under
Sec. 60.13(c) and calibration checks under Sec. 60.13(d). Acceptable
alternative methods and procedures are given in paragraph (j) of this
section.
(1) Methods 3B, 6, and 7 of appendix A of this part shall be used to
determine O2, SO2, and NOX
concentrations, respectively.
(2) SO2 or NOX (NO), as applicable, shall be
used for preparing the calibration gas mixtures (in N2, as
applicable) under Performance Specification 2 of appendix B of this
part.
(3) For affected facilities burning only fossil fuel, the span value
for a COMS is between 60 and 80 percent. Span values for a CEMS
measuring NOX shall be determined using one of the following
procedures:
(i) Except as provided under paragraph (i)(3)(ii) of this section,
NOX span values shall be determined as follows:
------------------------------------------------------------------------
Fossil fuel Span values for NOX (ppm)
------------------------------------------------------------------------
Gas................................. 500.
Liquid.............................. 500.
Solid............................... 1,000.
Combination......................... 500 (x + y) + 1,000z.
------------------------------------------------------------------------
Where:
x = Fraction of total heat input derived from gaseous fossil fuel,
y = Fraction of total heat input derived from liquid fossil fuel, and
z = Fraction of total heat input derived from solid fossil fuel.
(ii) As an alternative to meeting the requirements of paragraph
(i)(3)(i) of this section, the owner or operator of an affected facility
may elect to use the NOX span values determined according to
section 2.1.2 in appendix A to part 75 of this chapter.
(4) All span values computed under paragraph (i)(3)(i) of this
section for burning combinations of fossil fuels are rounded to the
nearest 500 ppm. Span values computed under paragraph (i)(3)(ii) of this
section shall be rounded off according to section 2.1.2 in appendix A to
part 75 of this chapter.
(5) For affected facilities burning fossil fuel, alone or in
combination with non-fossil fuel and determining span values under
paragraph (i)(3)(i) of this section, the span value of the
SO2 CEMS at the inlet to the SO2 control device is
125 percent of the maximum estimated hourly potential emissions of the
fuel fired, and the outlet of the SO2 control device is 50
percent of maximum estimated hourly potential emissions of the fuel
fired. For affected facilities determining span values under paragraph
(i)(3)(ii) of this section, SO2 span values shall be
determined according to section 2.1.1 in appendix A to part 75 of this
chapter.
(j) The owner or operator may use the following as alternatives to
the reference methods and procedures specified in this section:
(1) For Method 6 of appendix A of this part, Method 6A or 6B
(whenever Methods 6 and 3 or 3B of appendix A of this part data are
used) or 6C of appendix A of this part may be used. Each Method 6B of
appendix A of this part sample obtained over 24 hours represents 24 1-
hour averages. If Method 6A or 6B of appendix A of this part is used
under paragraph (i) of this section, the conditions under Sec.
60.48Da(d)(1) apply; these conditions do not apply under paragraph (h)
of this section.
(2) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or
7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of
appendix A of this part is used, the sampling time for each run shall be
1 hour.
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(3) For Method 3 of appendix A of this part, Method 3A or 3B of
appendix A of this part may be used if the sampling time is 1 hour.
(4) For Method 3B of appendix A of this part, Method 3A of appendix
A of this part may be used.
(k) The procedures specified in paragraphs (k)(1) through (3) of
this section shall be used to determine gross energy output for sources
demonstrating compliance with an output-based standard.
(1) The owner or operator of an affected facility with electricity
generation shall install, calibrate, maintain, and operate a wattmeter;
measure gross electrical output in MWh on a continuous basis; and record
the output of the monitor.
(2) The owner or operator of an affected facility with process steam
generation shall install, calibrate, maintain, and operate meters for
steam flow, temperature, and pressure; measure gross process steam
output in joules per hour (or Btu per hour) on a continuous basis; and
record the output of the monitor.
(3) For an affected facility generating process steam in combination
with electrical generation, the gross energy output is determined
according to the definition of ``gross energy output'' specified in
Sec. 60.41Da that is applicable to the affected facility.
(l) The owner or operator of an affected facility demonstrating
compliance with an output-based standard shall install, certify,
operate, and maintain a continuous flow monitoring system meeting the
requirements of Performance Specification 6 of appendix B of this part
and the calibration drift (CD) assessment, relative accuracy test audit
(RATA), and reporting provisions of procedure 1 of appendix F of this
part, and record the output of the system, for measuring the volumetric
flow rate of exhaust gases discharged to the atmosphere; or
(m) Alternatively, data from a continuous flow monitoring system
certified according to the requirements of Sec. 75.20(c) of this
chapter and appendix A to part 75 of this chapter, and continuing to
meet the applicable quality control and quality assurance requirements
of Sec. 75.21 of this chapter and appendix B to part 75 of this
chapter, may be used. Flow rate data reported to meet the requirements
of Sec. 60.51Da shall not include substitute data values derived from
the missing data procedures in subpart D of part 75 of this chapter, nor
shall the data have been bias adjusted according to the procedures of
part 75 of this chapter.
(n) Gas-fired and oil-fired units. The owner or operator of an
affected unit that qualifies as a gas-fired or oil-fired unit, as
defined in 40 CFR 72.2, may use, as an alternative to the requirements
specified in either paragraph (l) or (m) of this section, a fuel flow
monitoring system certified and operated according to the requirements
of appendix D of part 75 of this chapter.
(o) The owner or operator of a duct burner, as described in Sec.
60.41Da, which is subject to the NOX standards of Sec.
60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a
CEMS to measure NOX emissions; a wattmeter to measure gross
electrical output; meters to measure steam flow, temperature, and
pressure; and a continuous flow monitoring system to measure the flow of
exhaust gases discharged to the atmosphere.
(p)-(r) [Reserved]
(s) The owner or operator shall prepare and submit to the
Administrator for approval a unit-specific monitoring plan for each
monitoring system, at least 45 days before commencing certification
testing of the monitoring systems. The owner or operator shall comply
with the requirements in your plan. The plan must address the
requirements in paragraphs (s)(1) through (6) of this section.
(1) Installation of the CEMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of the exhaust emissions (e.g., on or
downstream of the last control device);
(2) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems;
(3) Performance evaluation procedures and acceptance criteria (e.g.,
calibrations, relative accuracy test audits (RATA), etc.);
[[Page 159]]
(4) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec. 60.13(d) or part 75 of this chapter
(as applicable);
(5) Ongoing data quality assurance procedures in accordance with the
general requirements of Sec. 60.13 or part 75 of this chapter (as
applicable); and
(6) Ongoing recordkeeping and reporting procedures in accordance
with the requirements of this subpart.
(t) The owner or operator of an affected facility demonstrating
compliance with the output-based emissions limit under Sec. 60.42Da
must either install, certify, operate, and maintain a CEMS for measuring
PM emissions according to the requirements of paragraph (v) of this
section or install, calibrate, operate, and maintain a PM CPMS according
to the requirements for new facilities specified in subpart UUUUU of
part 63 of this chapter. An owner or operator of an affected facility
demonstrating compliance with the input-based emissions limit in Sec.
60.42Da may install, certify, operate, and maintain a CEMS for measuring
PM emissions according to the requirements of paragraph (v) of this
section.
(u) The owner or operator of an affected facility using a CEMS
measuring CO emissions to meet requirements of this subpart shall meet
the requirements specified in paragraphs (u)(1) through (4) of this
section.
(1) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (u)(1)(i) through (iv) of this
section.
(i) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec. 60.58b(i)(3) of subpart Eb
of this part.
(ii) Each 1-hour CO emissions average is calculated using the data
points generated by the CO CEMS expressed in parts per million by volume
corrected to 3 percent oxygen (dry basis).
(iii) At a minimum, non-out-of-control 1-hour CO emissions averages
must be obtained for at least 90 percent of the operating hours on a 30-
boiler operating day rolling average basis. The 1-hour averages are
calculated using the data points required in Sec. 60.13(h)(2).
(iv) Quarterly accuracy determinations and daily calibration drift
tests for the CO CEMS must be performed in accordance with procedure 1
in appendix F of this part.
(2) You must calculate the 1-hour average CO emissions levels for
each boiler operating day by multiplying the average hourly CO output
concentration measured by the CO CEMS times the corresponding average
hourly flue gas flow rate and divided by the corresponding average
hourly useful energy output from the affected facility. The 24-hour
average CO emission level is determined by calculating the arithmetic
average of the hourly CO emission levels computed for each boiler
operating day.
(3) You must evaluate the preceding 24-hour average CO emission
level each boiler operating day excluding periods of affected facility
startup, shutdown, or malfunction. If the 24-hour average CO emission
level is greater than 1.4 lb/MWh, you must initiate investigation of the
relevant equipment and control systems within 24 hours of the first
discovery of the high emission incident and, take the appropriate
corrective action as soon as practicable to adjust control settings or
repair equipment to reduce the 24-hour average CO emission level to 1.4
lb/MWh or less.
(4) You must record the CO measurements and calculations performed
according to paragraph (u)(3) of this section and any corrective actions
taken. The record of corrective action taken must include the date and
time during which the 24-hour average CO emission level was greater than
1.4 lb/MWh, and the date, time, and description of the corrective
action.
(v) The owner or operator of an affected facility using a CEMS
measuring PM emissions to meet requirements of this subpart shall
install, certify, operate, and maintain the CEMS as specified in
paragraphs (v)(1) through (v)(4) of this section.
(1) The owner or operator shall conduct a performance evaluation of
the CEMS according to the applicable requirements of Sec. 60.13,
Performance Specification 11 in appendix B of this part, and procedure 2
in appendix F of this part.
(2) During each PM correlation testing run of the CEMS required by
Performance Specification 11 in appendix B of this part, PM and
O2 (or CO2) data
[[Page 160]]
shall be collected concurrently (or within a 30- to 60-minute period) by
both the CEMS and performance tests conducted using the following test
methods.
(i) For PM, Method 5 or 5B of appendix A-3 of this part or Method 17
of appendix A-6 of this part shall be used; and
(ii) For O2 (or CO2), Method 3A or 3B of
appendix A-2 of this part, as applicable shall be used.
(3) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 2 in appendix F of
this part. Relative Response Audit's must be performed annually and
Response Correlation Audits must be performed every 3 years.
(4) As of January 1, 2012, and within 90 days after the date of
completing each performance test, as defined in Sec. 60.8, conducted to
demonstrate compliance with this subpart, you must submit relative
accuracy test audit (i.e., reference method) data and performance test
(i.e., compliance test) data, except opacity data, electronically to
EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool
(ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or other
compatible electronic spreadsheet. Only data collected using test
methods compatible with ERT are subject to this requirement to be
submitted electronically into EPA's WebFire database.
(w) The owner or operator using a SO2, NOX,
CO2, and O2 CEMS to meet the requirements of this
subpart shall install, certify, operate, and maintain the CEMS as
specified in paragraphs (w)(1) through (w)(5) of this section.
(1) Except as provided for under paragraphs (w)(2), (w)(3), and
(w)(4) of this section, each SO2, NOX,
CO2, and O2 CEMS required under paragraphs (b)
through (d) of this section shall be installed, certified, and operated
in accordance with the applicable procedures in Performance
Specification 2 or 3 in appendix B to this part or according to the
procedures in appendices A and B to part 75 of this chapter. Daily
calibration drift assessments and quarterly accuracy determinations
shall be done in accordance with Procedure 1 in appendix F to this part,
and a data assessment report (DAR), prepared according to section 7 of
Procedure 1 in appendix F to this part, shall be submitted with each
compliance report required under Sec. 60.51Da.
(2) As an alternative to meeting the requirements of paragraph
(w)(1) of this section, an owner or operator may elect to implement the
following alternative data accuracy assessment procedures. For all
required CO2 and O2 CEMS and for SO2
and NOX CEMS with span values greater than or equal to 100
ppm, the daily calibration error test and calibration adjustment
procedures described in sections 2.1.1 and 2.1.3 of appendix B to part
75 of this chapter may be followed instead of the CD assessment
procedures in Procedure 1, section 4.1 of appendix F of this part. If
this option is selected, the data validation and out-of-control
provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 of this
chapter shall be followed instead of the excessive CD and out-of-control
criteria in Procedure 1, section 4.3 of appendix F to this part. For the
purposes of data validation under this subpart, the excessive CD and
out-of-control criteria in Procedure 1, section 4.3 of appendix F to
this part shall apply to SO2 and NOX span values
less than 100 ppm;
(3) As an alternative to meeting the requirements of paragraph
(w)(1) of this section, an owner or operator may elect to may elect to
implement the following alternative data accuracy assessment procedures.
For all required CO2 and O2 CEMS and for
SO2 and NOX CEMS with span values greater than 30
ppm, quarterly linearity checks may be performed in accordance with
section 2.2.1 of appendix B to part 75 of this chapter, instead of
performing the cylinder gas audits (CGAs) described in Procedure 1,
section 5.1.2 of appendix F to this part. If this option is selected:
The frequency of the linearity checks shall be as specified in section
2.2.1 of appendix B to part 75 of this chapter; the applicable linearity
specifications in section 3.2 of appendix A to part 75 of this chapter
shall be met; the data validation and out-of-control criteria in section
2.2.3 of appendix B to part 75 of this chapter shall be followed instead
of the excessive audit inaccuracy
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and out-of-control criteria in Procedure 1, section 5.2 of appendix F to
this part; and the grace period provisions in section 2.2.4 of appendix
B to part 75 of this chapter shall apply. For the purposes of data
validation under this subpart, the cylinder gas audits described in
Procedure 1, section 5.1.2 of appendix F to this part shall be performed
for SO2 and NOX span values less than or equal to
30 ppm;
(4) As an alternative to meeting the requirements of paragraph
(w)(1) of this section, an owner or operator may elect to may elect to
implement the following alternative data accuracy assessment procedures.
For SO2, CO2, and O2 CEMS and for
NOX CEMS, RATAs may be performed in accordance with section
2.3 of appendix B to part 75 of this chapter instead of following the
procedures described in Procedure 1, section 5.1.1 of appendix F to this
part. If this option is selected: The frequency of each RATA shall be as
specified in section 2.3.1 of appendix B to part 75 of this chapter; the
applicable relative accuracy specifications shown in Figure 2 in
appendix B to part 75 of this chapter shall be met; the data validation
and out-of-control criteria in section 2.3.2 of appendix B to part 75 of
this chapter shall be followed instead of the excessive audit inaccuracy
and out-of-control criteria in Procedure 1, section 5.2 of appendix F to
this part; and the grace period provisions in section 2.3.3 of appendix
B to part 75 of this chapter shall apply. For the purposes of data
validation under this subpart, the relative accuracy specification in
section 13.2 of Performance Specification 2 in appendix B to this part
shall be met on a lb/MMBtu basis for SO2 (regardless of the
SO2 emission level during the RATA), and for NOX
when the average NOX emission rate measured by the reference
method during the RATA is less than 0.100 lb/MMBtu;
(5) If the owner or operator elects to implement the alternative
data assessment procedures described in paragraphs (w)(2) through (w)(4)
of this section, each data assessment report shall include a summary of
the results of all of the RATAs, linearity checks, CGAs, and calibration
error or drift assessments required by paragraphs (w)(2) through (w)(4)
of this section.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5081, Jan. 28, 2009; 76
FR 3523, Jan. 20, 2011; 77 FR 9456, Feb. 16, 2012; 77 FR 23402, Apr. 19,
2012; 78 FR 24083, Apr. 24, 2013]
Sec. 60.50Da Compliance determination procedures and methods.
(a) In conducting the performance tests required in Sec. 60.8, the
owner or operator shall use as reference methods and procedures the
methods in appendix A of this part or the methods and procedures as
specified in this section, except as provided in Sec. 60.8(b). Section
60.8(f) does not apply to this section for SO2 and
NOX. Acceptable alternative methods are given in paragraph
(e) of this section.
(b) In conducting the performance tests to determine compliance with
the PM emissions limits in Sec. 60.42Da, the owner or operator shall
meet the requirements specified in paragraphs (b)(1) through (3) of this
section.
(1) The owner or operator shall measure filterable PM to determine
compliance with the applicable PM emissions limit in Sec. 60.42Da as
specified in paragraphs (b)(1)(i) through (ii) of this section.
(i) The dry basis F factor (O2) procedures in Method 19
of appendix A of this part shall be used to compute the emission rate of
PM.
(ii) For the PM concentration, Method 5 of appendix A of this part
shall be used for an affected facility that does not use a wet FGD. For
an affected facility that uses a wet FGD, Method 5B of appendix A of
this part shall be used downstream of the wet FGD.
(A) The sampling time and sample volume for each run shall be at
least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder
heating system in the sampling train may be set to provide an average
gas temperature of no greater than 160 14 [deg]C (320 25 [deg]F).
(B) For each particulate run, the emission rate correction factor,
integrated or grab sampling and analysis procedures of Method 3B of
appendix A of this part shall be used to determine the O2
concentration. The O2 sample shall be obtained simultaneously
with, and at the same traverse points as, the particulate run. If the
particulate run
[[Page 162]]
has more than 12 traverse points, the O2 traverse points may
be reduced to 12 provided that Method 1 of appendix A of this part is
used to locate the 12 O2 traverse points. If the grab
sampling procedure is used, the O2 concentration for the run
shall be the arithmetic mean of the sample O2 concentrations
at all traverse points.
(2) In conjunction with a performance test performed according to
the requirements in paragraph (b)(1) of this section, the owner or
operator of an affected facility for which construction, reconstruction,
or modification commenced after May 3, 2011, shall measure condensable
PM using Method 202 of appendix M of part 51.
(3) Method 9 of appendix A of this part and the procedures in Sec.
60.11 shall be used to determine opacity.
(c) The owner or operator shall determine compliance with the
SO2 standards in Sec. 60.43Da as follows:
(1) The percent of potential SO2 emissions (%Ps) to the
atmosphere shall be computed using the following equation:
[GRAPHIC] [TIFF OMITTED] TR13JN07.015
Where:
%Ps = Percent of potential SO2 emissions, percent;
%Rf = Percent reduction from fuel pretreatment, percent; and
%Rg = Percent reduction by SO2 control system, percent.
(2) The procedures in Method 19 of appendix A of this part may be
used to determine percent reduction (%Rf) of sulfur by such
processes as fuel pretreatment (physical coal cleaning,
hydrodesulfurization of fuel oil, etc.), coal pulverizers, and bottom
and fly ash interactions. This determination is optional.
(3) The procedures in Method 19 of appendix A of this part shall be
used to determine the percent SO2 reduction (%Rg)
of any SO2 control system. Alternatively, a combination of an
``as fired'' fuel monitor and emission rates measured after the control
system, following the procedures in Method 19 of appendix A of this
part, may be used if the percent reduction is calculated using the
average emission rate from the SO2 control device and the
average SO2 input rate from the ``as fired'' fuel analysis
for 30 successive boiler operating days.
(4) The appropriate procedures in Method 19 of appendix A of this
part shall be used to determine the emission rate.
(5) The CEMS in Sec. 60.49Da(b) and (d) shall be used to determine
the concentrations of SO2 and CO2 or
O2.
(d) The owner or operator shall determine compliance with the
NOX standard in Sec. 60.44Da as follows:
(1) The appropriate procedures in Method 19 of appendix A of this
part shall be used to determine the emission rate of NOX.
(2) The continuous monitoring system in Sec. 60.49Da(c) and (d)
shall be used to determine the concentrations of NOX and
CO2 or O2.
(e) The owner or operator may use the following as alternatives to
the reference methods and procedures specified in this section:
(1) For Method 5 or 5B of appendix A-3 of this part, Method 17 of
appendix A-6 of this part may be used at facilities with or without wet
FGD systems if the stack temperature at the sampling location does not
exceed an average temperature of 160 [deg]C (320 [deg]F). The procedures
of sections 8.1 and 11.1 of Method 5B of appendix A-3 of this part may
be used in Method 17 of appendix A-6 of this part only if it is used
after wet FGD systems. Method 17 of appendix A-6 of this part shall not
be used after wet FGD systems if the effluent is saturated or laden with
water droplets.
(2) The Fc factor (CO2) procedures in Method
19 of appendix A of this part may be used to compute the emission rate
of PM under the stipulations of Sec. 60.46(d)(1). The CO2
shall be determined in the same manner as the O2
concentration.
(f) The owner or operator of an electric utility combined cycle gas
turbine that does not meet the definition of an IGCC must conduct
performance tests for PM, SO2, and NOX using the
procedures of Method 19 of appendix A-7 of this part. The SO2
and NOX emission rates calculations from the gas turbine used
in Method 19 of appendix A-7 of this part are determined when the gas
turbine is performance tested under subpart GG of this part. The
potential
[[Page 163]]
uncontrolled PM emission rate from a gas turbine is defined as 17 ng/J
(0.04 lb/MMBtu) heat input.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5083, Jan. 28, 2009; 77
FR 9458, Feb. 16, 2012; 78 FR 24084, Apr. 24, 2013]
Sec. 60.51Da Reporting requirements.
(a) For SO2, NOX, PM, and NOX plus
CO emissions, the performance test data from the initial and subsequent
performance test and from the performance evaluation of the continuous
monitors (including the transmissometer) must be reported to the
Administrator.
(b) For SO2 and NOX the following information
is reported to the Administrator for each 24-hour period.
(1) Calendar date.
(2) The average SO2 and NOX emission rates
(ng/J, lb/MMBtu, or lb/MWh) for each 30 successive boiler operating
days, ending with the last 30-day period in the quarter; reasons for
non-compliance with the emission standards; and, description of
corrective actions taken.
(3) For owners or operators of affected facilities complying with
the percent reduction requirement, percent reduction of the potential
combustion concentration of SO2 for each 30 successive boiler
operating days, ending with the last 30-day period in the quarter;
reasons for non-compliance with the standard; and, description of
corrective actions taken.
(4) Identification of the boiler operating days for which pollutant
or diluent data have not been obtained by an approved method for at
least 75 percent of the hours of operation of the facility;
justification for not obtaining sufficient data; and description of
corrective actions taken.
(5) Identification of the times when emissions data have been
excluded from the calculation of average emission rates because of
startup, shutdown, or malfunction.
(6) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted.
(7) Identification of times when hourly averages have been obtained
based on manual sampling methods.
(8) Identification of the times when the pollutant concentration
exceeded full span of the CEMS.
(9) Description of any modifications to CEMS which could affect the
ability of the CEMS to comply with Performance Specifications 2 or 3.
(c) If the minimum quantity of emission data as required by Sec.
60.49Da is not obtained for any 30 successive boiler operating days, the
following information obtained under the requirements of Sec.
60.48Da(h) is reported to the Administrator for that 30-day period:
(1) The number of hourly averages available for outlet emission
rates (no) and inlet emission rates (ni) as applicable.
(2) The standard deviation of hourly averages for outlet emission
rates (so) and inlet emission rates (si) as
applicable.
(3) The lower confidence limit for the mean outlet emission rate
(Eo*) and the upper confidence limit for the mean inlet
emission rate (Ei*) as applicable.
(4) The applicable potential combustion concentration.
(5) The ratio of the upper confidence limit for the mean outlet
emission rate (Eo*) and the allowable emission rate
(Estd) as applicable.
(d) In addition to the applicable requirements in Sec. 60.7, the
owner or operator of an affected facility subject to the opacity limits
in Sec. 60.43c(c) and conducting performance tests using Method 9 of
appendix A-4 of this part shall submit excess emission reports for any
excess emissions from the affected facility that occur during the
reporting period and maintain records according to the requirements
specified in paragraph (d)(1) of this section.
(1) For each performance test conducted using Method 9 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (d)(1)(i) through (iii) of this
section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission reading
certification for each visible emission observer participating in the
performance test; and
(iii) Copies of all visible emission observer opacity field data
sheets.
(2) [Reserved]
(e) If fuel pretreatment credit toward the SO2 emission
standard under
[[Page 164]]
Sec. 60.43Da is claimed, the owner or operator of the affected facility
shall submit a signed statement:
(1) Indicating what percentage cleaning credit was taken for the
calendar quarter, and whether the credit was determined in accordance
with the provisions of Sec. 60.50Da and Method 19 of appendix A of this
part; and
(2) Listing the quantity, heat content, and date each pretreated
fuel shipment was received during the previous quarter; the name and
location of the fuel pretreatment facility; and the total quantity and
total heat content of all fuels received at the affected facility during
the previous quarter.
(f) For any periods for which opacity, SO2 or
NOX emissions data are not available, the owner or operator
of the affected facility shall submit a signed statement indicating if
any changes were made in operation of the emission control system during
the period of data unavailability. Operations of the control system and
affected facility during periods of data unavailability are to be
compared with operation of the control system and affected facility
before and following the period of data unavailability.
(g) [Reserved]
(h) The owner or operator of the affected facility shall submit a
signed statement indicating whether:
(1) The required CEMS calibration, span, and drift checks or other
periodic audits have or have not been performed as specified.
(2) The data used to show compliance was or was not obtained in
accordance with approved methods and procedures of this part and is
representative of plant performance.
(3) The minimum data requirements have or have not been met; or, the
minimum data requirements have not been met for errors that were
unavoidable.
(4) Compliance with the standards has or has not been achieved
during the reporting period.
(i) For the purposes of the reports required under Sec. 60.7,
periods of excess emissions are defined as all 6-minute periods during
which the average opacity exceeds the applicable opacity standards under
Sec. 60.42Da(b). Opacity levels in excess of the applicable opacity
standard and the date of such excesses are to be submitted to the
Administrator each calendar quarter.
(j) The owner or operator of an affected facility shall submit the
written reports required under this section and subpart A to the
Administrator semiannually for each six-month period. All semiannual
reports shall be postmarked by the 30th day following the end of each
six-month period.
(k) The owner or operator of an affected facility may submit
electronic quarterly reports for SO2 and/or NOX
and/or opacity in lieu of submitting the written reports required under
paragraphs (b) and (i) of this section. The format of each quarterly
electronic report shall be coordinated with the permitting authority.
The electronic report(s) shall be submitted no later than 30 days after
the end of the calendar quarter and shall be accompanied by a
certification statement from the owner or operator, indicating whether
compliance with the applicable emission standards and minimum data
requirements of this subpart was achieved during the reporting period.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5083, Jan. 28, 2009; 77
FR 9458, Feb. 16, 2012]
Sec. 60.52Da Recordkeeping requirements.
(a) [Reserved]
(b) The owner or operator of an affected facility subject to the
opacity limits in Sec. 60.42Da(b) that elects to monitor emissions
according to the requirements in Sec. 60.49Da(a)(3) shall maintain
records according to the requirements specified in paragraphs (b)(1)
through (3) of this section, as applicable to the visible emissions
monitoring method used.
(1) For each performance test conducted using Method 9 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (b)(1)(i) through (iii) of this
section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission reading
certification for each visible emission observer participating in the
performance test; and
[[Page 165]]
(iii) Copies of all visible emission observer opacity field data
sheets;
(2) For each performance test conducted using Method 22 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (b)(2)(i) through (iv) of this
section.
(i) Dates and time intervals of all visible emissions observation
periods;
(ii) Name and affiliation for each visible emission observer
participating in the performance test;
(iii) Copies of all visible emission observer opacity field data
sheets; and
(iv) Documentation of any adjustments made and the time the
adjustments were completed to the affected facility operation by the
owner or operator to demonstrate compliance with the applicable
monitoring requirements.
(3) For each digital opacity compliance system, the owner or
operator shall maintain records and submit reports according to the
requirements specified in the site-specific monitoring plan approved by
the Administrator.
[74 FR 5083, Jan. 28, 2009, as amended at 77 FR 9459, Feb. 16, 2012]
Subpart Db_Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units
Source: 72 FR 32742, June 13, 2007, unless otherwise noted.
Sec. 60.40b Applicability and delegation of authority.
(a) The affected facility to which this subpart applies is each
steam generating unit that commences construction, modification, or
reconstruction after June 19, 1984, and that has a heat input capacity
from fuels combusted in the steam generating unit of greater than 29
megawatts (MW) (100 million British thermal units per hour (MMBtu/hr)).
(b) Any affected facility meeting the applicability requirements
under paragraph (a) of this section and commencing construction,
modification, or reconstruction after June 19, 1984, but on or before
June 19, 1986, is subject to the following standards:
(1) Coal-fired affected facilities having a heat input capacity
between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, are subject to
the particulate matter (PM) and nitrogen oxides (NOX)
standards under this subpart.
(2) Coal-fired affected facilities having a heat input capacity
greater than 73 MW (250 MMBtu/hr) and meeting the applicability
requirements under subpart D (Standards of performance for fossil-fuel-
fired steam generators; Sec. 60.40) are subject to the PM and
NOX standards under this subpart and to the sulfur dioxide
(SO2) standards under subpart D (Sec. 60.43).
(3) Oil-fired affected facilities having a heat input capacity
between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, are subject to
the NOX standards under this subpart.
(4) Oil-fired affected facilities having a heat input capacity
greater than 73 MW (250 MMBtu/hr) and meeting the applicability
requirements under subpart D (Standards of performance for fossil-fuel-
fired steam generators; Sec. 60.40) are also subject to the
NOX standards under this subpart and the PM and
SO2 standards under subpart D (Sec. 60.42 and Sec. 60.43).
(c) Affected facilities that also meet the applicability
requirements under subpart J or subpart Ja of this part are subject to
the PM and NOX standards under this subpart and the
SO2 standards under subpart J or subpart Ja of this part, as
applicable.
(d) Affected facilities that also meet the applicability
requirements under subpart E (Standards of performance for incinerators;
Sec. 60.50) are subject to the NOX and PM standards under
this subpart.
(e) Steam generating units meeting the applicability requirements
under subpart Da (Standards of performance for electric utility steam
generating units; Sec. 60.40Da) are not subject to this subpart.
(f) Any change to an existing steam generating unit for the sole
purpose of combusting gases containing total reduced sulfur (TRS) as
defined under Sec. 60.281 is not considered a modification under Sec.
60.14 and the steam generating unit is not subject to this subpart.
[[Page 166]]
(g) In delegating implementation and enforcement authority to a
State under section 111(c) of the Clean Air Act, the following
authorities shall be retained by the Administrator and not transferred
to a State.
(1) Section 60.44b(f).
(2) Section 60.44b(g).
(3) Section 60.49b(a)(4).
(h) Any affected facility that meets the applicability requirements
and is subject to subpart Ea, subpart Eb, subpart AAAA, or subpart CCCC
of this part is not subject to this subpart.
(i) Affected facilities (i.e., heat recovery steam generators) that
are associated with stationary combustion turbines and that meet the
applicability requirements of subpart KKKK of this part are not subject
to this subpart. This subpart will continue to apply to all other
affected facilities (i.e. heat recovery steam generators with duct
burners) that are capable of combusting more than 29 MW (100 MMBtu/h)
heat input of fossil fuel. If the affected facility (i.e. heat recovery
steam generator) is subject to this subpart, only emissions resulting
from combustion of fuels in the steam generating unit are subject to
this subpart. (The stationary combustion turbine emissions are subject
to subpart GG or KKKK, as applicable, of this part.)
(j) Any affected facility meeting the applicability requirements
under paragraph (a) of this section and commencing construction,
modification, or reconstruction after June 19, 1986 is not subject to
subpart D (Standards of Performance for Fossil-Fuel-Fired Steam
Generators, Sec. 60.40).
(k) Any affected facility that meets the applicability requirements
and is subject to an EPA approved State or Federal section 111(d)/129
plan implementing subpart Cb or subpart BBBB of this part is not covered
by this subpart.
(l) Affected facilities that also meet the applicability
requirements under subpart BB of this part (Standards of Performance for
Kraft Pulp Mills) are subject to the SO2 and NOX
standards under this subpart and the PM standards under subpart BB.
(m) Temporary boilers are not subject to this subpart.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009; 77
FR 9459, Feb. 16, 2012]
Sec. 60.41b Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Clean Air Act and in subpart A of this part.
Annual capacity factor means the ratio between the actual heat input
to a steam generating unit from the fuels listed in Sec. 60.42b(a),
Sec. 60.43b(a), or Sec. 60.44b(a), as applicable, during a calendar
year and the potential heat input to the steam generating unit had it
been operated for 8,760 hours during a calendar year at the maximum
steady state design heat input capacity. In the case of steam generating
units that are rented or leased, the actual heat input shall be
determined based on the combined heat input from all operations of the
affected facility in a calendar year.
Byproduct/waste means any liquid or gaseous substance produced at
chemical manufacturing plants, petroleum refineries, or pulp and paper
mills (except natural gas, distillate oil, or residual oil) and
combusted in a steam generating unit for heat recovery or for disposal.
Gaseous substances with carbon dioxide (CO2) levels greater
than 50 percent or carbon monoxide levels greater than 10 percent are
not byproduct/waste for the purpose of this subpart.
Chemical manufacturing plants mean industrial plants that are
classified by the Department of Commerce under Standard Industrial
Classification (SIC) Code 28.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec. 60.17),
coal refuse, and petroleum coke. Coal-derived synthetic fuels, including
but not limited to solvent refined coal, gasified coal not meeting the
definition of natural gas, coal-oil mixtures, coke oven gas, and coal-
water mixtures, are also included in this definition for the purposes of
this subpart.
[[Page 167]]
Coal refuse means any byproduct of coal mining or coal cleaning
operations with an ash content greater than 50 percent, by weight, and a
heating value less than 13,900 kJ/kg (6,000 Btu/lb) on a dry basis.
Cogeneration, also known as combined heat and power, means a
facility that simultaneously produces both electric (or mechanical) and
useful thermal energy from the same primary energy source.
Coke oven gas means the volatile constituents generated in the
gaseous exhaust during the carbonization of bituminous coal to form
coke.
Combined cycle system means a system in which a separate source,
such as a gas turbine, internal combustion engine, kiln, etc., provides
exhaust gas to a steam generating unit.
Conventional technology means wet flue gas desulfurization (FGD)
technology, dry FGD technology, atmospheric fluidized bed combustion
technology, and oil hydrodesulfurization technology.
Distillate oil means fuel oils that contain 0.05 weight percent
nitrogen or less and comply with the specifications for fuel oil numbers
1 and 2, as defined by the American Society of Testing and Materials in
ASTM D396 (incorporated by reference, see Sec. 60.17), diesel fuel oil
numbers 1 and 2, as defined by the American Society for Testing and
Materials in ASTM D975 (incorporated by reference, see Sec. 60.17),
kerosine, as defined by the American Society of Testing and Materials in
ASTM D3699 (incorporated by reference, see Sec. 60.17), biodiesel as
defined by the American Society of Testing and Materials in ASTM D6751
(incorporated by reference, see Sec. 60.17), or biodiesel blends as
defined by the American Society of Testing and Materials in ASTM D7467
(incorporated by reference, see Sec. 60.17).
Dry flue gas desulfurization technology means a SO2
control system that is located downstream of the steam generating unit
and removes sulfur oxides from the combustion gases of the steam
generating unit by contacting the combustion gases with an alkaline
reagent and water, whether introduced separately or as a premixed slurry
or solution and forming a dry powder material. This definition includes
devices where the dry powder material is subsequently converted to
another form. Alkaline slurries or solutions used in dry flue gas
desulfurization technology include but are not limited to lime and
sodium.
Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source, such as a stationary gas turbine,
internal combustion engine, kiln, etc., to allow the firing of
additional fuel to heat the exhaust gases before the exhaust gases enter
a steam generating unit.
Emerging technology means any SO2 control system that is
not defined as a conventional technology under this section, and for
which the owner or operator of the facility has applied to the
Administrator and received approval to operate as an emerging technology
under Sec. 60.49b(a)(4).
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State Implementation
Plan, and any permit requirements established under 40 CFR 52.21 or
under 40 CFR 51.18 and 51.24.
Fluidized bed combustion technology means combustion of fuel in a
bed or series of beds (including but not limited to bubbling bed units
and circulating bed units) of limestone aggregate (or other sorbent
materials) in which these materials are forced upward by the flow of
combustion air and the gaseous products of combustion.
Fuel pretreatment means a process that removes a portion of the
sulfur in a fuel before combustion of the fuel in a steam generating
unit.
Full capacity means operation of the steam generating unit at 90
percent or more of the maximum steady-state design heat input capacity.
Gaseous fuel means any fuel that is a gas at ISO conditions. This
includes, but is not limited to, natural gas and gasified coal
(including coke oven gas).
Gross output means the gross useful work performed by the steam
generated. For units generating only electricity, the gross useful work
performed is the gross electrical output from the turbine/generator set.
For cogeneration units, the gross useful work
[[Page 168]]
performed is the gross electrical or mechanical output plus 75 percent
of the useful thermal output measured relative to ISO conditions that is
not used to generate additional electrical or mechanical output or to
enhance the performance of the unit (i.e., steam delivered to an
industrial process).
Heat input means heat derived from combustion of fuel in a steam
generating unit and does not include the heat derived from preheated
combustion air, recirculated flue gases, or exhaust gases from other
sources, such as gas turbines, internal combustion engines, kilns, etc.
Heat release rate means the steam generating unit design heat input
capacity (in MW or Btu/hr) divided by the furnace volume (in cubic
meters or cubic feet); the furnace volume is that volume bounded by the
front furnace wall where the burner is located, the furnace side
waterwall, and extending to the level just below or in front of the
first row of convection pass tubes.
Heat transfer medium means any material that is used to transfer
heat from one point to another point.
High heat release rate means a heat release rate greater than
730,000 J/sec-m\3\ (70,000 Btu/hr-ft\3\).
ISO Conditions means a temperature of 288 Kelvin, a relative
humidity of 60 percent, and a pressure of 101.3 kilopascals.
Lignite means a type of coal classified as lignite A or lignite B by
the American Society of Testing and Materials in ASTM D388 (incorporated
by reference, see Sec. 60.17).
Low heat release rate means a heat release rate of 730,000 J/sec-
m\3\ (70,000 Btu/hr-ft\3\) or less.
Mass-feed stoker steam generating unit means a steam generating unit
where solid fuel is introduced directly into a retort or is fed directly
onto a grate where it is combusted.
Maximum heat input capacity means the ability of a steam generating
unit to combust a stated maximum amount of fuel on a steady state basis,
as determined by the physical design and characteristics of the steam
generating unit.
Municipal-type solid waste means refuse, more than 50 percent of
which is waste consisting of a mixture of paper, wood, yard wastes, food
wastes, plastics, leather, rubber, and other combustible materials, and
noncombustible materials such as glass and rock.
Natural gas means:
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of which
the principal constituent is methane; or
(2) Liquefied petroleum gas, as defined by the American Society for
Testing and Materials in ASTM D1835 (incorporated by reference, see
Sec. 60.17); or
(3) A mixture of hydrocarbons that maintains a gaseous state at ISO
conditions. Additionally, natural gas must either be composed of at
least 70 percent methane by volume or have a gross calorific value
between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and
1,150 Btu per dry standard cubic foot).
Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
Oil means crude oil or petroleum or a liquid fuel derived from crude
oil or petroleum, including distillate and residual oil.
Petroleum refinery means industrial plants as classified by the
Department of Commerce under Standard Industrial Classification (SIC)
Code 29.
Potential sulfur dioxide emission rate means the theoretical
SO2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat
input) that would result from combusting fuel in an uncleaned state and
without using emission control systems. For gasified coal or oil that is
desulfurized prior to combustion, the Potential sulfur dioxide emission
rate is the theoretical SO2 emissions (ng/J or lb/MMBtu heat
input) that would result from combusting fuel in a cleaned state without
using any post combustion emission control systems.
Process heater means a device that is primarily used to heat a
material to initiate or promote a chemical reaction in which the
material participates as a reactant or catalyst.
[[Page 169]]
Pulp and paper mills means industrial plants that are classified by
the Department of Commerce under North American Industry Classification
System (NAICS) Code 322 or Standard Industrial Classification (SIC) Code
26.
Pulverized coal-fired steam generating unit means a steam generating
unit in which pulverized coal is introduced into an air stream that
carries the coal to the combustion chamber of the steam generating unit
where it is fired in suspension. This includes both conventional
pulverized coal-fired and micropulverized coal-fired steam generating
units. Residual oil means crude oil, fuel oil numbers 1 and 2 that have
a nitrogen content greater than 0.05 weight percent, and all fuel oil
numbers 4, 5 and 6, as defined by the American Society of Testing and
Materials in ASTM D396 (incorporated by reference, see Sec. 60.17).
Spreader stoker steam generating unit means a steam generating unit
in which solid fuel is introduced to the combustion zone by a mechanism
that throws the fuel onto a grate from above. Combustion takes place
both in suspension and on the grate.
Steam generating unit means a device that combusts any fuel or
byproduct/waste and produces steam or heats water or heats any heat
transfer medium. This term includes any municipal-type solid waste
incinerator with a heat recovery steam generating unit or any steam
generating unit that combusts fuel and is part of a cogeneration system
or a combined cycle system. This term does not include process heaters
as they are defined in this subpart.
Steam generating unit operating day means a 24-hour period between
12:00 midnight and the following midnight during which any fuel is
combusted at any time in the steam generating unit. It is not necessary
for fuel to be combusted continuously for the entire 24-hour period.
Temporary boiler means any gaseous or liquid fuel-fired steam
generating unit that is designed to, and is capable of, being carried or
moved from one location to another by means of, for example, wheels,
skids, carrying handles, dollies, trailers, or platforms. A steam
generating unit is not a temporary boiler if any one of the following
conditions exists:
(1) The equipment is attached to a foundation.
(2) The steam generating unit or a replacement remains at a location
for more than 180 consecutive days. Any temporary boiler that replaces a
temporary boiler at a location and performs the same or similar function
will be included in calculating the consecutive time period.
(3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one location to another in an
attempt to circumvent the residence time requirements of this
definition.
Very low sulfur oil means for units constructed, reconstructed, or
modified on or before February 28, 2005, oil that contains no more than
0.5 weight percent sulfur or that, when combusted without SO2
emission control, has a SO2 emission rate equal to or less
than 215 ng/J (0.5 lb/MMBtu) heat input. For units constructed,
reconstructed, or modified after February 28, 2005 and not located in a
noncontinental area, very low sulfur oil means oil that contains no more
than 0.30 weight percent sulfur or that, when combusted without
SO2 emission control, has a SO2 emission rate
equal to or less than 140 ng/J (0.32 lb/MMBtu) heat input. For units
constructed, reconstructed, or modified after February 28, 2005 and
located in a noncontinental area, very low sulfur oil means oil that
contains no more than 0.5 weight percent sulfur or that, when combusted
without SO2 emission control, has a SO2 emission
rate equal to or less than 215 ng/J (0.50 lb/MMBtu) heat input.
Wet flue gas desulfurization technology means a SO2
control system that is located downstream of the steam generating unit
and removes sulfur oxides from the combustion gases of the steam
generating unit by contacting the combustion gas with an alkaline slurry
or solution and forming a liquid
[[Page 170]]
material. This definition applies to devices where the aqueous liquid
material product of this contact is subsequently converted to other
forms. Alkaline reagents used in wet flue gas desulfurization technology
include, but are not limited to, lime, limestone, and sodium.
Wet scrubber system means any emission control device that mixes an
aqueous stream or slurry with the exhaust gases from a steam generating
unit to control emissions of PM or SO2.
Wood means wood, wood residue, bark, or any derivative fuel or
residue thereof, in any form, including, but not limited to, sawdust,
sanderdust, wood chips, scraps, slabs, millings, shavings, and processed
pellets made from wood or other forest residues.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009; 77
FR 9459, Feb. 16, 2012]
Sec. 60.42b Standard for sulfur dioxide (SO[bdi2]).
(a) Except as provided in paragraphs (b), (c), (d), or (j) of this
section, on and after the date on which the performance test is
completed or required to be completed under Sec. 60.8, whichever comes
first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification on or before February 28,
2005, that combusts coal or oil shall cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 87 ng/J
(0.20 lb/MMBtu) or 10 percent (0.10) of the potential SO2
emission rate (90 percent reduction) and the emission limit determined
according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR28JA09.003
Where:
Es = SO2 emission limit, in ng/J or lb/MMBtu heat
input;
Ka = 520 ng/J (or 1.2 lb/MMBtu);
Kb = 340 ng/J (or 0.80 lb/MMBtu);
Ha = Heat input from the combustion of coal, in J (MMBtu);
and
Hb = Heat input from the combustion of oil, in J (MMBtu).
For facilities complying with the percent reduction standard, only
the heat input supplied to the affected facility from the combustion of
coal and oil is counted in this paragraph. No credit is provided for the
heat input to the affected facility from the combustion of natural gas,
wood, municipal-type solid waste, or other fuels or heat derived from
exhaust gases from other sources, such as gas turbines, internal
combustion engines, kilns, etc.
(b) On and after the date on which the performance test is completed
or required to be completed under Sec. 60.8, whichever date comes
first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification on or before February 28,
2005, that combusts coal refuse alone in a fluidized bed combustion
steam generating unit shall cause to be discharged into the atmosphere
any gases that contain SO2 in excess of 87 ng/J (0.20 lb/
MMBtu) or 20 percent (0.20) of the potential SO2 emission
rate (80 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. If
coal or oil is fired with coal refuse, the affected facility is subject
to paragraph (a) or (d) of this section, as applicable. For facilities
complying with the percent reduction standard, only the heat input
supplied to the affected facility from the combustion of coal and oil is
counted in this paragraph. No credit is provided for the heat input to
the affected facility from the combustion of natural gas, wood,
municipal-type solid waste, or other fuels or heat derived from exhaust
gases from other sources, such as gas turbines, internal combustion
engines, kilns, etc.
(c) On and after the date on which the performance test is completed
or is required to be completed under Sec. 60.8, whichever comes first,
no owner or operator of an affected facility that combusts coal or oil,
either alone or in combination with any other fuel, and that uses an
emerging technology for the control of SO2 emissions, shall
cause to be discharged into the atmosphere any gases that contain
SO2 in excess of 50 percent of the potential SO2
emission rate (50 percent reduction) and that contain SO2 in
excess of the emission limit determined according to the following
formula:
[[Page 171]]
[GRAPHIC] [TIFF OMITTED] TR28JA09.004
Where:
Es = SO2 emission limit, in ng/J or lb/MM Btu heat input;
Kc = 260 ng/J (or 0.60 lb/MMBtu);
Kd = 170 ng/J (or 0.40 lb/MMBtu);
Hc = Heat input from the combustion of coal, in J (MMBtu);
and
Hd = Heat input from the combustion of oil, in J (MMBtu).
For facilities complying with the percent reduction standard, only
the heat input supplied to the affected facility from the combustion of
coal and oil is counted in this paragraph. No credit is provided for the
heat input to the affected facility from the combustion of natural gas,
wood, municipal-type solid waste, or other fuels, or from the heat input
derived from exhaust gases from other sources, such as gas turbines,
internal combustion engines, kilns, etc.
(d) On and after the date on which the performance test is completed
or required to be completed under Sec. 60.8, whichever comes first, no
owner or operator of an affected facility that commenced construction,
reconstruction, or modification on or before February 28, 2005 and
listed in paragraphs (d)(1), (2), (3), or (4) of this section shall
cause to be discharged into the atmosphere any gases that contain
SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the
affected facility combusts coal, or 215 ng/J (0.5 lb/MMBtu) heat input
if the affected facility combusts oil other than very low sulfur oil.
Percent reduction requirements are not applicable to affected facilities
under paragraphs (d)(1), (2), (3) or (4) of this section. For facilities
complying with paragraphs (d)(1), (2), or (3) of this section, only the
heat input supplied to the affected facility from the combustion of coal
and oil is counted in this paragraph. No credit is provided for the heat
input to the affected facility from the combustion of natural gas, wood,
municipal-type solid waste, or other fuels or heat derived from exhaust
gases from other sources, such as gas turbines, internal combustion
engines, kilns, etc.
(1) Affected facilities that have an annual capacity factor for coal
and oil of 30 percent (0.30) or less and are subject to a federally
enforceable permit limiting the operation of the affected facility to an
annual capacity factor for coal and oil of 30 percent (0.30) or less;
(2) Affected facilities located in a noncontinental area; or
(3) Affected facilities combusting coal or oil, alone or in
combination with any fuel, in a duct burner as part of a combined cycle
system where 30 percent (0.30) or less of the heat entering the steam
generating unit is from combustion of coal and oil in the duct burner
and 70 percent (0.70) or more of the heat entering the steam generating
unit is from the exhaust gases entering the duct burner; or
(4) The affected facility burns coke oven gas alone or in
combination with natural gas or very low sulfur distillate oil.
(e) Except as provided in paragraph (f) of this section, compliance
with the emission limits, fuel oil sulfur limits, and/or percent
reduction requirements under this section are determined on a 30-day
rolling average basis.
(f) Except as provided in paragraph (j)(2) of this section,
compliance with the emission limits or fuel oil sulfur limits under this
section is determined on a 24-hour average basis for affected facilities
that (1) have a federally enforceable permit limiting the annual
capacity factor for oil to 10 percent or less, (2) combust only very low
sulfur oil, and (3) do not combust any other fuel.
(g) Except as provided in paragraph (i) of this section and Sec.
60.45b(a), the SO2 emission limits and percent reduction
requirements under this section apply at all times, including periods of
startup, shutdown, and malfunction.
(h) Reductions in the potential SO2 emission rate through
fuel pretreatment are not credited toward the percent reduction
requirement under paragraph (c) of this section unless:
(1) Fuel pretreatment results in a 50 percent or greater reduction
in potential SO2 emissions and
(2) Emissions from the pretreated fuel (without combustion or post-
combustion SO2 control) are equal to or
[[Page 172]]
less than the emission limits specified in paragraph (c) of this
section.
(i) An affected facility subject to paragraph (a), (b), or (c) of
this section may combust very low sulfur oil or natural gas when the
SO2 control system is not being operated because of
malfunction or maintenance of the SO2 control system.
(j) Percent reduction requirements are not applicable to affected
facilities combusting only very low sulfur oil. The owner or operator of
an affected facility combusting very low sulfur oil shall demonstrate
that the oil meets the definition of very low sulfur oil by: (1)
Following the performance testing procedures as described in Sec.
60.45b(c) or Sec. 60.45b(d), and following the monitoring procedures as
described in Sec. 60.47b(a) or Sec. 60.47b(b) to determine
SO2 emission rate or fuel oil sulfur content; or (2)
maintaining fuel records as described in Sec. 60.49b(r).
(k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4)
of this section, on and after the date on which the initial performance
test is completed or is required to be completed under Sec. 60.8,
whichever date comes first, no owner or operator of an affected facility
that commences construction, reconstruction, or modification after
February 28, 2005, and that combusts coal, oil, natural gas, a mixture
of these fuels, or a mixture of these fuels with any other fuels shall
cause to be discharged into the atmosphere any gases that contain
SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 8
percent (0.08) of the potential SO2 emission rate (92 percent
reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. For facilities
complying with the percent reduction standard and paragraph (k)(3) of
this section, only the heat input supplied to the affected facility from
the combustion of coal and oil is counted in paragraph (k) of this
section. No credit is provided for the heat input to the affected
facility from the combustion of natural gas, wood, municipal-type solid
waste, or other fuels or heat derived from exhaust gases from other
sources, such as gas turbines, internal combustion engines, kilns, etc.
(2) Units firing only very low sulfur oil, gaseous fuel, a mixture
of these fuels, or a mixture of these fuels with any other fuels with a
potential SO2 emission rate of 140 ng/J (0.32 lb/MMBtu) heat
input or less are exempt from the SO2 emissions limit in
paragraph (k)(1) of this section.
(3) Units that are located in a noncontinental area and that combust
coal, oil, or natural gas shall not discharge any gases that contain
SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the
affected facility combusts coal, or 215 ng/J (0.50 lb/MMBtu) heat input
if the affected facility combusts oil or natural gas.
(4) As an alternative to meeting the requirements under paragraph
(k)(1) of this section, modified facilities that combust coal or a
mixture of coal with other fuels shall not cause to be discharged into
the atmosphere any gases that contain SO2 in excess of 87 ng/
J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential
SO2 emission rate (90 percent reduction) and 520 ng/J (1.2
lb/MMBtu) heat input.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009; 76
FR 3523, Jan. 20, 2011]
Sec. 60.43b Standard for particulate matter (PM).
(a) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
comes first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification on or before February 28,
2005 that combusts coal or combusts mixtures of coal with other fuels,
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain PM in excess of the following emission
limits:
(1) 22 ng/J (0.051 lb/MMBtu) heat input, (i) If the affected
facility combusts only coal, or
(ii) If the affected facility combusts coal and other fuels and has
an annual capacity factor for the other fuels of 10 percent (0.10) or
less.
(2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility
combusts coal and other fuels and has an annual capacity factor for the
other fuels greater than 10 percent (0.10) and is subject to a federally
enforceable requirement
[[Page 173]]
limiting operation of the affected facility to an annual capacity factor
greater than 10 percent (0.10) for fuels other than coal.
(3) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility
combusts coal or coal and other fuels and
(i) Has an annual capacity factor for coal or coal and other fuels
of 30 percent (0.30) or less,
(ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or
less,
(iii) Has a federally enforceable requirement limiting operation of
the affected facility to an annual capacity factor of 30 percent (0.30)
or less for coal or coal and other solid fuels, and
(iv) Construction of the affected facility commenced after June 19,
1984, and before November 25, 1986.
(4) An affected facility burning coke oven gas alone or in
combination with other fuels not subject to a PM standard under Sec.
60.43b and not using a post-combustion technology (except a wet
scrubber) for reducing PM or SO2 emissions is not subject to
the PM limits under Sec. 60.43b(a).
(b) On and after the date on which the performance test is completed
or required to be completed under Sec. 60.8, whichever comes first, no
owner or operator of an affected facility that commenced construction,
reconstruction, or modification on or before February 28, 2005, and that
combusts oil (or mixtures of oil with other fuels) and uses a
conventional or emerging technology to reduce SO2 emissions
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu)
heat input.
(c) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
comes first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification on or before February 28,
2005, and that combusts wood, or wood with other fuels, except coal,
shall cause to be discharged from that affected facility any gases that
contain PM in excess of the following emission limits:
(1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has
an annual capacity factor greater than 30 percent (0.30) for wood.
(2) 86 ng/J (0.20 lb/MMBtu) heat input if (i) The affected facility
has an annual capacity factor of 30 percent (0.30) or less for wood;
(ii) Is subject to a federally enforceable requirement limiting
operation of the affected facility to an annual capacity factor of 30
percent (0.30) or less for wood; and
(iii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or
less.
(d) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
combusts municipal-type solid waste or mixtures of municipal-type solid
waste with other fuels, shall cause to be discharged into the atmosphere
from that affected facility any gases that contain PM in excess of the
following emission limits:
(1) 43 ng/J (0.10 lb/MMBtu) heat input;
(i) If the affected facility combusts only municipal-type solid
waste; or
(ii) If the affected facility combusts municipal-type solid waste
and other fuels and has an annual capacity factor for the other fuels of
10 percent (0.10) or less.
(2) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility
combusts municipal-type solid waste or municipal-type solid waste and
other fuels; and
(i) Has an annual capacity factor for municipal-type solid waste and
other fuels of 30 percent (0.30) or less;
(ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or
less;
(iii) Has a federally enforceable requirement limiting operation of
the affected facility to an annual capacity factor of 30 percent (0.30)
or less for municipal-type solid waste, or municipal-type solid waste
and other fuels; and
(iv) Construction of the affected facility commenced after June 19,
1984, but on or before November 25, 1986.
(e) For the purposes of this section, the annual capacity factor is
determined by dividing the actual heat input to the steam generating
unit during the calendar year from the combustion of coal, wood, or
municipal-type
[[Page 174]]
solid waste, and other fuels, as applicable, by the potential heat input
to the steam generating unit if the steam generating unit had been
operated for 8,760 hours at the maximum heat input capacity.
(f) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
combusts coal, oil, wood, or mixtures of these fuels with any other
fuels shall cause to be discharged into the atmosphere any gases that
exhibit greater than 20 percent opacity (6-minute average), except for
one 6-minute period per hour of not more than 27 percent opacity. An
owner or operator of an affected facility that elects to install,
calibrate, maintain, and operate a continuous emissions monitoring
system (CEMS) for measuring PM emissions according to the requirements
of this subpart and is subject to a federally enforceable PM limit of
0.030 lb/MMBtu or less is exempt from the opacity standard specified in
this paragraph.
(g) The PM and opacity standards apply at all times, except during
periods of startup, shutdown, or malfunction.
(h)(1) Except as provided in paragraphs (h)(2), (h)(3), (h)(4),
(h)(5), and (h)(6) of this section, on and after the date on which the
initial performance test is completed or is required to be completed
under Sec. 60.8, whichever date comes first, no owner or operator of an
affected facility that commenced construction, reconstruction, or
modification after February 28, 2005, and that combusts coal, oil, wood,
a mixture of these fuels, or a mixture of these fuels with any other
fuels shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of 13 ng/J (0.030
lb/MMBtu) heat input,
(2) As an alternative to meeting the requirements of paragraph
(h)(1) of this section, the owner or operator of an affected facility
for which modification commenced after February 28, 2005, may elect to
meet the requirements of this paragraph. On and after the date on which
the initial performance test is completed or required to be completed
under Sec. 60.8, no owner or operator of an affected facility that
commences modification after February 28, 2005 shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain PM in excess of both:
(i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion
of coal, oil, wood, a mixture of these fuels, or a mixture of these
fuels with any other fuels; and
(ii) 0.2 percent of the combustion concentration (99.8 percent
reduction) when combusting coal, oil, wood, a mixture of these fuels, or
a mixture of these fuels with any other fuels.
(3) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commences modification after February 28, 2005, and that combusts over
30 percent wood (by heat input) on an annual basis and has a maximum
heat input capacity of 73 MW (250 MMBtu/h) or less shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
(4) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commences modification after February 28, 2005, and that combusts over
30 percent wood (by heat input) on an annual basis and has a maximum
heat input capacity greater than 73 MW (250 MMBtu/h) shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain PM in excess of 37 ng/J (0.085 lb/MMBtu) heat input.
(5) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, an owner or operator of an affected facility not
located in a noncontinental area that commences construction,
reconstruction, or modification after February 28, 2005, and that
combusts only oil that contains no more than 0.30 weight percent sulfur,
coke oven gas, a mixture of these fuels, or either
[[Page 175]]
fuel (or a mixture of these fuels) in combination with other fuels not
subject to a PM standard in Sec. 60.43b and not using a post-combustion
technology (except a wet scrubber) to reduce SO2 or PM
emissions is not subject to the PM limits in (h)(1) of this section.
(6) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, an owner or operator of an affected facility located
in a noncontinental area that commences construction, reconstruction, or
modification after February 28, 2005, and that combusts only oil that
contains no more than 0.5 weight percent sulfur, coke oven gas, a
mixture of these fuels, or either fuel (or a mixture of these fuels) in
combination with other fuels not subject to a PM standard in Sec.
60.43b and not using a post-combustion technology (except a wet
scrubber) to reduce SO2 or PM emissions is not subject to the
PM limits in (h)(1) of this section.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009; 77
FR 9459, Feb. 16, 2012]
Sec. 60.44b Standard for nitrogen oxides (NOX).
(a) Except as provided under paragraphs (k) and (l) of this section,
on and after the date on which the initial performance test is completed
or is required to be completed under Sec. 60.8, whichever date comes
first, no owner or operator of an affected facility that is subject to
the provisions of this section and that combusts only coal, oil, or
natural gas shall cause to be discharged into the atmosphere from that
affected facility any gases that contain NOX (expressed as
NO2) in excess of the following emission limits:
------------------------------------------------------------------------
Nitrogen oxide emission
limits (expressed as
Fuel/steam generating unit type NO2) heat input
-------------------------
ng/J lb/MMBTu
------------------------------------------------------------------------
(1) Natural gas and distillate oil, except
(4):
(i) Low heat release rate................. 43 0.10
(ii) High heat release rate............... 86 0.20
(2) Residual oil:
(i) Low heat release rate................. 130 0.30
(ii) High heat release rate............... 170 0.40
(3) Coal:
(i) Mass-feed stoker...................... 210 0.50
(ii) Spreader stoker and fluidized bed 260 0.60
combustion...............................
(iii) Pulverized coal..................... 300 0.70
(iv) Lignite, except (v).................. 260 0.60
(v) Lignite mined in North Dakota, South 340 0.80
Dakota, or Montana and combusted in a
slag tap furnace.........................
(vi) Coal-derived synthetic fuels......... 210 0.50
(4) Duct burner used in a combined cycle
system:
(i) Natural gas and distillate oil........ 86 0.20
(ii) Residual oil......................... 170 0.40
------------------------------------------------------------------------
(b) Except as provided under paragraphs (k) and (l) of this section,
on and after the date on which the initial performance test is completed
or is required to be completed under Sec. 60.8, whichever date comes
first, no owner or operator of an affected facility that simultaneously
combusts mixtures of only coal, oil, or natural gas shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain NOX in excess of a limit determined by the use
of the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.024
Where:
En = NOX emission limit (expressed as
NO2), ng/J (lb/MMBtu);
ELgo = Appropriate emission limit from paragraph (a)(1) for
combustion of natural gas or distillate oil, ng/J (lb/MMBtu);
Hgo = Heat input from combustion of natural gas or distillate
oil, J (MMBtu);
[[Page 176]]
ELro = Appropriate emission limit from paragraph (a)(2) for
combustion of residual oil, ng/J (lb/MMBtu);
Hro = Heat input from combustion of residual oil, J (MMBtu);
ELc = Appropriate emission limit from paragraph (a)(3) for
combustion of coal, ng/J (lb/MMBtu); and
Hc = Heat input from combustion of coal, J (MMBtu).
(c) Except as provided under paragraph (d) and (l) of this section,
on and after the date on which the initial performance test is completed
or is required to be completed under Sec. 60.8, whichever date comes
first, no owner or operator of an affected facility that simultaneously
combusts coal or oil, natural gas (or any combination of the three), and
wood, or any other fuel shall cause to be discharged into the atmosphere
any gases that contain NOX in excess of the emission limit
for the coal, oil, natural gas (or any combination of the three),
combusted in the affected facility, as determined pursuant to paragraph
(a) or (b) of this section. This standard does not apply to an affected
facility that is subject to and in compliance with a federally
enforceable requirement that limits operation of the affected facility
to an annual capacity factor of 10 percent (0.10) or less for coal, oil,
natural gas (or any combination of the three).
(d) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
simultaneously combusts natural gas and/or distillate oil with a
potential SO2 emissions rate of 26 ng/J (0.060 lb/MMBtu) or
less with wood, municipal-type solid waste, or other solid fuel, except
coal, shall cause to be discharged into the atmosphere from that
affected facility any gases that contain NOX in excess of 130
ng/J (0.30 lb/MMBtu) heat input unless the affected facility has an
annual capacity factor for natural gas, distillate oil, or a mixture of
these fuels of 10 percent (0.10) or less and is subject to a federally
enforceable requirement that limits operation of the affected facility
to an annual capacity factor of 10 percent (0.10) or less for natural
gas, distillate oil, or a mixture of these fuels.
(e) Except as provided under paragraph (l) of this section, on and
after the date on which the initial performance test is completed or is
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that simultaneously
combusts only coal, oil, or natural gas with byproduct/waste shall cause
to be discharged into the atmosphere any gases that contain
NOX in excess of the emission limit determined by the
following formula unless the affected facility has an annual capacity
factor for coal, oil, and natural gas of 10 percent (0.10) or less and
is subject to a federally enforceable requirement that limits operation
of the affected facility to an annual capacity factor of 10 percent
(0.10) or less:
(f) Any owner or operator of an affected facility that combusts
byproduct/waste with either natural gas or oil may petition the
Administrator within 180 days of the initial startup of the affected
facility to establish a NOX emission limit that shall apply
specifically to that affected facility when the byproduct/waste is
combusted. The petition shall include sufficient and appropriate data,
as determined by the Administrator, such as NOX emissions
from the affected facility, waste composition (including nitrogen
content), and combustion conditions to allow the Administrator to
confirm that the affected facility is unable to comply with the emission
limits in paragraph (e) of this section and to determine the appropriate
emission limit for the affected facility.
(1) Any owner or operator of an affected facility petitioning for a
facility-specific NOX emission limit under this section
shall:
(i) Demonstrate compliance with the emission limits for natural gas
and distillate oil in paragraph (a)(1) of this section or for residual
oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, by
conducting a 30-day performance test as provided in Sec. 60.46b(e).
During the performance test only natural gas, distillate oil, or
residual oil shall be combusted in the affected facility; and
(ii) Demonstrate that the affected facility is unable to comply with
the
[[Page 177]]
emission limits for natural gas and distillate oil in paragraph (a)(1)
of this section or for residual oil in paragraph (a)(2) or (l)(1) of
this section, as appropriate, when gaseous or liquid byproduct/waste is
combusted in the affected facility under the same conditions and using
the same technological system of emission reduction applied when
demonstrating compliance under paragraph (f)(1)(i) of this section.
(2) The NOX emission limits for natural gas or distillate
oil in paragraph (a)(1) of this section or for residual oil in paragraph
(a)(2) or (l)(1) of this section, as appropriate, shall be applicable to
the affected facility until and unless the petition is approved by the
Administrator. If the petition is approved by the Administrator, a
facility-specific NOX emission limit will be established at
the NOX emission level achievable when the affected facility
is combusting oil or natural gas and byproduct/waste in a manner that
the Administrator determines to be consistent with minimizing
NOX emissions. In lieu of amending this subpart, a letter
will be sent to the facility describing the facility-specific
NOX limit. The facility shall use the compliance procedures
detailed in the letter and make the letter available to the public. If
the Administrator determines it is appropriate, the conditions and
requirements of the letter can be reviewed and changed at any point.
(g) Any owner or operator of an affected facility that combusts
hazardous waste (as defined by 40 CFR part 261 or 40 CFR part 761) with
natural gas or oil may petition the Administrator within 180 days of the
initial startup of the affected facility for a waiver from compliance
with the NOX emission limit that applies specifically to that
affected facility. The petition must include sufficient and appropriate
data, as determined by the Administrator, on NOX emissions
from the affected facility, waste destruction efficiencies, waste
composition (including nitrogen content), the quantity of specific
wastes to be combusted and combustion conditions to allow the
Administrator to determine if the affected facility is able to comply
with the NOX emission limits required by this section. The
owner or operator of the affected facility shall demonstrate that when
hazardous waste is combusted in the affected facility, thermal
destruction efficiency requirements for hazardous waste specified in an
applicable federally enforceable requirement preclude compliance with
the NOX emission limits of this section. The NOX
emission limits for natural gas or distillate oil in paragraph (a)(1) of
this section or for residual oil in paragraph (a)(2) or (l)(1) of this
section, as appropriate, are applicable to the affected facility until
and unless the petition is approved by the Administrator. (See 40 CFR
761.70 for regulations applicable to the incineration of materials
containing polychlorinated biphenyls (PCB's).) In lieu of amending this
subpart, a letter will be sent to the facility describing the facility-
specific NOX limit. The facility shall use the compliance
procedures detailed in the letter and make the letter available to the
public. If the Administrator determines it is appropriate, the
conditions and requirements of the letter can be reviewed and changed at
any point.
(h) For purposes of paragraph (i) of this section, the
NOX standards under this section apply at all times including
periods of startup, shutdown, or malfunction.
(i) Except as provided under paragraph (j) of this section,
compliance with the emission limits under this section is determined on
a 30-day rolling average basis.
(j) Compliance with the emission limits under this section is
determined on a 24-hour average basis for the initial performance test
and on a 3-hour average basis for subsequent performance tests for any
affected facilities that:
(1) Combust, alone or in combination, only natural gas, distillate
oil, or residual oil with a nitrogen content of 0.30 weight percent or
less;
(2) Have a combined annual capacity factor of 10 percent or less for
natural gas, distillate oil, and residual oil with a nitrogen content of
0.30 weight percent or less; and
(3) Are subject to a federally enforceable requirement limiting
operation of the affected facility to the firing of natural gas,
distillate oil, and/or residual oil with a nitrogen content of 0.30
[[Page 178]]
weight percent or less and limiting operation of the affected facility
to a combined annual capacity factor of 10 percent or less for natural
gas, distillate oil, and residual oil with a nitrogen content of 0.30
weight percent or less.
(k) Affected facilities that meet the criteria described in
paragraphs (j)(1), (2), and (3) of this section, and that have a heat
input capacity of 73 MW (250 MMBtu/hr) or less, are not subject to the
NOX emission limits under this section.
(l) On and after the date on which the initial performance test is
completed or is required to be completed under 60.8, whichever date is
first, no owner or operator of an affected facility that commenced
construction after July 9, 1997 shall cause to be discharged into the
atmosphere from that affected facility any gases that contain NOx
(expressed as NO2) in excess of the following limits:
(1) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility
combusts coal, oil, or natural gas (or any combination of the three),
alone or with any other fuels. The affected facility is not subject to
this limit if it is subject to and in compliance with a federally
enforceable requirement that limits operation of the facility to an
annual capacity factor of 10 percent (0.10) or less for coal, oil, and
natural gas (or any combination of the three); or
(2) If the affected facility has a low heat release rate and
combusts natural gas or distillate oil in excess of 30 percent of the
heat input on a 30-day rolling average from the combustion of all fuels,
a limit determined by use of the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.026
Where:
En = NOX emission limit, (lb/MMBtu);
Hgo = 30-day heat input from combustion of natural gas or
distillate oil; and
Hr = 30-day heat input from combustion of any other fuel.
(3) After February 27, 2006, units where more than 10 percent of
total annual output is electrical or mechanical may comply with an
optional limit of 270 ng/J (2.1 lb/MWh) gross energy output, based on a
30-day rolling average. Units complying with this output-based limit
must demonstrate compliance according to the procedures of Sec.
60.48Da(i) of subpart Da of this part, and must monitor emissions
according to Sec. 60.49Da(c), (k), through (n) of subpart Da of this
part.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009; 77
FR 9459, Feb. 16, 2012]
Sec. 60.45b Compliance and performance test methods and procedures for
sulfur dioxide.
(a) The SO2 emission standards in Sec. 60.42b apply at
all times. Facilities burning coke oven gas alone or in combination with
any other gaseous fuels or distillate oil are allowed to exceed the
limit 30 operating days per calendar year for SO2 control
system maintenance.
(b) In conducting the performance tests required under Sec. 60.8,
the owner or operator shall use the methods and procedures in appendix A
(including fuel certification and sampling) of this part or the methods
and procedures as specified in this section, except as provided in Sec.
60.8(b). Section 60.8(f) does not apply to this section. The 30-day
notice required in Sec. 60.8(d) applies only to the initial performance
test unless otherwise specified by the Administrator.
(c) The owner or operator of an affected facility shall conduct
performance tests to determine compliance with the percent of potential
SO2 emission rate (% Ps) and the SO2
emission rate (Es) pursuant to Sec. 60.42b following the
procedures listed below, except as provided under paragraph (d) and (k)
of this section.
(1) The initial performance test shall be conducted over 30
consecutive operating days of the steam generating unit. Compliance with
the SO2 standards shall be determined using a 30-day average.
The first operating day included in the initial performance test shall
be scheduled within 30 days after achieving the maximum production rate
at which the affected facility will be operated, but not later than 180
days after initial startup of the facility.
[[Page 179]]
(2) If only coal, only oil, or a mixture of coal and oil is
combusted, the following procedures are used:
(i) The procedures in Method 19 of appendix A-7 of this part are
used to determine the hourly SO2 emission rate
(Eho) and the 30-day average emission rate (Eao).
The hourly averages used to compute the 30-day averages are obtained
from the CEMS of Sec. 60.47b(a) or (b).
(ii) The percent of potential SO2 emission rate
(%Ps) emitted to the atmosphere is computed using the
following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.027
Where:
%Ps = Potential SO2 emission rate, percent;
%Rg = SO2 removal efficiency of the control device
as determined by Method 19 of appendix A of this part, in
percent; and
%Rf = SO2 removal efficiency of fuel pretreatment
as determined by Method 19 of appendix A of this part, in
percent.
(3) If coal or oil is combusted with other fuels, the same
procedures required in paragraph (c)(2) of this section are used, except
as provided in the following:
(i) An adjusted hourly SO2 emission rate
(Eho\o\) is used in Equation 19-19 of Method 19 of appendix A
of this part to compute an adjusted 30-day average emission rate
(Eao\o\). The Eho[deg] is computed using the following
formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.028
Where:
Eho\o\ = Adjusted hourly SO2 emission rate, ng/J
(lb/MMBtu);
Eho = Hourly SO2 emission rate, ng/J (lb/MMBtu);
Ew = SO2 concentration in fuels other than coal
and oil combusted in the affected facility, as determined by
the fuel sampling and analysis procedures in Method 19 of
appendix A of this part, ng/J (lb/MMBtu). The value
Ew for each fuel lot is used for each hourly
average during the time that the lot is being combusted; and
Xk = Fraction of total heat input from fuel combustion
derived from coal, oil, or coal and oil, as determined by
applicable procedures in Method 19 of appendix A of this part.
(ii) To compute the percent of potential SO2 emission
rate (%Ps), an adjusted %Rg (%Rg\o\) is
computed from the adjusted Eao\o\ from paragraph (b)(3)(i) of
this section and an adjusted average SO2 inlet rate
(Eai\o\) using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.029
To compute Eai\o\, an adjusted hourly SO2
inlet rate (Ehi\o\) is used. The Ehi\o\ is
computed using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.030
Where:
Ehi\o\ = Adjusted hourly SO2 inlet rate, ng/J (lb/
MMBtu); and
Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu).
(4) The owner or operator of an affected facility subject to
paragraph (c)(3) of this section does not have to measure parameters
Ew or Xk if the owner or operator elects to assume
that Xk = 1.0. Owners or operators of affected facilities who
assume Xk = 1.0 shall:
(i) Determine %Ps following the procedures in paragraph
(c)(2) of this section; and
(ii) Sulfur dioxide emissions (Es) are considered to be
in compliance with SO2 emission limits under Sec. 60.42b.
(5) The owner or operator of an affected facility that qualifies
under the provisions of Sec. 60.42b(d) does not have to measure
parameters Ew or Xk in paragraph (c)(3) of this
section if the owner or operator of the affected facility elects to
measure SO2 emission rates of the coal or oil following the
fuel sampling and analysis procedures in Method 19 of appendix A-7 of
this part.
(d) Except as provided in paragraph (j) of this section, the owner
or operator of an affected facility that combusts only very low sulfur
oil, natural gas, or a mixture of these fuels, has an annual capacity
factor for oil of 10 percent (0.10) or less, and is subject to a
federally enforceable requirement limiting operation of the affected
facility to an annual capacity factor for oil of 10 percent (0.10) or
less shall:
[[Page 180]]
(1) Conduct the initial performance test over 24 consecutive steam
generating unit operating hours at full load;
(2) Determine compliance with the standards after the initial
performance test based on the arithmetic average of the hourly emissions
data during each steam generating unit operating day if a CEMS is used,
or based on a daily average if Method 6B of appendix A of this part or
fuel sampling and analysis procedures under Method 19 of appendix A of
this part are used.
(e) The owner or operator of an affected facility subject to Sec.
60.42b(d)(1) shall demonstrate the maximum design capacity of the steam
generating unit by operating the facility at maximum capacity for 24
hours. This demonstration will be made during the initial performance
test and a subsequent demonstration may be requested at any other time.
If the 24-hour average firing rate for the affected facility is less
than the maximum design capacity provided by the manufacturer of the
affected facility, the 24-hour average firing rate shall be used to
determine the capacity utilization rate for the affected facility,
otherwise the maximum design capacity provided by the manufacturer is
used.
(f) For the initial performance test required under Sec. 60.8,
compliance with the SO2 emission limits and percent reduction
requirements under Sec. 60.42b is based on the average emission rates
and the average percent reduction for SO2 for the first 30
consecutive steam generating unit operating days, except as provided
under paragraph (d) of this section. The initial performance test is the
only test for which at least 30 days prior notice is required unless
otherwise specified by the Administrator. The initial performance test
is to be scheduled so that the first steam generating unit operating day
of the 30 successive steam generating unit operating days is completed
within 30 days after achieving the maximum production rate at which the
affected facility will be operated, but not later than 180 days after
initial startup of the facility. The boiler load during the 30-day
period does not have to be the maximum design load, but must be
representative of future operating conditions and include at least one
24-hour period at full load.
(g) After the initial performance test required under Sec. 60.8,
compliance with the SO2 emission limits and percent reduction
requirements under Sec. 60.42b is based on the average emission rates
and the average percent reduction for SO2 for 30 successive
steam generating unit operating days, except as provided under paragraph
(d). A separate performance test is completed at the end of each steam
generating unit operating day after the initial performance test, and a
new 30-day average emission rate and percent reduction for
SO2 are calculated to show compliance with the standard.
(h) Except as provided under paragraph (i) of this section, the
owner or operator of an affected facility shall use all valid
SO2 emissions data in calculating %Ps and
Eho under paragraph (c), of this section whether or not the
minimum emissions data requirements under Sec. 60.46b are achieved. All
valid emissions data, including valid SO2 emission data
collected during periods of startup, shutdown and malfunction, shall be
used in calculating %Ps and Eho pursuant to
paragraph (c) of this section.
(i) During periods of malfunction or maintenance of the
SO2 control systems when oil is combusted as provided under
Sec. 60.42b(i), emission data are not used to calculate %Ps
or Es under Sec. 60.42b(a), (b) or (c), however, the
emissions data are used to determine compliance with the emission limit
under Sec. 60.42b(i).
(j) The owner or operator of an affected facility that only combusts
very low sulfur oil, natural gas, or a mixture of these fuels with any
other fuels not subject to an SO2 standard is not subject to
the compliance and performance testing requirements of this section if
the owner or operator obtains fuel receipts as described in Sec.
60.49b(r).
(k) The owner or operator of an affected facility seeking to
demonstrate compliance in Sec. Sec. 60.42b(d)(4), 60.42b(j),
60.42b(k)(2), and 60.42b(k)(3) (when not burning coal) shall follow the
applicable procedures in Sec. 60.49b(r).
[72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009]
[[Page 181]]
Sec. 60.46b Compliance and performance test methods and procedures for
particulate matter and nitrogen oxides.
(a) The PM emission standards and opacity limits under Sec. 60.43b
apply at all times except during periods of startup, shutdown, or
malfunction. The NOX emission standards under Sec. 60.44b
apply at all times.
(b) Compliance with the PM emission standards under Sec. 60.43b
shall be determined through performance testing as described in
paragraph (d) of this section, except as provided in paragraph (i) of
this section.
(c) Compliance with the NOX emission standards under
Sec. 60.44b shall be determined through performance testing under
paragraph (e) or (f), or under paragraphs (g) and (h) of this section,
as applicable.
(d) To determine compliance with the PM emission limits and opacity
limits under Sec. 60.43b, the owner or operator of an affected facility
shall conduct an initial performance test as required under Sec. 60.8,
and shall conduct subsequent performance tests as requested by the
Administrator, using the following procedures and reference methods:
(1) Method 3A or 3B of appendix A-2 of this part is used for gas
analysis when applying Method 5 of appendix A-3 of this part or Method
17 of appendix A-6 of this part.
(2) Method 5, 5B, or 17 of appendix A of this part shall be used to
measure the concentration of PM as follows:
(i) Method 5 of appendix A of this part shall be used at affected
facilities without wet flue gas desulfurization (FGD) systems; and
(ii) Method 17 of appendix A-6 of this part may be used at
facilities with or without wet scrubber systems provided the stack gas
temperature does not exceed a temperature of 160 [deg]C (320 [deg]F).
The procedures of sections 8.1 and 11.1 of Method 5B of appendix A-3 of
this part may be used in Method 17 of appendix A-6 of this part only if
it is used after a wet FGD system. Do not use Method 17 of appendix A-6
of this part after wet FGD systems if the effluent is saturated or laden
with water droplets.
(iii) Method 5B of appendix A of this part is to be used only after
wet FGD systems.
(3) Method 1 of appendix A of this part is used to select the
sampling site and the number of traverse sampling points. The sampling
time for each run is at least 120 minutes and the minimum sampling
volume is 1.7 dscm (60 dscf) except that smaller sampling times or
volumes may be approved by the Administrator when necessitated by
process variables or other factors.
(4) For Method 5 of appendix A of this part, the temperature of the
sample gas in the probe and filter holder is monitored and is maintained
at 16014 [deg]C (32025
[deg]F).
(5) For determination of PM emissions, the oxygen (O2) or
CO2 sample is obtained simultaneously with each run of Method
5, 5B, or 17 of appendix A of this part by traversing the duct at the
same sampling location.
(6) For each run using Method 5, 5B, or 17 of appendix A of this
part, the emission rate expressed in ng/J heat input is determined
using:
(i) The O2 or CO2 measurements and PM
measurements obtained under this section;
(ii) The dry basis F factor; and
(iii) The dry basis emission rate calculation procedure contained in
Method 19 of appendix A of this part.
(7) Method 9 of appendix A of this part is used for determining the
opacity of stack emissions.
(e) To determine compliance with the emission limits for
NOX required under Sec. 60.44b, the owner or operator of an
affected facility shall conduct the performance test as required under
Sec. 60.8 using the continuous system for monitoring NOX
under Sec. 60.48(b).
(1) For the initial compliance test, NOX from the steam
generating unit are monitored for 30 successive steam generating unit
operating days and the 30-day average emission rate is used to determine
compliance with the NOX emission standards under Sec.
60.44b. The 30-day average emission rate is calculated as the average of
all hourly emissions data recorded by the monitoring system during the
30-day test period.
(2) Following the date on which the initial performance test is
completed
[[Page 182]]
or is required to be completed in Sec. 60.8, whichever date comes
first, the owner or operator of an affected facility which combusts coal
(except as specified under Sec. 60.46b(e)(4)) or which combusts
residual oil having a nitrogen content greater than 0.30 weight percent
shall determine compliance with the NOX emission standards in
Sec. 60.44b on a continuous basis through the use of a 30-day rolling
average emission rate. A new 30-day rolling average emission rate is
calculated for each steam generating unit operating day as the average
of all of the hourly NOX emission data for the preceding 30
steam generating unit operating days.
(3) Following the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, the owner or operator of an affected facility that has
a heat input capacity greater than 73 MW (250 MMBtu/hr) and that
combusts natural gas, distillate oil, or residual oil having a nitrogen
content of 0.30 weight percent or less shall determine compliance with
the NOX standards under Sec. 60.44b on a continuous basis
through the use of a 30-day rolling average emission rate. A new 30-day
rolling average emission rate is calculated each steam generating unit
operating day as the average of all of the hourly NOX
emission data for the preceding 30 steam generating unit operating days.
(4) Following the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, the owner or operator of an affected facility that has a
heat input capacity of 73 MW (250 MMBtu/hr) or less and that combusts
natural gas, distillate oil, gasified coal, or residual oil having a
nitrogen content of 0.30 weight percent or less shall upon request
determine compliance with the NOX standards in Sec. 60.44b
through the use of a 30-day performance test. During periods when
performance tests are not requested, NOX emissions data
collected pursuant to Sec. 60.48b(g)(1) or Sec. 60.48b(g)(2) are used
to calculate a 30-day rolling average emission rate on a daily basis and
used to prepare excess emission reports, but will not be used to
determine compliance with the NOX emission standards. A new
30-day rolling average emission rate is calculated each steam generating
unit operating day as the average of all of the hourly NOX
emission data for the preceding 30 steam generating unit operating days.
(5) If the owner or operator of an affected facility that combusts
residual oil does not sample and analyze the residual oil for nitrogen
content, as specified in Sec. 60.49b(e), the requirements of Sec.
60.48b(g)(1) apply and the provisions of Sec. 60.48b(g)(2) are
inapplicable.
(f) To determine compliance with the emissions limits for
NOX required by Sec. 60.44b(a)(4) or Sec. 60.44b(l) for
duct burners used in combined cycle systems, either of the procedures
described in paragraph (f)(1) or (2) of this section may be used:
(1) The owner or operator of an affected facility shall conduct the
performance test required under Sec. 60.8 as follows:
(i) The emissions rate (E) of NOX shall be computed using
Equation 1 in this section:
[GRAPHIC] [TIFF OMITTED] TR13JN07.031
Where:
E = Emissions rate of NOX from the duct burner, ng/J (lb/
MMBtu) heat input;
Esg = Combined effluent emissions rate, in ng/J (lb/MMBtu)
heat input using appropriate F factor as described in Method
19 of appendix A of this part;
Hg = Heat input rate to the combustion turbine, in J/hr
(MMBtu/hr);
Hb = Heat input rate to the duct burner, in J/hr (MMBtu/hr);
and
Eg = Emissions rate from the combustion turbine, in ng/J (lb/
MMBtu) heat input calculated using appropriate F factor as
described in Method 19 of appendix A of this part.
(ii) Method 7E of appendix A of this part or Method 320 of appendix
A of part 63 shall be used to determine the NOX
concentrations. Method 3A or 3B of appendix A of this part shall be used
to determine O2 concentration.
(iii) The owner or operator shall identify and demonstrate to the
Administrator's satisfaction suitable methods to determine the average
hourly heat input rate to the combustion turbine and the average hourly
heat input rate to the affected duct burner.
[[Page 183]]
(iv) Compliance with the emissions limits under Sec. 60.44b(a)(4)
or Sec. 60.44b(l) is determined by the three-run average (nominal 1-
hour runs) for the initial and subsequent performance tests; or
(2) The owner or operator of an affected facility may elect to
determine compliance on a 30-day rolling average basis by using the CEMS
specified under Sec. 60.48b for measuring NOX and
O2 and meet the requirements of Sec. 60.48b. The sampling
site shall be located at the outlet from the steam generating unit. The
NOX emissions rate at the outlet from the steam generating
unit shall constitute the NOX emissions rate from the duct
burner of the combined cycle system.
(g) The owner or operator of an affected facility described in Sec.
60.44b(j) or Sec. 60.44b(k) shall demonstrate the maximum heat input
capacity of the steam generating unit by operating the facility at
maximum capacity for 24 hours. The owner or operator of an affected
facility shall determine the maximum heat input capacity using the heat
loss method or the heat input method described in sections 5 and 7.3 of
the ASME Power Test Codes 4.1 (incorporated by reference, see Sec.
60.17). This demonstration of maximum heat input capacity shall be made
during the initial performance test for affected facilities that meet
the criteria of Sec. 60.44b(j). It shall be made within 60 days after
achieving the maximum production rate at which the affected facility
will be operated, but not later than 180 days after initial start-up of
each facility, for affected facilities meeting the criteria of Sec.
60.44b(k). Subsequent demonstrations may be required by the
Administrator at any other time. If this demonstration indicates that
the maximum heat input capacity of the affected facility is less than
that stated by the manufacturer of the affected facility, the maximum
heat input capacity determined during this demonstration shall be used
to determine the capacity utilization rate for the affected facility.
Otherwise, the maximum heat input capacity provided by the manufacturer
is used.
(h) The owner or operator of an affected facility described in Sec.
60.44b(j) that has a heat input capacity greater than 73 MW (250 MMBtu/
hr) shall:
(1) Conduct an initial performance test as required under Sec. 60.8
over a minimum of 24 consecutive steam generating unit operating hours
at maximum heat input capacity to demonstrate compliance with the
NOX emission standards under Sec. 60.44b using Method 7, 7A,
or 7E of appendix A of this part, Method 320 of appendix A of part 63 of
this chapter, or other approved reference methods; and
(2) Conduct subsequent performance tests once per calendar year or
every 400 hours of operation (whichever comes first) to demonstrate
compliance with the NOX emission standards under Sec. 60.44b
over a minimum of 3 consecutive steam generating unit operating hours at
maximum heat input capacity using Method 7, 7A, or 7E of appendix A of
this part, Method 320 of appendix A of part 63, or other approved
reference methods.
(i) The owner or operator of an affected facility seeking to
demonstrate compliance with the PM limit in paragraphs Sec.
60.43b(a)(4) or Sec. 60.43b(h)(5) shall follow the applicable
procedures in Sec. 60.49b(r).
(j) In place of PM testing with Method 5 or 5B of appendix A-3 of
this part, or Method 17 of appendix A-6 of this part, an owner or
operator may elect to install, calibrate, maintain, and operate a CEMS
for monitoring PM emissions discharged to the atmosphere and record the
output of the system. The owner or operator of an affected facility who
elects to continuously monitor PM emissions instead of conducting
performance testing using Method 5 or 5B of appendix A-3 of this part or
Method 17 of appendix A-6 of this part shall comply with the
requirements specified in paragraphs (j)(1) through (j)(14) of this
section.
(1) Notify the Administrator one month before starting use of the
system.
(2) Notify the Administrator one month before stopping use of the
system.
(3) The monitor shall be installed, evaluated, and operated in
accordance with Sec. 60.13 of subpart A of this part.
(4) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of the affected
facility, as specified
[[Page 184]]
under Sec. 60.8 of subpart A of this part or within 180 days of
notification to the Administrator of use of the CEMS if the owner or
operator was previously determining compliance by Method 5, 5B, or 17 of
appendix A of this part performance tests, whichever is later.
(5) The owner or operator of an affected facility shall conduct an
initial performance test for PM emissions as required under Sec. 60.8
of subpart A of this part. Compliance with the PM emission limit shall
be determined by using the CEMS specified in paragraph (j) of this
section to measure PM and calculating a 24-hour block arithmetic average
emission concentration using EPA Reference Method 19 of appendix A of
this part, section 4.1.
(6) Compliance with the PM emission limit shall be determined based
on the 24-hour daily (block) average of the hourly arithmetic average
emission concentrations using CEMS outlet data.
(7) At a minimum, valid CEMS hourly averages shall be obtained as
specified in paragraphs (j)(7)(i) of this section for 75 percent of the
total operating hours per 30-day rolling average.
(i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(ii) [Reserved]
(8) The 1-hour arithmetic averages required under paragraph (j)(7)
of this section shall be expressed in ng/J or lb/MMBtu heat input and
shall be used to calculate the boiler operating day daily arithmetic
average emission concentrations. The 1-hour arithmetic averages shall be
calculated using the data points required under Sec. 60.13(e)(2) of
subpart A of this part.
(9) All valid CEMS data shall be used in calculating average
emission concentrations even if the minimum CEMS data requirements of
paragraph (j)(7) of this section are not met.
(10) The CEMS shall be operated according to Performance
Specification 11 in appendix B of this part.
(11) During the correlation testing runs of the CEMS required by
Performance Specification 11 in appendix B of this part, PM and
O2 (or CO2) data shall be collected concurrently
(or within a 30-to 60-minute period) by both the continuous emission
monitors and performance tests conducted using the following test
methods.
(i) For PM, Method 5 or 5B of appendix A-3 of this part or Method 17
of appendix A-6 of this part shall be used; and
(ii) For O2 (or CO2), Method 3A or 3B of
appendix A-2 of this part, as applicable shall be used.
(12) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 2 in appendix F of
this part. Relative Response Audit's must be performed annually and
Response Correlation Audits must be performed every 3 years.
(13) When PM emissions data are not obtained because of CEMS
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained by using other monitoring systems as
approved by the Administrator or EPA Reference Method 19 of appendix A
of this part to provide, as necessary, valid emissions data for a
minimum of 75 percent of total operating hours per 30-day rolling
average.
(14) As of January 1, 2012, and within 90 days after the date of
completing each performance test, as defined in Sec. 60.8, conducted to
demonstrate compliance with this subpart, you must submit relative
accuracy test audit (i.e., reference method) data and performance test
(i.e., compliance test) data, except opacity data, electronically to
EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool
(ERT) (see http://www.epa.gov/ttn/chief/ert/ert--tool.html/) or other
compatible electronic spreadsheet. Only data collected using test
methods compatible with ERT are subject to this requirement to be
submitted electronically into EPA's WebFIRE database.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009; 76
FR 3523, Jan. 20, 2011; 77 FR 9460, Feb. 16, 2012; 79 FR 11249, Feb. 27,
2014]
Sec. 60.47b Emission monitoring for sulfur dioxide.
(a) Except as provided in paragraphs (b) and (f) of this section,
the owner or operator of an affected facility subject to the
SO2 standards in Sec. 60.42b shall install, calibrate,
maintain, and operate
[[Page 185]]
CEMS for measuring SO2 concentrations and either
O2 or CO2 concentrations and shall record the
output of the systems. For units complying with the percent reduction
standard, the SO2 and either O2 or CO2
concentrations shall both be monitored at the inlet and outlet of the
SO2 control device. If the owner or operator has installed
and certified SO2 and O2 or CO2 CEMS
according to the requirements of Sec. 75.20(c)(1) of this chapter and
appendix A to part 75 of this chapter, and is continuing to meet the
ongoing quality assurance requirements of Sec. 75.21 of this chapter
and appendix B to part 75 of this chapter, those CEMS may be used to
meet the requirements of this section, provided that:
(1) When relative accuracy testing is conducted, SO2
concentration data and CO2 (or O2) data are
collected simultaneously; and
(2) In addition to meeting the applicable SO2 and
CO2 (or O2) relative accuracy specifications in
Figure 2 of appendix B to part 75 of this chapter, the relative accuracy
(RA) standard in section 13.2 of Performance Specification 2 in appendix
B to this part is met when the RA is calculated on a lb/MMBtu basis; and
(3) The reporting requirements of Sec. 60.49b are met.
SO2 and CO2 (or O2) data used to meet
the requirements of Sec. 60.49b shall not include substitute data
values derived from the missing data procedures in subpart D of part 75
of this chapter, nor shall the SO2 data have been bias
adjusted according to the procedures of part 75 of this chapter.
(b) As an alternative to operating CEMS as required under paragraph
(a) of this section, an owner or operator may elect to determine the
average SO2 emissions and percent reduction by:
(1) Collecting coal or oil samples in an as-fired condition at the
inlet to the steam generating unit and analyzing them for sulfur and
heat content according to Method 19 of appendix A of this part. Method
19 of appendix A of this part provides procedures for converting these
measurements into the format to be used in calculating the average
SO2 input rate, or
(2) Measuring SO2 according to Method 6B of appendix A of
this part at the inlet or outlet to the SO2 control system.
An initial stratification test is required to verify the adequacy of the
sampling location for Method 6B of appendix A of this part. The
stratification test shall consist of three paired runs of a suitable
SO2 and CO2 measurement train operated at the
candidate location and a second similar train operated according to the
procedures in Section 3.2 and the applicable procedures in Section 7 of
Performance Specification 2. Method 6B of appendix A of this part,
Method 6A of appendix A of this part, or a combination of Methods 6 and
3 or 3B of appendix A of this part or Methods 6C or Method 320 of
appendix A of part 63 of this chapter and 3A of appendix A of this part
are suitable measurement techniques. If Method 6B of appendix A of this
part is used for the second train, sampling time and timer operation may
be adjusted for the stratification test as long as an adequate sample
volume is collected; however, both sampling trains are to be operated
similarly. For the location to be adequate for Method 6B of appendix A
of this part, 24-hour tests, the mean of the absolute difference between
the three paired runs must be less than 10 percent.
(3) A daily SO2 emission rate, ED, shall be
determined using the procedure described in Method 6A of appendix A of
this part, section 7.6.2 (Equation 6A-8) and stated in ng/J (lb/MMBtu)
heat input.
(4) The mean 30-day emission rate is calculated using the daily
measured values in ng/J (lb/MMBtu) for 30 successive steam generating
unit operating days using equation 19-20 of Method 19 of appendix A of
this part.
(c) The owner or operator of an affected facility shall obtain
emission data for at least 75 percent of the operating hours in at least
22 out of 30 successive boiler operating days. If this minimum data
requirement is not met with a single monitoring system, the owner or
operator of the affected facility shall supplement the emission data
with data collected with other monitoring systems as approved by the
Administrator or the reference methods
[[Page 186]]
and procedures as described in paragraph (b) of this section.
(d) The 1-hour average SO2 emission rates measured by the
CEMS required by paragraph (a) of this section and required under Sec.
60.13(h) is expressed in ng/J or lb/MMBtu heat input and is used to
calculate the average emission rates under Sec. 60.42(b). Each 1-hour
average SO2 emission rate must be based on 30 or more minutes
of steam generating unit operation. The hourly averages shall be
calculated according to Sec. 60.13(h)(2). Hourly SO2
emission rates are not calculated if the affected facility is operated
less than 30 minutes in a given clock hour and are not counted toward
determination of a steam generating unit operating day.
(e) The procedures under Sec. 60.13 shall be followed for
installation, evaluation, and operation of the CEMS.
(1) Except as provided for in paragraph (e)(4) of this section, all
CEMS shall be operated in accordance with the applicable procedures
under Performance Specifications 1, 2, and 3 of appendix B of this part.
(2) Except as provided for in paragraph (e)(4) of this section,
quarterly accuracy determinations and daily calibration drift tests
shall be performed in accordance with Procedure 1 of appendix F of this
part.
(3) For affected facilities combusting coal or oil, alone or in
combination with other fuels, the span value of the SO2 CEMS
at the inlet to the SO2 control device is 125 percent of the
maximum estimated hourly potential SO2 emissions of the fuel
combusted, and the span value of the CEMS at the outlet to the
SO2 control device is 50 percent of the maximum estimated
hourly potential SO2 emissions of the fuel combusted.
Alternatively, SO2 span values determined according to
section 2.1.1 in appendix A to part 75 of this chapter may be used.
(4) As an alternative to meeting the requirements of requirements of
paragraphs (e)(1) and (e)(2) of this section, the owner or operator may
elect to implement the following alternative data accuracy assessment
procedures:
(i) For all required CO2 and O2 monitors and
for SO2 and NOX monitors with span values greater
than or equal to 100 ppm, the daily calibration error test and
calibration adjustment procedures described in sections 2.1.1 and 2.1.3
of appendix B to part 75 of this chapter may be followed instead of the
CD assessment procedures in Procedure 1, section 4.1 of appendix F to
this part.
(ii) For all required CO2 and O2 monitors and
for SO2 and NOX monitors with span values greater
than 30 ppm, quarterly linearity checks may be performed in accordance
with section 2.2.1 of appendix B to part 75 of this chapter, instead of
performing the cylinder gas audits (CGAs) described in Procedure 1,
section 5.1.2 of appendix F to this part. If this option is selected:
The frequency of the linearity checks shall be as specified in section
2.2.1 of appendix B to part 75 of this chapter; the applicable linearity
specifications in section 3.2 of appendix A to part 75 of this chapter
shall be met; the data validation and out-of-control criteria in section
2.2.3 of appendix B to part 75 of this chapter shall be followed instead
of the excessive audit inaccuracy and out-of-control criteria in
Procedure 1, section 5.2 of appendix F to this part; and the grace
period provisions in section 2.2.4 of appendix B to part 75 of this
chapter shall apply. For the purposes of data validation under this
subpart, the cylinder gas audits described in Procedure 1, section 5.1.2
of appendix F to this part shall be performed for SO2 and
NOX span values less than or equal to 30 ppm; and
(iii) For SO2, CO2, and O2
monitoring systems and for NOX emission rate monitoring
systems, RATAs may be performed in accordance with section 2.3 of
appendix B to part 75 of this chapter instead of following the
procedures described in Procedure 1, section 5.1.1 of appendix F to this
part. If this option is selected: The frequency of each RATA shall be as
specified in section 2.3.1 of appendix B to part 75 of this chapter; the
applicable relative accuracy specifications shown in Figure 2 in
appendix B to part 75 of this chapter shall be met; the data validation
and out-of-control criteria in section 2.3.2 of appendix B to part 75 of
this chapter shall be followed instead of the excessive audit inaccuracy
and out-of-control criteria in Procedure 1, section 5.2 of appendix F to
this part; and the grace period provisions in section 2.3.3
[[Page 187]]
of appendix B to part 75 of this chapter shall apply. For the purposes
of data validation under this subpart, the relative accuracy
specification in section 13.2 of Performance Specification 2 in appendix
B to this part shall be met on a lb/MMBtu basis for SO2
(regardless of the SO2 emission level during the RATA), and
for NOX when the average NOX emission rate
measured by the reference method during the RATA is less than 0.100 lb/
MMBtu.
(f) The owner or operator of an affected facility that combusts very
low sulfur oil or is demonstrating compliance under Sec. 60.45b(k) is
not subject to the emission monitoring requirements under paragraph (a)
of this section if the owner or operator maintains fuel records as
described in Sec. 60.49b(r).
[72 FR 32742, June 13, 2007, as amended at 74 FR 5087, Jan. 28, 2009; 79
FR 11249, Feb. 27, 2014]
Sec. 60.48b Emission monitoring for particulate matter and nitrogen oxides.
(a) Except as provided in paragraph (j) of this section, the owner
or operator of an affected facility subject to the opacity standard
under Sec. 60.43b shall install, calibrate, maintain, and operate a
continuous opacity monitoring systems (COMS) for measuring the opacity
of emissions discharged to the atmosphere and record the output of the
system. The owner or operator of an affected facility subject to an
opacity standard under Sec. 60.43b and meeting the conditions under
paragraphs (j)(1), (2), (3), (4), (5), or (6) of this section who elects
not to use a COMS shall conduct a performance test using Method 9 of
appendix A-4 of this part and the procedures in Sec. 60.11 to
demonstrate compliance with the applicable limit in Sec. 60.43b by
April 29, 2011, within 45 days of stopping use of an existing COMS, or
within 180 days after initial startup of the facility, whichever is
later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3)
of this section. The observation period for Method 9 of appendix A-4 of
this part performance tests may be reduced from 3 hours to 60 minutes if
all 6-minute averages are less than 10 percent and all individual 15-
second observations are less than or equal to 20 percent during the
initial 60 minutes of observation.
(1) Except as provided in paragraph (a)(2) and (a)(3) of this
section, the owner or operator shall conduct subsequent Method 9 of
appendix A-4 of this part performance tests using the procedures in
paragraph (a) of this section according to the applicable schedule in
paragraphs (a)(1)(i) through (a)(1)(iv) of this section, as determined
by the most recent Method 9 of appendix A-4 of this part performance
test results.
(i) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later;
(ii) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed within
6 calendar months from the date that the most recent performance test
was conducted or within 45 days of the next day that fuel with an
opacity standard is combusted, whichever is later;
(iii) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later; or
(iv) If the maximum 6-minute average opacity is greater than 10
percent, a subsequent Method 9 of appendix A-4 of this part performance
test must be completed within 45 calendar days from the date that the
most recent performance test was conducted.
(2) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 of this part performance tests, elect to
perform subsequent monitoring using Method 22 of appendix A-
[[Page 188]]
7 of this part according to the procedures specified in paragraphs
(a)(2)(i) and (ii) of this section.
(i) The owner or operator shall conduct 10 minute observations
(during normal operation) each operating day the affected facility fires
fuel for which an opacity standard is applicable using Method 22 of
appendix A-7 of this part and demonstrate that the sum of the
occurrences of any visible emissions is not in excess of 5 percent of
the observation period (i.e., 30 seconds per 10 minute period). If the
sum of the occurrence of any visible emissions is greater than 30
seconds during the initial 10 minute observation, immediately conduct a
30 minute observation. If the sum of the occurrence of visible emissions
is greater than 5 percent of the observation period (i.e., 90 seconds
per 30 minute period), the owner or operator shall either document and
adjust the operation of the facility and demonstrate within 24 hours
that the sum of the occurrence of visible emissions is equal to or less
than 5 percent during a 30 minute observation (i.e., 90 seconds) or
conduct a new Method 9 of appendix A-4 of this part performance test
using the procedures in paragraph (a) of this section within 45 calendar
days according to the requirements in Sec. 60.46d(d)(7).
(ii) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily observations
shall be resumed.
(3) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 performance tests, elect to perform subsequent
monitoring using a digital opacity compliance system according to a
site-specific monitoring plan approved by the Administrator. The
observations shall be similar, but not necessarily identical, to the
requirements in paragraph (a)(2) of this section. For reference purposes
in preparing the monitoring plan, see OAQPS ``Determination of Visible
Emission Opacity from Stationary Sources Using Computer-Based
Photographic Analysis Systems.'' This document is available from the
U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality
and Planning Standards; Sector Policies and Programs Division;
Measurement Policy Group (D243-02), Research Triangle Park, NC 27711.
This document is also available on the Technology Transfer Network (TTN)
under Emission Measurement Center Preliminary Methods.
(b) Except as provided under paragraphs (g), (h), and (i) of this
section, the owner or operator of an affected facility subject to a
NOX standard under Sec. 60.44b shall comply with either
paragraphs (b)(1) or (b)(2) of this section.
(1) Install, calibrate, maintain, and operate CEMS for measuring
NOX and O2 (or CO2) emissions
discharged to the atmosphere, and shall record the output of the system;
or
(2) If the owner or operator has installed a NOX emission
rate CEMS to meet the requirements of part 75 of this chapter and is
continuing to meet the ongoing requirements of part 75 of this chapter,
that CEMS may be used to meet the requirements of this section, except
that the owner or operator shall also meet the requirements of Sec.
60.49b. Data reported to meet the requirements of Sec. 60.49b shall not
include data substituted using the missing data procedures in subpart D
of part 75 of this chapter, nor shall the data have been bias adjusted
according to the procedures of part 75 of this chapter.
(c) The CEMS required under paragraph (b) of this section shall be
operated and data recorded during all periods of operation of the
affected facility except for CEMS breakdowns and repairs. Data is
recorded during calibration checks, and zero and span adjustments.
(d) The 1-hour average NOX emission rates measured by the
continuous NOX monitor required by paragraph (b) of this
section and required under Sec. 60.13(h) shall be expressed in ng/J or
lb/MMBtu heat input and shall be used to calculate the average emission
rates under Sec. 60.44b. The 1-hour averages shall be calculated using
the data points required under Sec. 60.13(h)(2).
[[Page 189]]
(e) The procedures under Sec. 60.13 shall be followed for
installation, evaluation, and operation of the continuous monitoring
systems.
(1) For affected facilities combusting coal, wood or municipal-type
solid waste, the span value for a COMS shall be between 60 and 80
percent.
(2) For affected facilities combusting coal, oil, or natural gas,
the span value for NOX is determined using one of the
following procedures:
(i) Except as provided under paragraph (e)(2)(ii) of this section,
NOX span values shall be determined as follows:
------------------------------------------------------------------------
Fuel Span values for NOX (ppm)
------------------------------------------------------------------------
Natural gas......................... 500.
Oil................................. 500.
Coal................................ 1,000.
Mixtures............................ 500 (x + y) + 1,000z.
------------------------------------------------------------------------
Where:
x = Fraction of total heat input derived from natural gas;
y = Fraction of total heat input derived from oil; and
z = Fraction of total heat input derived from coal.
(ii) As an alternative to meeting the requirements of paragraph
(e)(2)(i) of this section, the owner or operator of an affected facility
may elect to use the NOX span values determined according to
section 2.1.2 in appendix A to part 75 of this chapter.
(3) All span values computed under paragraph (e)(2)(i) of this
section for combusting mixtures of regulated fuels are rounded to the
nearest 500 ppm. Span values computed under paragraph (e)(2)(ii) of this
section shall be rounded off according to section 2.1.2 in appendix A to
part 75 of this chapter.
(f) When NOX emission data are not obtained because of
CEMS breakdowns, repairs, calibration checks and zero and span
adjustments, emission data will be obtained by using standby monitoring
systems, Method 7 of appendix A of this part, Method 7A of appendix A of
this part, or other approved reference methods to provide emission data
for a minimum of 75 percent of the operating hours in each steam
generating unit operating day, in at least 22 out of 30 successive steam
generating unit operating days.
(g) The owner or operator of an affected facility that has a heat
input capacity of 73 MW (250 MMBtu/hr) or less, and that has an annual
capacity factor for residual oil having a nitrogen content of 0.30
weight percent or less, natural gas, distillate oil, gasified coal, or
any mixture of these fuels, greater than 10 percent (0.10) shall:
(1) Comply with the provisions of paragraphs (b), (c), (d), (e)(2),
(e)(3), and (f) of this section; or
(2) Monitor steam generating unit operating conditions and predict
NOX emission rates as specified in a plan submitted pursuant
to Sec. 60.49b(c).
(h) The owner or operator of a duct burner, as described in Sec.
60.41b, that is subject to the NOX standards in Sec.
60.44b(a)(4), Sec. 60.44b(e), or Sec. 60.44b(l) is not required to
install or operate a continuous emissions monitoring system to measure
NOX emissions.
(i) The owner or operator of an affected facility described in Sec.
60.44b(j) or Sec. 60.44b(k) is not required to install or operate a
CEMS for measuring NOX emissions.
(j) The owner or operator of an affected facility that meets the
conditions in either paragraph (j)(1), (2), (3), (4), (5), (6), or (7)
of this section is not required to install or operate a COMS if:
(1) The affected facility uses a PM CEMS to monitor PM emissions; or
(2) The affected facility burns only liquid (excluding residual oil)
or gaseous fuels with potential SO2 emissions rates of 26 ng/
J (0.060 lb/MMBtu) or less and does not use a post-combustion technology
to reduce SO2 or PM emissions. The owner or operator must
maintain fuel records of the sulfur content of the fuels burned, as
described under Sec. 60.49b(r); or
(3) The affected facility burns coke oven gas alone or in
combination with fuels meeting the criteria in paragraph (j)(2) of this
section and does not use a post-combustion technology to reduce
SO2 or PM emissions; or
(4) The affected facility does not use post-combustion technology
(except a wet scrubber) for reducing PM, SO2, or carbon
monoxide (CO) emissions, burns only gaseous fuels or fuel oils that
contain less than or equal to 0.30 weight percent sulfur, and is
operated such
[[Page 190]]
that emissions of CO to the atmosphere from the affected facility are
maintained at levels less than or equal to 0.15 lb/MMBtu on a steam
generating unit operating day average basis. Owners and operators of
affected facilities electing to comply with this paragraph must
demonstrate compliance according to the procedures specified in
paragraphs (j)(4)(i) through (iv) of this section; or
(i) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (j)(4)(i)(A) through (D) of this
section.
(A) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec. 60.58b(i)(3) of subpart Eb
of this part.
(B) Each 1-hour CO emissions average is calculated using the data
points generated by the CO CEMS expressed in parts per million by volume
corrected to 3 percent oxygen (dry basis).
(C) At a minimum, valid 1-hour CO emissions averages must be
obtained for at least 90 percent of the operating hours on a 30-day
rolling average basis. The 1-hour averages are calculated using the data
points required in Sec. 60.13(h)(2).
(D) Quarterly accuracy determinations and daily calibration drift
tests for the CO CEMS must be performed in accordance with procedure 1
in appendix F of this part.
(ii) You must calculate the 1-hour average CO emissions levels for
each steam generating unit operating day by multiplying the average
hourly CO output concentration measured by the CO CEMS times the
corresponding average hourly flue gas flow rate and divided by the
corresponding average hourly heat input to the affected source. The 24-
hour average CO emission level is determined by calculating the
arithmetic average of the hourly CO emission levels computed for each
steam generating unit operating day.
(iii) You must evaluate the preceding 24-hour average CO emission
level each steam generating unit operating day excluding periods of
affected source startup, shutdown, or malfunction. If the 24-hour
average CO emission level is greater than 0.15 lb/MMBtu, you must
initiate investigation of the relevant equipment and control systems
within 24 hours of the first discovery of the high emission incident
and, take the appropriate corrective action as soon as practicable to
adjust control settings or repair equipment to reduce the 24-hour
average CO emission level to 0.15 lb/MMBtu or less.
(iv) You must record the CO measurements and calculations performed
according to paragraph (j)(4) of this section and any corrective actions
taken. The record of corrective action taken must include the date and
time during which the 24-hour average CO emission level was greater than
0.15 lb/MMBtu, and the date, time, and description of the corrective
action.
(5) The affected facility uses a bag leak detection system to
monitor the performance of a fabric filter (baghouse) according to the
most current requirements in section Sec. 60.48Da of this part; or
(6) The affected facility uses an ESP as the primary PM control
device and uses an ESP predictive model to monitor the performance of
the ESP developed in accordance and operated according to the most
current requirements in section Sec. 60.48Da of this part; or
(7) The affected facility burns only gaseous fuels or fuel oils that
contain less than or equal to 0.30 weight percent sulfur and operates
according to a written site-specific monitoring plan approved by the
permitting authority. This monitoring plan must include procedures and
criteria for establishing and monitoring specific parameters for the
affected facility indicative of compliance with the opacity standard.
(k) Owners or operators complying with the PM emission limit by
using a PM CEMS must calibrate, maintain, operate, and record the output
of the system for PM emissions discharged to the atmosphere as specified
in Sec. 60.46b(j). The CEMS specified in paragraph Sec. 60.46b(j)
shall be operated and data recorded during all periods of operation of
the affected facility except for CEMS breakdowns and repairs. Data is
recorded during calibration checks, and zero and span adjustments.
(l) An owner or operator of an affected facility that is subject to
an opacity standard under Sec. 60.43b(f) is not required to operate a
COMS provided
[[Page 191]]
that the unit burns only gaseous fuels and/or liquid fuels (excluding
residue oil) with a potential SO2 emissions rate no greater
than 26 ng/J (0.060 lb/MMBtu), and the unit operates according to a
written site-specific monitoring plan approved by the permitting
authority is not required to operate a COMS. This monitoring plan must
include procedures and criteria for establishing and monitoring specific
parameters for the affected facility indicative of compliance with the
opacity standard. For testing performed as part of this site-specific
monitoring plan, the permitting authority may require as an alternative
to the notification and reporting requirements specified in Sec. Sec.
60.8 and 60.11 that the owner or operator submit any deviations with the
excess emissions report required under Sec. 60.49b(h).
[72 FR 32742, June 13, 2007, as amended at 74 FR 5087, Jan. 28, 2009; 76
FR 3523, Jan. 20, 2011; 77 FR 9460, Feb. 16, 2012]
Sec. 60.49b Reporting and recordkeeping requirements.
(a) The owner or operator of each affected facility shall submit
notification of the date of initial startup, as provided by Sec. 60.7.
This notification shall include:
(1) The design heat input capacity of the affected facility and
identification of the fuels to be combusted in the affected facility;
(2) If applicable, a copy of any federally enforceable requirement
that limits the annual capacity factor for any fuel or mixture of fuels
under Sec. 60.42b(d)(1), Sec. 60.43b(a)(2), (a)(3)(iii), (c)(2)(ii),
(d)(2)(iii), Sec. 60.44b(c), (d), (e), (i), (j), (k), Sec. 60.45b(d),
(g), Sec. 60.46b(h), or Sec. 60.48b(i);
(3) The annual capacity factor at which the owner or operator
anticipates operating the facility based on all fuels fired and based on
each individual fuel fired; and
(4) Notification that an emerging technology will be used for
controlling emissions of SO2. The Administrator will examine
the description of the emerging technology and will determine whether
the technology qualifies as an emerging technology. In making this
determination, the Administrator may require the owner or operator of
the affected facility to submit additional information concerning the
control device. The affected facility is subject to the provisions of
Sec. 60.42b(a) unless and until this determination is made by the
Administrator.
(b) The owner or operator of each affected facility subject to the
SO2, PM, and/or NOX emission limits under
Sec. Sec. 60.42b, 60.43b, and 60.44b shall submit to the Administrator
the performance test data from the initial performance test and the
performance evaluation of the CEMS using the applicable performance
specifications in appendix B of this part. The owner or operator of each
affected facility described in Sec. 60.44b(j) or Sec. 60.44b(k) shall
submit to the Administrator the maximum heat input capacity data from
the demonstration of the maximum heat input capacity of the affected
facility.
(c) The owner or operator of each affected facility subject to the
NOX standard in Sec. 60.44b who seeks to demonstrate
compliance with those standards through the monitoring of steam
generating unit operating conditions in the provisions of Sec.
60.48b(g)(2) shall submit to the Administrator for approval a plan that
identifies the operating conditions to be monitored in Sec.
60.48b(g)(2) and the records to be maintained in Sec. 60.49b(g). This
plan shall be submitted to the Administrator for approval within 360
days of the initial startup of the affected facility. An affected
facility burning coke oven gas alone or in combination with other
gaseous fuels or distillate oil shall submit this plan to the
Administrator for approval within 360 days of the initial startup of the
affected facility or by November 30, 2009, whichever date comes later.
If the plan is approved, the owner or operator shall maintain records of
predicted nitrogen oxide emission rates and the monitored operating
conditions, including steam generating unit load, identified in the
plan. The plan shall:
(1) Identify the specific operating conditions to be monitored and
the relationship between these operating conditions and NOX
emission rates (i.e., ng/J or lbs/MMBtu heat input). Steam generating
unit operating conditions include, but are not limited to, the degree of
staged combustion (i.e., the
[[Page 192]]
ratio of primary air to secondary and/or tertiary air) and the level of
excess air (i.e., flue gas O2 level);
(2) Include the data and information that the owner or operator used
to identify the relationship between NOX emission rates and
these operating conditions; and
(3) Identify how these operating conditions, including steam
generating unit load, will be monitored under Sec. 60.48b(g) on an
hourly basis by the owner or operator during the period of operation of
the affected facility; the quality assurance procedures or practices
that will be employed to ensure that the data generated by monitoring
these operating conditions will be representative and accurate; and the
type and format of the records of these operating conditions, including
steam generating unit load, that will be maintained by the owner or
operator under Sec. 60.49b(g).
(d) Except as provided in paragraph (d)(2) of this section, the
owner or operator of an affected facility shall record and maintain
records as specified in paragraph (d)(1) of this section.
(1) The owner or operator of an affected facility shall record and
maintain records of the amounts of each fuel combusted during each day
and calculate the annual capacity factor individually for coal,
distillate oil, residual oil, natural gas, wood, and municipal-type
solid waste for the reporting period. The annual capacity factor is
determined on a 12-month rolling average basis with a new annual
capacity factor calculated at the end of each calendar month.
(2) As an alternative to meeting the requirements of paragraph
(d)(1) of this section, the owner or operator of an affected facility
that is subject to a federally enforceable permit restricting fuel use
to a single fuel such that the facility is not required to continuously
monitor any emissions (excluding opacity) or parameters indicative of
emissions may elect to record and maintain records of the amount of each
fuel combusted during each calendar month.
(e) For an affected facility that combusts residual oil and meets
the criteria under Sec. 60.46b(e)(4), Sec. 60.44b(j), or (k), the
owner or operator shall maintain records of the nitrogen content of the
residual oil combusted in the affected facility and calculate the
average fuel nitrogen content for the reporting period. The nitrogen
content shall be determined using ASTM Method D4629 (incorporated by
reference, see Sec. 60.17), or fuel suppliers. If residual oil blends
are being combusted, fuel nitrogen specifications may be prorated based
on the ratio of residual oils of different nitrogen content in the fuel
blend.
(f) For an affected facility subject to the opacity standard in
Sec. 60.43b, the owner or operator shall maintain records of opacity.
In addition, an owner or operator that elects to monitor emissions
according to the requirements in Sec. 60.48b(a) shall maintain records
according to the requirements specified in paragraphs (f)(1) through (3)
of this section, as applicable to the visible emissions monitoring
method used.
(1) For each performance test conducted using Method 9 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (f)(1)(i) through (iii) of this
section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission reading
certification for each visible emission observer participating in the
performance test; and
(iii) Copies of all visible emission observer opacity field data
sheets;
(2) For each performance test conducted using Method 22 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (f)(2)(i) through (iv) of this
section.
(i) Dates and time intervals of all visible emissions observation
periods;
(ii) Name and affiliation for each visible emission observer
participating in the performance test;
(iii) Copies of all visible emission observer opacity field data
sheets; and
(iv) Documentation of any adjustments made and the time the
adjustments were completed to the affected facility operation by the
owner or operator to demonstrate compliance with
[[Page 193]]
the applicable monitoring requirements.
(3) For each digital opacity compliance system, the owner or
operator shall maintain records and submit reports according to the
requirements specified in the site-specific monitoring plan approved by
the Administrator.
(g) Except as provided under paragraph (p) of this section, the
owner or operator of an affected facility subject to the NOX
standards under Sec. 60.44b shall maintain records of the following
information for each steam generating unit operating day:
(1) Calendar date;
(2) The average hourly NOX emission rates (expressed as
NO2) (ng/J or lb/MMBtu heat input) measured or predicted;
(3) The 30-day average NOX emission rates (ng/J or lb/
MMBtu heat input) calculated at the end of each steam generating unit
operating day from the measured or predicted hourly nitrogen oxide
emission rates for the preceding 30 steam generating unit operating
days;
(4) Identification of the steam generating unit operating days when
the calculated 30-day average NOX emission rates are in
excess of the NOX emissions standards under Sec. 60.44b,
with the reasons for such excess emissions as well as a description of
corrective actions taken;
(5) Identification of the steam generating unit operating days for
which pollutant data have not been obtained, including reasons for not
obtaining sufficient data and a description of corrective actions taken;
(6) Identification of the times when emission data have been
excluded from the calculation of average emission rates and the reasons
for excluding data;
(7) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
(8) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
(9) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or 3;
and
(10) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under appendix F, Procedure 1 of this part.
(h) The owner or operator of any affected facility in any category
listed in paragraphs (h)(1) or (2) of this section is required to submit
excess emission reports for any excess emissions that occurred during
the reporting period.
(1) Any affected facility subject to the opacity standards in Sec.
60.43b(f) or to the operating parameter monitoring requirements in Sec.
60.13(i)(1).
(2) Any affected facility that is subject to the NOX
standard of Sec. 60.44b, and that:
(i) Combusts natural gas, distillate oil, gasified coal, or residual
oil with a nitrogen content of 0.3 weight percent or less; or
(ii) Has a heat input capacity of 73 MW (250 MMBtu/hr) or less and
is required to monitor NOX emissions on a continuous basis
under Sec. 60.48b(g)(1) or steam generating unit operating conditions
under Sec. 60.48b(g)(2).
(3) For the purpose of Sec. 60.43b, excess emissions are defined as
all 6-minute periods during which the average opacity exceeds the
opacity standards under Sec. 60.43b(f).
(4) For purposes of Sec. 60.48b(g)(1), excess emissions are defined
as any calculated 30-day rolling average NOX emission rate,
as determined under Sec. 60.46b(e), that exceeds the applicable
emission limits in Sec. 60.44b.
(i) The owner or operator of any affected facility subject to the
continuous monitoring requirements for NOX under Sec.
60.48(b) shall submit reports containing the information recorded under
paragraph (g) of this section.
(j) The owner or operator of any affected facility subject to the
SO2 standards under Sec. 60.42b shall submit reports.
(k) For each affected facility subject to the compliance and
performance testing requirements of Sec. 60.45b and the reporting
requirement in paragraph (j) of this section, the following information
shall be reported to the Administrator:
(1) Calendar dates covered in the reporting period;
(2) Each 30-day average SO2 emission rate (ng/J or lb/
MMBtu heat input) measured during the reporting period,
[[Page 194]]
ending with the last 30-day period; reasons for noncompliance with the
emission standards; and a description of corrective actions taken; For
an exceedance due to maintenance of the SO2 control system
covered in paragraph 60.45b(a), the report shall identify the days on
which the maintenance was performed and a description of the
maintenance;
(3) Each 30-day average percent reduction in SO2
emissions calculated during the reporting period, ending with the last
30-day period; reasons for noncompliance with the emission standards;
and a description of corrective actions taken;
(4) Identification of the steam generating unit operating days that
coal or oil was combusted and for which SO2 or diluent
(O2 or CO2) data have not been obtained by an
approved method for at least 75 percent of the operating hours in the
steam generating unit operating day; justification for not obtaining
sufficient data; and description of corrective action taken;
(5) Identification of the times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and description of corrective action taken if data
have been excluded for periods other than those during which coal or oil
were not combusted in the steam generating unit;
(6) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
(7) Identification of times when hourly averages have been obtained
based on manual sampling methods;
(8) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
(9) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or 3;
(10) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under appendix F, Procedure 1 of this part; and
(11) The annual capacity factor of each fired as provided under
paragraph (d) of this section.
(l) For each affected facility subject to the compliance and
performance testing requirements of Sec. 60.45b(d) and the reporting
requirements of paragraph (j) of this section, the following information
shall be reported to the Administrator:
(1) Calendar dates when the facility was in operation during the
reporting period;
(2) The 24-hour average SO2 emission rate measured for
each steam generating unit operating day during the reporting period
that coal or oil was combusted, ending in the last 24-hour period in the
quarter; reasons for noncompliance with the emission standards; and a
description of corrective actions taken;
(3) Identification of the steam generating unit operating days that
coal or oil was combusted for which S02 or diluent
(O2 or CO2) data have not been obtained by an
approved method for at least 75 percent of the operating hours;
justification for not obtaining sufficient data; and description of
corrective action taken;
(4) Identification of the times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and description of corrective action taken if data
have been excluded for periods other than those during which coal or oil
were not combusted in the steam generating unit;
(5) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
(6) Identification of times when hourly averages have been obtained
based on manual sampling methods;
(7) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
(8) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or 3;
and
(9) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under Procedure 1 of appendix F 1 of this part.
If the owner or operator elects to implement the alternative data
assessment procedures described in Sec. Sec. 60.47b(e)(4)(i) through
(e)(4)(iii), each data assessment report shall include a summary of the
results of all of the RATAs, linearity checks,
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CGAs, and calibration error or drift assessments required by Sec. Sec.
60.47b(e)(4)(i) through (e)(4)(iii).
(m) For each affected facility subject to the SO2
standards in Sec. 60.42(b) for which the minimum amount of data
required in Sec. 60.47b(c) were not obtained during the reporting
period, the following information is reported to the Administrator in
addition to that required under paragraph (k) of this section:
(1) The number of hourly averages available for outlet emission
rates and inlet emission rates;
(2) The standard deviation of hourly averages for outlet emission
rates and inlet emission rates, as determined in Method 19 of appendix A
of this part, section 7;
(3) The lower confidence limit for the mean outlet emission rate and
the upper confidence limit for the mean inlet emission rate, as
calculated in Method 19 of appendix A of this part, section 7; and
(4) The ratio of the lower confidence limit for the mean outlet
emission rate and the allowable emission rate, as determined in Method
19 of appendix A of this part, section 7.
(n) If a percent removal efficiency by fuel pretreatment (i.e.,
%Rf) is used to determine the overall percent reduction
(i.e., %Ro) under Sec. 60.45b, the owner or operator of the
affected facility shall submit a signed statement with the report.
(1) Indicating what removal efficiency by fuel pretreatment (i.e.,
%Rf) was credited during the reporting period;
(2) Listing the quantity, heat content, and date each pre-treated
fuel shipment was received during the reporting period, the name and
location of the fuel pretreatment facility; and the total quantity and
total heat content of all fuels received at the affected facility during
the reporting period;
(3) Documenting the transport of the fuel from the fuel pretreatment
facility to the steam generating unit; and
(4) Including a signed statement from the owner or operator of the
fuel pretreatment facility certifying that the percent removal
efficiency achieved by fuel pretreatment was determined in accordance
with the provisions of Method 19 of appendix A of this part and listing
the heat content and sulfur content of each fuel before and after fuel
pretreatment.
(o) All records required under this section shall be maintained by
the owner or operator of the affected facility for a period of 2 years
following the date of such record.
(p) The owner or operator of an affected facility described in Sec.
60.44b(j) or (k) shall maintain records of the following information for
each steam generating unit operating day:
(1) Calendar date;
(2) The number of hours of operation; and
(3) A record of the hourly steam load.
(q) The owner or operator of an affected facility described in Sec.
60.44b(j) or Sec. 60.44b(k) shall submit to the Administrator a report
containing:
(1) The annual capacity factor over the previous 12 months;
(2) The average fuel nitrogen content during the reporting period,
if residual oil was fired; and
(3) If the affected facility meets the criteria described in Sec.
60.44b(j), the results of any NOX emission tests required
during the reporting period, the hours of operation during the reporting
period, and the hours of operation since the last NOX
emission test.
(r) The owner or operator of an affected facility who elects to use
the fuel based compliance alternatives in Sec. 60.42b or Sec. 60.43b
shall either:
(1) The owner or operator of an affected facility who elects to
demonstrate that the affected facility combusts only very low sulfur
oil, natural gas, wood, a mixture of these fuels, or any of these fuels
(or a mixture of these fuels) in combination with other fuels that are
known to contain an insignificant amount of sulfur in Sec. 60.42b(j) or
Sec. 60.42b(k) shall obtain and maintain at the affected facility fuel
receipts (such as a current, valid purchase contract, tariff sheet, or
transportation contract) from the fuel supplier that certify that the
oil meets the definition of distillate oil and gaseous fuel meets the
definition of natural gas as defined in Sec. 60.41b and the applicable
sulfur limit. For the purposes of this section, the distillate oil need
not meet the fuel nitrogen content specification
[[Page 196]]
in the definition of distillate oil. Reports shall be submitted to the
Administrator certifying that only very low sulfur oil meeting this
definition, natural gas, wood, and/or other fuels that are known to
contain insignificant amounts of sulfur were combusted in the affected
facility during the reporting period; or
(2) The owner or operator of an affected facility who elects to
demonstrate compliance based on fuel analysis in Sec. 60.42b or Sec.
60.43b shall develop and submit a site-specific fuel analysis plan to
the Administrator for review and approval no later than 60 days before
the date you intend to demonstrate compliance. Each fuel analysis plan
shall include a minimum initial requirement of weekly testing and each
analysis report shall contain, at a minimum, the following information:
(i) The potential sulfur emissions rate of the representative fuel
mixture in ng/J heat input;
(ii) The method used to determine the potential sulfur emissions
rate of each constituent of the mixture. For distillate oil and natural
gas a fuel receipt or tariff sheet is acceptable;
(iii) The ratio of different fuels in the mixture; and
(iv) The owner or operator can petition the Administrator to approve
monthly or quarterly sampling in place of weekly sampling.
(s) Facility specific NOX standard for Cytec Industries
Fortier Plant's C.AOG incinerator located in Westwego, Louisiana:
(1) Definitions.
Oxidation zone is defined as the portion of the C.AOG incinerator
that extends from the inlet of the oxidizing zone combustion air to the
outlet gas stack.
Reducing zone is defined as the portion of the C.AOG incinerator
that extends from the burner section to the inlet of the oxidizing zone
combustion air.
Total inlet air is defined as the total amount of air introduced
into the C.AOG incinerator for combustion of natural gas and chemical
by-product waste and is equal to the sum of the air flow into the
reducing zone and the air flow into the oxidation zone.
(2) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When natural gas and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 289 ng/J
(0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet air
provided for combustion shall be provided to the reducing zone of the
C.AOG incinerator.
(3) Emission monitoring. (i) The percent of total inlet air provided
to the reducing zone shall be determined at least every 15 minutes by
measuring the air flow of all the air entering the reducing zone and the
air flow of all the air entering the oxidation zone, and compliance with
the percentage of total inlet air that is provided to the reducing zone
shall be determined on a 3-hour average basis.
(ii) The NOX emission limit shall be determined by the
compliance and performance test methods and procedures for
NOX in Sec. 60.46b(i).
(iii) The monitoring of the NOX emission limit shall be
performed in accordance with Sec. 60.48b.
(4) Reporting and recordkeeping requirements. (i) The owner or
operator of the C.AOG incinerator shall submit a report on any
excursions from the limits required by paragraph (a)(2) of this section
to the Administrator with the quarterly report required by paragraph (i)
of this section.
(ii) The owner or operator of the C.AOG incinerator shall keep
records of the monitoring required by paragraph (a)(3) of this section
for a period of 2 years following the date of such record.
(iii) The owner of operator of the C.AOG incinerator shall perform
all the applicable reporting and recordkeeping requirements of this
section.
(t) Facility-specific NOX standard for Rohm and Haas
Kentucky Incorporated's Boiler No. 100 located in Louisville, Kentucky:
(1) Definitions.
Air ratio control damper is defined as the part of the low
NOX burner that is adjusted to control the split of total
combustion air delivered to the reducing and oxidation portions of the
combustion flame.
[[Page 197]]
Flue gas recirculation line is defined as the part of Boiler No. 100
that recirculates a portion of the boiler flue gas back into the
combustion air.
(2) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When fossil fuel and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 473 ng/J
(1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at
a minimum of 5 inches (12.7 centimeters) out of the boiler, and the flue
gas recirculation line shall be operated at a minimum of 10 percent open
as indicated by its valve opening position indicator.
(3) Emission monitoring for nitrogen oxides. (i) The air ratio
control damper tee handle setting and the flue gas recirculation line
valve opening position indicator setting shall be recorded during each
8-hour operating shift.
(ii) The NOX emission limit shall be determined by the
compliance and performance test methods and procedures for
NOX in Sec. 60.46b.
(iii) The monitoring of the NOX emission limit shall be
performed in accordance with Sec. 60.48b.
(4) Reporting and recordkeeping requirements. (i) The owner or
operator of Boiler No. 100 shall submit a report on any excursions from
the limits required by paragraph (b)(2) of this section to the
Administrator with the quarterly report required by Sec. 60.49b(i).
(ii) The owner or operator of Boiler No. 100 shall keep records of
the monitoring required by paragraph (b)(3) of this section for a period
of 2 years following the date of such record.
(iii) The owner of operator of Boiler No. 100 shall perform all the
applicable reporting and recordkeeping requirements of Sec. 60.49b.
(u) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant
in Elkton, Virginia. (1) This paragraph (u) applies only to the
pharmaceutical manufacturing facility, commonly referred to as the
Stonewall Plant, located at Route 340 South, in Elkton, Virginia
(``site'') and only to the natural gas-fired boilers installed as part
of the powerhouse conversion required pursuant to 40 CFR 52.2454(g). The
requirements of this paragraph shall apply, and the requirements of
Sec. Sec. 60.40b through 60.49b(t) shall not apply, to the natural gas-
fired boilers installed pursuant to 40 CFR 52.2454(g).
(i) The site shall equip the natural gas-fired boilers with low
NOX technology.
(ii) The site shall install, calibrate, maintain, and operate a
continuous monitoring and recording system for measuring NOX
emissions discharged to the atmosphere and opacity using a continuous
emissions monitoring system or a predictive emissions monitoring system.
(iii) Within 180 days of the completion of the powerhouse
conversion, as required by 40 CFR 52.2454, the site shall perform a
performance test to quantify criteria pollutant emissions.
(2) [Reserved]
(v) The owner or operator of an affected facility may submit
electronic quarterly reports for SO2 and/or NOX
and/or opacity in lieu of submitting the written reports required under
paragraphs (h), (i), (j), (k) or (l) of this section. The format of each
quarterly electronic report shall be coordinated with the permitting
authority. The electronic report(s) shall be submitted no later than 30
days after the end of the calendar quarter and shall be accompanied by a
certification statement from the owner or operator, indicating whether
compliance with the applicable emission standards and minimum data
requirements of this subpart was achieved during the reporting period.
Before submitting reports in the electronic format, the owner or
operator shall coordinate with the permitting authority to obtain their
agreement to submit reports in this alternative format.
(w) The reporting period for the reports required under this subpart
is each 6 month period. All reports shall be submitted to the
Administrator and shall be postmarked by the 30th day following the end
of the reporting period.
(x) Facility-specific NOX standard for Weyerhaeuser
Company's No. 2 Power Boiler located in New Bern, North Carolina:
(1) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted,
[[Page 198]]
the NOX emission limit for fossil fuel in Sec. 60.44b(a)
applies.
(ii) When fossil fuel and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 215 ng/J
(0.5 lb/MMBtu).
(2) Emission monitoring for nitrogen oxides. (i) The NOX
emissions shall be determined by the compliance and performance test
methods and procedures for NOX in Sec. 60.46b.
(ii) The monitoring of the NOX emissions shall be
performed in accordance with Sec. 60.48b.
(3) Reporting and recordkeeping requirements. (i) The owner or
operator of the No. 2 Power Boiler shall submit a report on any
excursions from the limits required by paragraph (x)(2) of this section
to the Administrator with the quarterly report required by Sec.
60.49b(i).
(ii) The owner or operator of the No. 2 Power Boiler shall keep
records of the monitoring required by paragraph (x)(3) of this section
for a period of 2 years following the date of such record.
(iii) The owner or operator of the No. 2 Power Boiler shall perform
all the applicable reporting and recordkeeping requirements of Sec.
60.49b.
(y) Facility-specific NOX standard for INEOS USA's AOGI
located in Lima, Ohio:
(1) Standard for NOX. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When fossil fuel and chemical byproduct/waste are
simultaneously combusted, the NOX emission limit is 645 ng/J
(1.5 lb/MMBtu).
(2) Emission monitoring for NOX. (i) The NOX
emissions shall be determined by the compliance and performance test
methods and procedures for NOX in Sec. 60.46b.
(ii) The monitoring of the NOX emissions shall be
performed in accordance with Sec. 60.48b.
(3) Reporting and recordkeeping requirements. (i) The owner or
operator of the AOGI shall submit a report on any excursions from the
limits required by paragraph (y)(2) of this section to the Administrator
with the quarterly report required by paragraph (i) of this section.
(ii) The owner or operator of the AOGI shall keep records of the
monitoring required by paragraph (y)(3) of this section for a period of
2 years following the date of such record.
(iii) The owner or operator of the AOGI shall perform all the
applicable reporting and recordkeeping requirements of this section.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5089, Jan. 28, 2009; 77
FR 9461, Feb. 16, 2012]
Subpart Dc_Standards of Performance for Small Industrial-Commercial-
Institutional Steam Generating Units
Source: 72 FR 32759, June 13, 2007, unless otherwise noted.
Sec. 60.40c Applicability and delegation of authority.
(a) Except as provided in paragraphs (d), (e), (f), and (g) of this
section, the affected facility to which this subpart applies is each
steam generating unit for which construction, modification, or
reconstruction is commenced after June 9, 1989 and that has a maximum
design heat input capacity of 29 megawatts (MW) (100 million British
thermal units per hour (MMBtu/h)) or less, but greater than or equal to
2.9 MW (10 MMBtu/h).
(b) In delegating implementation and enforcement authority to a
State under section 111(c) of the Clean Air Act, Sec. 60.48c(a)(4)
shall be retained by the Administrator and not transferred to a State.
(c) Steam generating units that meet the applicability requirements
in paragraph (a) of this section are not subject to the sulfur dioxide
(SO2) or particulate matter (PM) emission limits, performance
testing requirements, or monitoring requirements under this subpart
(Sec. Sec. 60.42c, 60.43c, 60.44c, 60.45c, 60.46c, or 60.47c) during
periods of combustion research, as defined in Sec. 60.41c.
(d) Any temporary change to an existing steam generating unit for
the purpose of conducting combustion research is not considered a
modification under Sec. 60.14.
(e) Affected facilities (i.e. heat recovery steam generators and
fuel heaters) that are associated with stationary
[[Page 199]]
combustion turbines and meet the applicability requirements of subpart
KKKK of this part are not subject to this subpart. This subpart will
continue to apply to all other heat recovery steam generators, fuel
heaters, and other affected facilities that are capable of combusting
more than or equal to 2.9 MW (10 MMBtu/h) heat input of fossil fuel but
less than or equal to 29 MW (100 MMBtu/h) heat input of fossil fuel. If
the heat recovery steam generator, fuel heater, or other affected
facility is subject to this subpart, only emissions resulting from
combustion of fuels in the steam generating unit are subject to this
subpart. (The stationary combustion turbine emissions are subject to
subpart GG or KKKK, as applicable, of this part.)
(f) Any affected facility that meets the applicability requirements
of and is subject to subpart AAAA or subpart CCCC of this part is not
subject to this subpart.
(g) Any facility that meets the applicability requirements and is
subject to an EPA approved State or Federal section 111(d)/129 plan
implementing subpart BBBB of this part is not subject to this subpart.
(h) Affected facilities that also meet the applicability
requirements under subpart J or subpart Ja of this part are subject to
the PM and NOX standards under this subpart and the
SO2 standards under subpart J or subpart Ja of this part, as
applicable.
(i) Temporary boilers are not subject to this subpart.
[72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009; 77
FR 9461, Feb. 16, 2012]
Sec. 60.41c Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Clean Air Act and in subpart A of this part.
Annual capacity factor means the ratio between the actual heat input
to a steam generating unit from an individual fuel or combination of
fuels during a period of 12 consecutive calendar months and the
potential heat input to the steam generating unit from all fuels had the
steam generating unit been operated for 8,760 hours during that 12-month
period at the maximum design heat input capacity. In the case of steam
generating units that are rented or leased, the actual heat input shall
be determined based on the combined heat input from all operations of
the affected facility during a period of 12 consecutive calendar months.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec. 60.17),
coal refuse, and petroleum coke. Coal-derived synthetic fuels derived
from coal for the purposes of creating useful heat, including but not
limited to solvent refined coal, gasified coal not meeting the
definition of natural gas, coal-oil mixtures, and coal-water mixtures,
are also included in this definition for the purposes of this subpart.
Coal refuse means any by-product of coal mining or coal cleaning
operations with an ash content greater than 50 percent (by weight) and a
heating value less than 13,900 kilojoules per kilogram (kJ/kg) (6,000
Btu per pound (Btu/lb) on a dry basis.
Combined cycle system means a system in which a separate source
(such as a stationary gas turbine, internal combustion engine, or kiln)
provides exhaust gas to a steam generating unit.
Combustion research means the experimental firing of any fuel or
combination of fuels in a steam generating unit for the purpose of
conducting research and development of more efficient combustion or more
effective prevention or control of air pollutant emissions from
combustion, provided that, during these periods of research and
development, the heat generated is not used for any purpose other than
preheating combustion air for use by that steam generating unit (i.e.,
the heat generated is released to the atmosphere without being used for
space heating, process heating, driving pumps, preheating combustion air
for other units, generating electricity, or any other purpose).
Conventional technology means wet flue gas desulfurization
technology, dry flue gas desulfurization technology, atmospheric
fluidized bed combustion technology, and oil hydrodesulfurization
technology.
[[Page 200]]
Distillate oil means fuel oil that complies with the specifications
for fuel oil numbers 1 or 2, as defined by the American Society for
Testing and Materials in ASTM D396 (incorporated by reference, see Sec.
60.17), diesel fuel oil numbers 1 or 2, as defined by the American
Society for Testing and Materials in ASTM D975 (incorporated by
reference, see Sec. 60.17), kerosine, as defined by the American
Society of Testing and Materials in ASTM D3699 (incorporated by
reference, see Sec. 60.17), biodiesel as defined by the American
Society of Testing and Materials in ASTM D6751 (incorporated by
reference, see Sec. 60.17), or biodiesel blends as defined by the
American Society of Testing and Materials in ASTM D7467 (incorporated by
reference, see Sec. 60.17).
Dry flue gas desulfurization technology means a SO2
control system that is located between the steam generating unit and the
exhaust vent or stack, and that removes sulfur oxides from the
combustion gases of the steam generating unit by contacting the
combustion gases with an alkaline reagent and water, whether introduced
separately or as a premixed slurry or solution and forming a dry powder
material. This definition includes devices where the dry powder material
is subsequently converted to another form. Alkaline reagents used in dry
flue gas desulfurization systems include, but are not limited to, lime
and sodium compounds.
Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source (such as a stationary gas turbine,
internal combustion engine, kiln, etc.) to allow the firing of
additional fuel to heat the exhaust gases before the exhaust gases enter
a steam generating unit.
Emerging technology means any SO2 control system that is
not defined as a conventional technology under this section, and for
which the owner or operator of the affected facility has received
approval from the Administrator to operate as an emerging technology
under Sec. 60.48c(a)(4).
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State implementation
plan, and any permit requirements established under 40 CFR 52.21 or
under 40 CFR 51.18 and 51.24.
Fluidized bed combustion technology means a device wherein fuel is
distributed onto a bed (or series of beds) of limestone aggregate (or
other sorbent materials) for combustion; and these materials are forced
upward in the device by the flow of combustion air and the gaseous
products of combustion. Fluidized bed combustion technology includes,
but is not limited to, bubbling bed units and circulating bed units.
Fuel pretreatment means a process that removes a portion of the
sulfur in a fuel before combustion of the fuel in a steam generating
unit.
Heat input means heat derived from combustion of fuel in a steam
generating unit and does not include the heat derived from preheated
combustion air, recirculated flue gases, or exhaust gases from other
sources (such as stationary gas turbines, internal combustion engines,
and kilns).
Heat transfer medium means any material that is used to transfer
heat from one point to another point.
Maximum design heat input capacity means the ability of a steam
generating unit to combust a stated maximum amount of fuel (or
combination of fuels) on a steady state basis as determined by the
physical design and characteristics of the steam generating unit.
Natural gas means:
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of which
the principal constituent is methane; or
(2) Liquefied petroleum (LP) gas, as defined by the American Society
for Testing and Materials in ASTM D1835 (incorporated by reference, see
Sec. 60.17); or
(3) A mixture of hydrocarbons that maintains a gaseous state at ISO
conditions. Additionally, natural gas must either be composed of at
least 70 percent methane by volume or have a gross calorific value
between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and
1,150 Btu per dry standard cubic foot).
[[Page 201]]
Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
Oil means crude oil or petroleum, or a liquid fuel derived from
crude oil or petroleum, including distillate oil and residual oil.
Potential sulfur dioxide emission rate means the theoretical
SO2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat
input) that would result from combusting fuel in an uncleaned state and
without using emission control systems.
Process heater means a device that is primarily used to heat a
material to initiate or promote a chemical reaction in which the
material participates as a reactant or catalyst.
Residual oil means crude oil, fuel oil that does not comply with the
specifications under the definition of distillate oil, and all fuel oil
numbers 4, 5, and 6, as defined by the American Society for Testing and
Materials in ASTM D396 (incorporated by reference, see Sec. 60.17).
Steam generating unit means a device that combusts any fuel and
produces steam or heats water or heats any heat transfer medium. This
term includes any duct burner that combusts fuel and is part of a
combined cycle system. This term does not include process heaters as
defined in this subpart.
Steam generating unit operating day means a 24-hour period between
12:00 midnight and the following midnight during which any fuel is
combusted at any time in the steam generating unit. It is not necessary
for fuel to be combusted continuously for the entire 24-hour period.
Temporary boiler means a steam generating unit that combusts natural
gas or distillate oil with a potential SO2 emissions rate no
greater than 26 ng/J (0.060 lb/MMBtu), and the unit is designed to, and
is capable of, being carried or moved from one location to another by
means of, for example, wheels, skids, carrying handles, dollies,
trailers, or platforms. A steam generating unit is not a temporary
boiler if any one of the following conditions exists:
(1) The equipment is attached to a foundation.
(2) The steam generating unit or a replacement remains at a location
for more than 180 consecutive days. Any temporary boiler that replaces a
temporary boiler at a location and performs the same or similar function
will be included in calculating the consecutive time period.
(3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one location to another in an
attempt to circumvent the residence time requirements of this
definition.
Wet flue gas desulfurization technology means an SO2
control system that is located between the steam generating unit and the
exhaust vent or stack, and that removes sulfur oxides from the
combustion gases of the steam generating unit by contacting the
combustion gases with an alkaline slurry or solution and forming a
liquid material. This definition includes devices where the liquid
material is subsequently converted to another form. Alkaline reagents
used in wet flue gas desulfurization systems include, but are not
limited to, lime, limestone, and sodium compounds.
Wet scrubber system means any emission control device that mixes an
aqueous stream or slurry with the exhaust gases from a steam generating
unit to control emissions of PM or SO2.
Wood means wood, wood residue, bark, or any derivative fuel or
residue thereof, in any form, including but not limited to sawdust,
sanderdust, wood chips, scraps, slabs, millings, shavings, and processed
pellets made from wood or other forest residues.
[72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009; 77
FR 9461, Feb. 16, 2012]
Sec. 60.42c Standard for sulfur dioxide (SO[bdi2]).
(a) Except as provided in paragraphs (b), (c), and (e) of this
section, on and after the date on which the performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, the owner or operator of
[[Page 202]]
an affected facility that combusts only coal shall neither: cause to be
discharged into the atmosphere from the affected facility any gases that
contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input
or 10 percent (0.10) of the potential SO2 emission rate (90
percent reduction), nor cause to be discharged into the atmosphere from
the affected facility any gases that contain SO2 in excess of
520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other
fuels, the affected facility shall neither: cause to be discharged into
the atmosphere from the affected facility any gases that contain
SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10
percent (0.10) of the potential SO2 emission rate (90 percent
reduction), nor cause to be discharged into the atmosphere from the
affected facility any gases that contain SO2 in excess of the
emission limit is determined pursuant to paragraph (e)(2) of this
section.
(b) Except as provided in paragraphs (c) and (e) of this section, on
and after the date on which the performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
the owner or operator of an affected facility that:
(1) Combusts only coal refuse alone in a fluidized bed combustion
steam generating unit shall neither:
(i) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 87 ng/J
(0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential
SO2 emission rate (80 percent reduction); nor
(ii) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of
SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal
is fired with coal refuse, the affected facility subject to paragraph
(a) of this section. If oil or any other fuel (except coal) is fired
with coal refuse, the affected facility is subject to the 87 ng/J (0.20
lb/MMBtu) heat input SO2 emissions limit or the 90 percent
SO2 reduction requirement specified in paragraph (a) of this
section and the emission limit is determined pursuant to paragraph
(e)(2) of this section.
(2) Combusts only coal and that uses an emerging technology for the
control of SO2 emissions shall neither:
(i) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 50 percent
(0.50) of the potential SO2 emission rate (50 percent
reduction); nor
(ii) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 260 ng/J
(0.60 lb/MMBtu) heat input. If coal is combusted with other fuels, the
affected facility is subject to the 50 percent SO2 reduction
requirement specified in this paragraph and the emission limit
determined pursuant to paragraph (e)(2) of this section.
(c) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that combusts
coal, alone or in combination with any other fuel, and is listed in
paragraphs (c)(1), (2), (3), or (4) of this section shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the emission limit determined
pursuant to paragraph (e)(2) of this section. Percent reduction
requirements are not applicable to affected facilities under paragraphs
(c)(1), (2), (3), or (4).
(1) Affected facilities that have a heat input capacity of 22 MW (75
MMBtu/h) or less;
(2) Affected facilities that have an annual capacity for coal of 55
percent (0.55) or less and are subject to a federally enforceable
requirement limiting operation of the affected facility to an annual
capacity factor for coal of 55 percent (0.55) or less.
(3) Affected facilities located in a noncontinental area; or
(4) Affected facilities that combust coal in a duct burner as part
of a combined cycle system where 30 percent (0.30) or less of the heat
entering the steam generating unit is from combustion of coal in the
duct burner and 70 percent (0.70) or more of the heat entering the steam
generating unit is from exhaust gases entering the duct burner.
(d) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first,
[[Page 203]]
no owner or operator of an affected facility that combusts oil shall
cause to be discharged into the atmosphere from that affected facility
any gases that contain SO2 in excess of 215 ng/J (0.50 lb/
MMBtu) heat input from oil; or, as an alternative, no owner or operator
of an affected facility that combusts oil shall combust oil in the
affected facility that contains greater than 0.5 weight percent sulfur.
The percent reduction requirements are not applicable to affected
facilities under this paragraph.
(e) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that combusts
coal, oil, or coal and oil with any other fuel shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the following:
(1) The percent of potential SO2 emission rate or
numerical SO2 emission rate required under paragraph (a) or
(b)(2) of this section, as applicable, for any affected facility that
(i) Combusts coal in combination with any other fuel;
(ii) Has a heat input capacity greater than 22 MW (75 MMBtu/h); and
(iii) Has an annual capacity factor for coal greater than 55 percent
(0.55); and
(2) The emission limit determined according to the following formula
for any affected facility that combusts coal, oil, or coal and oil with
any other fuel:
[GRAPHIC] [TIFF OMITTED] TR28JA09.005
Where:
Es = SO2 emission limit, expressed in ng/J or lb/
MMBtu heat input;
Ka = 520 ng/J (1.2 lb/MMBtu);
Kb = 260 ng/J (0.60 lb/MMBtu);
Kc = 215 ng/J (0.50 lb/MMBtu);
Ha = Heat input from the combustion of coal, except coal
combusted in an affected facility subject to paragraph (b)(2)
of this section, in Joules (J) [MMBtu];
Hb = Heat input from the combustion of coal in an affected
facility subject to paragraph (b)(2) of this section, in J
(MMBtu); and
Hc = Heat input from the combustion of oil, in J (MMBtu).
(f) Reduction in the potential SO2 emission rate through
fuel pretreatment is not credited toward the percent reduction
requirement under paragraph (b)(2) of this section unless:
(1) Fuel pretreatment results in a 50 percent (0.50) or greater
reduction in the potential SO2 emission rate; and
(2) Emissions from the pretreated fuel (without either combustion or
post-combustion SO2 control) are equal to or less than the
emission limits specified under paragraph (b)(2) of this section.
(g) Except as provided in paragraph (h) of this section, compliance
with the percent reduction requirements, fuel oil sulfur limits, and
emission limits of this section shall be determined on a 30-day rolling
average basis.
(h) For affected facilities listed under paragraphs (h)(1), (2),
(3), or (4) of this section, compliance with the emission limits or fuel
oil sulfur limits under this section may be determined based on a
certification from the fuel supplier, as described under Sec.
60.48c(f), as applicable.
(1) Distillate oil-fired affected facilities with heat input
capacities between 2.9 and 29 MW (10 and 100 MMBtu/hr).
(2) Residual oil-fired affected facilities with heat input
capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
(3) Coal-fired affected facilities with heat input capacities
between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
(4) Other fuels-fired affected facilities with heat input capacities
between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
(i) The SO2 emission limits, fuel oil sulfur limits, and
percent reduction requirements under this section apply at all times,
including periods of startup, shutdown, and malfunction.
(j) For affected facilities located in noncontinental areas and
affected facilities complying with the percent reduction standard, only
the heat input supplied to the affected facility from the combustion of
coal and oil is counted under this section. No credit is provided for
the heat input to the affected facility from wood or other fuels or for
heat derived from exhaust gases from other sources, such as stationary
gas
[[Page 204]]
turbines, internal combustion engines, and kilns.
[72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009; 77
FR 9462, Feb. 16, 2012]
Sec. 60.43c Standard for particulate matter (PM).
(a) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification on or before February 28,
2005, that combusts coal or combusts mixtures of coal with other fuels
and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater, shall
cause to be discharged into the atmosphere from that affected facility
any gases that contain PM in excess of the following emission limits:
(1) 22 ng/J (0.051 lb/MMBtu) heat input if the affected facility
combusts only coal, or combusts coal with other fuels and has an annual
capacity factor for the other fuels of 10 percent (0.10) or less.
(2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility
combusts coal with other fuels, has an annual capacity factor for the
other fuels greater than 10 percent (0.10), and is subject to a
federally enforceable requirement limiting operation of the affected
facility to an annual capacity factor greater than 10 percent (0.10) for
fuels other than coal.
(b) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification on or before February 28,
2005, that combusts wood or combusts mixtures of wood with other fuels
(except coal) and has a heat input capacity of 8.7 MW (30 MMBtu/h) or
greater, shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of the following
emissions limits:
(1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has
an annual capacity factor for wood greater than 30 percent (0.30); or
(2) 130 ng/J (0.30 lb/MMBtu) heat input if the affected facility has
an annual capacity factor for wood of 30 percent (0.30) or less and is
subject to a federally enforceable requirement limiting operation of the
affected facility to an annual capacity factor for wood of 30 percent
(0.30) or less.
(c) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that combusts
coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/h)
or greater shall cause to be discharged into the atmosphere from that
affected facility any gases that exhibit greater than 20 percent opacity
(6-minute average), except for one 6-minute period per hour of not more
than 27 percent opacity. Owners and operators of an affected facility
that elect to install, calibrate, maintain, and operate a continuous
emissions monitoring system (CEMS) for measuring PM emissions according
to the requirements of this subpart and are subject to a federally
enforceable PM limit of 0.030 lb/MMBtu or less are exempt from the
opacity standard specified in this paragraph (c).
(d) The PM and opacity standards under this section apply at all
times, except during periods of startup, shutdown, or malfunction.
(e)(1) On and after the date on which the initial performance test
is completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commences construction, reconstruction, or modification after February
28, 2005, and that combusts coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any other fuels and has a heat input
capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged
into the atmosphere from that affected facility any gases that contain
PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, except as provided
in paragraphs (e)(2), (e)(3), and (e)(4) of this section.
(2) As an alternative to meeting the requirements of paragraph
(e)(1) of this section, the owner or operator of an affected facility
for which modification commenced after February 28, 2005,
[[Page 205]]
may elect to meet the requirements of this paragraph. On and after the
date on which the initial performance test is completed or required to
be completed under Sec. 60.8, whichever date comes first, no owner or
operator of an affected facility that commences modification after
February 28, 2005 shall cause to be discharged into the atmosphere from
that affected facility any gases that contain PM in excess of both:
(i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion
of coal, oil, wood, a mixture of these fuels, or a mixture of these
fuels with any other fuels; and
(ii) 0.2 percent of the combustion concentration (99.8 percent
reduction) when combusting coal, oil, wood, a mixture of these fuels, or
a mixture of these fuels with any other fuels.
(3) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commences modification after February 28, 2005, and that combusts over
30 percent wood (by heat input) on an annual basis and has a heat input
capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged
into the atmosphere from that affected facility any gases that contain
PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
(4) An owner or operator of an affected facility that commences
construction, reconstruction, or modification after February 28, 2005,
and that combusts only oil that contains no more than 0.50 weight
percent sulfur or a mixture of 0.50 weight percent sulfur oil with other
fuels not subject to a PM standard under Sec. 60.43c and not using a
post-combustion technology (except a wet scrubber) to reduce PM or
SO2 emissions is not subject to the PM limit in this section.
[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009; 77
FR 9462, Feb. 16, 2012]
Sec. 60.44c Compliance and performance test methods and procedures
for sulfur dioxide.
(a) Except as provided in paragraphs (g) and (h) of this section and
Sec. 60.8(b), performance tests required under Sec. 60.8 shall be
conducted following the procedures specified in paragraphs (b), (c),
(d), (e), and (f) of this section, as applicable. Section 60.8(f) does
not apply to this section. The 30-day notice required in Sec. 60.8(d)
applies only to the initial performance test unless otherwise specified
by the Administrator.
(b) The initial performance test required under Sec. 60.8 shall be
conducted over 30 consecutive operating days of the steam generating
unit. Compliance with the percent reduction requirements and
SO2 emission limits under Sec. 60.42c shall be determined
using a 30-day average. The first operating day included in the initial
performance test shall be scheduled within 30 days after achieving the
maximum production rate at which the affect facility will be operated,
but not later than 180 days after the initial startup of the facility.
The steam generating unit load during the 30-day period does not have to
be the maximum design heat input capacity, but must be representative of
future operating conditions.
(c) After the initial performance test required under paragraph (b)
of this section and Sec. 60.8, compliance with the percent reduction
requirements and SO2 emission limits under Sec. 60.42c is
based on the average percent reduction and the average SO2
emission rates for 30 consecutive steam generating unit operating days.
A separate performance test is completed at the end of each steam
generating unit operating day, and a new 30-day average percent
reduction and SO2 emission rate are calculated to show
compliance with the standard.
(d) If only coal, only oil, or a mixture of coal and oil is
combusted in an affected facility, the procedures in Method 19 of
appendix A of this part are used to determine the hourly SO2
emission rate (Eho) and the 30-day average SO2
emission rate (Eao). The hourly averages used to compute the
30-day averages are obtained from the CEMS. Method 19 of appendix A of
this part shall be used to calculate Eao when using daily
fuel sampling or Method 6B of appendix A of this part.
(e) If coal, oil, or coal and oil are combusted with other fuels:
[[Page 206]]
(1) An adjusted Eho (Ehoo) is used in Equation
19-19 of Method 19 of appendix A of this part to compute the adjusted
Eao (Eaoo). The Ehoo is computed using
the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.033
Where:
Ehoo = Adjusted Eho, ng/J (lb/MMBtu);
Eho = Hourly SO2 emission rate, ng/J (lb/MMBtu);
Ew = SO2 concentration in fuels other than coal
and oil combusted in the affected facility, as determined by
fuel sampling and analysis procedures in Method 9 of appendix
A of this part, ng/J (lb/MMBtu). The value Ew for
each fuel lot is used for each hourly average during the time
that the lot is being combusted. The owner or operator does
not have to measure Ew if the owner or operator
elects to assume Ew = 0.
Xk = Fraction of the total heat input from fuel combustion
derived from coal and oil, as determined by applicable
procedures in Method 19 of appendix A of this part.
(2) The owner or operator of an affected facility that qualifies
under the provisions of Sec. 60.42c(c) or (d) (where percent reduction
is not required) does not have to measure the parameters Ew
or Xk if the owner or operator of the affected facility
elects to measure emission rates of the coal or oil using the fuel
sampling and analysis procedures under Method 19 of appendix A of this
part.
(f) Affected facilities subject to the percent reduction
requirements under Sec. 60.42c(a) or (b) shall determine compliance
with the SO2 emission limits under Sec. 60.42c pursuant to
paragraphs (d) or (e) of this section, and shall determine compliance
with the percent reduction requirements using the following procedures:
(1) If only coal is combusted, the percent of potential
SO2 emission rate is computed using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.034
Where:
%Ps = Potential SO2 emission rate, in percent;
%Rg = SO2 removal efficiency of the control device
as determined by Method 19 of appendix A of this part, in
percent; and
%Rf = SO2 removal efficiency of fuel pretreatment
as determined by Method 19 of appendix A of this part, in
percent.
(2) If coal, oil, or coal and oil are combusted with other fuels,
the same procedures required in paragraph (f)(1) of this section are
used, except as provided for in the following:
(i) To compute the %Ps, an adjusted %Rg
(%Rgo) is computed from Eaoo from paragraph (e)(1)
of this section and an adjusted average SO2 inlet rate
(Eaio) using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.035
Where:
%Rgo = Adjusted %Rg, in percent;
Eaoo = Adjusted Eao, ng/J (lb/MMBtu); and
Eaio = Adjusted average SO2 inlet rate, ng/J (lb/
MMBtu).
(ii) To compute Eaio, an adjusted hourly SO2
inlet rate (Ehio) is used. The Ehio is computed
using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.036
Where:
Ehio = Adjusted Ehi, ng/J (lb/MMBtu);
Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu);
Ew = SO2 concentration in fuels other than coal
and oil combusted in the affected facility, as determined by
fuel sampling and analysis procedures in Method 19 of appendix
A of this part, ng/J (lb/MMBtu). The value Ew for
each fuel lot is used for each hourly average during the time
that the lot is being combusted. The owner or operator does
not have to measure Ew if the owner or operator
elects to assume Ew = 0; and
Xk = Fraction of the total heat input from fuel combustion
derived from coal and oil, as determined by applicable
procedures in Method 19 of appendix A of this part.
(g) For oil-fired affected facilities where the owner or operator
seeks to demonstrate compliance with the fuel oil sulfur limits under
Sec. 60.42c based on shipment fuel sampling, the initial performance
test shall consist of sampling and analyzing the oil in the initial
[[Page 207]]
tank of oil to be fired in the steam generating unit to demonstrate that
the oil contains 0.5 weight percent sulfur or less. Thereafter, the
owner or operator of the affected facility shall sample the oil in the
fuel tank after each new shipment of oil is received, as described under
Sec. 60.46c(d)(2).
(h) For affected facilities subject to Sec. 60.42c(h)(1), (2), or
(3) where the owner or operator seeks to demonstrate compliance with the
SO2 standards based on fuel supplier certification, the
performance test shall consist of the certification from the fuel
supplier, as described in Sec. 60.48c(f), as applicable.
(i) The owner or operator of an affected facility seeking to
demonstrate compliance with the SO2 standards under Sec.
60.42c(c)(2) shall demonstrate the maximum design heat input capacity of
the steam generating unit by operating the steam generating unit at this
capacity for 24 hours. This demonstration shall be made during the
initial performance test, and a subsequent demonstration may be
requested at any other time. If the demonstrated 24-hour average firing
rate for the affected facility is less than the maximum design heat
input capacity stated by the manufacturer of the affected facility, the
demonstrated 24-hour average firing rate shall be used to determine the
annual capacity factor for the affected facility; otherwise, the maximum
design heat input capacity provided by the manufacturer shall be used.
(j) The owner or operator of an affected facility shall use all
valid SO2 emissions data in calculating %Ps and
Eho under paragraphs (d), (e), or (f) of this section, as
applicable, whether or not the minimum emissions data requirements under
Sec. 60.46c(f) are achieved. All valid emissions data, including valid
data collected during periods of startup, shutdown, and malfunction,
shall be used in calculating %Ps or Eho pursuant
to paragraphs (d), (e), or (f) of this section, as applicable.
[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009]
Sec. 60.45c Compliance and performance test methods and procedures
for particulate matter.
(a) The owner or operator of an affected facility subject to the PM
and/or opacity standards under Sec. 60.43c shall conduct an initial
performance test as required under Sec. 60.8, and shall conduct
subsequent performance tests as requested by the Administrator, to
determine compliance with the standards using the following procedures
and reference methods, except as specified in paragraph (c) of this
section.
(1) Method 1 of appendix A of this part shall be used to select the
sampling site and the number of traverse sampling points.
(2) Method 3A or 3B of appendix A-2 of this part shall be used for
gas analysis when applying Method 5 or 5B of appendix A-3 of this part
or 17 of appendix A-6 of this part.
(3) Method 5, 5B, or 17 of appendix A of this part shall be used to
measure the concentration of PM as follows:
(i) Method 5 of appendix A of this part may be used only at affected
facilities without wet scrubber systems.
(ii) Method 17 of appendix A of this part may be used at affected
facilities with or without wet scrubber systems provided the stack gas
temperature does not exceed a temperature of 160 [deg]C (320 [deg]F).
The procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of
this part may be used in Method 17 of appendix A of this part only if
Method 17 of appendix A of this part is used in conjunction with a wet
scrubber system. Method 17 of appendix A of this part shall not be used
in conjunction with a wet scrubber system if the effluent is saturated
or laden with water droplets.
(iii) Method 5B of appendix A of this part may be used in
conjunction with a wet scrubber system.
(4) The sampling time for each run shall be at least 120 minutes and
the minimum sampling volume shall be 1.7 dry standard cubic meters
(dscm) [60 dry standard cubic feet (dscf)] except that smaller sampling
times or volumes may be approved by the Administrator when necessitated
by process variables or other factors.
(5) For Method 5 or 5B of appendix A of this part, the temperature
of the
[[Page 208]]
sample gas in the probe and filter holder shall be monitored and
maintained at 160 14 [deg]C (32025 [deg]F).
(6) For determination of PM emissions, an oxygen (O2) or
carbon dioxide (CO2) measurement shall be obtained
simultaneously with each run of Method 5, 5B, or 17 of appendix A of
this part by traversing the duct at the same sampling location.
(7) For each run using Method 5, 5B, or 17 of appendix A of this
part, the emission rates expressed in ng/J (lb/MMBtu) heat input shall
be determined using:
(i) The O2 or CO2 measurements and PM
measurements obtained under this section, (ii) The dry basis F factor,
and
(iii) The dry basis emission rate calculation procedure contained in
Method 19 of appendix A of this part.
(8) Method 9 of appendix A-4 of this part shall be used for
determining the opacity of stack emissions.
(b) The owner or operator of an affected facility seeking to
demonstrate compliance with the PM standards under Sec. 60.43c(b)(2)
shall demonstrate the maximum design heat input capacity of the steam
generating unit by operating the steam generating unit at this capacity
for 24 hours. This demonstration shall be made during the initial
performance test, and a subsequent demonstration may be requested at any
other time. If the demonstrated 24-hour average firing rate for the
affected facility is less than the maximum design heat input capacity
stated by the manufacturer of the affected facility, the demonstrated
24-hour average firing rate shall be used to determine the annual
capacity factor for the affected facility; otherwise, the maximum design
heat input capacity provided by the manufacturer shall be used.
(c) In place of PM testing with Method 5 or 5B of appendix A-3 of
this part or Method 17 of appendix A-6 of this part, an owner or
operator may elect to install, calibrate, maintain, and operate a CEMS
for monitoring PM emissions discharged to the atmosphere and record the
output of the system. The owner or operator of an affected facility who
elects to continuously monitor PM emissions instead of conducting
performance testing using Method 5 or 5B of appendix A-3 of this part or
Method 17 of appendix A-6 of this part shall install, calibrate,
maintain, and operate a CEMS and shall comply with the requirements
specified in paragraphs (c)(1) through (c)(14) of this section.
(1) Notify the Administrator 1 month before starting use of the
system.
(2) Notify the Administrator 1 month before stopping use of the
system.
(3) The monitor shall be installed, evaluated, and operated in
accordance with Sec. 60.13 of subpart A of this part.
(4) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of the affected
facility, as specified under Sec. 60.8 of subpart A of this part or
within 180 days of notification to the Administrator of use of CEMS if
the owner or operator was previously determining compliance by Method 5,
5B, or 17 of appendix A of this part performance tests, whichever is
later.
(5) The owner or operator of an affected facility shall conduct an
initial performance test for PM emissions as required under Sec. 60.8
of subpart A of this part. Compliance with the PM emission limit shall
be determined by using the CEMS specified in paragraph (d) of this
section to measure PM and calculating a 24-hour block arithmetic average
emission concentration using EPA Reference Method 19 of appendix A of
this part, section 4.1.
(6) Compliance with the PM emission limit shall be determined based
on the 24-hour daily (block) average of the hourly arithmetic average
emission concentrations using CEMS outlet data.
(7) At a minimum, valid CEMS hourly averages shall be obtained as
specified in paragraph (c)(7)(i) of this section for 75 percent of the
total operating hours per 30-day rolling average.
(i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(ii) [Reserved]
(8) The 1-hour arithmetic averages required under paragraph (c)(7)
of this section shall be expressed in ng/J or lb/MMBtu heat input and
shall be used to calculate the boiler operating day daily arithmetic
average emission concentrations. The 1-hour arithmetic
[[Page 209]]
averages shall be calculated using the data points required under Sec.
60.13(e)(2) of subpart A of this part.
(9) All valid CEMS data shall be used in calculating average
emission concentrations even if the minimum CEMS data requirements of
paragraph (c)(7) of this section are not met.
(10) The CEMS shall be operated according to Performance
Specification 11 in appendix B of this part.
(11) During the correlation testing runs of the CEMS required by
Performance Specification 11 in appendix B of this part, PM and
O2 (or CO2) data shall be collected concurrently
(or within a 30- to 60-minute period) by both the continuous emission
monitors and performance tests conducted using the following test
methods.
(i) For PM, Method 5 or 5B of appendix A-3 of this part or Method 17
of appendix A-6 of this part shall be used; and
(ii) For O2 (or CO2), Method 3A or 3B of appendix A-2 of
this part, as applicable shall be used.
(12) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 2 in appendix F of
this part. Relative Response Audit's must be performed annually and
Response Correlation Audits must be performed every 3 years.
(13) When PM emissions data are not obtained because of CEMS
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained by using other monitoring systems as
approved by the Administrator or EPA Reference Method 19 of appendix A
of this part to provide, as necessary, valid emissions data for a
minimum of 75 percent of total operating hours on a 30-day rolling
average.
(14) As of January 1, 2012, and within 90 days after the date of
completing each performance test, as defined in Sec. 60.8, conducted to
demonstrate compliance with this subpart, you must submit relative
accuracy test audit (i.e., reference method) data and performance test
(i.e., compliance test) data, except opacity data, electronically to
EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool
(ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or other
compatible electronic spreadsheet. Only data collected using test
methods compatible with ERT are subject to this requirement to be
submitted electronically into EPA's WebFIRE database.
(d) The owner or operator of an affected facility seeking to
demonstrate compliance under Sec. 60.43c(e)(4) shall follow the
applicable procedures under Sec. 60.48c(f). For residual oil-fired
affected facilities, fuel supplier certifications are only allowed for
facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30
MMBtu/h).
[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009; 76
FR 3523, Jan. 20, 2011; 77 FR 9463, Feb. 16, 2012]
Sec. 60.46c Emission monitoring for sulfur dioxide.
(a) Except as provided in paragraphs (d) and (e) of this section,
the owner or operator of an affected facility subject to the
SO2 emission limits under Sec. 60.42c shall install,
calibrate, maintain, and operate a CEMS for measuring SO2
concentrations and either O2 or CO2 concentrations
at the outlet of the SO2 control device (or the outlet of the
steam generating unit if no SO2 control device is used), and
shall record the output of the system. The owner or operator of an
affected facility subject to the percent reduction requirements under
Sec. 60.42c shall measure SO2 concentrations and either
O2 or CO2 concentrations at both the inlet and
outlet of the SO2 control device.
(b) The 1-hour average SO2 emission rates measured by a
CEMS shall be expressed in ng/J or lb/MMBtu heat input and shall be used
to calculate the average emission rates under Sec. 60.42c. Each 1-hour
average SO2 emission rate must be based on at least 30
minutes of operation, and shall be calculated using the data points
required under Sec. 60.13(h)(2). Hourly SO2 emission rates
are not calculated if the affected facility is operated less than 30
minutes in a 1-hour period and are not counted toward determination of a
steam generating unit operating day.
(c) The procedures under Sec. 60.13 shall be followed for
installation, evaluation, and operation of the CEMS.
[[Page 210]]
(1) All CEMS shall be operated in accordance with the applicable
procedures under Performance Specifications 1, 2, and 3 of appendix B of
this part.
(2) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with Procedure 1 of appendix F of
this part.
(3) For affected facilities subject to the percent reduction
requirements under Sec. 60.42c, the span value of the SO2
CEMS at the inlet to the SO2 control device shall be 125
percent of the maximum estimated hourly potential SO2
emission rate of the fuel combusted, and the span value of the
SO2 CEMS at the outlet from the SO2 control device
shall be 50 percent of the maximum estimated hourly potential
SO2 emission rate of the fuel combusted.
(4) For affected facilities that are not subject to the percent
reduction requirements of Sec. 60.42c, the span value of the
SO2 CEMS at the outlet from the SO2 control device
(or outlet of the steam generating unit if no SO2 control
device is used) shall be 125 percent of the maximum estimated hourly
potential SO2 emission rate of the fuel combusted.
(d) As an alternative to operating a CEMS at the inlet to the
SO2 control device (or outlet of the steam generating unit if
no SO2 control device is used) as required under paragraph
(a) of this section, an owner or operator may elect to determine the
average SO2 emission rate by sampling the fuel prior to
combustion. As an alternative to operating a CEMS at the outlet from the
SO2 control device (or outlet of the steam generating unit if
no SO2 control device is used) as required under paragraph
(a) of this section, an owner or operator may elect to determine the
average SO2 emission rate by using Method 6B of appendix A of
this part. Fuel sampling shall be conducted pursuant to either paragraph
(d)(1) or (d)(2) of this section. Method 6B of appendix A of this part
shall be conducted pursuant to paragraph (d)(3) of this section.
(1) For affected facilities combusting coal or oil, coal or oil
samples shall be collected daily in an as-fired condition at the inlet
to the steam generating unit and analyzed for sulfur content and heat
content according the Method 19 of appendix A of this part. Method 19 of
appendix A of this part provides procedures for converting these
measurements into the format to be used in calculating the average
SO2 input rate.
(2) As an alternative fuel sampling procedure for affected
facilities combusting oil, oil samples may be collected from the fuel
tank for each steam generating unit immediately after the fuel tank is
filled and before any oil is combusted. The owner or operator of the
affected facility shall analyze the oil sample to determine the sulfur
content of the oil. If a partially empty fuel tank is refilled, a new
sample and analysis of the fuel in the tank would be required upon
filling. Results of the fuel analysis taken after each new shipment of
oil is received shall be used as the daily value when calculating the
30-day rolling average until the next shipment is received. If the fuel
analysis shows that the sulfur content in the fuel tank is greater than
0.5 weight percent sulfur, the owner or operator shall ensure that the
sulfur content of subsequent oil shipments is low enough to cause the
30-day rolling average sulfur content to be 0.5 weight percent sulfur or
less.
(3) Method 6B of appendix A of this part may be used in lieu of CEMS
to measure SO2 at the inlet or outlet of the SO2
control system. An initial stratification test is required to verify the
adequacy of the Method 6B of appendix A of this part sampling location.
The stratification test shall consist of three paired runs of a suitable
SO2 and CO2 measurement train operated at the
candidate location and a second similar train operated according to the
procedures in Sec. 3.2 and the applicable procedures in section 7 of
Performance Specification 2 of appendix B of this part. Method 6B of
appendix A of this part, Method 6A of appendix A of this part, or a
combination of Methods 6 and 3 of appendix A of this part or Methods 6C
and 3A of appendix A of this part are suitable measurement techniques.
If Method 6B of appendix A of this part is used for the second train,
sampling time and timer operation may be adjusted for the
[[Page 211]]
stratification test as long as an adequate sample volume is collected;
however, both sampling trains are to be operated similarly. For the
location to be adequate for Method 6B of appendix A of this part 24-hour
tests, the mean of the absolute difference between the three paired runs
must be less than 10 percent (0.10).
(e) The monitoring requirements of paragraphs (a) and (d) of this
section shall not apply to affected facilities subject to Sec.
60.42c(h) (1), (2), or (3) where the owner or operator of the affected
facility seeks to demonstrate compliance with the SO2
standards based on fuel supplier certification, as described under Sec.
60.48c(f), as applicable.
(f) The owner or operator of an affected facility operating a CEMS
pursuant to paragraph (a) of this section, or conducting as-fired fuel
sampling pursuant to paragraph (d)(1) of this section, shall obtain
emission data for at least 75 percent of the operating hours in at least
22 out of 30 successive steam generating unit operating days. If this
minimum data requirement is not met with a single monitoring system, the
owner or operator of the affected facility shall supplement the emission
data with data collected with other monitoring systems as approved by
the Administrator.
Sec. 60.47c Emission monitoring for particulate matter.
(a) Except as provided in paragraphs (c), (d), (e), and (f) of this
section, the owner or operator of an affected facility combusting coal,
oil, or wood that is subject to the opacity standards under Sec. 60.43c
shall install, calibrate, maintain, and operate a continuous opacity
monitoring system (COMS) for measuring the opacity of the emissions
discharged to the atmosphere and record the output of the system. The
owner or operator of an affected facility subject to an opacity standard
in Sec. 60.43c(c) that is not required to use a COMS due to paragraphs
(c), (d), (e), or (f) of this section that elects not to use a COMS
shall conduct a performance test using Method 9 of appendix A-4 of this
part and the procedures in Sec. 60.11 to demonstrate compliance with
the applicable limit in Sec. 60.43c by April 29, 2011, within 45 days
of stopping use of an existing COMS, or within 180 days after initial
startup of the facility, whichever is later, and shall comply with
either paragraphs (a)(1), (a)(2), or (a)(3) of this section. The
observation period for Method 9 of appendix A-4 of this part performance
tests may be reduced from 3 hours to 60 minutes if all 6-minute averages
are less than 10 percent and all individual 15-second observations are
less than or equal to 20 percent during the initial 60 minutes of
observation.
(1) Except as provided in paragraph (a)(2) and (a)(3) of this
section, the owner or operator shall conduct subsequent Method 9 of
appendix A-4 of this part performance tests using the procedures in
paragraph (a) of this section according to the applicable schedule in
paragraphs (a)(1)(i) through (a)(1)(iv) of this section, as determined
by the most recent Method 9 of appendix A-4 of this part performance
test results.
(i) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later;
(ii) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed within
6 calendar months from the date that the most recent performance test
was conducted or within 45 days of the next day that fuel with an
opacity standard is combusted, whichever is later;
(iii) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later; or
(iv) If the maximum 6-minute average opacity is greater than 10
percent, a subsequent Method 9 of appendix A-4 of this part performance
test must be
[[Page 212]]
completed within 45 calendar days from the date that the most recent
performance test was conducted.
(2) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 of this part performance tests, elect to
perform subsequent monitoring using Method 22 of appendix A-7 of this
part according to the procedures specified in paragraphs (a)(2)(i) and
(ii) of this section.
(i) The owner or operator shall conduct 10 minute observations
(during normal operation) each operating day the affected facility fires
fuel for which an opacity standard is applicable using Method 22 of
appendix A-7 of this part and demonstrate that the sum of the
occurrences of any visible emissions is not in excess of 5 percent of
the observation period (i.e. , 30 seconds per 10 minute period). If the
sum of the occurrence of any visible emissions is greater than 30
seconds during the initial 10 minute observation, immediately conduct a
30 minute observation. If the sum of the occurrence of visible emissions
is greater than 5 percent of the observation period (i.e., 90 seconds
per 30 minute period), the owner or operator shall either document and
adjust the operation of the facility and demonstrate within 24 hours
that the sum of the occurrence of visible emissions is equal to or less
than 5 percent during a 30 minute observation (i.e., 90 seconds) or
conduct a new Method 9 of appendix A-4 of this part performance test
using the procedures in paragraph (a) of this section within 45 calendar
days according to the requirements in Sec. 60.45c(a)(8).
(ii) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily observations
shall be resumed.
(3) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 performance tests, elect to perform subsequent
monitoring using a digital opacity compliance system according to a
site-specific monitoring plan approved by the Administrator. The
observations shall be similar, but not necessarily identical, to the
requirements in paragraph (a)(2) of this section. For reference purposes
in preparing the monitoring plan, see OAQPS ``Determination of Visible
Emission Opacity from Stationary Sources Using Computer-Based
Photographic Analysis Systems.'' This document is available from the
U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality
and Planning Standards; Sector Policies and Programs Division;
Measurement Policy Group (D243-02), Research Triangle Park, NC 27711.
This document is also available on the Technology Transfer Network (TTN)
under Emission Measurement Center Preliminary Methods.
(b) All COMS shall be operated in accordance with the applicable
procedures under Performance Specification 1 of appendix B of this part.
The span value of the opacity COMS shall be between 60 and 80 percent.
(c) Owners and operators of an affected facilities that burn only
distillate oil that contains no more than 0.5 weight percent sulfur and/
or liquid or gaseous fuels with potential sulfur dioxide emission rates
of 26 ng/J (0.060 lb/MMBtu) heat input or less and that do not use a
post-combustion technology to reduce SO2 or PM emissions and that are
subject to an opacity standard in Sec. 60.43c(c) are not required to
operate a COMS if they follow the applicable procedures in Sec.
60.48c(f).
(d) Owners or operators complying with the PM emission limit by
using a PM CEMS must calibrate, maintain, operate, and record the output
of the system for PM emissions discharged to the atmosphere as specified
in Sec. 60.45c(c). The CEMS specified in paragraph Sec. 60.45c(c)
shall be operated and data recorded during all periods of operation of
the affected facility except for CEMS breakdowns and repairs. Data is
recorded during calibration checks, and zero and span adjustments.
[[Page 213]]
(e) Owners and operators of an affected facility that is subject to
an opacity standard in Sec. 60.43c(c) and that does not use post-
combustion technology (except a wet scrubber) for reducing PM,
SO2, or carbon monoxide (CO) emissions, burns only gaseous
fuels or fuel oils that contain less than or equal to 0.5 weight percent
sulfur, and is operated such that emissions of CO discharged to the
atmosphere from the affected facility are maintained at levels less than
or equal to 0.15 lb/MMBtu on a boiler operating day average basis is not
required to operate a COMS. Owners and operators of affected facilities
electing to comply with this paragraph must demonstrate compliance
according to the procedures specified in paragraphs (e)(1) through (4)
of this section; or
(1) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (e)(1)(i) through (iv) of this
section.
(i) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec. 60.58b(i)(3) of subpart Eb
of this part.
(ii) Each 1-hour CO emissions average is calculated using the data
points generated by the CO CEMS expressed in parts per million by volume
corrected to 3 percent oxygen (dry basis).
(iii) At a minimum, valid 1-hour CO emissions averages must be
obtained for at least 90 percent of the operating hours on a 30-day
rolling average basis. The 1-hour averages are calculated using the data
points required in Sec. 60.13(h)(2).
(iv) Quarterly accuracy determinations and daily calibration drift
tests for the CO CEMS must be performed in accordance with procedure 1
in appendix F of this part.
(2) You must calculate the 1-hour average CO emissions levels for
each steam generating unit operating day by multiplying the average
hourly CO output concentration measured by the CO CEMS times the
corresponding average hourly flue gas flow rate and divided by the
corresponding average hourly heat input to the affected source. The 24-
hour average CO emission level is determined by calculating the
arithmetic average of the hourly CO emission levels computed for each
steam generating unit operating day.
(3) You must evaluate the preceding 24-hour average CO emission
level each steam generating unit operating day excluding periods of
affected source startup, shutdown, or malfunction. If the 24-hour
average CO emission level is greater than 0.15 lb/MMBtu, you must
initiate investigation of the relevant equipment and control systems
within 24 hours of the first discovery of the high emission incident
and, take the appropriate corrective action as soon as practicable to
adjust control settings or repair equipment to reduce the 24-hour
average CO emission level to 0.15 lb/MMBtu or less.
(4) You must record the CO measurements and calculations performed
according to paragraph (e) of this section and any corrective actions
taken. The record of corrective action taken must include the date and
time during which the 24-hour average CO emission level was greater than
0.15 lb/MMBtu, and the date, time, and description of the corrective
action.
(f) An owner or operator of an affected facility that is subject to
an opacity standard in Sec. 60.43c(c) is not required to operate a COMS
provided that the affected facility meets the conditions in either
paragraphs (f)(1), (2), or (3) of this section.
(1) The affected facility uses a fabric filter (baghouse) as the
primary PM control device and, the owner or operator operates a bag leak
detection system to monitor the performance of the fabric filter
according to the requirements in section Sec. 60.48Da of this part.
(2) The affected facility uses an ESP as the primary PM control
device, and the owner or operator uses an ESP predictive model to
monitor the performance of the ESP developed in accordance and operated
according to the requirements in section Sec. 60.48Da of this part.
(3) The affected facility burns only gaseous fuels and/or fuel oils
that contain no greater than 0.5 weight percent sulfur, and the owner or
operator operates the unit according to a written site-specific
monitoring plan approved by the permitting authority. This monitoring
plan must include procedures
[[Page 214]]
and criteria for establishing and monitoring specific parameters for the
affected facility indicative of compliance with the opacity standard.
For testing performed as part of this site-specific monitoring plan, the
permitting authority may require as an alternative to the notification
and reporting requirements specified in Sec. Sec. 60.8 and 60.11 that
the owner or operator submit any deviations with the excess emissions
report required under Sec. 60.48c(c).
[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009; 76
FR 3523, Jan. 20, 2011; 77 FR 9463, Feb. 16, 2012]
Sec. 60.48c Reporting and recordkeeping requirements.
(a) The owner or operator of each affected facility shall submit
notification of the date of construction or reconstruction and actual
startup, as provided by Sec. 60.7 of this part. This notification shall
include:
(1) The design heat input capacity of the affected facility and
identification of fuels to be combusted in the affected facility.
(2) If applicable, a copy of any federally enforceable requirement
that limits the annual capacity factor for any fuel or mixture of fuels
under Sec. 60.42c, or Sec. 60.43c.
(3) The annual capacity factor at which the owner or operator
anticipates operating the affected facility based on all fuels fired and
based on each individual fuel fired.
(4) Notification if an emerging technology will be used for
controlling SO2 emissions. The Administrator will examine the
description of the control device and will determine whether the
technology qualifies as an emerging technology. In making this
determination, the Administrator may require the owner or operator of
the affected facility to submit additional information concerning the
control device. The affected facility is subject to the provisions of
Sec. 60.42c(a) or (b)(1), unless and until this determination is made
by the Administrator.
(b) The owner or operator of each affected facility subject to the
SO2 emission limits of Sec. 60.42c, or the PM or opacity
limits of Sec. 60.43c, shall submit to the Administrator the
performance test data from the initial and any subsequent performance
tests and, if applicable, the performance evaluation of the CEMS and/or
COMS using the applicable performance specifications in appendix B of
this part.
(c) In addition to the applicable requirements in Sec. 60.7, the
owner or operator of an affected facility subject to the opacity limits
in Sec. 60.43c(c) shall submit excess emission reports for any excess
emissions from the affected facility that occur during the reporting
period and maintain records according to the requirements specified in
paragraphs (c)(1) through (3) of this section, as applicable to the
visible emissions monitoring method used.
(1) For each performance test conducted using Method 9 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (c)(1)(i) through (iii) of this
section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission reading
certification for each visible emission observer participating in the
performance test; and
(iii) Copies of all visible emission observer opacity field data
sheets;
(2) For each performance test conducted using Method 22 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (c)(2)(i) through (iv) of this
section.
(i) Dates and time intervals of all visible emissions observation
periods;
(ii) Name and affiliation for each visible emission observer
participating in the performance test;
(iii) Copies of all visible emission observer opacity field data
sheets; and
(iv) Documentation of any adjustments made and the time the
adjustments were completed to the affected facility operation by the
owner or operator to demonstrate compliance with the applicable
monitoring requirements.
(3) For each digital opacity compliance system, the owner or
operator shall maintain records and submit reports according to the
requirements specified in the site-specific monitoring plan approved by
the Administrator
[[Page 215]]
(d) The owner or operator of each affected facility subject to the
SO2 emission limits, fuel oil sulfur limits, or percent
reduction requirements under Sec. 60.42c shall submit reports to the
Administrator.
(e) The owner or operator of each affected facility subject to the
SO2 emission limits, fuel oil sulfur limits, or percent
reduction requirements under Sec. 60.42c shall keep records and submit
reports as required under paragraph (d) of this section, including the
following information, as applicable.
(1) Calendar dates covered in the reporting period.
(2) Each 30-day average SO2 emission rate (ng/J or lb/
MMBtu), or 30-day average sulfur content (weight percent), calculated
during the reporting period, ending with the last 30-day period; reasons
for any noncompliance with the emission standards; and a description of
corrective actions taken.
(3) Each 30-day average percent of potential SO2 emission
rate calculated during the reporting period, ending with the last 30-day
period; reasons for any noncompliance with the emission standards; and a
description of the corrective actions taken.
(4) Identification of any steam generating unit operating days for
which SO2 or diluent (O2 or CO2) data
have not been obtained by an approved method for at least 75 percent of
the operating hours; justification for not obtaining sufficient data;
and a description of corrective actions taken.
(5) Identification of any times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and a description of corrective actions taken if
data have been excluded for periods other than those during which coal
or oil were not combusted in the steam generating unit.
(6) Identification of the F factor used in calculations, method of
determination, and type of fuel combusted.
(7) Identification of whether averages have been obtained based on
CEMS rather than manual sampling methods.
(8) If a CEMS is used, identification of any times when the
pollutant concentration exceeded the full span of the CEMS.
(9) If a CEMS is used, description of any modifications to the CEMS
that could affect the ability of the CEMS to comply with Performance
Specifications 2 or 3 of appendix B of this part.
(10) If a CEMS is used, results of daily CEMS drift tests and
quarterly accuracy assessments as required under appendix F, Procedure 1
of this part.
(11) If fuel supplier certification is used to demonstrate
compliance, records of fuel supplier certification as described under
paragraph (f)(1), (2), (3), or (4) of this section, as applicable. In
addition to records of fuel supplier certifications, the report shall
include a certified statement signed by the owner or operator of the
affected facility that the records of fuel supplier certifications
submitted represent all of the fuel combusted during the reporting
period.
(f) Fuel supplier certification shall include the following
information:
(1) For distillate oil:
(i) The name of the oil supplier;
(ii) A statement from the oil supplier that the oil complies with
the specifications under the definition of distillate oil in Sec.
60.41c; and
(iii) The sulfur content or maximum sulfur content of the oil.
(2) For residual oil:
(i) The name of the oil supplier;
(ii) The location of the oil when the sample was drawn for analysis
to determine the sulfur content of the oil, specifically including
whether the oil was sampled as delivered to the affected facility, or
whether the sample was drawn from oil in storage at the oil supplier's
or oil refiner's facility, or other location;
(iii) The sulfur content of the oil from which the shipment came (or
of the shipment itself); and
(iv) The method used to determine the sulfur content of the oil.
(3) For coal:
(i) The name of the coal supplier;
(ii) The location of the coal when the sample was collected for
analysis to determine the properties of the coal, specifically including
whether the coal was sampled as delivered to the affected facility or
whether the sample was collected from coal in storage at the mine, at a
coal preparation plant,
[[Page 216]]
at a coal supplier's facility, or at another location. The certification
shall include the name of the coal mine (and coal seam), coal storage
facility, or coal preparation plant (where the sample was collected);
(iii) The results of the analysis of the coal from which the
shipment came (or of the shipment itself) including the sulfur content,
moisture content, ash content, and heat content; and
(iv) The methods used to determine the properties of the coal.
(4) For other fuels:
(i) The name of the supplier of the fuel;
(ii) The potential sulfur emissions rate or maximum potential sulfur
emissions rate of the fuel in ng/J heat input; and
(iii) The method used to determine the potential sulfur emissions
rate of the fuel.
(g)(1) Except as provided under paragraphs (g)(2) and (g)(3) of this
section, the owner or operator of each affected facility shall record
and maintain records of the amount of each fuel combusted during each
operating day.
(2) As an alternative to meeting the requirements of paragraph
(g)(1) of this section, the owner or operator of an affected facility
that combusts only natural gas, wood, fuels using fuel certification in
Sec. 60.48c(f) to demonstrate compliance with the SO2
standard, fuels not subject to an emissions standard (excluding
opacity), or a mixture of these fuels may elect to record and maintain
records of the amount of each fuel combusted during each calendar month.
(3) As an alternative to meeting the requirements of paragraph
(g)(1) of this section, the owner or operator of an affected facility or
multiple affected facilities located on a contiguous property unit where
the only fuels combusted in any steam generating unit (including steam
generating units not subject to this subpart) at that property are
natural gas, wood, distillate oil meeting the most current requirements
in Sec. 60.42C to use fuel certification to demonstrate compliance with
the SO2 standard, and/or fuels, excluding coal and residual
oil, not subject to an emissions standard (excluding opacity) may elect
to record and maintain records of the total amount of each steam
generating unit fuel delivered to that property during each calendar
month.
(h) The owner or operator of each affected facility subject to a
federally enforceable requirement limiting the annual capacity factor
for any fuel or mixture of fuels under Sec. 60.42c or Sec. 60.43c
shall calculate the annual capacity factor individually for each fuel
combusted. The annual capacity factor is determined on a 12-month
rolling average basis with a new annual capacity factor calculated at
the end of the calendar month.
(i) All records required under this section shall be maintained by
the owner or operator of the affected facility for a period of two years
following the date of such record.
(j) The reporting period for the reports required under this subpart
is each six-month period. All reports shall be submitted to the
Administrator and shall be postmarked by the 30th day following the end
of the reporting period.
[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009]
Subpart E_Standards of Performance for Incinerators
Sec. 60.50 Applicability and designation of affected facility.
(a) The provisions of this subpart are applicable to each
incinerator of more than 45 metric tons per day charging rate (50 tons/
day), which is the affected facility.
(b) Any facility under paragraph (a) of this section that commences
construction or modification after August 17, 1971, is subject to the
requirements of this subpart.
(c) Any facility covered by subpart Cb, Eb, AAAA, or BBBB of this
part is not covered by this subpart.
(d) Any facility covered by an EPA approved State section 111(d)/129
plan implementing subpart Cb or BBBB of this part is not covered by this
subpart.
[[Page 217]]
(e) Any facility covered by subpart FFF or JJJ of part 62 of this
title (Federal section 111(d)/129 plan implementing subpart Cb or BBBB
of this part) is not covered by this subpart.
[42 FR 37936, July 25, 1977, as amended at 71 FR 27335, May 10, 2006]
Sec. 60.51 Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Act and in subpart A of this part.
(a) Incinerator means any furnace used in the process of burning
solid waste for the purpose of reducing the volume of the waste by
removing combustible matter.
(b) Solid waste means refuse, more than 50 percent of which is
municipal type waste consisting of a mixture of paper, wood, yard
wastes, food wastes, plastics, leather, rubber, and other combustibles,
and noncombustible materials such as glass and rock.
(c) Day means 24 hours.
[36 FR 24877, Dec. 23, 1971, as amended at 39 FR 20792, June 14, 1974]
Sec. 60.52 Standard for particulate matter.
(a) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8 of this part,
whichever date comes first, no owner or operator subject to the
provisions of this part shall cause to be discharged into the atmosphere
from any affected facility any gases which contain particulate matter in
excess of 0.18 g/dscm (0.08 gr/dscf) corrected to 12 percent
CO2.
[39 FR 20792, June 14, 1974, as amended at 65 FR 61753, Oct. 17, 2000]
Sec. 60.53 Monitoring of operations.
(a) The owner or operator of any incinerator subject to the
provisions of this part shall record the daily charging rates and hours
of operation.
Sec. 60.54 Test methods and procedures.
(a) In conducting the performance tests required in Sec. 60.8, the
owner or operator shall use as reference methods and procedures the test
methods in appendix A of this part or other methods and procedures as
specified in this section, except as provided in Sec. 60.8(b).
(b) The owner or operator shall determine compliance with the
particulate matter standard in Sec. 60.52 as follows:
(1) The concentration (c12) of particulate matter,
corrected to 12 percent CO2, shall be computed for each run
using the following equation:
c12 = cs (12/%CO2)
where:
c12 = concentration of particulate matter, corrected to 12
percent CO2, g/dscm (gr/dscf).
cs = concentration of particulate matter, g/dscm (gr/dscf).
%CO2 = CO2 concentration, percent dry basis.
(2) Method 5 shall be used to determine the particulate matter
concentration (cs). The sampling time and sample volume for
each run shall be at least 60 minutes and 0.85 dscm (30 dscf).
(3) The emission rate correction factor, integrated or grab sampling
and analysis procedure of Method 3B shall be used to determine
CO2 concentration (%CO2).
(i) The CO2 sample shall be obtained simultaneously with,
and at the same traverse points as, the particulate run. If the
particulate run has more than 12 traverse points, the CO2
traverse points may be reduced to 12 if Method 1 is used to locate the
12 CO2 traverse points. If individual CO2 samples
are taken at each traverse point, the CO2 concentration
(%CO2) used in the correction equation shall be the
arithmetic mean of the sample CO2 concentrations at all
traverse points.
(ii) If sampling is conducted after a wet scrubber, an ``adjusted''
CO2 concentration [(%CO2)adj], which
accounts for the effects of CO2 absorption and dilution air,
may be used instead of the CO2 concentration determined in
this paragraph. The adjusted CO2 concentration shall be
determined by either of the procedures in paragraph (c) of this section.
(c) The owner or operator may use either of the following procedures
to determine the adjusted CO2 concentration.
(1) The volumetric flow rates at the inlet and outlet of the wet
scrubber and the inlet CO2 concentration may be used to
determine the adjusted CO2
[[Page 218]]
concentration [(%CO2)adj] using the following
equation:
(%CO2)adj = (%CO2)di
(Qdi/Qdo)
where:
(%CO2)adj = adjusted outlet CO2
concentration, percent dry basis.
(%CO2)di = CO2 concentration measured
before the scrubber, percent dry basis.
Qdi = volumetric flow rate of effluent gas before the wet
scrubber, dscm/min (dscf/min).
Qdo = volumetric flow rate of effluent gas after the wet
scrubber, dscm/min (dscf/min).
(i) At the outlet, Method 5 is used to determine the volumetric flow
rate (Qdo) of the effluent gas.
(ii) At the inlet, Method 2 is used to determine the volumetric flow
rate (Qdi) of the effluent gas as follows: Two full velocity
traverses are conducted, one immediately before and one immediately
after each particulate run conducted at the outlet, and the results are
averaged.
(iii) At the inlet, the emission rate correction factor, integrated
sampling and analysis procedure of Method 3B is used to determine the
CO2 concentration [(%CO2)di] as
follows: At least nine sampling points are selected randomly from the
velocity traverse points and are divided randomly into three sets, equal
in number of points; the first set of three or more points is used for
the first run, the second set for the second run, and the third set for
the third run. The CO2 sample is taken simultaneously with
each particulate run being conducted at the outlet, by traversing the
three sampling points (or more) and sampling at each point for equal
increments of time.
(2) Excess air measurements may be used to determine the adjusted
CO2 concentration [(%CO2)adj] using the
following equation:
(%CO2)adj = (%CO2)di [(100 +
%EAi)/(100 + %EAo)]
where:
(%CO2)adj = adjusted outlet CO2
concentration, percent dry basis.
(%CO2)di = CO2 concentration at the
inlet of the wet scrubber, percent dry basis.
%EAi = excess air at the inlet of the scrubber, percent.
%EAo = excess air at the outlet of the scrubber, percent.
(i) A gas sample is collected as in paragraph (c)(1)(iii) of this
section and the gas samples at both the inlet and outlet locations are
analyzed for CO2, O2, and N2.
(ii) Equation 3B-3 of Method 3B is used to compute the percentages
of excess air at the inlet and outlet of the wet scrubber.
[54 FR 6665, Feb. 14, 1989, as amended at 55 FR 5212, Feb. 14, 1990; 65
FR 61753, Oct. 17, 2000]
Subpart Ea_Standards of Performance for Municipal Waste Combustors for
Which Construction Is Commenced After December 20, 1989 and On or Before
September 20, 1994
Source: 56 FR 5507, Feb. 11, 1991, unless otherwise noted.
Sec. 60.50a Applicability and delegation of authority.
(a) The affected facility to which this subpart applies is each
municipal waste combustor unit with a municipal waste combustor unit
capacity greater than 225 megagrams per day (250 tons per day) of
municipal solid waste for which construction, modification, or
reconstruction is commenced as specified in paragraphs (a)(1) and (a)(2)
of this section.
(1) Construction is commenced after December 20, 1989 and on or
before September 20, 1994.
(2) Modification or reconstruction is commenced after December 20,
1989 and on or before June 19, 1996.
(b) [Reserved]
(c) Any unit combusting a single-item waste stream of tires is not
subject to this subpart if the owner or operator of the unit:
(1) Notifies the Administrator of an exemption claim; and
(2) Provides data documenting that the unit qualifies for this
exemption.
(d) Any cofired combustor, as defined under Sec. 60.51a, located at
a plant that meets the capacity specifications in paragraph (a) of this
section is not subject to this subpart if the owner or operator of the
cofired combustor:
(1) Notifies the Administrator of an exemption claim;
[[Page 219]]
(2) Provides a copy of the federally enforceable permit (specified
in the definition of cofired combustor in this section); and
(3) Keeps a record on a calendar quarter basis of the weight of
municipal solid waste combusted at the cofired combustor and the weight
of all other fuels combusted at the cofired combustor.
(e) Any cofired combustor that is subject to a federally enforceable
permit limiting the operation of the combustor to no more than 225
megagrams per day (250 tons per day) of municipal solid waste is not
subject to this subpart.
(f) Physical or operational changes made to an existing municipal
waste combustor unit primarily for the purpose of complying with
emission guidelines under subpart Cb are not considered a modification
or reconstruction and do not result in an existing municipal waste
combustor unit becoming subject to this subpart.
(g) A qualifying small power production facility, as defined in
section 3(17)(C) of the Federal Power Act (16 U.S.C. 796(17)(C)), that
burns homogeneous waste (such as automotive tires or used oil, but not
including refuse-derived fuel) for the production of electric energy is
not subject to this subpart if the owner or operator of the facility
notifies the Administrator of an exemption claim and provides data
documenting that the facility qualifies for this exemption.
(h) A qualifying cogeneration facility, as defined in section
3(18)(B) of the Federal Power Act (16 U.S.C. 796(18)(B)), that burns
homogeneous waste (such as automotive tires or used oil, but not
including refuse-derived fuel) for the production of electric energy and
steam or forms of useful energy (such as heat) that are used for
industrial, commercial, heating, or cooling purposes, is not subject to
this subpart if the owner or operator of the facility notifies the
Administrator of an exemption claim and provides data documenting that
the facility qualifies for this exemption.
(i) Any unit required to have a permit under section 3005 of the
Solid Waste Disposal Act is not subject to this subpart.
(j) Any materials recovery facility (including primary or secondary
smelters) that combusts waste for the primary purpose of recovering
metals is not subject to this subpart.
(k) Pyrolysis/combustion units that are an integrated part of a
plastics/rubber recycling unit (as defined in Sec. 60.51a) are not
subject to this subpart if the owner or operator of the plastics/rubber
recycling unit keeps records of: the weight of plastics, rubber, and/or
rubber tires processed on a calendar quarter basis; the weight of
chemical plant feedstocks and petroleum refinery feedstocks produced and
marketed on a calendar quarter basis; and the name and address of the
purchaser of the feedstocks. The combustion of gasoline, diesel fuel,
jet fuel, fuel oils, residual oil, refinery gas, petroleum coke,
liquified petroleum gas, propane, or butane produced by chemical plants
or petroleum refineries that use feedstocks produced by plastics/rubber
recycling units are not subject to this subpart.
(l) The following authorities shall be retained by the Administrator
and not transferred to a State:
None.
(m) This subpart shall become effective on August 12, 1991.
[56 FR 5507, Feb. 11, 1991, as amended at 60 FR 65384, Dec. 19, 1995]
Sec. 60.51a Definitions.
ASME means the American Society of Mechanical Engineers.
Batch MWC means an MWC unit designed such that it cannot combust MSW
continuously 24 hours per day because the design does not allow waste to
be fed to the unit or ash to be removed while combustion is occurring.
Bubbling fluidized bed combustor means a fluidized bed combustor in
which the majority of the bed material remains in a fluidized state in
the primary combustion zone.
Calendar quarter means a consecutive 3-month period (nonoverlapping)
beginning on January 1, April 1, July 1, and October 1.
Chief facility operator means the person in direct charge and
control of the operation of an MWC and who is responsible for daily on-
site supervision,
[[Page 220]]
technical direction, management, and overall performance of the
facility.
Circulating fluidized bed combustor means a fluidized bed combustor
in which the majority of the fluidized bed material is carried out of
the primary combustion zone and is transported back to the primary zone
through a recirculation loop.
Clean wood means untreated wood or untreated wood products including
clean untreated lumber, tree stumps (whole or chipped), and tree limbs
(whole or chipped). Clean wood does not include yard waste, which is
defined elsewhere in this section, or construction, renovation, and
demolition wastes (which includes but is not limited to railroad ties
and telephone poles), which are exempt from the definition of municipal
solid waste in this section.
Cofired combustor means a unit combusting municipal solid waste with
nonmunicipal solid waste fuel (e.g., coal, industrial process waste) and
subject to a federally enforceable permit limiting the unit to
combusting a fuel feed stream, 30 percent or less of the weight of which
is comprised, in aggregate, of municipal solid waste as measured on a
calendar quarter basis.
Continuous emission monitoring system or CEMS means a monitoring
system for continuously measuring the emissions of a pollutant from an
affected facility.
Continuous monitoring system means the total equipment used to
sample and condition (if applicable), to analyze, and to provide a
permanent record of emissions or process parameters.
Dioxin/furan means total tetra- through octachlorinated dibenzo-p-
dioxins and dibenzofurans.
Federally-enforceable means all limitations and conditions that are
enforceable by the Administrator including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State implementation
plan, and any permit requirements established under 40 CFR 52.21 or
under 40 CFR 51.18 and 40 CFR 51.24.
Four-hour block average or 4-hour block average means the average of
all hourly emission rates when the affected facility is operating and
combusting MSW measured over 4-hour periods of time from 12 midnight to
4 a.m., 4 a.m. to 8 a.m., 8 a.m. to 12 noon, 12 noon to 4 p.m., 4 p.m.
to 8 p.m., and 8 p.m. to 12 midnight.
Large municipal waste combustor plant means a municipal waste
combustor plant with a municipal waste combustor aggregate plant
capacity for affected facilities that is greater than 225 megagrams per
day (250 tons per day) of municipal solid waste.
Mass burn refractory municipal waste combustor means a field-erected
combustor that combusts municipal solid waste in a refractory wall
furnace. Unless otherwise specified, this includes combustors with a
cylindrical rotary refractory wall furnace.
Mass burn rotary waterwall municipal waste combustor means a field-
erected combustor that combusts municipal solid waste in a cylindrical
rotary waterwall furnace.
Mass burn waterwall municipal waste combustor means a field-erected
combustor that combusts municipal solid waste in a waterwall furnace.
Maximum demonstrated municipal waste combustor unit load means the
highest 4-hour arithmetic average municipal waste combustor unit load
achieved during four consecutive hours during the most recent dioxin/
furan performance test demonstrating compliance with the applicable
limit for municipal waste combustor organics specified under Sec.
60.53a.
Maximum demonstrated particulate matter control device temperature
means the highest 4-hour arithmetic average flue gas temperature
measured at the particulate matter control device inlet during four
consecutive hours during the most recent dioxin/furan performance test
demonstrating compliance with the applicable limit for municipal waste
combustor organics specified under Sec. 60.53a.
Modification or modified municipal waste combustor unit means a
municipal waste combustor unit to which changes have been made if the
cumulative cost of the changes, over the life of the unit, exceed 50
percent of the original cost of construction and installation of the
unit (not including the cost of any land purchased in connection with
such construction or installation) updated to current costs; or any
physical change
[[Page 221]]
in the municipal waste combustor unit or change in the method of
operation of the municipal waste combustor unit increases the amount of
any air pollutant emitted by the unit for which standards have been
established under section 129 or section 111. Increases in the amount of
any air pollutant emitted by the municipal waste combustor unit are
determined at 100-percent physical load capability and downstream of all
air pollution control devices, with no consideration given for load
restrictions based on permits or other nonphysical operational
restrictions.
Modular excess air MWC means a combustor that combusts MSW and that
is not field-erected and has multiple combustion chambers, all of which
are designed to operate at conditions with combustion air amounts in
excess of theoretical air requirements.
Modular starved air MWC means a combustor that combusts MSW and that
is not field-erected and has multiple combustion chambers in which the
primary combustion chamber is designed to operate at substoichiometric
conditions.
Municipal solid waste or municipal-type solid waste or MSW means
household, commercial/retail, and/or institutional waste. Household
waste includes material discarded by single and multiple residential
dwellings, hotels, motels, and other similar permanent or temporary
housing establishments or facilities. Commercial/retail waste includes
material discarded by stores, offices, restaurants, warehouses,
nonmanufacturing activities at industrial facilities, and other similar
establishments or facilities. Institutional waste includes material
discarded by schools, nonmedical waste discarded by hospitals, material
discarded by nonmanufacturing activities at prisons and government
facilities, and material discarded by other similar establishments or
facilities. Household, commercial/retail, and institutional waste does
not include used oil; sewage sludge; wood pallets; construction,
renovation, and demolition wastes (which includes but is not limited to
railroad ties and telephone poles); clean wood; industrial process or
manufacturing wastes; medical waste; or motor vehicles (including motor
vehicle parts or vehicle fluff). Household, commercial/retail, and
institutional wastes include:
(1) Yard waste;
(2) Refuse-derived fuel; and
(3) Motor vehicle maintenance materials limited to vehicle batteries
and tires except as specified in Sec. 60.50a(c).
Municipal waste combustor, MWC, or municipal waste combustor unit:
(1) Means any setting or equipment that combusts solid, liquid, or
gasified MSW including, but not limited to, field-erected incinerators
(with or without heat recovery), modular incinerators (starved-air or
excess-air), boilers (i.e., steam-generating units), furnaces (whether
suspension-fired, grate-fired, mass-fired, air curtain incinerators, or
fluidized bed-fired), and pyrolysis/combustion units. Municipal waste
combustors do not include pyrolysis/combustion units located at
plastics/ rubber recycling units (as specified in Sec. 60.50a(k) of
this section). Municipal waste combustors do not include internal
combustion engines, gas turbines, or other combustion devices that
combust landfill gases collected by landfill gas collection systems.
(2) The boundaries of an MWC are defined as follows. The MWC unit
includes, but is not limited to, the MSW fuel feed system, grate system,
flue gas system, bottom ash system, and the combustor water system. The
MWC boundary starts at the MSW pit or hopper and extends through:
(i) The combustor flue gas system, which ends immediately following
the heat recovery equipment or, if there is no heat recovery equipment,
immediately following the combustion chamber;
(ii) The combustor bottom ash system, which ends at the truck
loading station or similar ash handling equipment that transfer the ash
to final disposal, including all ash handling systems that are connected
to the bottom ash handling system; and
(iii) The combustor water system, which starts at the feed water
pump and ends at the piping exiting the steam drum or superheater.
(3) The MWC unit does not include air pollution control equipment,
the stack, water treatment equipment, or the turbine generator set.
[[Page 222]]
Municipal waste combustor plant means one or more MWC units at the
same location for which construction, modification, or reconstruction is
commenced after December 20, 1989 and on or before September 20, 1994.
Municipal waste combustor plant capacity means the aggregate MWC
unit capacity of all MWC units at an MWC plant for which construction,
modification, or reconstruction of the units commenced after December
20, 1989 and on or before September 20, 1994. Any MWC units for which
construction, modification, or reconstruction is commenced on or before
December 20, 1989 or after September 20, 1994 are not included for
determining applicability under this subpart.
Municipal waste combustor unit capacity means the maximum design
charging rate of an MWC unit expressed in megagrams per day (tons per
day) of MSW combusted, calculated according to the procedures under
Sec. 60.58a(j). Municipal waste combustor unit capacity is calculated
using a design heating value of 10,500 kilojoules per kilogram (4,500
British thermal units per pound) for MSW. The calculational procedures
under Sec. 60.58a(j) include procedures for determining MWC unit
capacity for continuous and batch feed MWC's.
Municipal waste combustor unit load means the steam load of the MWC
unit measured as specified in Sec. 60.58a(h)(6).
MWC acid gases means all acid gases emitted in the exhaust gases
from MWC units including, but not limited to, sulfur dioxide and
hydrogen chloride gases.
MWC metals means metals and metal compounds emitted in the exhaust
gases from MWC units.
MWC organics means organic compounds emitted in the exhaust gases
from MWC units and includes total tetra- through octa-chlorinated
dibenzo-p-dioxins and dibenzofurans.
Particulate matter means total particulate matter emitted from MWC
units as measured by Method 5 (see Sec. 60.58a).
Plastics/rubber recycling unit means an integrated processing unit
where plastics, rubber, and/or rubber tires are the only feed materials
(incidental contaminants may be included in the feed materials) and they
are processed into a chemical plant feedstock or petroleum refinery
feedstock, where the feedstock is marketed to and used by a chemical
plant or petroleum refinery as input feedstock. The combined weight of
the chemical plant feedstock and petroleum refinery feedstock produced
by the plastics/rubber recycling unit on a calendar quarter basis shall
be more than 70 percent of the combined weight of the plastics, rubber,
and rubber tires processed by the plastics/rubber recycling unit on a
calendar quarter basis. The plastics, rubber, and/or rubber tire feed
materials to the plastics/rubber recycling unit may originate from the
separation or diversion of plastics, rubber, or rubber tires from MSW or
industrial solid waste, and may include manufacturing scraps, trimmings,
and off-specification plastics, rubber, and rubber tire discards. The
plastics, rubber, and rubber tire feed materials to the plastics/rubber
recycling unit may contain incidental contaminants (e.g., paper labels
on plastic bottles, metal rings on plastic bottle caps, etc.).
Potential hydrogen chloride emission rate means the hydrogen
chloride emission rate that would occur from combustion of MSW in the
absence of any hydrogen chloride emissions control.
Potential sulfur dioxide emission rate means the sulfur dioxide
emission rate that would occur from combustion of MSW in the absence of
any sulfur dioxide emissions control.
Pulverized coal/refuse-derived fuel mixed fuel-fired combustor or
pulverized coal/RDF mixed fuel-fired combustor means a combustor that
fires coal and RDF simultaneously, in which pulverized coal is
introduced into an air stream that carries the coal to the combustion
chamber of the unit where it is fired in suspension. This includes both
conventional pulverized coal and micropulverized coal.
Pyrolysis/combustion unit means a unit that produces gases, liquids,
or solids through the heating of MSW, and the gases, liquids, or solids
produced are combusted and emissions vented to the atmosphere.
Reconstruction means rebuilding an MWC unit for which the cumulative
costs of the construction over the life of the unit exceed 50 percent of
the
[[Page 223]]
original cost of construction and installation of the unit (not
including any cost of land purchased in connection with such
construction or installation) updated to current costs (current
dollars).
Refractory unit or refractory wall furnace means a combustion unit
having no energy recovery (e.g., via a waterwall) in the furnace (i.e.,
radiant heat transfer section) of the combustor.
Refuse-derived fuel or RDF means a type of MSW produced by
processing MSW through shredding and size classification.
This includes all classes of RDF including low density fluff RDF
through densified RDF and RDF fuel pellets.
RDF stoker means a steam generating unit that combusts RDF in a
semi-suspension firing mode using air-fed distributors.
Same location means the same or contiguous property that is under
common ownership or control, including properties that are separated
only by a street, road, highway, or other public right-of-way. Common
ownership or control includes properties that are owned, leased, or
operated by the same entity, parent entity, subsidiary, subdivision, or
any combination thereof, including any municipality or other
governmental unit, or any quasigovernmental authority (e.g., a public
utility district or regional waste disposal authority).
Shift supervisor means the person in direct charge and control of
the operation of an MWC and who is responsible for on-site supervision,
technical direction, management, and overall performance of the facility
during an assigned shift.
Spreader stoker coal/refuse-derived fuel mixed fuel-fired combustor
or spreader stoker coal/RDF mixed fuel-fired combustor means a combustor
that fires coal and refuse-derived fuel simultaneously, in which coal is
introduced to the combustion zone by a mechanism that throws the fuel
onto a grate from above. Combustion takes place both in suspension and
on the grate.
Standard conditions means a temperature of 20 [deg]C (68 [deg]F) and
a pressure of 101.3 kilopascals (29.92 inches of mercury).
Twenty-four hour daily average or 24-hour daily average means the
arithmetic or geometric mean (as specified in Sec. 60.58a (e), (g), or
(h) as applicable) of all hourly emission rates when the affected
facility is operating and firing MSW measured over a 24-hour period
between 12 midnight and the following midnight.
Untreated lumber means wood or wood products that have been cut or
shaped and include wet, air-dried, and kiln-dried wood products.
Untreated lumber does not include wood products that have been painted,
pigment-stained, or ``pressure-treated.'' Pressure-treating compounds
include, but are not limited to, chromate copper arsenate,
pentachlorophenol, and creosote.
Waterwall furnace means a combustion unit having energy (heat)
recovery in the furnace (i.e., radiant heat transfer section) of the
combustor.
Yard waste means grass, grass clippings, bushes, shrubs, and
clippings from bushes and shrubs that are generated by residential,
commercial/retail, institutional, and/or industrial sources as part of
maintenance activities associated with yards or other private or public
lands. Yard waste does not include construction, renovation, and
demolition wastes, which are exempt from the definition of MSW in this
section. Yard waste does not include clean wood, which is exempt from
the definition of MSW in this section.
[56 FR 5507, Feb. 11, 1991, as amended at 60 FR 65384, Dec. 19, 1995; 65
FR 61753, Oct. 17, 2000]
Sec. 60.52a Standard for municipal waste combustor metals.
(a) On and after the date on which the initial compliance test is
completed or is required to be completed under Sec. 60.8, no owner or
operator of an affected facility located within a large MWC plant shall
cause to be discharged into the atmosphere from that affected facility
any gases that contain particulate matter in excess of 34 milligrams per
dry standard cubic meter (0.015 grains per dry standard cubic foot),
corrected to 7 percent oxygen (dry basis).
(b) On and after the date on which the initial compliance test is
completed or is required to be completed
[[Page 224]]
under Sec. 60.8, no owner or operator of an affected facility subject
to the particulate matter emission limit under paragraph (a) of this
section shall cause to be discharged into the atmosphere from that
affected facility any gases that exhibit greater than 10 percent opacity
(6-minute average).
(c) [Reserved]
Sec. 60.53a Standard for municipal waste combustor organics.
(a) [Reserved]
(b) On and after the date on which the initial compliance test is
completed or is required to be completed under Sec. 60.8, no owner or
operator of an affected facility located within a large MWC plant shall
cause to be discharged into the atmosphere from that affected facility
any gases that contain dioxin/furan emissions that exceed 30 nanograms
per dry standard cubic meter (12 grains per billion dry standard cubic
feet), corrected to 7 percent oxygen (dry basis).
Sec. 60.54a Standard for municipal waste combustor acid gases.
(a)-(b) [Reserved]
(c) On and after the date on which the initial compliance test is
completed or is required to be completed under Sec. 60.8, no owner or
operator of an affected facility located within a large MWC plant shall
cause to be discharged into the atmosphere from that affected facility
any gases that contain sulfur dioxide in excess of 20 percent of the
potential sulfur dioxide emission rate (80 percent reduction by weight
or volume) or 30 parts per million by volume, corrected to 7 percent
oxygen (dry basis), whichever is less stringent. The averaging time is
specified in Sec. 60.58a(e).
(d) On and after the date on which the initial compliance test is
completed or is required to be completed under Sec. 60.8, no owner or
operator of an affected facility located within a large MWC plant shall
cause to be discharged into the atmosphere from that affected facility
any gases that contain hydrogen chloride in excess of 5 percent of the
potential hydrogen chloride emission rate (95 percent reduction by
weight or volume) or 25 parts per million by volume, corrected to 7
percent oxygen (dry basis), whichever is less stringent.
Sec. 60.55a Standard for nitrogen oxides.
On and after the date on which the initial compliance test is
completed or is required to be completed under Sec. 60.8, no owner or
operator of an affected facility located within a large MWC plant shall
cause to be discharged into the atmosphere from that affected facility
any gases that contain nitrogen oxides in excess of 180 parts per
million by volume, corrected to 7 percent oxygen (dry basis). The
averaging time is specified under Sec. 60.58a(g).
Sec. 60.56a Standards for municipal waste combustor operating practices.
(a) On and after the date on which the initial compliance test is
completed or is required to be completed under Sec. 60.8, no owner or
operator of an affected facility located within a large MWC plant shall
cause such facility to exceed the carbon monoxide standards shown in
table 1.
Table 1--MWC Operating Standards
------------------------------------------------------------------------
Carbon
monoxide
emission limit
MWC technology (parts per
million by
volume) \1\
------------------------------------------------------------------------
Mass burn waterwall..................................... 100
Mass burn refractory.................................... 100
Mass burn rotary waterwall.............................. 100
Modular starved air..................................... 50
Modular excess air...................................... 50
RDF stoker.............................................. 150
Bubbling fluidized bed combustor........................ 100
Circulating fluidized bed combustor..................... 100
Pulverized coal/RDF mixed fuel-fired combustor.......... 150
Spreader stoker coal/RDF mixed fuel-fird combustor...... 150
------------------------------------------------------------------------
\1\ Measured at the combustor outlet in conjunction with a measurement
of oxygen concentration, corrected to 7 percent oxygen (dry basis).
The averaging times are specified in Sec. 60.58a(h).
(b) No owner or operator of an affected facility located within a
large MWC plant shall cause such facility to operate at a load level
greater than 110 percent of the maximum demonstrated MWC unit load as
defined in Sec. 60.51a. The averaging time is specified under Sec.
60.58a(h).
(c) No owner or operator of an affected facility located within a
large MWC plant shall cause such facility to operate at a temperature,
measured at
[[Page 225]]
the final particulate matter control device inlet, exceeding 17
[deg]Centigrade (30 [deg]Fahrenheit) above the maximum demonstrated
particulate matter control device temperature as defined in Sec.
60.51a. The averaging time is specified under Sec. 60.58a(h).
(d) Within 24 months from the date of start-up of an affected
facility or before February 11, 1993, whichever is later, each chief
facility operator and shift supervisor of an affected facility located
within a large MWC plant shall obtain and keep current either a
provisional or operator certification in accordance with ASME QRO-1-1994
(incorporated by reference, see Sec. 60.17) or an equivalent State-
approved certification program.
(e) No owner or operator of an affected facility shall allow such
affected facility located at a large MWC plant to operate at any time
without a certified shift supervisor, as provided under paragraph (d) of
this section, on duty at the affected facility. This requirement shall
take effect 24 months after the date of start-up of the affected
facility or on and after February 11, 1993, whichever is later.
(f) The owner or operator of an affected facility located within a
large MWC plant shall develop and update on a yearly basis a
sitespecific operating manual that shall, at a minimum, address the
following elements of MWC unit operation:
(1) Summary of the applicable standards under this subpart;
(2) Description of basic combustion theory applicable to an MWC
unit;
(3) Procedures for receiving, handling, and feeding MSW;
(4) MWC unit start-up, shutdown, and malfunction procedures;
(5) Procedures for maintaining proper combustion air supply levels;
(6) Procedures for operating the MWC unit within the standards
established under this subpart;
(7) Procedures for responding to periodic upset or off-specification
conditions;
(8) Procedures for minimizing particulate matter carryover;
(9) [Reserved]
(10) Procedures for handling ash;
(11) Procedures for monitoring MWC unit emissions; and
(12) Reporting and recordkeeping procedures.
(g) The owner or operator of an affected facility located within a
large MWC plant shall establish a program for reviewing the operating
manual annually with each person who has responsibilities affecting the
operation of an affected facility including, but not limited to, chief
facility operators, shift supervisors, control room operators, ash
handlers, maintenance personnel, and crane/load handlers.
(h) The initial review of the operating manual, as specified under
paragraph (g) of this section, shall be conducted prior to assumption of
responsibilities affecting MWC unit operation by any person required to
undergo training under paragraph (g) of this section. Subsequent reviews
of the manual shall be carried out annually by each such person.
(i) The operating manual shall be kept in a readily accessible
location for all persons required to undergo training under paragraph
(g) of this section. The operating manual and records of training shall
be available for inspection by EPA or its delegated enforcement agent
upon request.
(j)-(k) [Reserved]
[56 FR 5507, Feb. 11, 1991, as amended at 60 FR 65386, Dec. 19, 1995]
Sec. 60.57a [Reserved]
Sec. 60.58a Compliance and performance testing.
(a) The standards under this subpart apply at all times, except
during periods of start-up, shutdown, or malfunction; provided, however,
that the duration of start-up, shutdown, or malfunction shall not exceed
3 hours per occurrence.
(1) The start-up period commences when the affected facility begins
the continuous burning of MSW and does not include any warm-up period
when the affected facility is combusting only a fossil fuel or other
non-MSW fuel and no MSW is being combusted.
(2) Continuous burning is the continuous, semicontinuous, or batch
feeding of MSW for purposes of waste disposal, energy production, or
providing heat to the combustion system in preparation
[[Page 226]]
for waste disposal or energy production. The use of MSW solely to
provide thermal protection of grate or hearth during the start-up period
shall not be considered to be continuous burning.
(b) The following procedures and test methods shall be used to
determine compliance with the emission limits for particulate matter
under Sec. 60.52a:
(1) Method 1 shall be used to select sampling site and number of
traverse points.
(2) Method 3 shall be used for gas analysis.
(3) Method 5 shall be used for determining compliance with the
particulate matter emission limit. The minimum sample volume shall be
1.7 cubic meters (60 cubic feet). The probe and filter holder heating
systems in the sample train shall be set to provide a gas temperature of
160[deg]14 [deg]Centigrade (320[deg]25 [deg]Fahrenheit). An oxygen or carbon dioxide
measurement shall be obtained simultaneously with each Method 5 run.
(4) For each Method 5 run, the emission rate shall be determined
using:
(i) Oxygen or carbon dioxide measurements,
(ii) Dry basis F factor, and
(iii) Dry basis emission rate calculation procedures in Method 19.
(5) An owner or operator may request that compliance be determined
using carbon dioxide measurements corrected to an equivalent of 7
percent oxygen. The relationship between oxygen and carbon dioxide
levels for the affected facility shall be established during the initial
compliance test.
(6) The owner or operator of an affected facility shall conduct an
initial compliance test for particulate matter and opacity as required
under Sec. 60.8.
(7) Method 9 shall be used for determining compliance with the
opacity limit.
(8) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a continuous opacity monitoring system
(COMS) and record the output of the system on a 6-minute average basis.
(9) Following the date the initial compliance test for particulate
matter is completed or is required to be completed under Sec. 60.8 for
an affected facility located within a large MWC plant, the owner or
operator shall conduct a performance test for particulate matter on an
annual basis (no more than 12 calendar months following the previous
compliance test).
(10) [Reserved]
(c) [Reserved]
(d) The following procedures and test methods shall be used to
determine compliance with the limits for dioxin/furan emissions under
Sec. 60.53a:
(1) Method 23 shall be used for determining compliance with the
dioxin/furan emission limits. The minimum sample time shall be 4 hours
per test run.
(2) The owner or operator of an affected facility shall conduct an
initial compliance test for dioxin/furan emissions as required under
Sec. 60.8.
(3) Following the date of the initial compliance test or the date on
which the initial compliance test is required to be completed under
Sec. 60.8, the owner or operator of an affected facility located within
a large MWC plant shall conduct a performance test for dioxin/furan
emissions on an annual basis (no more than 12 calendar months following
the previous compliance test).
(4) [Reserved]
(5) An owner or operator may request that compliance with the
dioxin/furan emissions limit be determined using carbon dioxide
measurements corrected to an equivalent of 7 percent oxygen. The
relationship between oxygen and carbon dioxide levels for the affected
facility shall be established during the initial compliance test.
(e) The following procedures and test methods shall be used for
determining compliance with the sulfur dioxide limit under Sec. 60.54a:
(1) Method 19, section 5.4, shall be used to determine the daily
geometric average percent reduction in the potential sulfur dioxide
emission rate.
(2) Method 19, section 4.3, shall be used to determine the daily
geometric average sulfur dioxide emission rate.
(3) An owner or operator may request that compliance with the sulfur
dioxide emissions limit be determined using carbon dioxide measurements
corrected to an equivalent of 7 percent oxygen. The relationship between
oxygen
[[Page 227]]
and carbon dioxide levels for the affected facility shall be established
during the initial compliance test.
(4) The owner or operator of an affected facility shall conduct an
initial compliance test for sulfur dioxide as required under Sec. 60.8.
Compliance with the sulfur dioxide emission limit and percent reduction
is determined by using a CEMS to measure sulfur dioxide and calculating
a 24-hour daily geometric mean emission rate and daily geometric mean
percent reduction using Method 19 sections 4.3 and 5.4, as applicable,
except as provided under paragraph (e)(5) of this section.
(5) For batch MWC's or MWC units that do not operate continuously,
compliance shall be determined using a daily geometric mean of all
hourly average values for the hours during the day that the affected
facility is combusting MSW.
(6) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a CEMS for measuring sulfur dioxide
emissions discharged to the atmosphere and record the output of the
system.
(7) Following the date of the initial compliance test or the date on
which the initial compliance test is required to be completed under
Sec. 60.8, compliance with the sulfur dioxide emission limit or percent
reduction shall be determined based on the geometric mean of the hourly
arithmetic average emission rates during each 24-hour daily period
measured between 12:00 midnight and the following midnight using: CEMS
inlet and outlet data, if compliance is based on a percent reduction; or
CEMS outlet data only if compliance is based on an emission limit.
(8) At a minimum, valid CEMS data shall be obtained for 75 percent
of the hours per day for 75 percent of the days per month the affected
facility is operated and combusting MSW.
(9) The 1-hour arithmetic averages required under paragraph (e)(7)
of this section shall be expressed in parts per million (dry basis) and
used to calculate the 24-hour daily geometric mean emission rates. The
1-hour arithmetic averages shall be calculated using the data points
required under Sec. 60.13(e)(2). At least two data points shall be used
to calculate each 1-hour arithmetic average.
(10) All valid CEMS data shall be used in calculating emission rates
and percent reductions even if the minimum CEMS data requirements of
paragraph (e)(8) of this section are not met.
(11) The procedures under Sec. 60.1 3 shall be followed for
installation, evaluation, and operation of the CEMS.
(12) The CEMS shall be operated according to Performance
Specifications 1, 2, and 3 (appendix B of part 60).
(13) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with Procedure 1 (appendix F of
part 60).
(14) The span value of the CEMS at the inlet to the sulfur dioxide
control device is 125 percent of the maximum estimated hourly potential
sulfur dioxide emissions of the MWC unit, and the span value of the CEMS
at the outlet of the sulfur dioxide control device is 50 percent of the
maximum estimated hourly potential sulfur dioxide emissions of the MWC
unit.
(15) When sulfur dioxide emissions data are not obtained because of
CEMS breakdowns, repairs, calibration checks and zero and span
adjustments, emissions data shall be obtained by using other monitoring
systems as approved by the Administrator or Method 19 to provide as
necessary valid emission data for a minimum of 75 percent of the hours
per day for 75 percent of the days per month the unit is operated and
combusting MSW.
(16) Not operating a sorbent injection system for the sole purpose
of testing in order to demonstrate compliance with the percent reduction
standards for MWC acid gases shall not be considered a physical change
in the method of operation under 40 CFR 52.21, or under regulations
approved pursuant to 40 CFR 51.166 or 40 CFR 51.165 (a) and (b).
(f) The following procedures and test methods shall be used for
determining compliance with the hydrogen chloride limits under Sec.
60.54a:
(1) The percentage reduction in the potential hydrogen chloride
emissions (%PHCl) is computed using the following formula:
[[Page 228]]
[GRAPHIC] [TIFF OMITTED] TC16NO91.003
where:
Ei is the potential hydrogen chloride emission rate.
Eo is the hydrogen chloride emission rate measured at the
outlet of the acid gas control device.
(2) Method 26 or 26A shall be used for determining the hydrogen
chloride emission rate. The minimum sampling time for Method 26 or 26A
shall be 1 hour.
(3) An owner or operator may request that compliance with the
hydrogen chloride emissions limit be determined using carbon dioxide
measurements corrected to an equivalent of 7 percent oxygen. The
relationship between oxygen and carbon dioxide levels for the affected
facility shall be established during the initial compliance test.
(4) The owner or operator of an affected facility shall conduct an
initial compliance test for hydrogen chloride as required under Sec.
60.8.
(5) Following the date of the initial compliance test or the date on
which the initial compliance test is required under Sec. 60.8, the
owner or operator of an affected facility located within a large MWC
plant shall conduct a performance test for hydrogen chloride on an
annual basis (no more than 12 calendar months following the previous
compliance test).
(6) [Reserved]
(7) Not operating a sorbent injection system for the sole purpose of
testing in order to demonstrate compliance with the percent reduction
standards for MWC acid gases shall not be considered a physical change
in the method of operation under 40 CFR 52.21, or under regulations
approved pursuant to 40 CFR 51.166 or 40 CFR 51.165 (a) and (b).
(g) The following procedures and test methods shall be used to
determine compliance with the nitrogen oxides limit under Sec. 60.55a:
(1) Method 19, section 4.1, shall be used for determining the daily
arithmetic average nitrogen oxides emission rate.
(2) An owner or operator may request that compliance with the
nitrogen oxides emissions limit be determined using carbon dioxide
measurements corrected to an equivalent of 7 percent oxygen. The
relationship between oxygen and carbon dioxide levels for the affected
facility shall be established during the initial compliance test.
(3) The owner or operator of an affected facility subject to the
nitrogen oxides limit under Sec. 60.55a shall conduct an initial
compliance test for nitrogen oxides as required under Sec. 60.8.
Compliance with the nitrogen oxides emission standard shall be
determined by using a CEMS for measuring nitrogen oxides and calculating
a 24-hour daily arithmetic average emission rate using Method 19,
section 4.1, except as specified under paragraph (g)(4) of this section.
(4) For batch MWC's or MWC's that do not operate continuously,
compliance shall be determined using a daily arithmetic average of all
hourly average values for the hours during the day that the affected
facility is combusting MSW.
(5) The owner or operator of an affected facility subject to the
nitrogen oxides emissions limit under Sec. 60.55a shall install,
calibrate, maintain, and operate a CEMS for measuring nitrogen oxides
discharged to the atmosphere and record the output of the system.
(6) Following the initial compliance test or the date on which the
initial compliance test is required to be completed under Sec. 60.8,
compliance with the emission limit for nitrogen oxides required under
Sec. 60.55a shall be determined based on the arithmetic average of the
arithmetic average hourly emission rates during each 24-hour daily
period measured between 12:00 midnight and the following midnight using
CEMS data.
(7) At a minimum valid CEMS data shall be obtained for 75 percent of
the hours per day for 75 percent of the days per month the affected
facility is operated and combusting MSW.
(8) The 1-hour arithmetic averages required by paragraph (g)(6) of
this section shall be expressed in parts per million volume (dry basis)
and used to calculate the 24-hour daily arithmetic average emission
rates. The 1-hour arithmetic averages shall be calculated using the data
points required under
[[Page 229]]
Sec. 60.13(b). At least two data points shall be used to calculate each
1-hour arithmetic average.
(9) All valid CEMS data must be used in calculating emission rates
even if the minimum CEMS data requirements of paragraph (g)(7) of this
section are not met.
(10) The procedures under Sec. 60.13 shall be followed for
installation, evaluation, and operation of the CEMS.
(11) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with Procedure 1 (appendix F of
part 60).
(12) When nitrogen oxides emissions data are not obtained because of
CEMS breakdowns, repairs, calibration checks, and zero and span
adjustments, emission data calculations to determine compliance shall be
made using other monitoring systems as approved by the Administrator or
Method 19 to provide as necessary valid emission data for a minimum of
75 percent of the hours per day for 75 percent of the days per month the
unit is operated and combusting MSW.
(h) The following procedures shall be used for determining
compliance with the operating standards under Sec. 60.56a:
(1) Compliance with the carbon monoxide emission limits in Sec.
60.56a(a) shall be determined using a 4-hour block arithmetic average
for all types of affected facilities except mass burn rotary waterwall
MWC's, RDF stokers, and spreader stoker/RDF mixed fuel-fired combustors.
(2) For affected mass burn rotary waterwall MWC's, RDF stokers, and
spreader stoker/RDF mixed fuel-fired combustors, compliance with the
carbon monoxide emission limits in Sec. 60.56a(a) shall be determined
using a 24-hour daily arithmetic average.
(3) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a CEMS for measuring carbon monoxide at
the combustor outlet and record the output of the system.
(4) The 4-hour and 24-hour daily arithmetic averages in paragraphs
(h) (1) and (2) of this section shall be calculated from 1-hour
arithmetic averages expressed in parts per million by volume (dry
basis). The 1-hour arithmetic averages shall be calculated using the
data points generated by the CEMS. At least two data points shall be
used to calculate each 1-hour arithmetic average.
(5) An owner or operator may request that compliance with the carbon
monoxide emission limit be determined using carbon dioxide measurements
corrected to an equivalent of 7 percent oxygen. The relationship between
oxygen and carbon dioxide levels for the affected facility shall be
established during the initial compliance test.
(6) The following procedures shall be used to determine compliance
with load level requirements under Sec. 60.56a(b):
(i) The owner or operator of an affected facility with steam
generation capability shall install, calibrate, maintain, and operate a
steam flow meter or a feedwater flow meter; measure steam or feedwater
flow in kilograms per hour (pounds per hour) on a continuous basis; and
record the output of the monitor. Steam or feedwater flow shall be
calculated in 4-hour block arithmetic averages.
(ii) The method included in ``American Society of Mechanical
Engineers Power Test Codes: Test Code for Steam Generating Units, Power
Test Code 4.1--1964'', Section 4 (incorporated by reference, see Sec.
60.17) shall be used for calculating the steam (or feedwater flow)
required under paragraph (h)(6)(i) of this section. The recommendations
of ``American Society of Mechanical Engineers Interim Supplement 19.5 on
Instruments and Apparatus: Application, Part II of Fluid Meters, 6th
edition (1971),'' chapter 4 (incorporated by reference, see Sec. 60.17)
shall be followed for design, construction, installation, calibration,
and use of nozzles and orifices except as specified in (h)(6)(iii) of
this section.
(iii) Measurement devices such as flow nozzles and orifices are not
required to be recalibrated after they are installed.
(iv) All signal conversion elements associated with steam (or
feedwater flow) measurements must be calibrated according to the
manufacturer's instructions before each dioxin/furan compliance and
performance test, and at least once per year.
[[Page 230]]
(v) The owner or operator of an affected facility without heat
recovery shall:
(A) [Reserved]
(7) To determine compliance with the maximum particulate matter
control device temperature requirements under Sec. 60.56a(c), the owner
or operator of an affected facility shall install, calibrate, maintain,
and operate a device for measuring temperature of the flue gas stream at
the inlet to the final particulate matter control device on a continuous
basis and record the output of the device. Temperature shall be
calculated in 4-hour block arithmetic averages.
(8) Maximum demonstrated MWC unit load shall be determined during
the initial compliance test for dioxins/furans and each subsequent
performance test during which compliance with the dioxin/furan emission
limit under Sec. 60.53a is achieved. Maximum demonstrated MWC unit load
shall be the maximum 4-hour arithmetic average load achieved during the
most recent test during which compliance with the dioxin/furan limit was
achieved.
(9) The maximum demonstrated particulate matter control device
temperature shall be determined during the initial compliance test for
dioxins/furans and each subsequent performance test during which
compliance with the dioxin/furan emission limit under Sec. 60.53a is
achieved. Maximum demonstrated particulate matter control device
temperature shall be the maximum 4-hour arithmetic average temperature
achieved at the final particulate matter control device inlet during the
most recent test during which compliance with the dioxin/furan limit was
achieved.
(10) At a minimum, valid CEMS data for carbon monoxide, steam or
feedwater flow, and particulate matter control device inlet temperature
shall be obtained 75 percent of the hours per day for 75 percent of the
days per month the affected facility is operated and combusting MSW.
(11) All valid data must be used in calculating the parameters
specified under paragraph (h) of this section even if the minimum data
requirements of paragraph (h)(10) of this section are not met.
(12) Quarterly accuracy determinations and daily calibration drift
tests for carbon monoxide CEMS shall be performed in accordance with
Procedure 1 (appendix F).
(i) [Reserved]
(j) The following procedures shall be used for calculating MWC unit
capacity as defined under Sec. 60.51a:
(1) For MWC units capable of combusting MSW continuously for a 24-
hour period, MWC unit capacity, in megagrams per day (tons per day) of
MSW combusted, shall be calculated based on 24 hours of operation at the
maximum design charging rate. The design heating values under paragraph
(j)(4) of this section shall be used in calculating the design charging
rate.
(2) For batch MWC units, MWC unit capacity, in megagrams per day
(tons per day) of MSW combusted, shall be calculated as the maximum
design amount of MSW that can be charged per batch multiplied by the
maximum number of batches that could be processed in a 24-hour period.
The maximum number of batches that could be processed in a 24-hour
period is calculated as 24 hours divided by the design number of hours
required to process one batch of MSW, and may include fractional
batches. \1\ The design heating values under paragraph (j)(4) of this
section shall be used in calculating the MWC unit capacity in megagrams
per day (tons per day) of MSW.
---------------------------------------------------------------------------
\1\ For example, if one batch requires 16 hours, then 24/16, or 1.5
batches, could be combusted in a 24-hour period.
---------------------------------------------------------------------------
(3) [Reserved]
(4) The MWC unit capacity shall be calculated using a design heating
value of 10,500 kilojoules per kilogram (4,500 British thermal units per
pound) for all MSW.
[56 FR 5507, Feb. 11, 1991, as amended at 60 FR 65387, Dec. 19, 1995; 65
FR 61753, Oct. 17, 2000]
Sec. 60.59a Reporting and recordkeeping requirements.
(a) The owner or operator of an affected facility located at an MWC
plant with a capacity greater than 225 megagrams per day (250 tons per
day) shall provide notification of intent to construct and of planned
initial start-
[[Page 231]]
up date and the type(s) of fuels that they plan to combust in the
affected facility. The MWC unit capacity and MWC plant capacity and
supporting capacity calculations shall be provided at the time of the
notification of construction.
(b) The owner or operator of an affected facility located within a
small or large MWC plant and subject to the standards under Sec.
60.52a, Sec. 60.53a, Sec. 60.54a, Sec. 60.55a, Sec. 60.56a, or Sec.
60.57a shall maintain records of the following information for each
affected facility for a period of at least 2 years:
(1) Calendar date.
(2) The emission rates and parameters measured using CEMS as
specified under (b)(2) (i) and (ii) of this section:
(i) The following measurements shall be recorded in computer-
readable format and on paper:
(A) All 6-minute average opacity levels required under Sec.
60.58a(b).
(B) All 1 hour average sulfur dioxide emission rates at the inlet
and outlet of the acid gas control device if compliance is based on a
percent reduction, or at the outlet only if compliance is based on the
outlet emission limit, as specified under Sec. 60.58a(e).
(C) All 1-hour average nitrogen oxides emission rates as specified
under Sec. 60.58a(g).
(D) All 1-hour average carbon monoxide emission rates, MWC unit load
measurements, and particulate matter control device inlet temperatures
as specified under Sec. 60.58a(h).
(ii) The following average rates shall be computed and recorded:
(A) All 24-hour daily geometric average percent reductions in sulfur
dioxide emissions and all 24-hour daily geometric average sulfur dioxide
emission rates as specified under Sec. 60.58a(e).
(B) All 24-hour daily arithmetic average nitrogen oxides emission
rates as specified under Sec. 60.58a(g).
(C) All 4-hour block or 24-hour daily arithmetic average carbon
monoxide emission rates, as applicable, as specified under Sec.
60.58a(h).
(D) All 4-hour block arithmetic average MWC unit load levels and
particulate matter control device inlet temperatures as specified under
Sec. 60.58a(h).
(3) Identification of the operating days when any of the average
emission rates, percent reductions, or operating parameters specified
under paragraph (b)(2)(ii) of this section or the opacity level exceeded
the applicable limits, with reasons for such exceedances as well as a
description of corrective actions taken.
(4) Identification of operating days for which the minimum number of
hours of sulfur dioxide or nitrogen oxides emissions or operational data
(carbon monoxide emissions, unit load, particulate matter control device
temperature) have not been obtained, including reasons for not obtaining
sufficient data and a description of corrective actions taken.
(5) Identification of the times when sulfur dioxide or nitrogen
oxides emission or operational data (carbon monoxide emissions, unit
load, particulate matter control device temperature) have been excluded
from the calculation of average emission rates or parameters and the
reasons for excluding data.
(6) The results of daily sulfur dioxide, nitrogen oxides, and carbon
monoxide CEMS drift tests and accuracy assessments as required under
appendix F, Procedure 1.
(7) The results of all annual performance tests conducted to
determine compliance with the particulate matter, dioxin/furan and
hydrogen chloride limits. For all annual dioxin/furan tests, the maximum
demonstrated MWC unit load and maximum demonstrated particulate matter
control device temperature shall be recorded along with supporting
calculations.
(8)-(15) [Reserved]
(c) Following the initial compliance test as required under
Sec. Sec. 60.8 and 60.58a, the owner or operator of an affected
facility located within a large MWC plant shall submit the initial
compliance test data, the performance evaluation of the CEMS using the
applicable performance specifications in appendix B, and the maximum
demonstrated MWC unit load and maximum demonstrated particulate matter
control device temperature established during the dioxin/furan
compliance test.
(d) [Reserved]
[[Page 232]]
(e)(1) The owner or operator of an affected facility located within
a large MWC plant shall submit annual compliance reports for sulfur
dioxide, nitrogen oxide (if applicable), carbon monoxide, load level,
and particulate matter control device temperature to the Administrator
containing the information recorded under paragraphs (b)(1), (2)(ii),
(4), (5), and (6) of this section for each pollutant or parameter. The
hourly average values recorded under paragraph (b)(2)(i) of this section
are not required to be included in the annual reports. Combustors firing
a mixture of medical waste and other MSW shall also provide the
information under paragraph (b)(15) of this section, as applicable, in
each annual report. The owner or operator of an affected facility must
submit reports semiannually once the affected facility is subject to
permitting requirements under Title V of the Act.
(2) The owner or operator shall submit a semiannual report for any
pollutant or parameter that does not comply with the pollutant or
parameter limits specified in this subpart. Such report shall include
the information recorded under paragraph (b)(3) of this section. For
each of the dates reported, include the sulfur dioxide, nitrogen oxide,
carbon monoxide, load level, and particulate matter control device
temperature data, as applicable, recorded under paragraphs (b)(2)(ii)(A)
through (D) of this section.
(3) Reports shall be postmarked no later than the 30th day following
the end of the annual or semiannual period, as applicable.
(f)(1) The owner or operator of an affected facility located within
a large MWC plant shall submit annual compliance reports, as applicable,
for opacity. The annual report shall list the percent of the affected
facility operating time for the reporting period that the opacity CEMS
was operating and collecting valid data. Once the unit is subject to
permitting requirements under Title V of the Act, the owner or operator
of an affected facility must submit these reports semiannually.
(2) The owner or operator shall submit a semiannual report for all
periods when the 6-minute average levels exceeded the opacity limit
under Sec. 60.52a. The semiannual report shall include all information
recorded under paragraph (b)(3) of this section which pertains to
opacity, and a listing of the 6-minute average opacity levels recorded
under paragraph (b)(2)(i)(A) of this section, which exceeded the opacity
limit.
(3) Reports shall be postmarked no later than the 30th day following
the end of the annual of semiannual period, as applicable.
(g)(1) The owner or operator of an affected facility located within
a large MWC plant shall submit reports to the Administrator of all
annual performance tests for particulate matter, dioxin/furan, and
hydrogen chloride as recorded under paragraph (b)(7) of this section, as
applicable, from the affected facility. For each annual dioxin/furan
compliance test, the maximum demonstrated MWC unit load and maximum
demonstrated particulate matter control device temperature shall be
reported. Such reports shall be submitted when available and in no case
later than the date of required submittal of the annual report specified
under paragraphs (e) and (f) of this section, or within six months of
the date the test was conducted, whichever is earlier.
(2) The owner or operator shall submit a report of test results
which document any particulate matter, dioxin/furan, and hydrogen
chloride levels that were above the applicable pollutant limit. The
report shall include a copy of the test report documenting the emission
levels and shall include the corrective action taken. Such reports shall
be submitted when available and in no case later than the date required
for submittal of any semiannual report required in paragraphs (e) or (f)
of this section, or within six months of the date the test was
conducted, whichever is earlier.
(h) [Reserved]
(i) Records of CEMS data for opacity, sulfur dioxide, nitrogen
oxides, and carbon monoxide, load level data, and particulate matter
control device temperature data shall be maintained for at least 2 years
after date of recordation and be made available for inspection upon
request.
(j) Records showing the names of persons who have completed review
of the operating manual, including the date
[[Page 233]]
of the initial review and all subsequent annual reviews, shall be
maintained for at least 2 years after date of review and be made
available for inspection upon request.
[56 FR 5507, Feb. 11, 1991, as amended at 60 FR 65387, Dec. 19, 1995; 64
FR 7465, Feb. 12, 1999]
Subpart Eb_Standards of Performance for Large Municipal Waste Combustors
for Which Construction is Commenced After September 20, 1994 or for
Which Modification or Reconstruction is Commenced After June 19, 1996
Source: 60 FR 65419, Dec. 19, 1995, unless otherwise noted.
Sec. 60.50b Applicability and delegation of authority.
(a) The affected facility to which this subpart applies is each
municipal waste combustor unit with a combustion capacity greater than
250 tons per day of municipal solid waste for which construction,
modification, or reconstruction is commenced after September 20, 1994.
(b) Any waste combustion unit that is capable of combusting more
than 250 tons per day of municipal solid waste and is subject to a
federally enforceable permit limiting the maximum amount of municipal
solid waste that may be combusted in the unit to less than or equal to
11 tons per day is not subject to this subpart if the owner or operator:
(1) Notifies EPA of an exemption claim;
(2) Provides a copy of the federally enforceable permit that limits
the firing of municipal solid waste to less than 11 tons per day; and
(3) Keeps records of the amount of municipal solid waste fired on a
daily basis.
(c) An affected facility to which this subpart applies is not
subject to subpart E or Ea of this part.
(d) Physical or operational changes made to an existing municipal
waste combustor unit primarily for the purpose of complying with
emission guidelines under subpart Cb are not considered a modification
or reconstruction and do not result in an existing municipal waste
combustor unit becoming subject to this subpart.
(e) A qualifying small power production facility, as defined in
section 3(17)(C) of the Federal Power Act (16 U.S.C. 796(17)(C)), that
burns homogeneous waste (such as automotive tires or used oil, but not
including refuse-derived fuel) for the production of electric energy is
not subject to this subpart if the owner or operator of the facility
notifies EPA of this exemption and provides data documenting that the
facility qualifies for this exemption.
(f) A qualifying cogeneration facility, as defined in section
3(18)(B) of the Federal Power Act (16 U.S.C. 796(18)(B)), that burns
homogeneous waste (such as automotive tires or used oil, but not
including refuse-derived fuel) for the production of electric energy and
steam or forms of useful energy (such as heat) that are used for
industrial, commercial, heating, or cooling purposes, is not subject to
this subpart if the owner or operator of the facility notifies EPA of
this exemption and provides data documenting that the facility qualifies
for this exemption.
(g) Any unit combusting a single-item waste stream of tires is not
subject to this subpart if the owner or operator of the unit:
(1) Notifies EPA of an exemption claim; and
(2) [Reserved]
(3) Provides data documenting that the unit qualifies for this
exemption.
(h) Any unit required to have a permit under section 3005 of the
Solid Waste Disposal Act is not subject to this subpart.
(i) Any materials recovery facility (including primary or secondary
smelters) that combusts waste for the primary purpose of recovering
metals is not subject to this subpart.
(j) Any cofired combustor, as defined under Sec. 60.51b, that meets
the capacity specifications in paragraph (a) of this section is not
subject to this subpart if the owner or operator of the cofired
combustor:
(1) Notifies EPA of an exemption claim;
[[Page 234]]
(2) Provides a copy of the federally enforceable permit (specified
in the definition of cofired combustor in this section); and
(3) Keeps a record on a calendar quarter basis of the weight of
municipal solid waste combusted at the cofired combustor and the weight
of all other fuels combusted at the cofired combustor.
(k) Air curtain incinerators, as defined under Sec. 60.51b, located
at a plant that meet the capacity specifications in paragraph (a) of
this section and that combust a fuel stream composed of 100 percent yard
waste are exempt from all provisions of this subpart except the opacity
limit under Sec. 60.56b, the testing procedures under Sec. 60.58b(l),
and the reporting and recordkeeping provisions under Sec. 60.59b (e)
and (i).
(l) Air curtain incinerators located at plants that meet the
capacity specifications in paragraph (a) of this section combusting
municipal solid waste other than yard waste are subject to all
provisions of this subpart.
(m) Pyrolysis/combustion units that are an integrated part of a
plastics/rubber recycling unit (as defined in Sec. 60.51b) are not
subject to this subpart if the owner or operator of the plastics/rubber
recycling unit keeps records of the weight of plastics, rubber, and/or
rubber tires processed on a calendar quarter basis; the weight of
chemical plant feedstocks and petroleum refinery feedstocks produced and
marketed on a calendar quarter basis; and the name and address of the
purchaser of the feedstocks. The combustion of gasoline, diesel fuel,
jet fuel, fuel oils, residual oil, refinery gas, petroleum coke,
liquified petroleum gas, propane, or butane produced by chemical plants
or petroleum refineries that use feedstocks produced by plastics/rubber
recycling units are not subject to this subpart.
(n) The following authorities are retained by the Administrator of
the U.S. EPA and are not transferred to a State:
(1) Approval of exemption claims in paragraphs (b), (e), (f), (g)
and (j) of this section;
(2) Enforceability under Federal law of all Federally enforceable,
as defined in Sec. 60.51b, limitations and conditions;
(3) Determination of compliance with the siting requirements as
specified in Sec. 60.57b(a);
(4) Acceptance of relationship between carbon monoxide and oxygen as
part of initial and annual performance tests as specified in Sec.
60.58b(b)(7);
(5) Approval of other monitoring systems used to obtain emissions
data when data is not obtained by CEMS as specified in Sec.
60.58b(e)(14), (h)(12), (i)(11), and (n)(14), and (p)(11);
(6) Approval of a site-specific monitoring plan for the continuous
emission monitoring system specified in ``60.58b(n)(13) and (o) of this
section or the continuous automated sampling system specified in Sec.
60.58b(p)(10) and (q) of this section;
(7) Approval of major alternatives to test methods;
(8) Approval of major alternatives to monitoring;
(9) Waiver of recordkeeping; and
(10) Performance test and data reduction waivers under ``608(b).
(o) This subpart shall become effective June 19, 1996.
(p) Cement kilns firing municipal solid waste are not subject to
this subpart.
[60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45120, 45125, Aug. 25,
1997; 71 FR 27335, May 10, 2006]
Sec. 60.51b Definitions.
Administrator means:
(1) For approved and effective State Section 111(d)/129 plans, the
Director of the State air pollution control agency, or employee of the
State air pollution control agency that is delegated the authority to
perform the specified task;
(2) For Federal Section 111(d)/129 plans, the Administrator of the
EPA, an employee of the EPA, the Director of the State air pollution
control agency, or employee of the State air pollution control agency to
whom the authority has been delegated by the Administrator of the EPA to
perform the specified task; and
(3) For NSPS, the Administrator of the EPA, an employee of the EPA,
the Director of the State air pollution control agency, or employee of
the State air pollution control agency to whom the authority has been
delegated by
[[Page 235]]
the Administrator of the EPA to perform the specified task.
Air curtain incinerator means an incinerator that operates by
forcefully projecting a curtain of air across an open chamber or pit in
which burning occurs. Incinerators of this type can be constructed above
or below ground and with or without refractory walls and floor.
Batch municipal waste combustor means a municipal waste combustor
unit designed so that it cannot combust municipal solid waste
continuously 24 hours per day because the design does not allow waste to
be fed to the unit or ash to be removed while combustion is occurring.
Bubbling fluidized bed combustor means a fluidized bed combustor in
which the majority of the bed material remains in a fluidized state in
the primary combustion zone.
Calendar quarter means a consecutive 3-month period (nonoverlapping)
beginning on January 1, April 1, July 1, and October 1.
Calendar year means the period including 365 days starting January 1
and ending on December 31.
Chief facility operator means the person in direct charge and
control of the operation of a municipal waste combustor and who is
responsible for daily onsite supervision, technical direction,
management, and overall performance of the facility.
Circulating fluidized bed combustor means a fluidized bed combustor
in which the majority of the fluidized bed material is carried out of
the primary combustion zone and is transported back to the primary zone
through a recirculation loop.
Clean wood means untreated wood or untreated wood products including
clean untreated lumber, tree stumps (whole or chipped), and tree limbs
(whole or chipped). Clean wood does not include yard waste, which is
defined elsewhere in this section, or construction, renovation, and
demolition wastes (including but not limited to railroad ties and
telephone poles), which are exempt from the definition of municipal
solid waste in this section.
Cofired combustor means a unit combusting municipal solid waste with
nonmunicipal solid waste fuel (e.g., coal, industrial process waste) and
subject to a federally enforceable permit limiting the unit to
combusting a fuel feed stream, 30 percent or less of the weight of which
is comprised, in aggregate, of municipal solid waste as measured on a
calendar quarter basis.
Continuous automated sampling system means the total equipment and
procedures for automated sample collection and sample recovery/analysis
to determine a pollutant concentration or emission rate by collecting a
single or multiple integrated sample(s) of the pollutant (or diluent
gas) for subsequent on-or off-site analysis; integrated sample(s)
collected are representative of the emissions for the sample time as
specified by the applicable requirement.
Continuous emission monitoring system means a monitoring system for
continuously measuring the emissions of a pollutant from an affected
facility.
Dioxin/furan means tetra- through octa- chlorinated dibenzo-p-
dioxins and dibenzofurans.
EPA means the Administrator of the U.S. EPA or employee of the U.S.
EPA who is delegated to perform the specified task.
Federally enforceable means all limitations and conditions that are
enforceable by EPA including the requirements of 40 CFR part 60, 40 CFR
part 61, and 40 CFR part 63, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
First calendar half means the period starting on January 1 and
ending on June 30 in any year.
Four-hour block average or 4-hour block average means the average of
all hourly emission concentrations when the affected facility is
operating and combusting municipal solid waste measured over 4-hour
periods of time from 12:00 midnight to 4 a.m., 4 a.m. to 8 a.m., 8 a.m.
to 12:00 noon, 12:00 noon to 4 p.m., 4 p.m. to 8 p.m., and 8 p.m. to
12:00 midnight.
Mass burn refractory municipal waste combustor means a field-erected
combustor that combusts municipal solid
[[Page 236]]
waste in a refractory wall furnace. Unless otherwise specified, this
includes combustors with a cylindrical rotary refractory wall furnace.
Mass burn rotary waterwall municipal waste combustor means a field-
erected combustor that combusts municipal solid waste in a cylindrical
rotary waterwall furnace or on a tumbling-tile grate.
Mass burn waterwall municipal waste combustor means a field-erected
combustor that combusts municipal solid waste in a waterwall furnace.
Materials separation plan means a plan that identifies both a goal
and an approach to separate certain components of municipal solid waste
for a given service area in order to make the separated materials
available for recycling. A materials separation plan may include
elements such as dropoff facilities, buy-back or deposit-return
incentives, curbside pickup programs, or centralized mechanical
separation systems. A materials separation plan may include different
goals or approaches for different subareas in the service area, and may
include no materials separation activities for certain subareas or, if
warranted, an entire service area.
Maximum demonstrated municipal waste combustor unit load means the
highest 4-hour arithmetic average municipal waste combustor unit load
achieved during four consecutive hours during the most recent dioxin/
furan performance test demonstrating compliance with the applicable
limit for municipal waste combustor organics specified under Sec.
60.52b(c).
Maximum demonstrated particulate matter control device temperature
means the highest 4-hour arithmetic average flue gas temperature
measured at the particulate matter control device inlet during four
consecutive hours during the most recent dioxin/furan performance test
demonstrating compliance with the applicable limit for municipal waste
combustor organics specified under Sec. 60.52b(c).
Modification or modified municipal waste combustor unit means a
municipal waste combustor unit to which changes have been made after
June 19, 1996 if the cumulative cost of the changes, over the life of
the unit, exceed 50 percent of the original cost of construction and
installation of the unit (not including the cost of any land purchased
in connection with such construction or installation) updated to current
costs; or any physical change in the municipal waste combustor unit or
change in the method of operation of the municipal waste combustor unit
increases the amount of any air pollutant emitted by the unit for which
standards have been established under section 129 or section 111.
Increases in the amount of any air pollutant emitted by the municipal
waste combustor unit are determined at 100-percent physical load
capability and downstream of all air pollution control devices, with no
consideration given for load restrictions based on permits or other
nonphysical operational restrictions.
Modular excess-air municipal waste combustor means a combustor that
combusts municipal solid waste and that is not field-erected and has
multiple combustion chambers, all of which are designed to operate at
conditions with combustion air amounts in excess of theoretical air
requirements.
Modular starved-air municipal waste combustor means a combustor that
combusts municipal solid waste and that is not field-erected and has
multiple combustion chambers in which the primary combustion chamber is
designed to operate at substoichiometric conditions.
Municipal solid waste or municipal-type solid waste or MSW means
household, commercial/retail, and/or institutional waste. Household
waste includes material discarded by single and multiple residential
dwellings, hotels, motels, and other similar permanent or temporary
housing establishments or facilities. Commercial/retail waste includes
material discarded by stores, offices, restaurants, warehouses,
nonmanufacturing activities at industrial facilities, and other similar
establishments or facilities. Institutional waste includes material
discarded by schools, nonmedical waste discarded by hospitals, material
discarded by nonmanufacturing activities at prisons and government
facilities, and material discarded by other similar establishments
[[Page 237]]
or facilities. Household, commercial/retail, and institutional waste
does not include used oil; sewage sludge; wood pallets; construction,
renovation, and demolition wastes (which includes but is not limited to
railroad ties and telephone poles); clean wood; industrial process or
manufacturing wastes; medical waste; or motor vehicles (including motor
vehicle parts or vehicle fluff). Household, commercial/retail, and
institutional wastes include:
(1) Yard waste;
(2) Refuse-derived fuel; and
(3) Motor vehicle maintenance materials limited to vehicle batteries
and tires except as specified in Sec. 60.50b(g).
Municipal waste combustor, MWC, or municipal waste combustor unit:
(1) Means any setting or equipment that combusts solid, liquid, or
gasified municipal solid waste including, but not limited to, field-
erected incinerators (with or without heat recovery), modular
incinerators (starved-air or excess-air), boilers (i.e., steam
generating units), furnaces (whether suspension-fired, grate-fired,
mass-fired, air curtain incinerators, or fluidized bed-fired), and
pyrolysis/combustion units. Municipal waste combustors do not include
pyrolysis/combustion units located at a plastics/rubber recycling unit
(as specified in Sec. 60.50b(m)). Municipal waste combustors do not
include cement kilns firing municipal solid waste (as specified in Sec.
60.50b(p)). Municipal waste combustors do not include internal
combustion engines, gas turbines, or other combustion devices that
combust landfill gases collected by landfill gas collection systems.
(2) The boundaries of a municipal solid waste combustor are defined
as follows. The municipal waste combustor unit includes, but is not
limited to, the municipal solid waste fuel feed system, grate system,
flue gas system, bottom ash system, and the combustor water system. The
municipal waste combustor boundary starts at the municipal solid waste
pit or hopper and extends through:
(i) The combustor flue gas system, which ends immediately following
the heat recovery equipment or, if there is no heat recovery equipment,
immediately following the combustion chamber,
(ii) The combustor bottom ash system, which ends at the truck
loading station or similar ash handling equipment that transfer the ash
to final disposal, including all ash handling systems that are connected
to the bottom ash handling system; and
(iii) The combustor water system, which starts at the feed water
pump and ends at the piping exiting the steam drum or superheater.
(3) The municipal waste combustor unit does not include air
pollution control equipment, the stack, water treatment equipment, or
the turbine-generator set.
Municipal waste combustor acid gases means all acid gases emitted in
the exhaust gases from municipal waste combustor units including, but
not limited to, sulfur dioxide and hydrogen chloride gases.
Municipal waste combustor metals means metals and metal compounds
emitted in the exhaust gases from municipal waste combustor units.
Municipal waste combustor organics means organic compounds emitted
in the exhaust gases from municipal waste combustor units and includes
tetra-through octa- chlorinated dibenzo-p-dioxins and dibenzofurans.
Municipal waste combustor plant means one or more affected
facilities (as defined in Sec. 60.50b) at the same location.
Municipal waste combustor unit capacity means the maximum charging
rate of a municipal waste combustor unit expressed in tons per day of
municipal solid waste combusted, calculated according to the procedures
under Sec. 60.58b(j). Section 60.58b(j) includes procedures for
determining municipal waste combustor unit capacity for continuous and
batch feed municipal waste combustors.
Municipal waste combustor unit load means the steam load of the
municipal waste combustor unit measured as specified in Sec.
60.58b(i)(6).
Particulate matter means total particulate matter emitted from
municipal waste combustor units as measured by EPA Reference Method 5
(see Sec. 60.58b(c)).
Plastics/rubber recycling unit means an integrated processing unit
where plastics, rubber, and/or rubber tires are the
[[Page 238]]
only feed materials (incidental contaminants may be included in the feed
materials) and they are processed into a chemical plant feedstock or
petroleum refinery feedstock, where the feedstock is marketed to and
used by a chemical plant or petroleum refinery as input feedstock. The
combined weight of the chemical plant feedstock and petroleum refinery
feedstock produced by the plastics/rubber recycling unit on a calendar
quarter basis shall be more than 70 percent of the combined weight of
the plastics, rubber, and rubber tires processed by the plastics/rubber
recycling unit on a calendar quarter basis. The plastics, rubber, and/or
rubber tire feed materials to the plastics/rubber recycling unit may
originate from the separation or diversion of plastics, rubber, or
rubber tires from MSW or industrial solid waste, and may include
manufacturing scraps, trimmings, and off-specification plastics, rubber,
and rubber tire discards. The plastics, rubber, and rubber tire feed
materials to the plastics/rubber recycling unit may contain incidental
contaminants (e.g., paper labels on plastic bottles, metal rings on
plastic bottle caps, etc.).
Potential hydrogen chloride emission concentration means the
hydrogen chloride emission concentration that would occur from
combustion of municipal solid waste in the absence of any emission
controls for municipal waste combustor acid gases.
Potential mercury emission concentration means the mercury emission
concentration that would occur from combustion of municipal solid waste
in the absence of any mercury emissions control.
Potential sulfur dioxide emissions means the sulfur dioxide emission
concentration that would occur from combustion of municipal solid waste
in the absence of any emission controls for municipal waste combustor
acid gases.
Pulverized coal/refuse-derived fuel mixed fuel-fired combustor means
a combustor that fires coal and refuse-derived fuel simultaneously, in
which pulverized coal is introduced into an air stream that carries the
coal to the combustion chamber of the unit where it is fired in
suspension. This includes both conventional pulverized coal and
micropulverized coal.
Pyrolysis/combustion unit means a unit that produces gases, liquids,
or solids through the heating of municipal solid waste, and the gases,
liquids, or solids produced are combusted and emissions vented to the
atmosphere.
Reconstruction means rebuilding a municipal waste combustor unit for
which the reconstruction commenced after June 19, 1996, and the
cumulative costs of the construction over the life of the unit exceed 50
percent of the original cost of construction and installation of the
unit (not including any cost of land purchased in connection with such
construction or installation) updated to current costs (current
dollars).
Refractory unit or refractory wall furnace means a combustion unit
having no energy recovery (e.g., via a waterwall) in the furnace (i.e.,
radiant heat transfer section) of the combustor.
Refuse-derived fuel means a type of municipal solid waste produced
by processing municipal solid waste through shredding and size
classification. This includes all classes of refuse-derived fuel
including low-density fluff refuse-derived fuel through densified
refuse-derived fuel and pelletized refuse-derived fuel.
Refuse-derived fuel stoker means a steam generating unit that
combusts refuse-derived fuel in a semisuspension firing mode using air-
fed distributors.
Same location means the same or contiguous property that is under
common ownership or control including properties that are separated only
by a street, road, highway, or other public right-of-way. Common
ownership or control includes properties that are owned, leased, or
operated by the same entity, parent entity, subsidiary, subdivision, or
any combination thereof including any municipality or other governmental
unit, or any quasi-governmental authority (e.g., a public utility
district or regional waste disposal authority).
Second calendar half means the period starting July 1 and ending on
December 31 in any year.
Shift supervisor means the person who is in direct charge and
control of the
[[Page 239]]
operation of a municipal waste combustor and who is responsible for
onsite supervision, technical direction, management, and overall
performance of the facility during an assigned shift.
Spreader stoker coal/refuse-derived fuel mixed fuel-fired combustor
means a combustor that fires coal and refuse-derived fuel
simultaneously, in which coal is introduced to the combustion zone by a
mechanism that throws the fuel onto a grate from above. Combustion takes
place both in suspension and on the grate.
Standard conditions means a temperature of 20 [deg]C and a pressure
of 101.3 kilopascals.
Total mass dioxin/furan or total mass means the total mass of tetra-
through octa- chlorinated dibenzo-p-dioxins and dibenzofurans, as
determined using EPA Reference Method 23 and the procedures specified
under Sec. 60.58b(g).
Tumbling-tile means a grate tile hinged at one end and attached to a
ram at the other end. When the ram extends, the grate tile rotates
around the hinged end.
Twenty-four hour daily average or 24-hour daily average means either
the arithmetic mean or geometric mean (as specified) of all hourly
emission concentrations when the affected facility is operating and
combusting municipal solid waste measured over a 24-hour period between
12:00 midnight and the following midnight.
Untreated lumber means wood or wood products that have been cut or
shaped and include wet, air-dried, and kiln-dried wood products.
Untreated lumber does not include wood products that have been painted,
pigment-stained, or ``pressure-treated.'' Pressure-treating compounds
include, but are not limited to, chromate copper arsenate,
pentachlorophenol, and creosote.
Waterwall furnace means a combustion unit having energy (heat)
recovery in the furnace (i.e., radiant heat transfer section) of the
combustor.
Yard waste means grass, grass clippings, bushes, shrubs, and
clippings from bushes and shrubs that are generated by residential,
commercial/retail, institutional, and/or industrial sources as part of
maintenance activities associated with yards or other private or public
lands. Yard waste does not include construction, renovation, and
demolition wastes, which are exempt from the definition of municipal
solid waste in this section. Yard waste does not include clean wood,
which is exempt from the definition of municipal solid waste in this
section.
[60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45121, 45126, Aug. 25,
1997; 66 FR 36476, July 12, 2001; 71 FR 27335, May 10, 2006]
Sec. 60.52b Standards for municipal waste combustor metals, acid gases,
organics, and nitrogen oxides.
(a) The limits for municipal waste combustor metals are specified in
paragraphs (a)(1) through (a)(5) of this section.
(1) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility shall cause
to be discharged into the atmosphere from that affected facility any
gases that contain particulate matter in excess of the limits specified
in paragraph (a)(1)(i) or (a)(1)(ii) of this section.
(i) For affected facilities that commenced construction,
modification, or reconstruction after September 20, 1994, and on or
before December 19, 2005, the emission limit is 24 milligrams per dry
standard cubic meter, corrected to 7 percent oxygen.
(ii) For affected facilities that commenced construction,
modification, or reconstruction after December 19, 2005, the emission
limit is 20 milligrams per dry standard cubic meter, corrected to 7
percent oxygen.
(2) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility shall cause
to be discharged into the atmosphere from that affected facility any
gases that exhibit greater than 10 percent opacity (6-minute average).
(3) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility shall cause
to be discharged into
[[Page 240]]
the atmosphere from that affected facility any gases that contain
cadmium in excess of the limits specified in paragraph (a)(3)(i) or
(a)(3)(ii) of this section.
(i) For affected facilities that commenced construction,
modification, or reconstruction after September 20, 1994, and on or
before December 19, 2005, the emission limit is 20 micrograms per dry
standard cubic meter, corrected to 7 percent oxygen.
(ii) For affected facilities that commenced construction,
modification, or reconstruction after December 19, 2005, the emission
limit is 10 micrograms per dry standard cubic meter, corrected to 7
percent oxygen.
(4) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility shall cause
to be discharged into the atmosphere from the affected facility any
gases that contain lead in excess of the limits specified in paragraph
(a)(4)(i) or (a)(4)(ii) of this section.
(i) For affected facilities that commenced construction,
modification, or reconstruction after September 20, 1994, and on or
before December 19, 2005, the emission limit is 200 micrograms per dry
standard cubic meter, corrected to 7 percent oxygen.
(ii) For affected facilities that commenced construction,
modification, or reconstruction after December 19, 2005, the emission
limit is 140 micrograms per dry standard cubic meter, corrected to 7
percent oxygen.
(5) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility shall cause
to be discharged into the atmosphere from the affected facility any
gases that contain mercury in excess of the limits specified in
paragraph (a)(5)(i) or (a)(5)(ii) of this section.
(i) For affected facilities that commenced construction,
modification, or reconstruction after September 20, 1994 and on or
before December 19, 2005, the emission limit is 80 micrograms per dry
standard cubic meter or 15 percent of the potential mercury emission
concentration (85-percent reduction by weight), corrected to 7 percent
oxygen, whichever is less stringent.
(ii) For affected facilities that commenced construction,
modification, or reconstruction after December 19, 2005, the emission
limit is 50 micrograms per dry standard cubic meter, or 15 percent of
the potential mercury emission concentration (85-percent reduction by
weight), corrected to 7 percent oxygen, whichever is less stringent.
(b) The limits for municipal waste combustor acid gases are
specified in paragraphs (b)(1) and (b)(2) of this section.
(1) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility shall cause
to be discharged into the atmosphere from that affected facility any
gases that contain sulfur dioxide in excess of 30 parts per million by
volume or 20 percent of the potential sulfur dioxide emission
concentration (80-percent reduction by weight or volume), corrected to 7
percent oxygen (dry basis), whichever is less stringent. The averaging
time is specified under Sec. 60.58b(e).
(2) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility shall cause
to be discharged into the atmosphere from that affected facility any
gases that contain hydrogen chloride in excess of 25 parts per million
by volume or 5 percent of the potential hydrogen chloride emission
concentration (95-percent reduction by weight or volume), corrected to 7
percent oxygen (dry basis), whichever is less stringent.
(c) The limits for municipal waste combustor organics are specified
in paragraphs (c)(1) and (c)(2) of this section.
(1) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility for which
construction, modification or reconstruction commences on
[[Page 241]]
or before November 20, 1997 shall cause to be discharged into the
atmosphere from that affected facility any gases that contain dioxin/
furan emissions that exceed 30 nanograms per dry standard cubic meter
(total mass), corrected to 7 percent oxygen, for the first 3 years
following the date of initial startup. After the first 3 years following
the date of initial startup, no owner or operator shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain dioxin/furan total mass emissions that exceed 13 nanograms
per dry standard cubic meter (total mass), corrected to 7 percent
oxygen.
(2) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility for which
construction, modification, or reconstruction commences after November
20, 1997 shall cause to be discharged into the atmosphere from that
affected facility any gases that contain dioxin/furan total mass
emissions that exceed 13 nanograms per dry standard cubic meter (total
mass), corrected to 7 percent oxygen.
(d) The limits for nitrogen oxides are specified in paragraphs
(d)(1) and (d)(2) of this section.
(1) During the first year of operation after the date on which the
initial performance test is completed or is required to be completed
under Sec. 60.8 of subpart A of this part, no owner or operator of an
affected facility shall cause to be discharged into the atmosphere from
that affected facility any gases that contain nitrogen oxides in excess
of 180 parts per million by volume, corrected to 7 percent oxygen (dry
basis). The averaging time is specified under Sec. 60.58b(h).
(2) After the first year of operation following the date on which
the initial performance test is completed or is required to be completed
under Sec. 60.8 of subpart A of this part, no owner or operator of an
affected facility shall cause to be discharged into the atmosphere from
that affected facility any gases that contain nitrogen oxides in excess
of 150 parts per million by volume, corrected to 7 percent oxygen (dry
basis). The averaging time is specified under Sec. 60.58b(h).
[60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45121, 45126, Aug. 25,
1997; 71 FR 27336, May 10, 2006]
Sec. 60.53b Standards for municipal waste combustor operating practices.
(a) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility shall cause
to be discharged into the atmosphere from that affected facility any
gases that contain carbon monoxide in excess of the emission limits
specified in table 1 of this subpart.
Table 1--Municipal Waste Combustor Operating Standards
------------------------------------------------------------------------
Carbon monoxide
emission limit
Municipal waste combustor technology (parts per Averaging time
million by (hours) \b\
volume) \a\
------------------------------------------------------------------------
Mass burn waterwall................. 100 4
Mass burn refractory................ 100 4
Mass burn rotary waterwall.......... 100 24
Modular starved air................. 50 4
Modular excess air.................. 50 4
Refuse-derived fuel stoker.......... 150 24
Bubbling fluidized bed combustor.... 100 4
Circulating fluidized bed combustor. 100 4
Pulverized coal/refuse-derived fuel 150 4
mixed fuel-fired combustor.........
Spreader stoker coal/refuse-derived 150 24
fuel mixed fuel-fired combustor....
------------------------------------------------------------------------
\a\ Measured at the combustor outlet in conjunction with a measurement
of oxygen concentration, corrected to 7 percent oxygen (dry basis).
The averaging times are specified in greater detail in Sec.
60.58b(i).
\b\ Averaging times are 4-hour or 24-hour block averages.
[[Page 242]]
(b) No owner or operator of an affected facility shall cause such
facility to operate at a load level greater than 110 percent of the
maximum demonstrated municipal waste combustor unit load as defined in
Sec. 60.51b, except as specified in paragraphs (b)(1) and (b)(2) of
this section. The averaging time is specified under Sec. 60.58b(i).
(1) During the annual dioxin/furan or mercury performance test and
the 2 weeks preceding the annual dioxin/furan or mercury performance
test, no municipal waste combustor unit load limit is applicable if the
provisions of paragraph (b)(2) of this section are met.
(2) The municipal waste combustor unit load limit may be waived in
writing by the Administrator for the purpose of evaluating system
performance, testing new technology or control technologies, diagnostic
testing, or related activities for the purpose of improving facility
performance or advancing the state-of-the-art for controlling facility
emissions. The municipal waste combustor unit load limit continues to
apply, and remains enforceable, until and unless the Administrator
grants the waiver.
(c) No owner or operator of an affected facility shall cause such
facility to operate at a temperature, measured at the particulate matter
control device inlet, exceeding 17 [deg]C above the maximum demonstrated
particulate matter control device temperature as defined in Sec.
60.51b, except as specified in paragraphs (c)(1) and (c)(2) of this
section. The averaging time is specified under Sec. 60.58b(i). The
requirements specified in this paragraph apply to each particulate
matter control device utilized at the affected facility.
(1) During the annual dioxin/furan or mercury performance test and
the 2 weeks preceding the annual dioxin/furan or mercury performance
test, no particulate matter control device temperature limitations are
applicable if the provisions of paragraph (b)(2) of this section are
met.
(2) The particulate matter control device temperature limits may be
waived in writing by the Administrator for the purpose of evaluating
system performance, testing new technology or control technologies,
diagnostic testing, or related activities for the purpose of improving
facility performance or advancing the state-of-the-art for controlling
facility emissions. The temperature limits continue to apply, and remain
enforceable, until and unless the Administrator grants the waiver.
(d) Paragraph (m)(2) of Sec. 60.58b addresses treatment of
activated carbon injection rate during dioxin/furan or mercury testing.
[60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997;
71 FR 27336, May 10, 2006]
Sec. 60.54b Standards for municipal waste combustor operator training
and certification.
(a) No later than the date 6 months after the date of startup of an
affected facility or on December 19, 1996, whichever is later, each
chief facility operator and shift supervisor shall obtain and maintain a
current provisional operator certification from either the American
Society of Mechanical Engineers [QRO-1-1994 (incorporated by reference--
see Sec. 60.17 of subpart A of this part)] or a State certification
program.
(b) Not later than the date 6 months after the date of startup of an
affected facility or on December 19, 1996, whichever is later, each
chief facility operator and shift supervisor shall have completed full
certification or shall have scheduled a full certification exam with
either the American Society of Mechanical Engineers [QRO-1-1994
(incorporated by reference--see Sec. 60.17 of subpart A of this part)]
or a State certification program.
(c) No owner or operator of an affected facility shall allow the
facility to be operated at any time unless one of the following persons
is on duty and at the affected facility: A fully certified chief
facility operator, a provisionally certified chief facility operator who
is scheduled to take the full certification exam according to the
schedule specified in paragraph (b) of this section, a fully certified
shift supervisor, or a provisionally certified shift supervisor who is
scheduled to take the full certification exam according to the schedule
specified in paragraph (b) of this section.
(1) The requirement specified in paragraph (c) of this section shall
take effect 6 months after the date of startup
[[Page 243]]
of the affected facility or on December 19, 1996, whichever is later.
(2) If both the certified chief facility operator and certified
shift supervisor are unavailable, a provisionally certified control room
operator on site at the municipal waste combustion unit may fulfill the
certified operator requirement. Depending on the length of time that a
certified chief facility operator and certified shift supervisor are
away, the owner or operator of the affected facility must meet one of
three criteria:
(i) When the certified chief facility operator and certified shift
supervisor are both off site for 12 hours or less, and no other
certified operator is on site, the provisionally certified control room
operator may perform the duties of the certified chief facility operator
or certified shift supervisor.
(ii) When the certified chief facility operator and certified shift
supervisor are off site for more than 12 hours, but for two weeks or
less, and no other certified operator is on site, the provisionally
certified control room operator may perform the duties of the certified
chief facility operator or certified shift supervisor without notice to,
or approval by, the Administrator. However, the owner or operator of the
affected facility must record the period when the certified chief
facility operator and certified shift supervisor are off site and
include that information in the annual report as specified under Sec.
60.59b(g)(5).
(iii) When the certified chief facility operator and certified shift
supervisor are off site for more than two weeks, and no other certified
operator is on site, the provisionally certified control room operator
may perform the duties of the certified chief facility operator or
certified shift supervisor without approval by the Administrator.
However, the owner or operator of the affected facility must take two
actions:
(A) Notify the Administrator in writing. In the notice, state what
caused the absence and what actions are being taken by the owner or
operator of the facility to ensure that a certified chief facility
operator or certified shift supervisor is on site as expeditiously as
practicable.
(B) Submit a status report and corrective action summary to the
Administrator every four weeks following the initial notification. If
the Administrator provides notice that the status report or corrective
action summary is disapproved, the municipal waste combustion unit may
continue operation for 90 days, but then must cease operation. If
corrective actions are taken in the 90-day period such that the
Administrator withdraws the disapproval, municipal waste combustion unit
operation may continue.
(3) A provisionally certified operator who is newly promoted or
recently transferred to a shift supervisor position or a chief facility
operator position at the municipal waste combustion unit may perform the
duties of the certified chief facility operator or certified shift
supervisor without notice to, or approval by, the Administrator for up
to six months before taking the ASME QRO certification exam.
(d) All chief facility operators, shift supervisors, and control
room operators at affected facilities must complete the EPA or State
municipal waste combustor operator training course no later than the
date 6 months after the date of startup of the affected facility or by
December 19, 1996, whichever is later.
(e) The owner or operator of an affected facility shall develop and
update on a yearly basis a site-specific operating manual that shall, at
a minimum, address the elements of municipal waste combustor unit
operation specified in paragraphs (e)(1) through (e)(11) of this
section.
(1) A summary of the applicable standards under this subpart;
(2) A description of basic combustion theory applicable to a
municipal waste combustor unit;
(3) Procedures for receiving, handling, and feeding municipal solid
waste;
(4) Municipal waste combustor unit startup, shutdown, and
malfunction procedures;
(5) Procedures for maintaining proper combustion air supply levels;
(6) Procedures for operating the municipal waste combustor unit
within the standards established under this subpart;
[[Page 244]]
(7) Procedures for responding to periodic upset or off-specification
conditions;
(8) Procedures for minimizing particulate matter carryover;
(9) Procedures for handling ash;
(10) Procedures for monitoring municipal waste combustor unit
emissions; and
(11) Reporting and recordkeeping procedures.
(f) The owner or operator of an affected facility shall establish a
training program to review the operating manual according to the
schedule specified in paragraphs (f)(1) and (f)(2) of this section with
each person who has responsibilities affecting the operation of an
affected facility including, but not limited to, chief facility
operators, shift supervisors, control room operators, ash handlers,
maintenance personnel, and crane/load handlers.
(1) Each person specified in paragraph (f) of this section shall
undergo initial training no later than the date specified in paragraph
(f)(1)(i), (f)(1)(ii), or (f)(1)(iii) of this section whichever is
later.
(i) The date 6 months after the date of startup of the affected
facility;
(ii) The date prior to the day the person assumes responsibilities
affecting municipal waste combustor unit operation; or
(iii) December 19, 1996.
(2) Annually, following the initial review required by paragraph
(f)(1) of this section.
(g) The operating manual required by paragraph (e) of this section
shall be kept in a readily accessible location for all persons required
to undergo training under paragraph (f) of this section. The operating
manual and records of training shall be available for inspection by the
EPA or its delegated enforcement agency upon request.
[60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997;
71 FR 27337, May 10, 2006]
Sec. 60.55b Standards for municipal waste combustor fugitive ash
emissions.
(a) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, no owner or operator of an affected facility shall cause
to be discharged to the atmosphere visible emissions of combustion ash
from an ash conveying system (including conveyor transfer points) in
excess of 5 percent of the observation period (i.e., 9 minutes per 3-
hour period), as determined by EPA Reference Method 22 observations as
specified in Sec. 60.58b(k), except as provided in paragraphs (b) and
(c) of this section.
(b) The emission limit specified in paragraph (a) of this section
does not cover visible emissions discharged inside buildings or
enclosures of ash conveying systems; however, the emission limit
specified in paragraph (a) of this section does cover visible emissions
discharged to the atmosphere from buildings or enclosures of ash
conveying systems.
(c) The provisions specified in paragraph (a) of this section do not
apply during maintenance and repair of ash conveying systems.
[60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997]
Sec. 60.56b Standards for air curtain incinerators.
On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, the owner or operator of an air curtain incinerator with
the capacity to combust greater than 250 tons per day of municipal solid
waste and that combusts a fuel feed stream composed of 100 percent yard
waste and no other municipal solid waste materials shall at no time
cause to be discharged into the atmosphere from that incinerator any
gases that exhibit greater than 10-percent opacity (6-minute average),
except that an opacity level of up to 35 percent (6-minute average) is
permitted during startup periods during the first 30 minutes of
operation of the unit.
[60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997]
Sec. 60.57b Siting requirements.
(a) The owner or operator of an affected facility shall prepare a
materials separation plan, as defined in Sec. 60.51b, for the affected
facility and its
[[Page 245]]
service area, and shall comply with the requirements specified in
paragraphs (a)(1) through (a)(10) of this section. The initial
application is defined as representing a good faith submittal as
determined by EPA.
(1) The owner or operator shall prepare a preliminary draft
materials separation plan and shall make the plan available to the
public as specified in paragraphs (a)(1)(i) and (a)(1)(ii) of this
section.
(i) The owner or operator shall distribute the preliminary draft
materials separation plan to the principal public libraries in the area
where the affected facility is to be constructed.
(ii) The owner or operator shall publish a notification of a public
meeting in the principal newspaper(s) serving the area where the
affected facility is to be constructed and where the waste treated by
the affected facility will primarily be collected. As a minimum, the
notification shall include the information specified in paragraphs
(a)(1)(ii)(A) through (a)(1)(ii)(D) of this section.
(A) The date, time, and location of the public meeting.
(B) The location of the public libraries where the preliminary draft
materials separation plan may be found, including normal business hours
of the libraries.
(C) An agenda of the issues to be discussed at the public meeting.
(D) The dates that the public comment period on the preliminary
draft materials separation plan begins and ends.
(2) The owner or operator shall conduct a public meeting, accept
comments on the preliminary draft materials separation plan, and comply
with the requirements specified in paragraphs (a)(2)(i) through
(a)(2)(iv) of this section.
(i) The public meeting shall be conducted in the county where the
affected facility is to be located.
(ii) The public meeting shall be scheduled to occur 30 days or more
after making the preliminary draft materials separation plan available
to the public as specified under paragraph (a)(1) of this section.
(iii) Suggested issues to be addressed at the public meeting are
listed in paragraphs (a)(2)(iii)(A) through (a)(2)(iii)(H) of this
section.
(A) The expected size of the service area for the affected facility.
(B) The amount of waste generation anticipated for the service area.
(C) The types and estimated amounts of materials proposed for
separation.
(D) The methods proposed for materials separation.
(E) The amount of residual waste to be disposed.
(F) Alternate disposal methods for handling the residual waste.
(G) Identification of the location(s) where responses to public
comment on the preliminary draft materials separation plan will be
available for inspection, as specified in paragraphs (a)(3) and (a)(4)
of this section.
(H) Identification of the locations where the final draft materials
separation plan will be available for inspection, as specified in
paragraph (a)(7).
(iv) Nothing in this section shall preclude an owner or operator
from combining this public meeting with any other public meeting
required as part of any other Federal, State, or local permit review
process except the public meeting required under paragraph (b)(4) of
this section.
(3) Following the public meeting required by paragraph (a)(2) of
this section, the owner or operator shall prepare responses to the
comments received at the public meeting.
(4) The owner or operator shall make the document summarizing
responses to public comments available to the public (including
distribution to the principal public libraries used to announce the
meeting) in the service area where the affected facility is to be
located.
(5) The owner or operator shall prepare a final draft materials
separation plan for the affected facility considering the public
comments received at the public meeting.
(6) As required under Sec. 60.59b(a), the owner or operator shall
submit to EPA a copy of the notification of the public meeting, a
transcript of the public meeting, the document summarizing responses to
public comments, and copies of both the preliminary and final draft
materials separation plans on or
[[Page 246]]
before the time the facility's application for a construction permit is
submitted under 40 CFR part 51, subpart I, or part 52, as applicable.
(7) As part of the distribution of the siting analysis required
under paragraph (b)(3) of this section, the owner or operator shall make
the final draft materials separation plan required under paragraph
(a)(5) of this section available to the public, as specified in
paragraph (b)(3) of this section.
(8) As part of the public meeting for review of the siting analysis
required under paragraph (b)(4) of this section, the owner or operator
shall address questions concerning the final draft materials separation
plan required by paragraph (a)(5) of this section including discussion
of how the final draft materials separation plan has changed from the
preliminary draft materials separation plan that was discussed at the
first public meeting required by paragraph (a)(2) of this section.
(9) If the owner or operator receives any comments on the final
draft materials separation plan during the public meeting required in
paragraph (b)(4) of this section, the owner or operator shall respond to
those comments in the document prepared in accordance with paragraph
(b)(5) of this section.
(10) The owner or operator shall prepare a final materials
separation plan and shall submit, as required under Sec.
60.59b(b)(5)(ii), the final materials separation plan as part of the
initial notification of construction.
(b) The owner or operator of an affected facility for which the
initial application for a construction permit under 40 CFR part 51,
subpart I, or part 52, as applicable, is submitted after December 19,
1995 shall prepare a siting analysis in accordance with paragraphs
(b)(1) and (b)(2) of this section and shall comply with the requirements
specified in paragraphs (b)(3) through (b)(7) of this section.
(1) The siting analysis shall be an analysis of the impact of the
affected facility on ambient air quality, visibility, soils, and
vegetation.
(2) The analysis shall consider air pollution control alternatives
that minimize, on a site-specific basis, to the maximum extent
practicable, potential risks to the public health or the environment.
(3) The owner or operator shall make the siting analysis and final
draft materials separation plan required by paragraph (a)(5) of this
section available to the public as specified in paragraphs (b)(3)(i) and
(b)(3)(ii) of this section.
(i) The owner or operator shall distribute the siting analysis and
final draft materials separation plan to the principal public libraries
in the area where the affected facility is to be constructed.
(ii) The owner or operator shall publish a notification of a public
meeting in the principal newspaper(s) serving the area where the
affected facility is to be constructed and where the waste treated by
the affected facility will primarily be collected. As a minimum, the
notification shall include the information specified in paragraphs
(b)(3)(ii)(A) through (b)(3)(ii)(D) of this section.
(A) The date, time, and location of the public meeting.
(B) The location of the public libraries where the siting analyses
and final draft materials separation plan may be found, including normal
business hours.
(C) An agenda of the issues to be discussed at the public meeting.
(D) The dates that the public comment period on the siting analyses
and final draft materials separation plan begins and ends.
(4) The owner or operator shall conduct a public meeting and accept
comments on the siting analysis and the final draft materials separation
plan required under paragraph (a)(5) of this section. The public meeting
shall be conducted in the county where the affected facility is to be
located and shall be scheduled to occur 30 days or more after making the
siting analysis available to the public as specified under paragraph
(b)(3) of this section.
(5) The owner or operator shall prepare responses to the comments on
the siting analysis and the final draft materials separation plan that
are received at the public meeting.
(6) The owner or operator shall make the document summarizing
responses to public comments available to the
[[Page 247]]
public (including distribution to all public libraries) in the service
area where the affected facility is to be located.
(7) As required under Sec. 60.59b(b)(5), the owner or operator
shall submit a copy of the notification of the public meeting, a
transcript of the public meeting, the document summarizing responses to
public comments, and the siting analysis as part of the initial
notification of construction.
(c) The owner or operator of an affected facility for which
construction is commenced after September 20, 1994 shall prepare a
siting analysis in accordance with 40 CFR part 51, subpart I, or part
52, as applicable, and shall submit the siting analysis as part of the
initial notification of construction. Affected facilities subject to
paragraphs (a) and (b) of this section are not subject to this
paragraph.
[60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997;
71 FR 27337, May 10, 2006]
Sec. 60.58b Compliance and performance testing.
(a) The provisions for startup, shutdown, and malfunction are
provided in paragraphs (a)(1) and (a)(2) of this section.
(1) Except as provided by Sec. 60.56b, the standards under this
subpart apply at all times except during periods of startup, shutdown,
and malfunction. Duration of startup, shutdown, or malfunction periods
are limited to 3 hours per occurrence, except as provided in paragraph
(a)(1)(iii) of this section. During periods of startup, shutdown, or
malfunction, monitoring data shall be dismissed or excluded from
compliance calculations, but shall be recorded and reported in
accordance with the provisions of 40 CFR 60.59b(d)(7).
(i) The startup period commences when the affected facility begins
the continuous burning of municipal solid waste and does not include any
warmup period when the affected facility is combusting fossil fuel or
other nonmunicipal solid waste fuel, and no municipal solid waste is
being fed to the combustor.
(ii) Continuous burning is the continuous, semicontinuous, or batch
feeding of municipal solid waste for purposes of waste disposal, energy
production, or providing heat to the combustion system in preparation
for waste disposal or energy production. The use of municipal solid
waste solely to provide thermal protection of the grate or hearth during
the startup period when municipal solid waste is not being fed to the
grate is not considered to be continuous burning.
(iii) For the purpose of compliance with the carbon monoxide
emission limits in Sec. 60.53b(a), if a loss of boiler water level
control (e.g., boiler waterwall tube failure) or a loss of combustion
air control (e.g., loss of combustion air fan, induced draft fan,
combustion grate bar failure) is determined to be a malfunction, the
duration of the malfunction period is limited to 15 hours per
occurrence. During such periods of malfunction, monitoring data shall be
dismissed or excluded from compliance calculations, but shall be
recorded and reported in accordance with the provisions of Sec.
60.59b(d)(7).
(2) The opacity limits for air curtain incinerators specified in
Sec. 60.56b apply at all times as specified under Sec. 60.56b except
during periods of malfunction. Duration of malfunction periods are
limited to 3 hours per occurrence.
(b) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a continuous emission monitoring system
for measuring the oxygen or carbon dioxide content of the flue gas at
each location where carbon monoxide, sulfur dioxide, nitrogen oxides
emissions, or particulate matter (if the owner or operator elects to
continuously monitor emissions under paragraph (n) of this section) are
monitored and record the output of the system and shall comply with the
test procedures and test methods specified in paragraphs (b)(1) through
(b)(8) of this section.
(1) The span value of the oxygen (or 20 percent carbon dioxide)
monitor shall be 25 percent oxygen (or 20 percent carbon dioxide).
(2) The monitor shall be installed, evaluated, and operated in
accordance with Sec. 60.13 of subpart A of this part.
(3) The initial performance evaluation shall be completed no later
than
[[Page 248]]
180 days after the date of initial startup of the affected facility, as
specified under Sec. 60.8 of subpart A of this part.
(4) The monitor shall conform to Performance Specification 3 in
appendix B of this part except for section 2.3 (relative accuracy
requirement).
(5) The quality assurance procedures of appendix F of this part
except for section 5.1.1 (relative accuracy test audit) shall apply to
the monitor.
(6) If carbon dioxide is selected for use in diluent corrections,
the relationship between oxygen and carbon dioxide levels shall be
established during the initial performance test according to the
procedures and methods specified in paragraphs (b)(6)(i) through
(b)(6)(iv) of this section. This relationship may be reestablished
during performance compliance tests.
(i) The fuel factor equation in Method 3B shall be used to determine
the relationship between oxygen and carbon dioxide at a sampling
location. Method 3, 3A, or 3B, or as an alternative ASME PTC-19-10-
1981--part10, as applicable, shall be used to determine the oxygen
concentration at the same location as the carbon dioxide monitor.
(ii) Samples shall be taken for at least 30 minutes in each hour.
(iii) Each sample shall represent a 1-hour average.
(iv) A minimum of three runs shall be performed.
(7) The relationship between carbon dioxide and oxygen
concentrations that is established in accordance with paragraph (b)(6)
of this section shall be submitted to EPA as part of the initial
performance test report and, if applicable, as part of the annual test
report if the relationship is reestablished during the annual
performance test.
(8) During a loss of boiler water level control or loss of
combustion air control malfunction period as specified in paragraph
(a)(1)(iii) of this section, a diluent cap of 14 percent for oxygen or 5
percent for carbon dioxide may be used in the emissions calculations for
sulfur dioxide and nitrogen oxides.
(c) Except as provided in paragraph (c)(10) of this section, the
procedures and test methods specified in paragraphs (c)(1) through
(c)(11) of this section shall be used to determine compliance with the
emission limits for particulate matter and opacity under Sec.
60.52b(a)(1) and (a)(2).
(1) The EPA Reference Method 1 shall be used to select sampling site
and number of traverse points.
(2) The EPA Reference Method 3, 3A or 3B, or as an alternative ASME
PTC-19-10-1981--part10, as applicable, shall be used for gas analysis.
(3) EPA Reference Method 5 shall be used for determining compliance
with the particulate matter emission limit. The minimum sample volume
shall be 1.7 cubic meters. The probe and filter holder heating systems
in the sample train shall be set to provide a gas temperature no greater
than 160 [deg]C. An oxygen or carbon dioxide measurement shall be
obtained simultaneously with each Method 5 run.
(4) The owner or operator of an affected facility may request that
compliance with the particulate matter emission limit be determined
using carbon dioxide measurements corrected to an equivalent of 7
percent oxygen. The relationship between oxygen and carbon dioxide
levels for the affected facility shall be established as specified in
paragraph (b)(6) of this section.
(5) As specified under Sec. 60.8 of subpart A of this part, all
performance tests shall consist of three test runs. The average of the
particulate matter emission concentrations from the three test runs is
used to determine compliance.
(6) In accordance with paragraphs (c)(7) and (c)(11) of this
section, EPA Reference Method 9 shall be used for determining compliance
with the opacity limit except as provided under Sec. 60.11(e) of
subpart A of this part.
(7) The owner or operator of an affected facility shall conduct an
initial performance test for particulate matter emissions and opacity as
required under Sec. 60.8 of subpart A of this part.
(8) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a continuous opacity monitoring system
for measuring opacity and shall follow the methods and procedures
specified in paragraphs (c)(8)(i) through (c)(8)(iv) of this section.
(i) The output of the continuous opacity monitoring system shall be
recorded on a 6-minute average basis.
[[Page 249]]
(ii) The continuous opacity monitoring system shall be installed,
evaluated, and operated in accordance with Sec. 60.13 of subpart A of
this part.
(iii) The continuous opacity monitoring system shall conform to
Performance Specification 1 in appendix B of this part.
(iv) The initial performance evaluation shall be completed no later
than 180 days after the date of the initial startup of the municipal
waste combustor unit, as specified under Sec. 60.8 of subpart A of this
part.
(9) Following the date that the initial performance test for
particulate matter is completed or is required to be completed under
Sec. 60.8 of subpart A of this part for an affected facility, the owner
or operator shall conduct a performance test for particulate matter on a
calendar year basis (no less than 9 calendar months and no more than 15
calendar months following the previous performance test; and must
complete five performance tests in each 5-year calendar period).
(10) In place of particulate matter testing with EPA Reference
Method 5, an owner or operator may elect to install, calibrate,
maintain, and operate a continuous emission monitoring system for
monitoring particulate matter emissions discharged to the atmosphere and
record the output of the system. The owner or operator of an affected
facility who elects to continuously monitor particulate matter emissions
instead of conducting performance testing using EPA Method 5 shall
install, calibrate, maintain, and operate a continuous emission
monitoring system and shall comply with the requirements specified in
paragraphs (c)(10)(i) through (c)(10)(xiv) of this section. The owner or
operator who elects to continuously monitor particulate matter emissions
instead of conducting performance testing using EPA Method 5 is not
required to complete performance testing for particulate matter as
specified in paragraph (c)(9) of this section and is not required to
continuously monitor opacity as specified in paragraph (c)(8) of this
section.
(i) Notify the Administrator one month before starting use of the
system.
(ii) Notify the Administrator one month before stopping use of the
system.
(iii) The monitor shall be installed, evaluated, and operated in
accordance with Sec. 60.13 of subpart A of this part.
(iv) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of the affected
facility, as specified under Sec. 60.8 of subpart A of this part or
within 180 days of notification to the Administrator of use of the
continuous monitoring system if the owner or operator was previously
determining compliance by Method 5 performance tests, whichever is
later.
(v) The owner or operator of an affected facility may request that
compliance with the particulate matter emission limit be determined
using carbon dioxide measurements corrected to an equivalent of 7
percent oxygen. The relationship between oxygen and carbon dioxide
levels for the affected facility shall be established as specified in
paragraph (b)(6) of this section.
(vi) The owner or operator of an affected facility shall conduct an
initial performance test for particulate matter emissions as required
under Sec. 60.8 of subpart A of this part. Compliance with the
particulate matter emission limit shall be determined by using the
continuous emission monitoring system specified in paragraph (c)(10) of
this section to measure particulate matter and calculating a 24-hour
block arithmetic average emission concentration using EPA Reference
Method 19, section 12.4.1.
(vii) Compliance with the particulate matter emission limit shall be
determined based on the 24-hour daily (block) average of the hourly
arithmetic average emission concentrations using continuous emission
monitoring system outlet data.
(viii) After April 28, 2008, at a minimum, valid continuous
monitoring system hourly averages shall be obtained as specified in
paragraphs (c)(10)(viii)(A) and (c)(10)(viii)(B) for at least 90 percent
of the operating hours per calendar quarter and 95 percent of the
operating hours per calendar year that the affected facility is
combusting municipal solid waste.
[[Page 250]]
(A) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(B) Each particulate matter 1-hour arithmetic average shall be
corrected to 7 percent oxygen on an hourly basis using the 1-hour
arithmetic average of the oxygen (or carbon dioxide) continuous emission
monitoring system data.
(ix) The 1-hour arithmetic averages required under paragraph
(c)(10)(vii) of this section shall be expressed in milligrams per dry
standard cubic meter corrected to 7 percent oxygen (dry basis) and shall
be used to calculate the 24-hour daily arithmetic average emission
concentrations. The 1-hour arithmetic averages shall be calculated using
the data points required under Sec. 60.13(e)(2) of subpart A of this
part.
(x) All valid continuous emission monitoring system data shall be
used in calculating average emission concentrations even if the minimum
continuous emission monitoring system data requirements of paragraph
(c)(10)(viii) of this section are not met.
(xi) The continuous emission monitoring system shall be operated
according to Performance Specification 11 in appendix B of this part.
(xii) During each relative accuracy test run of the continuous
emission monitoring system required by Performance Specification 11 in
appendix B of this part, particulate matter and oxygen (or carbon
dioxide) data shall be collected concurrently (or within a 30- to 60-
minute period) by both the continuous emission monitors and the test
methods specified in paragraphs (c)(10)(xii)(A) and (c)(10)(xii)(B) of
this section.
(A) For particulate matter, EPA Reference Method 5 shall be used.
(B) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or
3B, as applicable shall be used.
(xiii) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 2 in appendix F of
this part.
(xiv) When particulate matter emissions data are not obtained
because of continuous emission monitoring system breakdowns, repairs,
calibration checks, and zero and span adjustments, emissions data shall
be obtained by using other monitoring systems as approved by the
Administrator or EPA Reference Method 19 to provide, as necessary, valid
emissions data for a minimum of 90 percent of the hours per calendar
quarter and 95 percent of the hours per calendar year that the affected
facility is operated and combusting municipal solid waste.
(11) Following the date that the initial performance test for
opacity is completed or is required to be completed under Sec. 60.8 of
subpart A of this part for an affected facility, the owner or operator
shall conduct a performance test for opacity on an annual basis (no less
than 9 calendar months and no more than 15 calendar months following the
previous performance test; and must complete five performance tests in
each 5-year calendar period) using the test method specified in
paragraph (c)(6) of this section.
(d) The procedures and test methods specified in paragraphs (d)(1)
and (d)(2) of this section shall be used to determine compliance with
the emission limits for cadmium, lead, and mercury under Sec.
60.52b(a).
(1) The procedures and test methods specified in paragraphs
(d)(1)(i) through (d)(1)(ix) of this section shall be used to determine
compliance with the emission limits for cadmium and lead under Sec.
60.52b(a) (3) and (4).
(i) The EPA Reference Method 1 shall be used for determining the
location and number of sampling points.
(ii) The EPA Reference Method 3, 3A, or 3B, or as an alternative
ASME PTC-19-10-1981--part10, as applicable, shall be used for flue gas
analysis.
(iii) The EPA Reference Method 29 shall be used for determining
compliance with the cadmium and lead emission limits.
(iv) An oxygen or carbon dioxide measurement shall be obtained
simultaneously with each Method 29 test run for cadmium and lead
required under paragraph (d)(1)(iii) of this section.
(v) The owner or operator of an affected facility may request that
compliance with the cadmium or lead emission limit be determined using
carbon dioxide measurements corrected to an equivalent of 7 percent
oxygen. The relationship between oxygen and carbon dioxide levels for
the affected facility
[[Page 251]]
shall be established as specified in paragraph (b)(6) of this section.
(vi) All performance tests shall consist of a minimum of three test
runs conducted under representative full load operating conditions. The
average of the cadmium or lead emission concentrations from three test
runs or more shall be used to determine compliance.
(vii) Following the date of the initial performance test or the date
on which the initial performance test is required to be completed under
Sec. 60.8 of subpart A of this part, the owner or operator of an
affected facility shall conduct a performance test for compliance with
the emission limits for cadmium and lead on a calendar year basis (no
less than 9 calendar months and no more than 15 calendar months
following the previous performance test; and must complete five
performance tests in each 5-year calendar period).
(viii)-(ix) [Reserved]
(2) The procedures and test methods specified in paragraphs
(d)(2)(i) through (d)(2)(xi) of this section shall be used to determine
compliance with the mercury emission limit under Sec. 60.52b(a)(5).
(i) The EPA Reference Method 1 shall be used for determining the
location and number of sampling points.
(ii) The EPA Reference Method 3, 3A, or 3B, or as an alternative
ASME PTC-19-10-1981--part10, as applicable, shall be used for flue gas
analysis.
(iii) The EPA Reference Method 29 or as an alternative ASTM D6784-02
shall be used to determine the mercury emission concentration. The
minimum sample volume when using Method 29 as an alternative ASTM D6784-
02 for mercury shall be 1.7 cubic meters.
(iv) An oxygen (or carbon dioxide) measurement shall be obtained
simultaneously with each Method 29 or as an alternative ASTM D6784-02
test run for mercury required under paragraph (d)(2)(iii) of this
section.
(v) The percent reduction in the potential mercury emissions (%PHg)
is computed using equation 1:
[GRAPHIC] [TIFF OMITTED] TR19DE95.001
where:
%PHg = percent reduction of the potential mercury emissions
achieved.
Ei = potential mercury emission concentration measured at the
control device inlet, corrected to 7 percent oxygen (dry
basis).
Eo = controlled mercury emission concentration measured at
the mercury control device outlet, corrected to 7 percent
oxygen (dry basis).
(vi) All performance tests shall consist of a minimum of three test
runs conducted under representative full load operating conditions. The
average of the mercury emission concentrations or percent reductions
from three test runs or more is used to determine compliance.
(vii) The owner or operator of an affected facility may request that
compliance with the mercury emission limit be determined using carbon
dioxide measurements corrected to an equivalent of 7 percent oxygen. The
relationship between oxygen and carbon dioxide levels for the affected
facility shall be established as specified in paragraph (b)(6) of this
section.
(viii) The owner or operator of an affected facility shall conduct
an initial performance test for mercury emissions as required under
Sec. 60.8 of subpart A of this part.
(ix) Following the date that the initial performance test for
mercury is completed or is required to be completed under Sec. 60.8 of
subpart A of this part, the owner or operator of an affected facility
shall conduct a performance test for mercury emissions on a calendar
year basis (no less than 9 calendar months and no more than 15 calendar
months from the previous performance test; and must complete five
performance tests in each 5-year calendar period).
(x) [Reserved]
(xi) The owner or operator of an affected facility where activated
carbon injection is used to comply with the mercury emission limit shall
follow the procedures specified in paragraph (m) of this section for
measuring and calculating carbon usage.
(3) In place of cadmium and lead testing with EPA Reference Method
29 as an alternative ASTM D6784-02, an owner or operator may elect to
install, calibrate, maintain, and operate a continuous emission
monitoring system
[[Page 252]]
for monitoring cadmium and lead emissions discharged to the atmosphere
and record the output of the system according to the provisions of
paragraphs (n) and (o) of this section.
(4) In place of mercury testing with EPA Reference Method 29 or as
an alternative ASTM D6784-02, an owner or operator may elect to install,
calibrate, maintain, and operate a continuous emission monitoring system
or a continuous automated sampling system for monitoring mercury
emissions discharged to the atmosphere and record the output of the
system according to the provisions of paragraphs (n) and (o) of this
section, or paragraphs (p) and (q) of this section, as appropriate. The
owner or operator who elects to continuously monitor mercury in place of
mercury testing with EPA Reference Method 29 or as an alternative ASTM
D6784-02 is not required to complete performance testing for mercury as
specified in paragraph (d)(2)(ix) of this section.
(e) The procedures and test methods specified in paragraphs (e)(1)
through (e)(14) of this section shall be used for determining compliance
with the sulfur dioxide emission limit under Sec. 60.52b(b)(1).
(1) The EPA Reference Method 19, section 4.3, shall be used to
calculate the daily geometric average sulfur dioxide emission
concentration.
(2) The EPA Reference Method 19, section 5.4, shall be used to
determine the daily geometric average percent reduction in the potential
sulfur dioxide emission concentration.
(3) The owner or operator of an affected facility may request that
compliance with the sulfur dioxide emission limit be determined using
carbon dioxide measurements corrected to an equivalent of 7 percent
oxygen. The relationship between oxygen and carbon dioxide levels for
the affected facility shall be established as specified in paragraph
(b)(6) of this section.
(4) The owner or operator of an affected facility shall conduct an
initial performance test for sulfur dioxide emissions as required under
Sec. 60.8 of subpart A of this part. Compliance with the sulfur dioxide
emission limit (concentration or percent reduction) shall be determined
by using the continuous emission monitoring system specified in
paragraph (e)(5) of this section to measure sulfur dioxide and
calculating a 24-hour daily geometric average emission concentration or
a 24-hour daily geometric average percent reduction using EPA Reference
Method 19, sections 4.3 and 5.4, as applicable.
(5) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a continuous emission monitoring system
for measuring sulfur dioxide emissions discharged to the atmosphere and
record the output of the system.
(6) Following the date that the initial performance test for sulfur
dioxide is completed or is required to be completed under Sec. 60.8 of
subpart A of this part, compliance with the sulfur dioxide emission
limit shall be determined based on the 24-hour daily geometric average
of the hourly arithmetic average emission concentrations using
continuous emission monitoring system outlet data if compliance is based
on an emission concentration, or continuous emission monitoring system
inlet and outlet data if compliance is based on a percent reduction.
(7) At a minimum, valid continuous monitoring system hourly averages
shall be obtained as specified in paragraphs (e)(7)(i) and (e)(7)(ii)
for 90 percent of the operating hours per calendar quarter and 95
percent of the operating days per calendar year that the affected
facility is combusting municipal solid waste.
(i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(ii) Each sulfur dioxide 1-hour arithmetic average shall be
corrected to 7 percent oxygen on an hourly basis using the 1-hour
arithmetic average of the oxygen (or carbon dioxide) continuous emission
monitoring system data.
(8) The 1-hour arithmetic averages required under paragraph (e)(6)
of this section shall be expressed in parts per million corrected to 7
percent oxygen (dry basis) and used to calculate the 24-hour daily
geometric average emission concentrations and daily geometric average
emission percent reductions. The 1-hour arithmetic averages shall be
[[Page 253]]
calculated using the data points required under Sec. 60.13(e)(2) of
subpart A of this part.
(9) All valid continuous emission monitoring system data shall be
used in calculating average emission concentrations and percent
reductions even if the minimum continuous emission monitoring system
data requirements of paragraph (e)(7) of this section are not met.
(10) The procedures under Sec. 60.13 of subpart A of this part
shall be followed for installation, evaluation, and operation of the
continuous emission monitoring system.
(11) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of the municipal waste
combustor as specified under Sec. 60.8 of subpart A of this part.
(12) The continuous emission monitoring system shall be operated
according to Performance Specification 2 in appendix B of this part. For
sources that have actual inlet emissions less than 100 parts per million
dry volume, the relative accuracy criterion for inlet sulfur dioxide
continuous emission monitoring systems should be no greater than 20
percent of the mean value of the reference method test data in terms of
the units of the emission standard, or 5 parts per million dry volume
absolute value of the mean difference between the reference method and
the continuous emission monitoring systems, whichever is greater.
(i) During each relative accuracy test run of the continuous
emission monitoring system required by Performance Specification 2 in
appendix B of this part, sulfur dioxide and oxygen (or carbon dioxide)
data shall be collected concurrently (or within a 30- to 60-minute
period) by both the continuous emission monitors and the test methods
specified in paragraphs (e)(12)(i)(A) and (e)(12)(i)(B) of this section.
(A) For sulfur dioxide, EPA Reference Method 6, 6A, or 6C, or as an
alternative ASME PTC-19-10-1981--part10, shall be used.
(B) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or
3B, or as an alternative ASME PTC-19-10-1981--part10, as applicable,
shall be used.
(ii) The span value of the continuous emissions monitoring system at
the inlet to the sulfur dioxide control device shall be 125 percent of
the maximum estimated hourly potential sulfur dioxide emissions of the
municipal waste combustor unit. The span value of the continuous
emission monitoring system at the outlet of the sulfur dioxide control
device shall be 50 percent of the maximum estimated hourly potential
sulfur dioxide emissions of the municipal waste combustor unit.
(13) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 1 in appendix F of
this part.
(14) When sulfur dioxide emissions data are not obtained because of
continuous emission monitoring system breakdowns, repairs, calibration
checks, and/or zero and span adjustments, emissions data shall be
obtained by using other monitoring systems as approved by EPA or EPA
Reference Method 19 to provide, as necessary, valid emissions data for a
minimum of 90 percent of the hours per calendar quarter and 95 percent
of the hours per calendar year that the affected facility is operated
and combusting municipal solid waste.
(f) The procedures and test methods specified in paragraphs (f)(1)
through (f)(8) of this section shall be used for determining compliance
with the hydrogen chloride emission limit under Sec. 60.52b(b)(2).
(1) The EPA Reference Method 26 or 26A, as applicable, shall be used
to determine the hydrogen chloride emission concentration. The minimum
sampling time shall be 1 hour.
(2) An oxygen (or carbon dioxide) measurement shall be obtained
simultaneously with each test run for hydrogen chloride required by
paragraph (f)(1) of this section.
(3) The percent reduction in potential hydrogen chloride emissions
(% PHCl) is computed using equation 2:
[GRAPHIC] [TIFF OMITTED] TR19DE95.002
where:
%PHCl = percent reduction of the potential hydrogen chloride
emissions achieved.
[[Page 254]]
Ei = potential hydrogen chloride emission concentration
measured at the control device inlet, corrected to 7 percent
oxygen (dry basis).
Eo = controlled hydrogen chloride emission concentration
measured at the control device outlet, corrected to 7 percent
oxygen (dry basis).
(4) The owner or operator of an affected facility may request that
compliance with the hydrogen chloride emission limit be determined using
carbon dioxide measurements corrected to an equivalent of 7 percent
oxygen. The relationship between oxygen and carbon dioxide levels for
the affected facility shall be established as specified in paragraph
(b)(6) of this section.
(5) As specified under Sec. 60.8 of subpart A of this part, all
performance tests shall consist of three test runs. The average of the
hydrogen chloride emission concentrations or percent reductions from the
three test runs is used to determine compliance.
(6) The owner or operator of an affected facility shall conduct an
initial performance test for hydrogen chloride as required under Sec.
60.8 of subpart A of this part.
(7) Following the date that the initial performance test for
hydrogen chloride is completed or is required to be completed under
Sec. 60.8 of subpart A of this part, the owner or operator of an
affected facility shall conduct a performance test for hydrogen chloride
emissions on an annual basis (no more than 12 calendar months following
the previous performance test).
(8) In place of hydrogen chloride testing with EPA Reference Method
26 or 26A, an owner or operator may elect to install, calibrate,
maintain, and operate a continuous emission monitoring system for
monitoring hydrogen chloride emissions discharged to the atmosphere and
record the output of the system according to the provisions of
paragraphs (n) and (o) of this section.
(g) The procedures and test methods specified in paragraphs (g)(1)
through (g)(9) of this section shall be used to determine compliance
with the limits for dioxin/furan emissions under Sec. 60.52b(c).
(1) The EPA Reference Method 1 shall be used for determining the
location and number of sampling points.
(2) The EPA Reference Method 3, 3A, or 3B, or as an alternative ASME
PTC-19-10-1981--part10, as applicable, shall be used for flue gas
analysis.
(3) The EPA Reference Method 23 shall be used for determining the
dioxin/furan emission concentration.
(i) The minimum sample time shall be 4 hours per test run.
(ii) An oxygen (or carbon dioxide) measurement shall be obtained
simultaneously with each Method 23 test run for dioxins/furans.
(4) The owner or operator of an affected facility shall conduct an
initial performance test for dioxin/furan emissions in accordance with
paragraph (g)(3) of this section, as required under Sec. 60.8 of
subpart A of this part.
(5) Following the date that the initial performance test for
dioxins/furans is completed or is required to be completed under Sec.
60.8 of subpart A of this part, the owner or operator of an affected
facility shall conduct performance tests for dioxin/furan emissions in
accordance with paragraph (g)(3) of this section, according to one of
the schedules specified in paragraphs (g)(5)(i) through (g)(5)(iii) of
this section.
(i) For affected facilities, performance tests shall be conducted on
a calendar year basis (no less than 9 calendar months and no more than
15 calendar months following the previous performance test; and must
complete five performance tests in each 5-year calendar period).
(ii) For the purpose of evaluating system performance to establish
new operating parameter levels, testing new technology or control
technologies, diagnostic testing, or related activities for the purpose
of improving facility performance or advancing the state-of-the-art for
controlling facility emissions, the owner or operator of an affected
facility that qualifies for the performance testing schedule specified
in paragraph (g)(5)(iii) of this section, may test one unit for dioxin/
furan and apply the dioxin/furan operating parameters to similarly
designed and equipped units on site by meeting the requirements
specified in paragraphs (g)(5)(ii)(A) through (g)(5)(ii)(D) of this
section.
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(A) Follow the testing schedule established in paragraph (g)(5)(iii)
of this section. For example, each year a different affected facility at
the municipal waste combustor plant shall be tested, and the affected
facilities at the plant shall be tested in sequence (e.g., unit 1, unit
2, unit 3, as applicable).
(B) Upon meeting the requirements in paragraph (g)(5)(iii) of this
section for one affected facility, the owner or operator may elect to
apply the average carbon mass feed rate and associated carbon injection
system operating parameter levels for dioxin/furan as established in
paragraph (m) of this section to similarly designed and equipped units
on site.
(C) Upon testing each subsequent unit in accordance with the testing
schedule established in paragraph (g)(5)(iii) of this section, the
dioxin/furan and mercury emissions of the subsequent unit shall not
exceed the dioxin/furan and mercury emissions measured in the most
recent test of that unit prior to the revised operating parameter
levels.
(D) The owner or operator of an affected facility that selects to
follow the performance testing schedule specified in paragraph
(g)(5)(iii) of this section and apply the carbon injection system
operating parameters to similarly designed and equipped units on site
shall follow the procedures specified in Sec. 60.59b(g)(4) for
reporting.
(iii) Where all performance tests over a 2-year period indicate that
dioxin/furan emissions are less than or equal to 7 nanograms per dry
standard cubic meter (total mass) for all affected facilities located
within a municipal waste combustor plant, the owner or operator of the
municipal waste combustor plant may elect to conduct annual performance
tests for one affected facility (i.e., unit) per year at the municipal
waste combustor plant. At a minimum, a performance test for dioxin/furan
emissions shall be conducted on a calendar year basis (no less than 9
calendar months and no more than 15 months following the previous
performance test; and must complete five performance tests in each 5-
year calendar period) for one affected facility at the municipal waste
combustor plant. Each year a different affected facility at the
municipal waste combustor plant shall be tested, and the affected
facilities at the plant shall be tested in sequence (e.g., unit 1, unit
2, unit 3, as applicable). If each annual performance test continues to
indicate a dioxin/furan emission level less than or equal to 7 nanograms
per dry standard cubic meter (total mass), the owner or operator may
continue conducting a performance test on only one affected facility per
calendar year. If any annual performance test indicates either a dioxin/
furan emission level greater than 7 nanograms per dry standard cubic
meter (total mass), performance tests shall thereafter be conducted
annually on all affected facilities at the plant until and unless all
annual performance tests for all affected facilities at the plant over a
2-year period indicate a dioxin/furan emission level less than or equal
to 7 nanograms per dry standard cubic meter (total mass).
(6) The owner or operator of an affected facility that selects to
follow the performance testing schedule specified in paragraph
(g)(5)(iii) of this section shall follow the procedures specified in
Sec. 60.59b(g)(4) for reporting the selection of this schedule.
(7) The owner or operator of an affected facility where activated
carbon is used shall follow the procedures specified in paragraph (m) of
this section for measuring and calculating the carbon usage rate.
(8) The owner or operator of an affected facility may request that
compliance with the dioxin/furan emission limit be determined using
carbon dioxide measurements corrected to an equivalent of 7 percent
oxygen. The relationship between oxygen and carbon dioxide levels for
the affected facility shall be established as specified in paragraph
(b)(6) of this section.
(9) As specified under Sec. 60.8 of subpart A of this part, all
performance tests shall consist of three test runs. The average of the
dioxin/furan emission concentrations from the three test runs is used to
determine compliance.
(10) In place of dioxin/furan sampling and testing with EPA
Reference Method 23, an owner or operator may elect to sample dioxin/
furan by installing,
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calibrating, maintaining, and operating a continuous automated sampling
system for monitoring dioxin/furan emissions discharged to the
atmosphere, recording the output of the system, and analyzing the sample
using EPA Method 23. This option to use a continuous automated sampling
system takes effect on the date a final performance specification
applicable to dioxin/furan from monitors is published in the Federal
Register or the date of approval of a site-specific monitoring plan. The
owner or operator of an affected facility who elects to continuously
sample dioxin/furan emissions instead of sampling and testing using EPA
Method 23 shall install, calibrate, maintain, and operate a continuous
automated sampling system and shall comply with the requirements
specified in paragraphs (p) and (q) of this section.
(h) The procedures and test methods specified in paragraphs (h)(1)
through (h)(12) of this section shall be used to determine compliance
with the nitrogen oxides emission limit for affected facilities under
Sec. 60.52b(d).
(1) The EPA Reference Method 19, section 4.1, shall be used for
determining the daily arithmetic average nitrogen oxides emission
concentration.
(2) The owner or operator of an affected facility may request that
compliance with the nitrogen oxides emission limit be determined using
carbon dioxide measurements corrected to an equivalent of 7 percent
oxygen. The relationship between oxygen and carbon dioxide levels for
the affected facility shall be established as specified in paragraph
(b)(6) of this section.
(3) The owner or operator of an affected facility subject to the
nitrogen oxides limit under Sec. 60.52b(d) shall conduct an initial
performance test for nitrogen oxides as required under Sec. 60.8 of
subpart A of this part. Compliance with the nitrogen oxides emission
limit shall be determined by using the continuous emission monitoring
system specified in paragraph (h)(4) of this section for measuring
nitrogen oxides and calculating a 24-hour daily arithmetic average
emission concentration using EPA Reference Method 19, section 4.1.
(4) The owner or operator of an affected facility subject to the
nitrogen oxides emission limit under Sec. 60.52b(d) shall install,
calibrate, maintain, and operate a continuous emission monitoring system
for measuring nitrogen oxides discharged to the atmosphere, and record
the output of the system.
(5) Following the date that the initial performance test for
nitrogen oxides is completed or is required to be completed under Sec.
60.8 of subpart A of this part, compliance with the emission limit for
nitrogen oxides required under Sec. 60.52b(d) shall be determined based
on the 24-hour daily arithmetic average of the hourly emission
concentrations using continuous emission monitoring system outlet data.
(6) At a minimum, valid continuous emission monitoring system hourly
averages shall be obtained as specified in paragraphs (h)(6)(i) and
(h)(6)(ii) of this section for 90 percent of the operating hours per
calendar quarter and for 95 percent of the operating hours per calendar
year that the affected facility is combusting municipal solid waste.
(i) At least 2 data points per hour shall be used to calculate each
1-hour arithmetic average.
(ii) Each nitrogen oxides 1-hour arithmetic average shall be
corrected to 7 percent oxygen on an hourly basis using the 1-hour
arithmetic average of the oxygen (or carbon dioxide) continuous emission
monitoring system data.
(7) The 1-hour arithmetic averages required by paragraph (h)(5) of
this section shall be expressed in parts per million by volume (dry
basis) and used to calculate the 24-hour daily arithmetic average
concentrations. The 1-hour arithmetic averages shall be calculated using
the data points required under Sec. 60.13(e)(2) of subpart A of this
part.
(8) All valid continuous emission monitoring system data must be
used in calculating emission averages even if the minimum continuous
emission monitoring system data requirements of paragraph (h)(6) of this
section are not met.
(9) The procedures under Sec. 60.13 of subpart A of this part shall
be followed for installation, evaluation, and operation of the
continuous emission monitoring system. The initial performance
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evaluation shall be completed no later than 180 days after the date of
initial startup of the municipal waste combustor unit, as specified
under Sec. 60.8 of subpart A of this part.
(10) The owner or operator of an affected facility shall operate the
continuous emission monitoring system according to Performance
Specification 2 in appendix B of this part and shall follow the
procedures and methods specified in paragraphs (h)(10)(i) and
(h)(10)(ii) of this section.
(i) During each relative accuracy test run of the continuous
emission monitoring system required by Performance Specification 2 of
appendix B of this part, nitrogen oxides and oxygen (or carbon dioxide)
data shall be collected concurrently (or within a 30- to 60-minute
period) by both the continuous emission monitors and the test methods
specified in paragraphs (h)(10)(i)(A) and (h)(10)(i)(B) of this section.
(A) For nitrogen oxides, EPA Reference Method 7, 7A, 7C, 7D, or 7E
shall be used.
(B) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or
3B, or as an alternative ASME PTC-19-10-1981--part10, as applicable,
shall be used.
(ii) The span value of the continuous emission monitoring system
shall be 125 percent of the maximum estimated hourly potential nitrogen
oxide emissions of the municipal waste combustor unit.
(11) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 1 in appendix F of
this part.
(12) When nitrogen oxides continuous emission data are not obtained
because of continuous emission monitoring system breakdowns, repairs,
calibration checks, and zero and span adjustments, emissions data shall
be obtained using other monitoring systems as approved by EPA or EPA
Reference Method 19 to provide, as necessary, valid emissions data for a
minimum of 90 percent of the hours per calendar quarter and 95 percent
of the hours per calendar year the unit is operated and combusting
municipal solid waste.
(i) The procedures specified in paragraphs (i)(1) through (i)(12) of
this section shall be used for determining compliance with the operating
requirements under Sec. 60.53b.
(1) Compliance with the carbon monoxide emission limits in Sec.
60.53b(a) shall be determined using a 4-hour block arithmetic average
for all types of affected facilities except mass burn rotary waterwall
municipal waste combustors and refuse-derived fuel stokers.
(2) For affected mass burn rotary waterwall municipal waste
combustors and refuse-derived fuel stokers, compliance with the carbon
monoxide emission limits in Sec. 60.53b(a) shall be determined using a
24-hour daily arithmetic average.
(3) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a continuous emission monitoring system
for measuring carbon monoxide at the combustor outlet and record the
output of the system and shall follow the procedures and methods
specified in paragraphs (i)(3)(i) through (i)(3)(iii) of this section.
(i) The continuous emission monitoring system shall be operated
according to Performance Specification 4A in appendix B of this part.
(ii) During each relative accuracy test run of the continuous
emission monitoring system required by Performance Specification 4A in
appendix B of this part, carbon monoxide and oxygen (or carbon dioxide)
data shall be collected concurrently (or within a 30- to 60-minute
period) by both the continuous emission monitors and the test methods
specified in paragraphs (i)(3)(ii)(A) and (i)(3)(ii)(B) of this section.
For affected facilities subject to the 100 parts per million dry volume
carbon monoxide standard, the relative accuracy criterion of 5 parts per
million dry volume is calculated as the absolute value of the mean
difference between the reference method and continuous emission
monitoring systems.
(A) For carbon monoxide, EPA Reference Method 10, 10A, or 10B shall
be used.
(B) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or
3B, or ASME PTC-19-10-1981--part10 (incorporated by reference, see Sec.
60.17 of subpart A of this part), as applicable, shall be used.
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(iii) The span value of the continuous emission monitoring system
shall be 125 percent of the maximum estimated hourly potential carbon
monoxide emissions of the municipal waste combustor unit.
(4) The 4-hour block and 24-hour daily arithmetic averages specified
in paragraphs (i)(1) and (i)(2) of this section shall be calculated from
1-hour arithmetic averages expressed in parts per million by volume
corrected to 7 percent oxygen (dry basis). The 1-hour arithmetic
averages shall be calculated using the data points generated by the
continuous emission monitoring system. At least two data points shall be
used to calculate each 1-hour arithmetic average.
(5) The owner or operator of an affected facility may request that
compliance with the carbon monoxide emission limit be determined using
carbon dioxide measurements corrected to an equivalent of 7 percent
oxygen. The relationship between oxygen and carbon dioxide levels for
the affected facility shall be established as specified in paragraph
(b)(6) of this section.
(6) The procedures specified in paragraphs (i)(6)(i) through
(i)(6)(v) of this section shall be used to determine compliance with
load level requirements under Sec. 60.53b(b).
(i) The owner or operator of an affected facility with steam
generation capability shall install, calibrate, maintain, and operate a
steam flow meter or a feedwater flow meter; measure steam (or feedwater)
flow in kilograms per hour (or pounds per hour) on a continuous basis;
and record the output of the monitor. Steam (or feedwater) flow shall be
calculated in 4-hour block arithmetic averages.
(ii) The method included in the ``American Society of Mechanical
Engineers Power Test Codes: Test Code for Steam Generating Units, Power
Test Code 4.1--1964 (R1991)'' section 4 (incorporated by reference, see
Sec. 60.17 of subpart A of this part) shall be used for calculating the
steam (or feedwater) flow required under paragraph (i)(6)(i) of this
section. The recommendations in ``American Society of Mechanical
Engineers Interim Supplement 19.5 on Instruments and Apparatus:
Application, partII of Fluid Meters, 6th edition (1971),'' chapter 4
(incorporated by reference--see Sec. 60.17 of subpart A of this part)
shall be followed for design, construction, installation, calibration,
and use of nozzles and orifices except as specified in (i)(6)(iii) of
this section.
(iii) Measurement devices such as flow nozzles and orifices are not
required to be recalibrated after they are installed.
(iv) All signal conversion elements associated with steam (or
feedwater flow) measurements must be calibrated according to the
manufacturer's instructions before each dioxin/furan performance test,
and at least once per year.
(7) To determine compliance with the maximum particulate matter
control device temperature requirements under Sec. 60.53b(c), the owner
or operator of an affected facility shall install, calibrate, maintain,
and operate a device for measuring on a continuous basis the temperature
of the flue gas stream at the inlet to each particulate matter control
device utilized by the affected facility. Temperature shall be
calculated in 4-hour block arithmetic averages.
(8) The maximum demonstrated municipal waste combustor unit load
shall be determined during the initial performance test for dioxins/
furans and each subsequent performance test during which compliance with
the dioxin/furan emission limit specified in Sec. 60.52b(c) is
achieved. The maximum demonstrated municipal waste combustor unit load
shall be the highest 4-hour arithmetic average load achieved during four
consecutive hours during the most recent test during which compliance
with the dioxin/furan emission limit was achieved. If a subsequent
dioxin/furan performance test is being performed on only one affected
facility at the MWC plant, as provided in paragraph (g)(5)(iii) of this
section, the owner or operator may elect to apply the same maximum
municipal waste combustor unit load from the tested facility for all the
similarly designed and operated affected facilities at the MWC plant.
(9) For each particulate matter control device employed at the
affected facility, the maximum demonstrated
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particulate matter control device temperature shall be determined during
the initial performance test for dioxins/furans and each subsequent
performance test during which compliance with the dioxin/furan emission
limit specified in Sec. 60.52b(c) is achieved. The maximum demonstrated
particulate matter control device temperature shall be the highest 4-
hour arithmetic average temperature achieved at the particulate matter
control device inlet during four consecutive hours during the most
recent test during which compliance with the dioxin/furan limit was
achieved. If a subsequent dioxin/furan performance test is being
performed on only one affected facility at the MWC plant, as provided in
paragraph (g)(5)(iii) of this section, the owner or operator may elect
to apply the same maximum particulate matter control device temperature
from the tested facility for all the similarly designed and operated
affected facilities at the MWC plant.
(10) At a minimum, valid continuous emission monitoring system
hourly averages shall be obtained as specified in paragraphs (i)(10)(i)
and (i)(10)(ii) of this section for at least 90 percent of the operating
hours per calendar quarter and 95 percent of the operating hours per
calendar year that the affected facility is combusting municipal solid
waste.
(i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(ii) At a minimum, each carbon monoxide 1-hour arithmetic average
shall be corrected to 7 percent oxygen on an hourly basis using the 1-
hour arithmetic average of the oxygen (or carbon dioxide) continuous
emission monitoring system data.
(11) All valid continuous emission monitoring system data must be
used in calculating the parameters specified under paragraph (i) of this
section even if the minimum data requirements of paragraph (i)(10) of
this section are not met. When carbon monoxide continuous emission data
are not obtained because of continuous emission monitoring system
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained using other monitoring systems as
approved by EPA or EPA Reference Method 10 to provide, as necessary, the
minimum valid emission data.
(12) Quarterly accuracy determinations and daily calibration drift
tests for the carbon monoxide continuous emission monitoring system
shall be performed in accordance with procedure 1 in appendix F of this
part.
(j) The procedures specified in paragraphs (j)(1) and (j)(2) of this
section shall be used for calculating municipal waste combustor unit
capacity as defined under Sec. 60.51b.
(1) For municipal waste combustor units capable of combusting
municipal solid waste continuously for a 24-hour period, municipal waste
combustor unit capacity shall be calculated based on 24 hours of
operation at the maximum charging rate. The maximum charging rate shall
be determined as specified in paragraphs (j)(1)(i) and (j)(1)(ii) of
this section as applicable.
(i) For combustors that are designed based on heat capacity, the
maximum charging rate shall be calculated based on the maximum design
heat input capacity of the unit and a heating value of 12,800 kilojoules
per kilogram for combustors firing refuse-derived fuel and a heating
value of 10,500 kilojoules per kilogram for combustors firing municipal
solid waste that is not refuse-derived fuel.
(ii) For combustors that are not designed based on heat capacity,
the maximum charging rate shall be the maximum design charging rate.
(2) For batch feed municipal waste combustor units, municipal waste
combustor unit capacity shall be calculated as the maximum design amount
of municipal solid waste that can be charged per batch multiplied by the
maximum number of batches that could be processed in a 24-hour period.
The maximum number of batches that could be processed in a 24-hour
period is calculated as 24 hours divided by the design number of hours
required to process one batch of municipal solid waste, and may include
fractional batches (e.g., if one batch requires 16 hours, then 24/16, or
1.5 batches, could be combusted in a 24-hour period). For batch
combustors that are designed based on heat capacity, the design
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heating value of 12,800 kilojoules per kilogram for combustors firing
refuse-derived fuel and a heating value of 10,500 kilojoules per
kilogram for combustors firing municipal solid waste that is not refuse-
derived fuel shall be used in calculating the municipal waste combustor
unit capacity in megagrams per day of municipal solid waste.
(k) The procedures specified in paragraphs (k)(1) through (k)(4) of
this section shall be used for determining compliance with the fugitive
ash emission limit under Sec. 60.55b.
(1) The EPA Reference Method 22 shall be used for determining
compliance with the fugitive ash emission limit under Sec. 60.55b. The
minimum observation time shall be a series of three 1-hour observations.
The observation period shall include times when the facility is
transferring ash from the municipal waste combustor unit to the area
where ash is stored or loaded into containers or trucks.
(2) The average duration of visible emissions per hour shall be
calculated from the three 1-hour observations. The average shall be used
to determine compliance with Sec. 60.55b.
(3) The owner or operator of an affected facility shall conduct an
initial performance test for fugitive ash emissions as required under
Sec. 60.8 of subpart A of this part.
(4) Following the date that the initial performance test for
fugitive ash emissions is completed or is required to be completed under
Sec. 60.8 of subpart A of this part for an affected facility, the owner
or operator shall conduct a performance test for fugitive ash emissions
on an annual basis (no more than 12 calendar months following the
previous performance test).
(l) The procedures specified in paragraphs (l)(1) through (l)(3) of
this section shall be used to determine compliance with the opacity
limit for air curtain incinerators under Sec. 60.56b.
(1) The EPA Reference Method 9 shall be used for determining
compliance with the opacity limit.
(2) The owner or operator of the air curtain incinerator shall
conduct an initial performance test for opacity as required under Sec.
60.8 of subpart A of this part.
(3) Following the date that the initial performance test is
completed or is required to be completed under Sec. 60.8 of subpart A
of this part, the owner or operator of the air curtain incinerator shall
conduct a performance test for opacity on an annual basis (no more than
12 calendar months following the previous performance test).
(m) The owner or operator of an affected facility where activated
carbon injection is used to comply with the mercury emission limit under
Sec. 60.52b(a)(5), and/or the dioxin/furan emission limits under Sec.
60.52(b)(c), or the dioxin/furan emission level specified in paragraph
(g)(5)(iii) of this section shall follow the procedures specified in
paragraphs (m)(1) through (m)(4) of this section.
(1) During the performance tests for dioxins/furans and mercury, as
applicable, the owner or operator shall estimate an average carbon mass
feed rate based on carbon injection system operating parameters such as
the screw feeder speed, hopper volume, hopper refill frequency, or other
parameters appropriate to the feed system being employed, as specified
in paragraphs (m)(1)(i) and (m)(1)(ii) of this section.
(i) An average carbon mass feed rate in kilograms per hour or pounds
per hour shall be estimated during the initial performance test for
mercury emissions and each subsequent performance test for mercury
emissions.
(ii) An average carbon mass feed rate in kilograms per hour or
pounds per hour shall be estimated during the initial performance test
for dioxin/furan emissions and each subsequent performance test for
dioxin/furan emissions. If a subsequent dioxin/furan performance test is
being performed on only one affected facility at the MWC plant, as
provided in paragraph (g)(5)(iii) of this section, the owner or operator
may elect to apply the same estimated average carbon mass feed rate from
the tested facility for all the similarly designed and operated affected
facilities at the MWC plant.
(2) During operation of the affected facility, the carbon injection
system operating parameter(s) that are the primary indicator(s) of the
carbon mass feed rate (e.g., screw feeder setting) shall be averaged
over a block 8-
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hour period, and the 8-hour block average must equal or exceed the
level(s) documented during the performance tests specified under
paragraphs (m)(1)(i) and (m)(1)(ii) of this section, except as specified
in paragraphs (m)(2)(i) and (m)(2)(ii) of this section.
(i) During the annual dioxin/furan or mercury performance test and
the 2 weeks preceding the annual dioxin/furan or mercury performance
test, no limit is applicable for average mass carbon feed rate if the
provisions of paragraph (m)(2)(ii) of this section are met.
(ii) The limit for average mass carbon feed rate may be waived in
accordance with permission granted by the Administrator for the purpose
of evaluating system performance, testing new technology or control
technologies, diagnostic testing, or related activities for the purpose
of improving facility performance or advancing the state-of-the-art for
controlling facility emissions.
(3) The owner or operator of an affected facility shall estimate the
total carbon usage of the plant (kilograms or pounds) for each calendar
quarter by two independent methods, according to the procedures in
paragraphs (m)(3)(i) and (m)(3)(ii) of this section.
(i) The weight of carbon delivered to the plant.
(ii) Estimate the average carbon mass feed rate in kilograms per
hour or pounds per hour for each hour of operation for each affected
facility based on the parameters specified under paragraph (m)(1) of
this section, and sum the results for all affected facilities at the
plant for the total number of hours of operation during the calendar
quarter.
(4) Pneumatic injection pressure or other carbon injection system
operational indicator shall be used to provide additional verification
of proper carbon injection system operation. The operational indicator
shall provide an instantaneous visual and/or audible alarm to alert the
operator of a potential interruption in the carbon feed that would not
normally be indicated by direct monitoring of carbon mass feed rate
(e.g., continuous weight loss feeder) or monitoring of the carbon system
operating parameter(s) that are the indicator(s) of carbon mass feed
rate (e.g., screw feeder speed). The carbon injection system operational
indicator used to provide additional verification of carbon injection
system operation, including basis for selecting the indicator and
operator response to the indicator alarm, shall be included in section
(e)(6) of the site-specific operating manual required under Sec.
60.54b(e) of this subpart.
(n) In place of periodic manual testing of mercury, cadmium, lead,
or hydrogen chloride with EPA Reference Method 26, 26A, 29, or as an
alternative ASTM D6784-02 (as applicable), the owner or operator of an
affected facility may elect to install, calibrate, maintain, and operate
a continuous emission monitoring system for monitoring emissions
discharged to the atmosphere and record the output of the system. The
option to use a continuous emission monitoring system for mercury takes
effect on the date of approval of the site-specific monitoring plan
required in paragraph (n)(13) and (o) of this section. The option to use
a continuous emission monitoring system for cadmium, lead, or hydrogen
chloride takes effect on the date a final performance specification
applicable to cadmium, lead, or hydrogen chloride monitor is published
in the Federal Register or the date of approval of the site-specific
monitoring plan required in paragraphs (n)(13) and (o) of this section.
The owner or operator of an affected facility who elects to continuously
monitor emissions instead of conducting manual performance testing shall
install, calibrate, maintain, and operate a continuous emission
monitoring system and shall comply with the requirements specified in
paragraphs (n)(1) through (n)(13) of this section.
(1) Notify the Administrator one month before starting use of the
system.
(2) Notify the Administrator one month before stopping use of the
system.
(3) The monitor shall be installed, evaluated, and operated in
accordance with Sec. 60.13 of subpart A of this part.
(4) The initial performance evaluation shall be completed no later
than
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180 days after the date of initial startup of the affected facility, as
specified under Sec. 60.8 of subpart A of this part or within 180 days
of notification to the Administrator of use of the continuous monitoring
system if the owner or operator was previously determining compliance by
Method 26, 26A, 29, or as an alternative ASTM D6784-02 (as applicable)
performance tests, whichever is later.
(5) The owner or operator may request that compliance with the
emission limits be determined using carbon dioxide measurements
corrected to an equivalent of 7 percent oxygen. The relationship between
oxygen and carbon dioxide levels for the affected facility shall be
established as specified in paragraph (b)(6) of this section.
(6) The owner or operator shall conduct an initial performance test
for emissions as required under Sec. 60.8 of subpart A of this part.
Compliance with the emission limits shall be determined by using the
continuous emission monitoring system specified in paragraph (n) of this
section to measure emissions and calculating a 24-hour block arithmetic
average emission concentration using EPA Reference Method 19, section
12.4.1.
(7) Compliance with the emission limits shall be determined based on
the 24-hour daily (block) average of the hourly arithmetic average
emission concentrations using continuous emission monitoring system
outlet data.
(8) Beginning on April 28, 2008 for mercury and on the date two
years after final performance specifications for cadmium, lead or
hydrogen chloride monitors are published in the Federal Register or the
date two years after approval of a site-specific monitoring plan, valid
continuous monitoring system hourly averages shall be obtained as
specified in paragraphs (n)(8)(i) and (n)(8)(ii) of this section for at
least 90 percent of the operating hours per calendar quarter and 95
percent of the operating hours per calendar year that the affected
facility is combusting municipal solid waste.
(i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(ii) Each 1-hour arithmetic average shall be corrected to 7 percent
oxygen on an hourly basis using the 1-hour arithmetic average of the
oxygen (or carbon dioxide) continuous emission monitoring system data.
(9) The 1-hour arithmetic averages required under paragraph (n)(7)
of this section shall be expressed in micrograms per dry standard cubic
meter for mercury, cadmium, lead and parts per million dry volume for
hydrogen chloride corrected to 7 percent oxygen (dry basis) and shall be
used to calculate the 24-hour daily arithmetic (block) average emission
concentrations. The 1-hour arithmetic averages shall be calculated using
the data points required under Sec. 60.13(e)(2) of subpart A of this
part.
(10) All valid continuous emission monitoring system data shall be
used in calculating average emission concentrations even if the minimum
continuous emission monitoring system data requirements of paragraph
(n)(8) of this section are not met.
(11) The continuous emission monitoring system shall be operated
according to the performance specifications in paragraphs (n)(11)(i)
through (n)(11)(iii) of this section or the approved site-specific
monitoring plan.
(i) For mercury, Performance Specification 12A in appendix B of this
part.
(ii)-(iii) [Reserved]
(12) During each relative accuracy test run of the continuous
emission monitoring system required by the performance specifications in
paragraph (n)(11) of this section, mercury, cadmium, lead, hydrogen
chloride, and oxygen (or carbon dioxide) data shall be collected
concurrently (or within a 30- to 60-minute period) by both the
continuous emission monitors and the test methods specified in
paragraphs (n)(12)(i) through (n)(12)(iii) of this section.
(i) For mercury, cadmium, and lead, EPA Reference Method 29 or as an
alternative ASTM D6784-02 shall be used.
(ii) For hydrogen chloride, EPA Reference Method 26 or 26A shall be
used.
(iii) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or
3B, as applicable shall be used.
(13) The owner or operator who elects to install, calibrate,
maintain, and operate a continuous emission monitoring system for
mercury, cadmium,
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lead, or hydrogen chloride must develop and implement a site-specific
monitoring plan as specified in paragraph (o) of this section. The owner
or operator who relies on a performance specification may refer to that
document in addressing applicable procedures and criteria.
(14) When emissions data are not obtained because of continuous
emission monitoring system breakdowns, repairs, calibration checks, and
zero and span adjustments, parametric monitoring data shall be obtained
by using other monitoring systems as approved by EPA.
(o) The owner or operator who elects to install, calibrate,
maintain, and operate a continuous emission monitoring system for
mercury, cadmium, lead, or hydrogen chloride must develop and submit for
approval by EPA, a site-specific mercury, cadmium, lead, or hydrogen
chloride monitoring plan that addresses the elements and requirements in
paragraphs (o)(1) through (o)(7) of this section.
(1) Installation of the continuous emission monitoring system
sampling probe or other interface at a measurement location relative to
each affected process unit such that the measurement is representative
of control of the exhaust emissions (e.g., on or downstream of the last
control device).
(2) Performance and equipment specifications for the sample
interface, the pollutant concentration analyzer, and the data collection
and reduction system.
(3) Performance evaluation procedures and acceptance criteria (e.g.,
calibrations).
(4) Provisions for periods when the continuous emission monitoring
system is out of control as described in paragraphs (o)(4)(i) through
(o)(4)(iii) of this section.
(i) A continuous emission monitoring system is out of control if
either of the conditions in paragraphs (o)(4)(i)(A) or (o)(4)(ii)(B) of
this section are met.
(A) The zero (low-level), mid-level (if applicable), or high-level
calibration drift exceeds two times the applicable calibration drift
specification in the applicable performance specification or in the
relevant standard; or
(B) The continuous emission monitoring system fails a performance
test audit (e.g., cylinder gas audit), relative accuracy audit, relative
accuracy test audit, or linearity test audit.
(ii) When the continuous emission monitoring system is out of
control as defined in paragraph (o)(4)(i) of this section, the owner or
operator of the affected source shall take the necessary corrective
action and shall repeat all necessary tests that indicate that the
system is out of control. The owner or operator shall take corrective
action and conduct retesting until the performance requirements are
below the applicable limits. The beginning of the out-of-control period
is the hour the owner or operator conducts a performance check (e.g.,
calibration drift) that indicates an exceedance of the performance
requirements established under this part. The end of the out-of-control
period is the hour following the completion of corrective action and
successful demonstration that the system is within the allowable limits.
During the period the continuous emission monitoring system is out of
control, recorded data shall not be used in data averages and
calculations or to meet any data availability requirements in paragraph
(n)(8) of this section.
(iii) The owner or operator of a continuous emission monitoring
system that is out of control as defined in paragraph (o)(4) of this
section shall submit all information concerning out-of-control periods,
including start and end dates and hours and descriptions of corrective
actions taken in the annual or semiannual compliance reports required in
Sec. 60.59b(g) or (h).
(5) Ongoing data quality assurance procedures for continuous
emission monitoring systems as described in paragraphs (o)(5)(i) and
(o)(5)(ii) of this section.
(i) Develop and implement a continuous emission monitoring system
quality control program. As part of the quality control program, the
owner or operator shall develop and submit to EPA for approval, upon
request, a site-specific performance evaluation test plan for the
continuous emission monitoring system performance evaluation required in
paragraph (o)(5)(ii) of this
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section. In addition, each quality control program shall include, at a
minimum, a written protocol that describes procedures for each of the
operations described in paragraphs (o)(7)(i)(A) through (o)(7)(i)(F) of
this section.
(A) Initial and any subsequent calibration of the continuous
emission monitoring system;
(B) Determination and adjustment of the calibration drift of the
continuous emission monitoring system;
(C) Preventive maintenance of the continuous emission monitoring
system, including spare parts inventory;
(D) Data recording, calculations, and reporting;
(E) Accuracy audit procedures, including sampling and analysis
methods; and
(F) Program of corrective action for a malfunctioning continuous
emission monitoring system.
(ii) The performance evaluation test plan shall include the
evaluation program objectives, an evaluation program summary, the
performance evaluation schedule, data quality objectives, and both an
internal and external quality assurance program. Data quality objectives
are the pre-evaluation expectations of precision, accuracy, and
completeness of data. The internal quality assurance program shall
include, at a minimum, the activities planned by routine operators and
analysts to provide an assessment of continuous emission monitoring
system performance, for example, plans for relative accuracy testing
using the appropriate reference method in Sec. 60.58b(n)(12) of this
section. The external quality assurance program shall include, at a
minimum, systems audits that include the opportunity for on-site
evaluation by the Administrator of instrument calibration, data
validation, sample logging, and documentation of quality control data
and field maintenance activities.
(6) Conduct a performance evaluation of each continuous emission
monitoring system in accordance with the site-specific monitoring plan.
(7) Operate and maintain the continuous emission monitoring system
in continuous operation according to the site-specific monitoring plan.
(p) In place of periodic manual testing of dioxin/furan or mercury
with EPA Reference Method 23, 29, or as an alternative ASTM D6784-02 (as
applicable), the owner or operator of an affected facility may elect to
install, calibrate, maintain, and operate a continuous automated
sampling system for determining emissions discharged to the atmosphere.
This option takes effect on the date a final performance specification
applicable to such continuous automated sampling systems is published in
the Federal Register or the date of approval of a site-specific
monitoring plan required in paragraphs (p)(10) and (q) of this section.
The owner or operator of an affected facility who elects to use a
continuous automated sampling system to determine emissions instead of
conducting manual performance testing shall install, calibrate,
maintain, and operate the sampling system and conduct analyses in
compliance with the requirements specified in paragraphs (p)(1) through
(p)(12) of this section.
(1) Notify the Administrator one month before starting use of the
system.
(2) Notify the Administrator one month before stopping use of the
system.
(3) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of the affected
facility, as specified under Sec. 60.8 of subpart A of this part or
within 180 days of notification to the Administrator of use of the
continuous monitoring system if the owner or operator was previously
determining compliance by manual performance testing using Method 23,
29, or as an alternative ASTM D6784-02 (as applicable), whichever is
later.
(4) The owner or operator may request that compliance with the
emission limits be determined using carbon dioxide measurements
corrected to an equivalent of 7 percent oxygen. The relationship between
oxygen and carbon dioxide levels for the affected facility shall be
established as specified in paragraph (b)(6) of this section.
(5) The owner or operator shall conduct an initial performance test
for emissions as required under Sec. 60.8 of subpart A of this part.
Compliance
[[Page 265]]
with the emission limits shall be determined by using the continuous
automated sampling system specified in paragraph (p) of this section to
collect integrated samples and analyze emissions for the time period
specified in paragraphs (p)(5)(i) and (ii) of this section.
(i) For dioxin/furan, the continuous automated sampling system shall
collect an integrated sample over each 2-week period. The collected
sample shall be analyzed using Method 23.
(ii) For mercury, the continuous automated sampling system shall
collect an integrated sample over each 24-hour daily period and the
sample shall be analyzed according to the applicable final performance
specification or the approved site-specific monitoring plan required by
paragraph (q) of this section.
(6) Compliance with the emission limits shall be determined based on
2-week emission concentrations for dioxin/furan and on the 24-hour daily
emission concentrations for mercury using samples collected at the
system outlet. The emission concentrations shall be expressed in
nanograms per dry standard cubic meter (total mass) for dioxin/furan and
micrograms per dry standard cubic meter for mercury, corrected to 7
percent oxygen (dry basis).
(7) Beginning on the date two years after the respective final
performance specification for continuous automated sampling systems for
dioxin/furan or mercury is published in the Federal Register or two
years after approval of a site-specific monitoring plan, the continuous
automated sampling system must be operated and collect emissions for at
least 90 percent of the operating hours per calendar quarter and 95
percent of the operating hours per calendar year that the affected
facility is combusting municipal solid waste.
(8) All valid data shall be used in calculating emission
concentrations.
(9) The continuous automated sampling system shall be operated
according to the final performance specification in paragraphs (p)(9)(i)
or (p)(9)(ii) of this section or the approved site-specific monitoring
plan.
(i)-(ii) [Reserved]
(10) The owner or operator who elects to install, calibrate,
maintain, and operate a continuous automated sampling system for dioxin/
furan or mercury must develop and implement a site-specific monitoring
plan as specified in paragraph (q) of this section. The owner or
operator who relies on a performance specification may refer to that
document in addressing applicable procedures and criteria.
(11) When emissions data are not obtained because of continuous
automated sampling system breakdowns, repairs, quality assurance checks,
or adjustments, parametric monitoring data shall be obtained by using
other monitoring systems as approved by EPA.
(q) The owner or operator who elects to install, calibrate,
maintain, and operate a continuous automated sampling system for dioxin/
furan or mercury must develop and submit for approval by EPA, a site-
specific monitoring plan that has sufficient detail to assure the
validity of the continuous automated sampling system data and that
addresses the elements and requirements in paragraphs (q)(1) through
(q)(7) of this section.
(1) Installation of the continuous automated sampling system
sampling probe or other interface at a measurement location relative to
each affected process unit such that the measurement is representative
of control of the exhaust emissions (e.g., on or downstream of the last
control device).
(2) Performance and equipment specifications for the sample
interface, the pollutant concentration analytical method, and the data
collection system.
(3) Performance evaluation procedures and acceptance criteria.
(4) Provisions for periods when the continuous automated sampling
system is malfunctioning or is out of control as described in paragraphs
(q)(4)(i) through (q)(4)(iii) of this section.
(i) The site-specific monitoring plan shall identify criteria for
determining that the continuous automated sampling system is out of
control. This shall include periods when the sampling system is not
collecting a representative sample or is malfunctioning, or when the
analytical method
[[Page 266]]
does not meet site-specific quality criteria established in paragraph
(q)(5) of this section.
(ii) When the continuous automated sampling system is out of control
as defined in paragraph (q)(4)(i) of this section, the owner or operator
shall take the necessary corrective action and shall repeat all
necessary tests that indicate that the system is out of control. The
owner or operator shall take corrective action and conduct retesting
until the performance requirements are within the applicable limits. The
out-of-control period includes all hours that the sampling system was
not collecting a representative sample or was malfunctioning, or hours
represented by a sample for which the analysis did not meet the relevant
quality criteria. Emissions data obtained during an out-of-control
period shall not be used in determining compliance with the emission
limits or to meet any data availability requirements in paragraph (p)(8)
of this section.
(iii) The owner or operator of a continuous automated sampling
system that is out of control as defined in paragraph (q)(4) of this
section shall submit all information concerning out-of-control periods,
including start and end dates and hours and descriptions of corrective
actions taken in the annual or semiannual compliance reports required in
Sec. 60.59b(g) or (h).
(5) Ongoing data quality assurance procedures for continuous
automated sampling systems as described in paragraphs (q)(5)(i) and
(q)(5)(ii) of this section.
(i) Develop and implement a continuous automated sampling system and
analysis quality control program. As part of the quality control
program, the owner or operator shall develop and submit to EPA for
approval, upon request, a site-specific performance evaluation test plan
for the continuous automated sampling system performance evaluation
required in paragraph (q)(5)(ii) of this section. In addition, each
quality control program shall include, at a minimum, a written protocol
that describes procedures for each of the operations described in
paragraphs (q)(7)(i)(A) through (q)(7)(i)(F) of this section.
(A) Correct placement, installation of the continuous automated
sampling system such that the system is collecting a representative
sample of gas;
(B) Initial and subsequent calibration of flow such that the sample
collection rate of the continuous automated sampling system is known and
verifiable;
(C) Procedures to assure representative (e.g., proportional or
isokinetic) sampling;
(D) Preventive maintenance of the continuous automated sampling
system, including spare parts inventory and procedures for cleaning
equipment, replacing sample collection media, or other servicing at the
end of each sample collection period;
(E) Data recording and reporting, including an automated indicator
and recording device to show when the continuous automated monitoring
system is operating and collecting data and when it is not collecting
data;
(F) Accuracy audit procedures for analytical methods; and
(G) Program of corrective action for a malfunctioning continuous
automated sampling system.
(ii) The performance evaluation test plan shall include the
evaluation program objectives, an evaluation program summary, the
performance evaluation schedule, data quality objectives, and both an
internal and external quality assurance program. Data quality objectives
are the pre-evaluation expectations of precision, accuracy, and
completeness of data. The internal quality assurance program shall
include, at a minimum, the activities planned by routine operators and
analysts to provide an assessment of continuous automated sampling
system performance, for example, plans for relative accuracy testing
using the appropriate reference method in 60.58b(p)(3), and an
assessment of quality of analysis results. The external quality
assurance program shall include, at a minimum, systems audits that
include the opportunity for on-site evaluation by the Administrator of
instrument calibration, data validation, sample logging, and
documentation of quality control data and field maintenance activities.
[[Page 267]]
(6) Conduct a performance evaluation of each continuous automated
sampling system in accordance with the site-specific monitoring plan.
(7) Operate and maintain the continuous automated sampling system in
continuous operation according to the site-specific monitoring plan.
[60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997;
65 FR 61753, Oct. 17, 2000; 66 FR 57827, Nov. 16, 2001; 71 FR 27337, May
10, 2006]
Sec. 60.59b Reporting and recordkeeping requirements.
(a) The owner or operator of an affected facility with a capacity to
combust greater than 250 tons per day shall submit, on or before the
date the application for a construction permit is submitted under 40 CFR
part 51, subpart I, or part 52, as applicable, the items specified in
paragraphs (a)(1) through (a)(4) of this section.
(1) The preliminary and final draft materials separation plans
required by Sec. 60.57b(a)(1) and (a)(5).
(2) A copy of the notification of the public meeting required by
Sec. 60.57b(a)(1)(ii).
(3) A transcript of the public meeting required by Sec.
60.57b(a)(2).
(4) A copy of the document summarizing responses to public comments
required by Sec. 60.57b(a)(3).
(b) The owner or operator of an affected facility with a capacity to
combust greater than 250 tons per day shall submit a notification of
construction, which includes the information specified in paragraphs
(b)(1) through (b)(5) of this section.
(1) Intent to construct.
(2) Planned initial startup date.
(3) The types of fuels that the owner or operator plans to combust
in the affected facility.
(4) The municipal waste combustor unit capacity, and supporting
capacity calculations prepared in accordance with Sec. 60.58b(j).
(5) Documents associated with the siting requirements under Sec.
60.57b (a) and (b), as specified in paragraphs (b)(5)(i) through
(b)(5)(v) of this section.
(i) The siting analysis required by Sec. 60.57b (b)(1) and (b)(2).
(ii) The final materials separation plan for the affected facility
required by Sec. 60.57b(a)(10).
(iii) A copy of the notification of the public meeting required by
Sec. 60.57b(b)(3)(ii).
(iv) A transcript of the public meeting required by Sec.
60.57b(b)(4).
(v) A copy of the document summarizing responses to public comments
required by Sec. 60.57b (a)(9) and (b)(5).
(c) The owner or operator of an air curtain incinerator subject to
the opacity limit under Sec. 60.56b shall provide a notification of
construction that includes the information specified in paragraphs
(b)(1) through (b)(4) of this section.
(d) The owner or operator of an affected facility subject to the
standards under Sec. Sec. 60.52b, 60.53b, 60.54b, 60.55b, and 60.57b
shall maintain records of the information specified in paragraphs (d)(1)
through (d)(15) of this section, as applicable, for each affected
facility for a period of at least 5 years.
(1) The calendar date of each record.
(2) The emission concentrations and parameters measured using
continuous monitoring systems as specified under paragraphs (d)(2)(i)
and (d)(2)(ii) of this section.
(i) The measurements specified in paragraphs (d)(2)(i)(A) through
(d)(2)(i)(F) of this section shall be recorded and be available for
submittal to the Administrator or review on site by an EPA or State
inspector.
(A) All 6-minute average opacity levels as specified under Sec.
60.58b(c).
(B) All 1-hour average sulfur dioxide emission concentrations as
specified under Sec. 60.58b(e).
(C) All 1-hour average nitrogen oxides emission concentrations as
specified under Sec. 60.58b(h).
(D) All 1-hour average carbon monoxide emission concentrations,
municipal waste combustor unit load measurements, and particulate matter
control device inlet temperatures as specified under Sec. 60.58b(i).
(E) For owners and operators who elect to continuously monitor
particulate matter, cadmium, lead, mercury, or hydrogen chloride
emissions instead of conducting performance testing using EPA manual
test methods, all 1-
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hour average particulate matter, cadmium, lead, mercury, or hydrogen
chloride emission concentrations as specified under Sec. 60.58b(n).
(ii) The average concentrations and percent reductions, as
applicable, specified in paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(F)
of this section shall be computed and recorded, and shall be available
for submittal to the Administrator or review on-site by an EPA or State
inspector.
(A) All 24-hour daily geometric average sulfur dioxide emission
concentrations and all 24-hour daily geometric average percent
reductions in sulfur dioxide emissions as specified under Sec.
60.58b(e).
(B) All 24-hour daily arithmetic average nitrogen oxides emission
concentrations as specified under Sec. 60.58b(h).
(C) All 4-hour block or 24-hour daily arithmetic average carbon
monoxide emission concentrations, as applicable, as specified under
Sec. 60.58b(i).
(D) All 4-hour block arithmetic average municipal waste combustor
unit load levels and particulate matter control device inlet
temperatures as specified under Sec. 60.58b(i).
(E) For owners and operators who elect to continuously monitor
particulate matter, cadmium, lead, mercury, or hydrogen chloride
emissions instead of conducting performance testing using EPA manual
test methods, all 24-hour daily arithmetic average particulate matter,
cadmium, lead, mercury, or hydrogen chloride emission concentrations as
specified under Sec. 60.58b(n).
(F) For owners and operators who elect to use a continuous automated
sampling system to monitor mercury or dioxin/furan instead of conducting
performance testing using EPA manual test methods, all integrated 24-
hour mercury concentrations or all integrated 2-week dioxin/furan
concentrations as specified under Sec. 60.586(p).
(3) Identification of the calendar dates when any of the average
emission concentrations, percent reductions, or operating parameters
recorded under paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(F) of this
section, or the opacity levels recorded under paragraph (d)(2)(i)(A) of
this section are above the applicable limits, with reasons for such
exceedances and a description of corrective actions taken.
(4) For affected facilities that apply activated carbon for mercury
or dioxin/furan control, the records specified in paragraphs (d)(4)(i)
through (d)(4)(v) of this section.
(i) The average carbon mass feed rate (in kilograms per hour or
pounds per hour) estimated as required under Sec. 60.58b(m)(1)(i) of
this section during the initial mercury performance test and all
subsequent annual performance tests, with supporting calculations.
(ii) The average carbon mass feed rate (in kilograms per hour or
pounds per hour) estimated as required under Sec. 60.58b(m)(1)(ii) of
this section during the initial dioxin/furan performance test and all
subsequent annual performance tests, with supporting calculations.
(iii) The average carbon mass feed rate (in kilograms per hour or
pounds per hour) estimated for each hour of operation as required under
Sec. 60.58b(m)(3)(ii) of this section, with supporting calculations.
(iv) The total carbon usage for each calendar quarter estimated as
specified by paragraph 60.58b(m)(3) of this section, with supporting
calculations.
(v) Carbon injection system operating parameter data for the
parameter(s) that are the primary indicator(s) of carbon feed rate
(e.g., screw feeder speed).
(5) [Reserved]
(6) Identification of the calendar dates and times (hours) for which
valid hourly data specified in paragraphs (d)(6)(i) through (d)(6)(vi)
of this section have not been obtained, or continuous automated sampling
systems were not operated as specified in paragraph (d)(6)(vii) of this
section, including reasons for not obtaining the data and a description
of corrective actions taken.
(i) Sulfur dioxide emissions data;
(ii) Nitrogen oxides emissions data;
(iii) Carbon monoxide emissions data;
(iv) Municipal waste combustor unit load data;
(v) Particulate matter control device temperature data; and
(vi) For owners and operators who elect to continuously monitor
particulate matter, cadmium, lead, mercury,
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or hydrogen chloride emissions instead of performance testing by EPA
manual test methods, particulate matter, cadmium, lead, mercury, or
hydrogen chloride emissions data.
(vii) For owners and operators who elect to use continuous automated
sampling systems for dioxins/furans or mercury as allowed under
``60.58b(p) and (q), dates and times when the sampling systems were not
operating or were not collecting a valid sample.
(7) Identification of each occurrence that sulfur dioxide emissions
data, nitrogen oxides emissions data, particulate matter emissions data,
cadmium emissions data, lead emissions data, mercury emissions data,
hydrogen chloride emissions data, or dioxin/furan emissions data (for
owners and operators who elect to continuously monitor particulate
matter, cadmium, lead, mercury, or hydrogen chloride, or who elect to
use continuous automated sampling systems for dioxin/furan or mercury
emissions, instead of conducting performance testing using EPA manual
test methods) or operational data (i.e., carbon monoxide emissions, unit
load, and particulate matter control device temperature) have been
excluded from the calculation of average emission concentrations or
parameters, and the reasons for excluding the data.
(8) The results of daily drift tests and quarterly accuracy
determinations for sulfur dioxide, nitrogen oxides, and carbon monoxide
continuous emission monitoring systems, as required under appendix F of
this part, procedure 1.
(9) The test reports documenting the results of the initial
performance test and all annual performance tests listed in paragraphs
(d)(9)(i) and (d)(9)(ii) of this section shall be recorded along with
supporting calculations.
(i) The results of the initial performance test and all annual
performance tests conducted to determine compliance with the particulate
matter, opacity, cadmium, lead, mercury, dioxins/furans, hydrogen
chloride, and fugitive ash emission limits.
(ii) For the initial dioxin/furan performance test and all
subsequent dioxin/furan performance tests recorded under paragraph
(d)(9)(i) of this section, the maximum demonstrated municipal waste
combustor unit load and maximum demonstrated particulate matter control
device temperature (for each particulate matter control device).
(10) An owner or operator who elects to continuously monitor
emissions instead of performance testing by EPA manual methods must
maintain records specified in paragraphs (10)(i) through (iii) of this
section.
(i) For owners and operators who elect to continuously monitor
particulate matter instead of conducting performance testing using EPA
manual test methods), as required under appendix F of this part,
procedure 2, the results of daily drift tests and quarterly accuracy
determinations for particulate matter.
(ii) For owners and operators who elect to continuously monitor
cadmium, lead, mercury, or hydrogen chloride instead of conducting EPA
manual test methods, the results of all quality evaluations, such as
daily drift tests and periodic accuracy determinations, specified in the
approved site-specific performance evaluation test plan required by
Sec. 60.58b(o)(5).
(iii) For owners and operators who elect to use continuous automated
sampling systems for dioxin/furan or mercury, the results of all quality
evaluations specified in the approved site-specific performance
evaluation test plan required by Sec. 60.58b(q)(5).
(11) For each affected facility subject to the siting provisions
under Sec. 60.57b, the siting analysis, the final materials separation
plan, a record of the location and date of the public meetings, and the
documentation of the responses to public comments received at the public
meetings.
(12) The records specified in paragraphs (d)(12)(i) through
(d)(12)(iv) of this section.
(i) Records showing the names of the municipal waste combustor chief
facility operator, shift supervisors, and control room operators who
have been provisionally certified by the American Society of Mechanical
Engineers or an equivalent State-approved certification program as
required by Sec. 60.54b(a) including the dates of initial and renewal
certifications and documentation of current certification.
[[Page 270]]
(ii) Records showing the names of the municipal waste combustor
chief facility operator, shift supervisors, and control room operators
who have been fully certified by the American Society of Mechanical
Engineers or an equivalent State-approved certification program as
required by Sec. 60.54b(b) including the dates of initial and renewal
certifications and documentation of current certification.
(iii) Records showing the names of the municipal waste combustor
chief facility operator, shift supervisors, and control room operators
who have completed the EPA municipal waste combustor operator training
course or a State-approved equivalent course as required by Sec.
60.54b(d) including documentation of training completion.
(iv) Records of when a certified operator is temporarily off site.
Include two main items:
(A) If the certified chief facility operator and certified shift
supervisor are off site for more than 12 hours, but for 2 weeks or less,
and no other certified operator is on site, record the dates that the
certified chief facility operator and certified shift supervisor were
off site.
(B) When all certified chief facility operators and certified shift
supervisors are off site for more than 2 weeks and no other certified
operator is on site, keep records of four items:
(1) Time of day that all certified persons are off site.
(2) The conditions that cause those people to be off site.
(3) The corrective actions taken by the owner or operator of the
affected facility to ensure a certified chief facility operator or
certified shift supervisor is on site as soon as practicable.
(4) Copies of the written reports submitted every 4 weeks that
summarize the actions taken by the owner or operator of the affected
facility to ensure that a certified chief facility operator or certified
shift supervisor will be on site as soon as practicable.
(13) Records showing the names of persons who have completed a
review of the operating manual as required by Sec. 60.54b(f) including
the date of the initial review and subsequent annual reviews.
(14) For affected facilities that apply activated carbon,
identification of the calendar dates when the average carbon mass feed
rates recorded under paragraph (d)(4)(iii) of this section were less
than either of the hourly carbon feed rates estimated during performance
tests for mercury emissions and recorded under paragraphs (d)(4)(i) and
(d)(4)(ii) of this section, respectively, with reasons for such feed
rates and a description of corrective actions taken. For affected
facilities that apply activated carbon, identification of the calendar
dates when the average carbon mass feed rates recorded under paragraph
(d)(4)(iii) of this section were less than either of the hourly carbon
feed rates estimated during performance tests for dioxin/furan emissions
and recorded under paragraphs (d)(4)(i) and (d)(4)(ii) of this section,
respectively, with reasons for such feed rates and a description of
corrective actions taken.
(15) For affected facilities that apply activated carbon for mercury
or dioxin/furan control, identification of the calendar dates when the
carbon injection system operating parameter(s) that are the primary
indicator(s) of carbon mass feed rate (e.g., screw feeder speed)
recorded under paragraph (d)(4)(v) of this section are below the
level(s) estimated during the performance tests as specified in Sec.
60.58b(m)(1)(i) and Sec. 60.58b(m)(1)(ii) of this section, with reasons
for such occurrences and a description of corrective actions taken.
(e) The owner or operator of an air curtain incinerator subject to
the opacity limit under Sec. 60.56b shall maintain records of results
of the initial opacity performance test and subsequent performance tests
required by Sec. 60.58b(l) for a period of at least 5 years.
(f) The owner or operator of an affected facility shall submit the
information specified in paragraphs (f)(1) through (f)(6) of this
section in the initial performance test report.
(1) The initial performance test data as recorded under paragraphs
(d)(2)(ii)(A) through (d)(2)(ii)(D) of this section for the initial
performance test for sulfur dioxide, nitrogen oxides, carbon monoxide,
municipal waste combustor unit load level, and particulate
[[Page 271]]
matter control device inlet temperature.
(2) The test report documenting the initial performance test
recorded under paragraph (d)(9) of this section for particulate matter,
opacity, cadmium, lead, mercury, dioxins/furans, hydrogen chloride, and
fugitive ash emissions.
(3) The performance evaluation of the continuous emission monitoring
system using the applicable performance specifications in appendix B of
this part.
(4) The maximum demonstrated municipal waste combustor unit load and
maximum demonstrated particulate matter control device inlet
temperature(s) established during the initial dioxin/furan performance
test as recorded under paragraph (d)(9) of this section.
(5) For affected facilities that apply activated carbon injection
for mercury control, the owner or operator shall submit the average
carbon mass feed rate recorded under paragraph (d)(4)(i) of this
section.
(6) For those affected facilities that apply activated carbon
injection for dioxin/furan control, the owner or operator shall submit
the average carbon mass feed rate recorded under paragraph (d)(4)(ii) of
this section.
(g) Following the first year of municipal waste combustor operation,
the owner or operator of an affected facility shall submit an annual
report that includes the information specified in paragraphs (g)(1)
through (g)(5) of this section, as applicable, no later than February 1
of each year following the calendar year in which the data were
collected (once the unit is subject to permitting requirements under
title V of the Act, the owner or operator of an affected facility must
submit these reports semiannually).
(1) A summary of data collected for all pollutants and parameters
regulated under this subpart, which includes the information specified
in paragraphs (g)(1)(i) through (g)(1)(v) of this section.
(i) A list of the particulate matter, opacity, cadmium, lead,
mercury, dioxins/furans, hydrogen chloride, and fugitive ash emission
levels achieved during the performance tests recorded under paragraph
(d)(9) of this section.
(ii) A list of the highest emission level recorded for sulfur
dioxide, nitrogen oxides, carbon monoxide, particulate matter, cadmium,
lead, mercury, hydrogen chloride, and dioxin/furan (for owners and
operators who elect to continuously monitor particulate matter, cadmium,
lead, mercury, hydrogen chloride, and dioxin/furan emissions instead of
conducting performance testing using EPA manual test methods), municipal
waste combustor unit load level, and particulate matter control device
inlet temperature based on the data recorded under paragraphs
(d)(2)(ii)(A) through (d)(2)(ii)(E) of this section.
(iii) List the highest opacity level measured, based on the data
recorded under paragraph (d)(2)(i)(A) of this section.
(iv) Periods when valid data were not obtained as described in
paragraphs (g)(1)(iv)(A) through (g)(1)(iv)(C) of this section.
(A) The total number of hours per calendar quarter and hours per
calendar year that valid data for sulfur dioxide, nitrogen oxides,
carbon monoxide, municipal waste combustor unit load, or particulate
matter control device temperature data were not obtained based on the
data recorded under paragraph (d)(6) of this section.
(B) For owners and operators who elect to continuously monitor
particulate matter, cadmium, lead, mercury, and hydrogen chloride
emissions instead of conducting performance testing using EPA manual
test methods, the total number of hours per calendar quarter and hours
per calendar year that valid data for particulate matter, cadmium, lead,
mercury, and hydrogen chloride were not obtained based on the data
recorded under paragraph (d)(6) of this section. For each continuously
monitored pollutant or parameter, the hours of valid emissions data per
calendar quarter and per calendar year expressed as a percent of the
hours per calendar quarter or year that the affected facility was
operating and combusting municipal solid waste.
(C) For owners and operators who elect to use continuous automated
sampling systems for dioxin/furan or mercury, the total number of hours
per
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calendar quarter and hours per calendar year that the sampling systems
were not operating or were not collecting a valid sample based on the
data recorded under paragraph (d)(6)(vii) of this section. Also, the
number of hours during which the continuous automated sampling system
was operating and collecting a valid sample as a percent of hours per
calendar quarter or year that the affected facility was operating and
combusting municipal solid waste.
(v) Periods when valid data were excluded from the calculation of
average emission concentrations or parameters as described in paragraphs
(g)(1)(v)(A) through (g)(1)(v)(C) of this section.
(A) The total number of hours that data for sulfur dioxide, nitrogen
oxides, carbon monoxide, municipal waste combustor unit load, and
particulate matter control device temperature were excluded from the
calculation of average emission concentrations or parameters based on
the data recorded under paragraph (d)(7) of this section.
(B) For owners and operators who elect to continuously monitor
particulate matter, cadmium, lead, mercury, or hydrogen chloride
emissions instead of conducting performance testing using EPA manual
test methods, the total number of hours that data for particulate
matter, cadmium, lead, mercury, or hydrogen chloride were excluded from
the calculation of average emission concentrations or parameters based
on the data recorded under paragraph (d)(7) of this section.
(C) For owners and operators who elect to use continuous automated
sampling systems for dioxin/furan or mercury, the total number of hours
that data for mercury and dioxin/furan were excluded from the
calculation of average emission concentrations or parameters based on
the data recorded under paragraph (d)(7) of this section.
(2) The summary of data reported under paragraph (g)(1) of this
section shall also provide the types of data specified in paragraphs
(g)(1)(i) through (g)(1)(vi) of this section for the calendar year
preceding the year being reported, in order to provide the Administrator
with a summary of the performance of the affected facility over a 2-year
period.
(3) The summary of data including the information specified in
paragraphs (g)(1) and (g)(2) of this section shall highlight any
emission or parameter levels that did not achieve the emission or
parameter limits specified under this subpart.
(4) A notification of intent to begin the reduced dioxin/furan
performance testing schedule specified in Sec. 60.58b(g)(5)(iii) of
this section during the following calendar year and notification of
intent to apply the average carbon mass feed rate and associated carbon
injection system operating parameter levels as established in Sec.
60.58b(m) to similarly designed and equipped units on site.
(5) Documentation of periods when all certified chief facility
operators and certified shift supervisors are off site for more than 12
hours.
(h) The owner or operator of an affected facility shall submit a
semiannual report that includes the information specified in paragraphs
(h)(1) through (h)(5) of this section for any recorded pollutant or
parameter that does not comply with the pollutant or parameter limit
specified under this subpart, according to the schedule specified under
paragraph (h)(6) of this section.
(1) The semiannual report shall include information recorded under
paragraph (d)(3) of this section for sulfur dioxide, nitrogen oxides,
carbon monoxide, particulate matter, cadmium, lead, mercury, hydrogen
chloride, dioxin/furan (for owners and operators who elect to
continuously monitor particulate matter, cadmium, lead, mercury, or
hydrogen chloride, or who elect to use continuous automated sampling
systems for dioxin/furan or mercury emissions, instead of conducting
performance testing using EPA manual test methods) municipal waste
combustor unit load level, particulate matter control device inlet
temperature, and opacity.
(2) For each date recorded as required by paragraph (d)(3) of this
section and reported as required by paragraph (h)(1) of this section,
the semiannual report shall include the sulfur dioxide, nitrogen oxides,
carbon monoxide, municipal waste combustor unit load level, particulate
matter control device
[[Page 273]]
inlet temperature, or opacity data, as applicable, recorded under
paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(D) and (d)(2)(i)(A) of this
section, as applicable.
(3) If the test reports recorded under paragraph (d)(9) of this
section document any particulate matter, opacity, cadmium, lead,
mercury, dioxins/furans, hydrogen chloride, and fugitive ash emission
levels that were above the applicable pollutant limits, the semiannual
report shall include a copy of the test report documenting the emission
levels and the corrective actions taken.
(4) The semiannual report shall include the information recorded
under paragraph (d)(15) of this section for the carbon injection system
operating parameter(s) that are the primary indicator(s) of carbon mass
feed rate.
(5) For each operating date reported as required by paragraph (h)(4)
of this section, the semiannual report shall include the carbon feed
rate data recorded under paragraph (d)(4)(iii) of this section.
(6) Semiannual reports required by paragraph (h) of this section
shall be submitted according to the schedule specified in paragraphs
(h)(6)(i) and (h)(6)(ii) of this section.
(i) If the data reported in accordance with paragraphs (h)(1)
through (h)(5) of this section were collected during the first calendar
half, then the report shall be submitted by August 1 following the first
calendar half.
(ii) If the data reported in accordance with paragraphs (h)(1)
through (h)(5) of this section were collected during the second calendar
half, then the report shall be submitted by February 1 following the
second calendar half.
(i) The owner or operator of an air curtain incinerator subject to
the opacity limit under Sec. 60.56b shall submit the results of the
initial opacity performance test and all subsequent annual performance
tests recorded under paragraph (e) of this section. Annual performance
tests shall be submitted by February 1 of the year following the year of
the performance test.
(j) All reports specified under paragraphs (a), (b), (c), (f), (g),
(h), and (i) of this section shall be submitted as a paper copy,
postmarked on or before the submittal dates specified under these
paragraphs, and maintained onsite as a paper copy for a period of 5
years.
(k) All records specified under paragraphs (d) and (e) of this
section shall be maintained onsite in either paper copy or computer-
readable format, unless an alternative format is approved by the
Administrator.
(l) If the owner or operator of an affected facility would prefer a
different annual or semiannual date for submitting the periodic reports
required by paragraphs (g), (h) and (i) of this section, then the dates
may be changed by mutual agreement between the owner or operator and the
Administrator according to the procedures specified in Sec. 60.19(c) of
subpart A of this part.
(m) Owners and operators who elect to continuously monitor
particulate matter, cadmium, lead, mercury, or hydrogen chloride, or who
elect to use continuous automated sampling systems for dioxin/furan or
mercury emissions, instead of conducting performance testing using EPA
manual test methods must notify the Administrator one month prior to
starting or stopping use of the particulate matter, cadmium, lead,
mercury, hydrogen chloride, and dioxin/furan continuous emission
monitoring systems or continuous automated sampling systems.
(n) Additional recordkeeping and reporting requirements for affected
facilities with continuous cadmium, lead, mercury, or hydrogen chloride
monitoring systems. In addition to complying with the requirements
specified in paragraphs (a) through (m) of this section, the owner or
operator of an affected source who elects to install a continuous
emission monitoring system for cadmium, lead, mercury, or hydrogen
chloride as specified in Sec. 60.58b(n), shall maintain the records in
paragraphs (n)(1) through (n)(10) of this section and report the
information in paragraphs (n)(11) through (n)(12) of this section,
relevant to the continuous emission monitoring system:
(1) All required continuous emission monitoring measurements
(including monitoring data recorded during unavoidable continuous
emission monitoring system breakdowns and out-of-control periods);
[[Page 274]]
(2) The date and time identifying each period during which the
continuous emission monitoring system was inoperative except for zero
(low-level) and high-level checks;
(3) The date and time identifying each period during which the
continuous emission monitoring system was out of control, as defined in
Sec. 60.58b(o)(4);
(4) The specific identification (i.e., the date and time of
commencement and completion) of each period of excess emissions and
parameter monitoring exceedances, as defined in the standard, that
occurs during startups, shutdowns, and malfunctions of the affected
source;
(5) The specific identification (i.e., the date and time of
commencement and completion) of each time period of excess emissions and
parameter monitoring exceedances, as defined in the standard, that
occurs during periods other than startups, shutdowns, and malfunctions
of the affected source;
(6) The nature and cause of any malfunction (if known);
(7) The corrective action taken to correct any malfunction or
preventive measures adopted to prevent further malfunctions;
(8) The nature of the repairs or adjustments to the continuous
emission monitoring system that was inoperative or out of control;
(9) All procedures that are part of a quality control program
developed and implemented for the continuous emission monitoring system
under Sec. 60.58b(o);
(10) When more than one continuous emission monitoring system is
used to measure the emissions from one affected source (e.g., multiple
breechings, multiple outlets), the owner or operator shall report the
results as required for each continuous emission monitoring system.
(11) Submit to EPA for approval, the site-specific monitoring plan
required by Sec. 60.58b(n)(13) and Sec. 60.58b(o), including the site-
specific performance evaluation test plan for the continuous emission
monitoring system required by Sec. 60.58(b)(o)(5). The owner or
operator shall maintain copies of the site-specific monitoring plan on
record for the life of the affected source to be made available for
inspection, upon request, by the Administrator. If the site-specific
monitoring plan is revised and approved, the owner or operator shall
keep previous (i.e., superseded) versions of the plan on record to be
made available for inspection, upon request, by the Administrator, for a
period of 5 years after each revision to the plan.
(12) Submit information concerning all out-of-control periods for
each continuous emission monitoring system, including start and end
dates and hours and descriptions of corrective actions taken, in the
annual or semiannual reports required in paragraphs (g) or (h) of this
section.
(o) Additional recordkeeping and reporting requirements for affected
facilities with continuous automated sampling systems for dioxin/furan
or mercury monitoring. In addition to complying with the requirements
specified in paragraphs (a) through (m) of this section, the owner or
operator of an affected source who elects to install a continuous
automated sampling system for dioxin/furan or mercury, as specified in
Sec. 60.58b(p), shall maintain the records in paragraphs (o)(1) through
(o)(10) of this section and report the information in (o)(11) and
(o)(12) of this section, relevant to the continuous automated sampling
system:
(1) All required 24-hour integrated mercury concentration or 2-week
integrated dioxin/furan concentration data (including any data obtained
during unavoidable system breakdowns and out-of-control periods);
(2) The date and time identifying each period during which the
continuous automated sampling system was inoperative;
(3) The date and time identifying each period during which the
continuous automated sampling system was out of control, as defined in
Sec. 60.58b(q)(4);
(4) The specific identification (i.e., the date and time of
commencement and completion) of each period of excess emissions and
parameter monitoring exceedances, as defined in the standard, that
occurs during startups, shutdowns, and malfunctions of the affected
source;
[[Page 275]]
(5) The specific identification (i.e., the date and time of
commencement and completion) of each time period of excess emissions and
parameter monitoring exceedances, as defined in the standard, that
occurs during periods other than startups, shutdowns, and malfunctions
of the affected source;
(6) The nature and cause of any malfunction (if known);
(7) The corrective action taken to correct any malfunction or
preventive measures adopted to prevent further malfunctions;
(8) The nature of the repairs or adjustments to the continuous
automated sampling system that was inoperative or out of control;
(9) All procedures that are part of a quality control program
developed and implemented for the continuous automated sampling system
under Sec. 60.58b(q);
(10) When more than one continuous automated sampling system is used
to measure the emissions from one affected source (e.g., multiple
breechings, multiple outlets), the owner or operator shall report the
results as required for each system.
(11) Submit to EPA for approval, the site-specific monitoring plan
required by Sec. 60.58b(p)(11) and Sec. 60.58b(q) including the site-
specific performance evaluation test plan for the continuous emission
monitoring system required by Sec. 60.58(b)(q)(5). The owner or
operator shall maintain copies of the site-specific monitoring plan on
record for the life of the affected source to be made available for
inspection, upon request, by the Administrator. If the site-specific
monitoring plan is revised and approved, the owner or operator shall
keep previous (i.e., superseded) versions of the plan on record to be
made available for inspection, upon request, by the Administrator, for a
period of 5 years after each revision to the plan.
(12) Submit information concerning all out-of-control periods for
each continuous automated sampling system, including start and end dates
and hours and descriptions of corrective actions taken in the annual or
semiannual reports required in paragraphs (g) or (h) of this section.
[60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45121, 45127, Aug. 25,
1997; 71 FR 27345, May 10, 2006]
Subpart Ec_Standards of Performance for New Stationary Sources:
Hospital/Medical/Infectious Waste Incinerators
Source: 62 FR 48382, Sept. 15, 1997, unless otherwise noted.
Sec. 60.50c Applicability and delegation of authority.
(a) Except as provided in paragraphs (b) through (h) of this
section, the affected facility to which this subpart applies is each
individual hospital/medical/infectious waste incinerator (HMIWI):
(1) For which construction is commenced after June 20, 1996 but no
later than December 1, 2008; or
(2) For which modification is commenced after March 16, 1998 but no
later than April 6, 2010.
(3) For which construction is commenced after December 1, 2008; or
(4) For which modification is commenced after April 6, 2010.
(b) A combustor is not subject to this subpart during periods when
only pathological waste, low-level radioactive waste, and/or
chemotherapeutic waste (all defined in Sec. 60.51c) is burned, provided
the owner or operator of the combustor:
(1) Notifies the Administrator of an exemption claim; and
(2) Keeps records on a calendar quarter basis of the periods of time
when only pathological waste, low-level radioactivewaste and/or
chemotherapeutic waste is burned.
(c) Any co-fired combustor (defined in Sec. 60.51c) is not subject
to this subpart if the owner or operator of the co-fired combustor:
(1) Notifies the Administrator of an exemption claim;
(2) Provides an estimate of the relative amounts of hospital waste,
medical/infectious waste, and other fuels and wastes to be combusted;
and
(3) Keeps records on a calendar quarter basis of the weight of
hospital
[[Page 276]]
waste and medical/infectious waste combusted, and the weight of all
other fuels and wastes combusted at the co-fired combustor.
(d) Any combustor required to have a permit under section 3005 of
the Solid Waste Disposal Act is not subject to this subpart.
(e) Any combustor which meets the applicability requirements under
subpart Cb, Ea, or Eb of this part (standards or guidelines for certain
municipal waste combustors) is not subject to this subpart.
(f) Any pyrolysis unit (defined in Sec. 60.51c) is not subject to
this subpart.
(g) Cement kilns firing hospital waste and/or medical/infectious
waste are not subject to this subpart.
(h) Physical or operational changes made to an existing HMIWI solely
for the purpose of complying with emission guidelines under subpart Ce
are not considered a modification and do not result in an existing HMIWI
becoming subject to this subpart.
(i) In delegating implementation and enforcement authority to a
State under section 111(c) of the Clean Air Act, the following
authorities shall be retained by the Administrator and not transferred
to a State:
(1) The requirements of Sec. 60.56c(i) establishing operating
parameters when using controls other than those listed in Sec.
60.56c(d).
(2) Approval of alternative methods of demonstrating compliance
under Sec. 60.8 including:
(i) Approval of CEMS for PM, HCl, multi-metals, and Hg where used
for purposes of demonstrating compliance,
(ii) Approval of continuous automated sampling systems for dioxin/
furan and Hg where used for purposes of demonstrating compliance, and
(iii) Approval of major alternatives to test methods;
(3) Approval of major alternatives to monitoring;
(4) Waiver of recordkeeping requirements; and
(5) Performance test and data reduction waivers under Sec. 60.8(b).
(j) Affected facilities subject to this subpart are not subject to
the requirements of 40 CFR part 64.
(i) Approval of CEMS for PM, HCl, multi-metals, and Hg where used
for purposes of demonstrating compliance,
(ii) Approval of continuous automated sampling systems for dioxin/
furan and Hg where used for purposes of demonstrating compliance, and
(iii) Approval of major alternatives to test methods;
(3) Approval of major alternatives to monitoring;
(4) Waiver of recordkeeping requirements; and
(5) Performance test and data reduction waivers under Sec. 60.8(b).
(k) The requirements of this subpart shall become effective March
16, 1998
(l) Beginning September 15, 2000, or on the effective date of an
EPA-approved operating permit program under Clean Air Act title V and
the implementing regulations under 40 CFR part 70 in the State in which
the unit is located, whichever date is later, affected facilities
subject to this subpart shall operate pursuant to a permit issued under
the EPA approved State operating permit program.
(m) The requirements of this subpart as promulgated on September 15,
1997, shall apply to the affected facilities defined in paragraph (a)(1)
and (2) of this section until the applicable compliance date of the
requirements of subpart Ce of this part, as amended on October 6, 2009.
Upon the compliance date of the requirements of the amended subpart Ce
of this part, affected facilities as defined in paragraph (a) of this
section are no longer subject to the requirements of this subpart, but
are subject to the requirements of subpart Ce of this part, as amended
on October 6, 2009, except where the emissions limits of this subpart as
promulgated on September 15, 1997 are more stringent than the emissions
limits of the amended subpart Ce of this part. Compliance with subpart
Ce of this part, as amended on October 6, 2009 is required on or before
the date 3 years after EPA approval of the State plan for States in
which an affected facility as defined in paragraph (a) of this section
is located (but not later than the date 5 years after promulgation of
the amended subpart).
[[Page 277]]
(n) The requirements of this subpart, as amended on October 6, 2009,
shall become effective April 6, 2010.
[62 FR 48382, Sept. 15, 1997, as amended at 74 FR 51408, Oct. 6, 2009]
Sec. 60.51c Definitions.
Bag leak detection system means an instrument that is capable of
monitoring PM loadings in the exhaust of a fabric filter in order to
detect bag failures. A bag leak detection system includes, but is not
limited to, an instrument that operates on triboelectric, light-
scattering, light-transmittance, or other effects to monitor relative PM
loadings.
Batch HMIWI means an HMIWI that is designed such that neither waste
charging nor ash removal can occur during combustion.
Biologicals means preparations made from living organisms and their
products, including vaccines, cultures, etc., intended for use in
diagnosing, immunizing, or treating humans or animals or in research
pertaining thereto.
Blood products means any product derived from human blood, including
but not limited to blood plasma, platelets, red or white blood
corpuscles, and other derived licensed products, such as interferon,
etc.
Body fluids means liquid emanating or derived from humans and
limited to blood; dialysate; amniotic, cerebrospinal, synovial, pleural,
peritoneal and pericardial fluids; and semen and vaginal secretions.
Bypass stack means a device used for discharging combustion gases to
avoid severe damage to the air pollution control device or other
equipment.
Chemotherapeutic waste means waste material resulting from the
production or use of antineoplastic agents used for the purpose of
stopping or reversing the growth of malignant cells.
Co-fired combustor means a unit combusting hospital waste and/or
medical/infectious waste with other fuels or wastes (e.g., coal,
municipal solid waste) and subject to an enforceable requirement
limiting the unit to combusting a fuel feed stream, 10 percent or less
of the weight of which is comprised, in aggregate, of hospital waste and
medical/infectious waste as measured on a calendar quarter basis. For
purposes of this definition, pathological waste, chemotherapeutic waste,
and low-level radioactive waste are considered ``other'' wastes when
calculating the percentage of hospital waste and medical/infectious
waste combusted.
Commercial HMIWI means a HMIWI which offers incineration services
for hospital/medical/infectious waste generated offsite by firms
unrelated to the firm that owns the HMIWI.
Continuous emission monitoring system or CEMS means a monitoring
system for continuously measuring and recording the emissions of a
pollutant from an affected facility.
Continuous HMIWI means an HMIWI that is designed to allow waste
charging and ash removal during combustion.
Dioxins/furans means the combined emissions of tetra-through octa-
chlorinated dibenzo-para-dioxins and dibenzofurans, as measured by EPA
Reference Method 23.
Dry scrubber means an add-on air pollution control system that
injects dry alkaline sorbent (dry injection) or sprays an alkaline
sorbent (spray dryer) to react with and neutralize acid gases in the
HMIWI exhaust stream forming a dry powder material.
Fabric filter or baghouse means an add-on air pollution control
system that removes particulate matter (PM) and nonvaporous metals
emissions by passing flue gas through filter bags.
Facilities manager means the individual in charge of purchasing,
maintaining, and operating the HMIWI or the owner's or operator's
representative responsible for the management of the HMIWI. Alternative
titles may include director of facilities or vice president of support
services.
High-air phase means the stage of the batch operating cycle when the
primary chamber reaches and maintains maximum operating temperatures.
Hospital means any facility which has an organized medical staff,
maintains at least six inpatient beds, and where the primary function of
the institution is to provide diagnostic and therapeutic patient
services and continuous nursing care primarily to human inpatients who
are not related and who stay on average in excess of 24 hours
[[Page 278]]
per admission. This definition does not include facilities maintained
for the sole purpose of providing nursing or convalescent care to human
patients who generally are not acutely ill but who require continuing
medical supervision.
Hospital/medical/infectious waste incinerator or HMIWI or HMIWI unit
means any device that combusts any amount of hospital waste and/or
medical/infectious waste.
Hospital/medical/infectious waste incinerator operator or HMIWI
operator means any person who operates, controls or supervises the day-
to-day operation of an HMIWI.
Hospital waste means discards generated at a hospital, except unused
items returned to the manufacturer. The definition of hospital waste
does not include human corpses, remains, and anatomical parts that are
intended for interment or cremation.
Infectious agent means any organism (such as a virus or bacteria)
that is capable of being communicated by invasion and multiplication in
body tissues and capable of causing disease or adverse health impacts in
humans.
Intermittent HMIWI means an HMIWI that is designed to allow waste
charging, but not ash removal, during combustion.
Large HMIWI means:
(1) Except as provided in (2);
(i) An HMIWI whose maximum design waste burning capacity is more
than 500 pounds per hour; or
(ii) A continuous or intermittent HMIWI whose maximum charge rate is
more than 500 pounds per hour; or
(iii) A batch HMIWI whose maximum charge rate is more than 4,000
pounds per day.
(2) The following are not large HMIWI:
(i) A continuous or intermittent HMIWI whose maximum charge rate is
less than or equal to 500 pounds per hour; or
(ii) A batch HMIWI whose maximum charge rate is less than or equal
to 4,000 pounds per day.
Low-level radioactive waste means waste material which contains
radioactive nuclides emitting primarily beta or gamma radiation, or
both, in concentrations or quantities that exceed applicable federal or
State standards for unrestricted release. Low-level radioactive waste is
not high-level radioactive waste, spent nuclear fuel, or by-product
material as defined by the Atomic Energy Act of 1954 (42 U.S.C.
2014(e)(2)).
Malfunction means any sudden, infrequent, and not reasonably
preventable failure of air pollution control equipment, process
equipment, or a process to operate in a normal or usual manner. Failures
that are caused, in part, by poor maintenance or careless operation are
not malfunctions. During periods of malfunction the operator shall
operate within established parameters as much as possible, and
monitoring of all applicable operating parameters shall continue until
all waste has been combusted or until the malfunction ceases, whichever
comes first.
Maximum charge rate means:
(1) For continuous and intermittent HMIWI, 110 percent of the lowest
3-hour average charge rate measured during the most recent performance
test demonstrating compliance with all applicable emission limits.
(2) For batch HMIWI, 110 percent of the lowest daily charge rate
measured during the most recent performance test demonstrating
compliance with all applicable emission limits.
Maximum design waste burning capacity means:
(1) For intermittent and continuous HMIWI,
C = PV x 15,000/8,500
Where:
C = HMIWI capacity, lb/hr
PV = primary chamber volume, ft\3\
15,000 = primary chamber heat release rate factor, Btu/ft\3\/hr
8,500 = standard waste heating value, Btu/lb;
(2) For batch HMIWI,
C = PV x 4.5/8
Where:
C = HMIWI capacity, lb/hr
PV = primary chamber volume, ft\3\
4.5 = waste density, lb/ft\3\
8 = typical hours of operation of a batch HMIWI, hours.
Maximum fabric filter inlet temperature means 110 percent of the
lowest 3-hour average temperature at the inlet to the fabric filter
(taken, at a minimum,
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once every minute) measured during the most recent performance test
demonstrating compliance with the dioxin/furan emission limit.
Maximum flue gas temperature means 110 percent of the lowest 3-hour
average temperature at the outlet from the wet scrubber (taken, at a
minimum, once every minute) measured during the most recent performance
test demonstrating compliance with the mercury (Hg) emission limit.
Medical/infectious waste means any waste generated in the diagnosis,
treatment, or immunization of human beings or animals, in research
pertaining thereto, or in the production or testing of biologicals that
are listed in paragraphs (1) through (7) of this definition. The
definition of medical/infectious waste does not include hazardous waste
identified or listed under the regulations in part 261 of this chapter;
household waste, as defined in Sec. 261.4(b)(1) of this chapter; ash
from incineration of medical/infectious waste, once the incineration
process has been completed; human corpses, remains, and anatomical parts
that are intended for interment or cremation; and domestic sewage
materials identified in Sec. 261.4(a)(1) of this chapter.
(1) Cultures and stocks of infectious agents and associated
biologicals, including: Cultures from medical and pathological
laboratories; cultures and stocks of infectious agents from research and
industrial laboratories; wastes from the production of biologicals;
discarded live and attenuated vaccines; and culture dishes and devices
used to transfer, inoculate, and mix cultures.
(2) Human pathological waste, including tissues, organs, and body
parts and body fluids that are removed during surgery or autopsy, or
other medical procedures, and specimens of body fluids and their
containers.
(3) Human blood and blood products including:
(i) Liquid waste human blood;
(ii) Products of blood;
(iii) Items saturated and/or dripping with human blood; or
(iv) Items that were saturated and/or dripping with human blood that
are now caked with dried human blood; including serum, plasma, and other
blood components, and their containers, which were used or intended for
use in either patient care, testing and laboratory analysis or the
development of pharmaceuticals. Intravenous bags are also included in
this category.
(4) Sharps that have been used in animal or human patient care or
treatment or in medical, research, or industrial laboratories, including
hypodermic needles, syringes (with or without the attached needle),
pasteur pipettes, scalpel blades, blood vials, needles with attached
tubing, and culture dishes (regardless of presence of infectious
agents). Also included are other types of broken or unbroken glassware
that were in contact with infectious agents, such as used slides and
cover slips.
(5) Animal waste including contaminated animal carcasses, body
parts, and bedding of animals that were known to have been exposed to
infectious agents during research (including research in veterinary
hospitals), production of biologicals or testing of pharmaceuticals.
(6) Isolation wastes including biological waste and discarded
materials contaminated with blood, excretions, exudates, or secretions
from humans who are isolated to protect others from certain highly
communicable diseases, or isolated animals known to be infected with
highly communicable diseases.
(7) Unused sharps including the following unused, discarded sharps:
hypodermic needles, suture needles, syringes, and scalpel blades.
Medium HMIWI means:
(1) Except as provided in paragraph (2);
(i) An HMIWI whose maximum design waste burning capacity is more
than 200 pounds per hour but less than or equal to 500 pounds per hour;
or
(ii) A continuous or intermittent HMIWI whose maximum charge rate is
more than 200 pounds per hour but less than or equal to 500 pounds per
hour; or
(iii) A batch HMIWI whose maximum charge rate is more than 1,600
pounds per day but less than or equal to 4,000 pounds per day.
(2) The following are not medium HMIWI:
[[Page 280]]
(i) A continuous or intermittent HMIWI whose maximum charge rate is
less than or equal to 200 pounds per hour or more than 500 pounds per
hour; or
(ii) A batch HMIWI whose maximum charge rate is more than 4,000
pounds per day or less than or equal to 1,600 pounds per day.
Minimum dioxin/furan sorbent flow rate means 90 percent of the
highest 3-hour average dioxin/furan sorbent flow rate (taken, at a
minimum, once every hour) measured during the most recent performance
test demonstrating compliance with the dioxin/furan emission limit.
Minimum Hg sorbent flow rate means 90 percent of the highest 3-hour
average Hg sorbent flow rate (taken, at a minimum, once every hour)
measured during the most recent performance test demonstrating
compliance with the Hg emission limit.
Minimum hydrogen chloride (HCl) sorbent flow rate means 90 percent
of the highest 3-hour average HCl sorbent flow rate (taken, at a
minimum, once every hour) measured during the most recent performance
test demonstrating compliance with the HCl emission limit.
Minimum horsepower or amperage means 90 percent of the highest 3-
hour average horsepower or amperage to the wet scrubber (taken, at a
minimum, once every minute) measured during the most recent performance
test demonstrating compliance with the applicable emission limits.
Minimum pressure drop across the wet scrubber means 90 percent of
the highest 3-hour average pressure drop across the wet scrubber PM
control device (taken, at a minimum, once every minute) measured during
the most recent performance test demonstrating compliance with the PM
emission limit.
Minimum reagent flow rate means 90 percent of the highest 3-hour
average reagent flow rate at the inlet to the selective noncatalytic
reduction technology (taken, at a minimum, once every minute) measured
during the most recent performance test demonstrating compliance with
the NOX emissions limit.
Minimum scrubber liquor flow rate means 90 percent of the highest 3-
hour average liquor flow rate at the inlet to the wet scrubber (taken,
at a minimum, once every minute) measured during the most recent
performance test demonstrating compliance with all applicable emission
limits.
Minimum scrubber liquor pH means 90 percent of the highest 3-hour
average liquor pH at the inlet to the wet scrubber (taken, at a minimum,
once every minute) measured during the most recent performance test
demonstrating compliance with the HCl emission limit.
Minimum secondary chamber temperature means 90 percent of the
highest 3-hour average secondary chamber temperature (taken, at a
minimum, once every minute) measured during the most recent performance
test demonstrating compliance with the PM, CO, dioxin/furan, and
NOX emissions limits.
Modification or Modified HMIWI means any change to an HMIWI unit
after the effective date of these standards such that:
(1) The cumulative costs of the modifications, over the life of the
unit, exceed 50 per centum of the original cost of the construction and
installation of the unit (not including the cost of any land purchased
in connection with such construction or installation) updated to current
costs, or
(2) The change involves a physical change in or change in the method
of operation of the unit which increases the amount of any air pollutant
emitted by the unit for which standards have been established under
section 129 or section 111.
Operating day means a 24-hour period between 12:00 midnight and the
following midnight during which any amount of hospital waste or medical/
infectious waste is combusted at any time in the HMIWI.
Operation means the period during which waste is combusted in the
incinerator excluding periods of startup or shutdown.
Particulate matter or PM means the total particulate matter emitted
from an HMIWI as measured by EPA Reference Method 5 or EPA Reference
Method 29.
[[Page 281]]
Pathological waste means waste material consisting of only human or
animal remains, anatomical parts, and/or tissue, the bags/containers
used to collect and transport the waste material, and animal bedding (if
applicable).
Primary chamber means the chamber in an HMIWI that receives waste
material, in which the waste is ignited, and from which ash is removed.
Pyrolysis means the endothermic gasification of hospital waste and/
or medical/infectious waste using external energy.
Secondary chamber means a component of the HMIWI that receives
combustion gases from the primary chamber and in which the combustion
process is completed.
Shutdown means the period of time after all waste has been combusted
in the primary chamber. For continuous HMIWI, shutdown shall commence no
less than 2 hours after the last charge to the incinerator. For
intermittent HMIWI, shutdown shall commence no less than 4 hours after
the last charge to the incinerator. For batch HMIWI, shutdown shall
commence no less than 5 hours after the high-air phase of combustion has
been completed.
Small HMIWI means:
(1) Except as provided in (2);
(i) An HMIWI whose maximum design waste burning capacity is less
than or equal to 200 pounds per hour; or
(ii) A continuous or intermittent HMIWI whose maximum charge rate is
less than or equal to 200 pounds per hour; or
(iii) A batch HMIWI whose maximum charge rate is less than or equal
to 1,600 pounds per day.
(2) The following are not small HMIWI:
(i) A continuous or intermittent HMIWI whose maximum charge rate is
more than 200 pounds per hour;
(ii) A batch HMIWI whose maximum charge rate is more than 1,600
pounds per day.
Standard conditions means a temperature of 20 [deg]C and a pressure
of 101.3 kilopascals.
Startup means the period of time between the activation of the
system and the first charge to the unit. For batch HMIWI, startup means
the period of time between activation of the system and ignition of the
waste.
Wet scrubber means an add-on air pollution control device that
utilizes an alkaline scrubbing liquor to collect particulate matter
(including nonvaporous metals and condensed organics) and/or to absorb
and neutralize acid gases.
[62 FR 48382, Sept. 15, 1997, as amended at 74 FR 51408, Oct. 6, 2009;
79 FR 11249, Feb. 27, 2014]
Sec. 60.52c Emission limits.
(a) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility shall
cause to be discharged into the atmosphere:
(1) From an affected facility as defined in Sec. 60.50c(a)(1) and
(2), any gases that contain stack emissions in excess of the limits
presented in Table 1A to this subpart.
(2) From an affected facility as defined in Sec. 60.50c(a)(3) and
(4), any gases that contain stack emissions in excess of the limits
presented in Table 1B to this subpart.
(b) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility shall
cause to be discharged into the atmosphere:
(1) From an affected facility as defined in Sec. 60.50c(a)(1) and
(2), any gases that exhibit greater than 10 percent opacity (6-minute
block average).
(2) From an affected facility as defined in Sec. 60.50c(a)(3) and
(4), any gases that exhibit greater than 6 percent opacity (6-minute
block average).
(c) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility as
defined in Sec. 60.50c(a)(1) and (2) and utilizing a large HMIWI, and
in Sec. 60.50c(a)(3) and (4), shall cause to be discharged into the
atmosphere visible emissions of combustion ash from an ash conveying
system (including conveyor transfer points) in excess of 5 percent of
the observation period (i.e., 9
[[Page 282]]
minutes per 3-hour period), as determined by EPA Reference Method 22 of
appendix A-1 of this part, except as provided in paragraphs (d) and (e)
of this section.
(d) The emission limit specified in paragraph (c) of this section
does not cover visible emissions discharged inside buildings or
enclosures of ash conveying systems; however, the emission limit does
cover visible emissions discharged to the atmosphere from buildings or
enclosures of ash conveying systems.
(e) The provisions specified in paragraph (c) of this section do not
apply during maintenance and repair of ash conveying systems.
Maintenance and/or repair shall not exceed 10 operating days per
calendar quarter unless the owner or operator obtains written approval
from the State agency establishing a date whereby all necessary
maintenance and repairs of ash conveying systems shall be completed.
[62 FR 48382, Sept. 15, 1997, as amended at 74 FR 51409, Oct. 6, 2009]
Sec. 60.53c Operator training and qualification requirements.
(a) No owner or operator of an affected facility shall allow the
affected facility to operate at any time unless a fully trained and
qualified HMIWI operator is accessible, either at the facility or
available within 1 hour. The trained and qualified HMIWI operator may
operate the HMIWI directly or be the direct supervisor of one or more
HMIWI operators.
(b) Operator training and qualification shall be obtained through a
State-approved program or by completing the requirements included in
paragraphs (c) through (g) of this section.
(c) Training shall be obtained by completing an HMIWI operator
training course that includes, at a minimum, the following provisions:
(1) 24 hours of training on the following subjects:
(i) Environmental concerns, including pathogen destruction and types
of emissions;
(ii) Basic combustion principles, including products of combustion;
(iii) Operation of the type of incinerator to be used by the
operator, including proper startup, waste charging, and shutdown
procedures;
(iv) Combustion controls and monitoring;
(v) Operation of air pollution control equipment and factors
affecting performance (if applicable);
(vi) Methods to monitor pollutants (continuous emission monitoring
systems and monitoring of HMIWI and air pollution control device
operating parameters) and equipment calibration procedures (where
applicable);
(vii) Inspection and maintenance of the HMIWI, air pollution control
devices, and continuous emission monitoring systems;
(viii) Actions to correct malfunctions or conditions that may lead
to malfunction;
(ix) Bottom and fly ash characteristics and handling procedures;
(x) Applicable Federal, State, and local regulations;
(xi) Work safety procedures;
(xii) Pre-startup inspections; and
(xiii) Recordkeeping requirements.
(2) An examination designed and administered by the instructor.
(3) Reference material distributed to the attendees covering the
course topics.
(d) Qualification shall be obtained by:
(1) Completion of a training course that satisfies the criteria
under paragraph (c) of this section; and
(2) Either 6 months experience as an HMIWI operator, 6 months
experience as a direct supervisor of an HMIWI operator, or completion of
at least two burn cycles under the observation of two qualified HMIWI
operators.
(e) Qualification is valid from the date on which the examination is
passed or the completion of the required experience, whichever is later.
(f) To maintain qualification, the trained and qualified HMIWI
operator shall complete and pass an annual review or refresher course of
at least 4 hours covering, at a minimum, the following:
(1) Update of regulations;
(2) Incinerator operation, including startup and shutdown
procedures;
(3) Inspection and maintenance;
[[Page 283]]
(4) Responses to malfunctions or conditions that may lead to
malfunction; and
(5) Discussion of operating problems encountered by attendees.
(g) A lapsed qualification shall be renewed by one of the following
methods:
(1) For a lapse of less than 3 years, the HMIWI operator shall
complete and pass a standard annual refresher course described in
paragraph (f) of this section.
(2) For a lapse of 3 years or more, the HMIWI operator shall
complete and pass a training course with the minimum criteria described
in paragraph (c) of this section.
(h) The owner or operator of an affected facility shall maintain
documentation at the facility that address the following:
(1) Summary of the applicable standards under this subpart;
(2) Description of basic combustion theory applicable to an HMIWI;
(3) Procedures for receiving, handling, and charging waste;
(4) HMIWI startup, shutdown, and malfunction procedures;
(5) Procedures for maintaining proper combustion air supply levels;
(6) Procedures for operating the HMIWI and associated air pollution
control systems within the standards established under this subpart;
(7) Procedures for responding to periodic malfunction or conditions
that may lead to malfunction;
(8) Procedures for monitoring HMIWI emissions;
(9) Reporting and recordkeeping procedures; and
(10) Procedures for handling ash.
(i) The owner or operator of an affected facility shall establish a
program for reviewing the information listed in paragraph (h) of this
section annually with each HMIWI operator (defined in Sec. 60.51c).
(1) The initial review of the information listed in paragraph (h) of
this section shall be conducted within 6 months after the effective date
of this subpart or prior to assumption of responsibilities affecting
HMIWI operation, whichever date is later.
(2) Subsequent reviews of the information listed in paragraph (h) of
this section shall be conducted annually.
(j) The information listed in paragraph (h) of this section shall be
kept in a readily accessible location for all HMIWI operators. This
information, along with records of training shall be available for
inspection by the EPA or its delegated enforcement agent upon request.
Sec. 60.54c Siting requirements.
(a) The owner or operator of an affected facility for which
construction is commenced after September 15, 1997 shall prepare an
analysis of the impacts of the affected facility. The analysis shall
consider air pollution control alternatives that minimize, on a site-
specific basis, to the maximum extent practicable, potential risks to
public health or the environment. In considering such alternatives, the
analysis may consider costs, energy impacts, non-air environmental
impacts, or any other factors related to the practicability of the
alternatives.
(b) Analyses of facility impacts prepared to comply with State,
local, or other Federal regulatory requirements may be used to satisfy
the requirements of this section, as long as they include the
consideration of air pollution control alternatives specified in
paragraph (a) of this section.
(c) The owner or operator of the affected facility shall complete
and submit the siting requirements of this section as required under
Sec. 60.58c(a)(1)(iii).
Sec. 60.55c Waste management plan.
The owner or operator of an affected facility shall prepare a waste
management plan. The waste management plan shall identify both the
feasibility and the approach to separate certain components of solid
waste from the health care waste stream in order to reduce the amount of
toxic emissions from incinerated waste. A waste management plan may
include, but is not limited to, elements such as segregation and
recycling of paper, cardboard, plastics, glass, batteries, food waste,
and metals (e.g., aluminum cans, metals-containing devices); segregation
of non-recyclable wastes (e.g., polychlorinated biphenyl-containing
waste, pharmaceutical waste, and mercury-containing waste, such as
dental
[[Page 284]]
waste); and purchasing recycled or recyclable products. A waste
management plan may include different goals or approaches for different
areas or departments of the facility and need not include new waste
management goals for every waste stream. It should identify, where
possible, reasonably available additional waste management measures,
taking into account the effectiveness of waste management measures
already in place, the costs of additional measures, the emissions
reductions expected to be achieved, and any other environmental or
energy impacts they might have. The American Hospital Association
publication entitled ``An Ounce of Prevention: Waste Reduction
Strategies for Health Care Facilities'' (incorporated by reference, see
Sec. 60.17) shall be considered in the development of the waste
management plan. The owner or operator of each commercial HMIWI company
shall conduct training and education programs in waste segregation for
each of the company's waste generator clients and ensure that each
client prepares its own waste management plan that includes, but is not
limited to, the provisions listed previously in this section.
[74 FR 51409, Oct. 6, 2009]
Sec. 60.56c Compliance and performance testing.
(a) The emissions limits apply at all times.
(b) The owner or operator of an affected facility as defined in
Sec. 60.50c(a)(1) and (2), shall conduct an initial performance test as
required under Sec. 60.8 to determine compliance with the emissions
limits using the procedures and test methods listed in paragraphs (b)(1)
through (b)(6) and (b)(9) through (b)(14) of this section. The owner or
operator of an affected facility as defined in Sec. 60.50c(a)(3) and
(4), shall conduct an initial performance test as required under Sec.
60.8 to determine compliance with the emissions limits using the
procedures and test methods listed in paragraphs (b)(1) through (b)(14).
The use of the bypass stack during a performance test shall invalidate
the performance test.
(1) All performance tests shall consist of a minimum of three test
runs conducted under representative operating conditions.
(2) The minimum sample time shall be 1 hour per test run unless
otherwise indicated.
(3) EPA Reference Method 1 of appendix A of this part shall be used
to select the sampling location and number of traverse points.
(4) EPA Reference Method 3, 3A, or 3B of appendix A-2 of this part
shall be used for gas composition analysis, including measurement of
oxygen concentration. EPA Reference Method 3, 3A, or 3B of appendix A-2
of this part shall be used simultaneously with each of the other EPA
reference methods. As an alternative to EPA Reference Method 3B, ASME
PTC-19-10-1981-Part 10 may be used (incorporated by reference, see Sec.
60.17).
(5) The pollutant concentrations shall be adjusted to 7 percent
oxygen using the following equation:
Cadj = Cmeas (20.9-7)/(20.9-%O2)
where:
Cadj = pollutant concentration adjusted to 7 percent oxygen;
Cmeas = pollutant concentration measured on a dry basis
(20.9-7) = 20.9 percent oxygen--7 percent oxygen (defined
oxygen correction basis);
20.9 = oxygen concentration in air, percent; and
%O2 = oxygen concentration measured on a dry basis, percent.
(6) EPA Reference Method 5 of appendix A-3 or Method 26A or Method
29 of appendix A-8 of this part shall be used to measure the particulate
matter emissions. As an alternative, PM CEMS may be used as specified in
paragraph (c)(5) of this section.
(7) EPA Reference Method 7 or 7E of appendix A-4 of this part shall
be used to measure NOX emissions.
(8) EPA Reference Method 6 or 6C of appendix A-4 of this part shall
be used to measure SO2 emissions.
(9) EPA Reference Method 9 of appendix A-4 of this part shall be
used to measure stack opacity. As an alternative, demonstration of
compliance with the PM standards using bag leak detection systems as
specified in Sec. 60.57c(h) or PM CEMS as specified in paragraph (c)(5)
of this section is considered demonstrative of compliance with the
opacity requirements.
[[Page 285]]
(10) EPA Reference Method 10 or 10B of appendix A-4 of this part
shall be used to measure the CO emissions. As specified in paragraph
(c)(4) of this section, use of CO CEMS are required for affected
facilities under Sec. 60.50c(a)(3) and (4).
(11) EPA Reference Method 23 of appendix A-7 of this part shall be
used to measure total dioxin/furan emissions. As an alternative, an
owner or operator may elect to sample dioxins/furans by installing,
calibrating, maintaining, and operating a continuous automated sampling
system for monitoring dioxin/furan emissions as specified in paragraph
(c)(6) of this section. For Method 23 of appendix A-7 sampling, the
minimum sample time shall be 4 hours per test run. If the affected
facility has selected the toxic equivalency standards for dioxins/
furans, under Sec. 60.52c, the following procedures shall be used to
determine compliance:
(i) Measure the concentration of each dioxin/furan tetra-through
octa-congener emitted using EPA Reference Method 23.
(ii) For each dioxin/furan congener measured in accordance with
paragraph (b)(9)(i) of this section, multiply the congener concentration
by its corresponding toxic equivalency factor specified in table 2 of
this subpart.
(iii) Sum the products calculated in accordance with paragraph
(b)(9)(ii) of this section to obtain the total concentration of dioxins/
furans emitted in terms of toxic equivalency.
(12) EPA Reference Method 26 or 26A of appendix A-8 of this part
shall be used to measure HCl emissions. As an alternative, HCl CEMS may
be used as specified in paragraph (c)(5) of this section.
(13) EPA Reference Method 29 of appendix A-8 of this part shall be
used to measure Pb, Cd, and Hg emissions. As an alternative, Hg
emissions may be measured using ASTM D6784-02 (incorporated by
reference, see Sec. 60.17). As an alternative for Pb, Cd, and Hg,
multi-metals CEMS or Hg CEMS, may be used as specified in paragraph
(c)(5) of this section. As an alternative, an owner or operator may
elect to sample Hg by installing, calibrating, maintaining, and
operating a continuous automated sampling system for monitoring Hg
emissions as specified in paragraph (c)(7) of this section.
(14) The EPA Reference Method 22 of appendix A-7 of this part shall
be used to determine compliance with the fugitive ash emissions limit
under Sec. 60.52c(c). The minimum observation time shall be a series of
three 1-hour observations.
(c) Following the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, the owner or operator of an affected facility shall:
(1) Determine compliance with the opacity limit by conducting an
annual performance test (no more than 12 months following the previous
performance test) using the applicable procedures and test methods
listed in paragraph (b) of this section.
(2) Except as provided in paragraphs (c)(4) and (c)(5) of this
section, determine compliance with the PM, CO, and HCl emissions limits
by conducting an annual performance test (no more than 12 months
following the previous performance test) using the applicable procedures
and test methods listed in paragraph (b) of this section. If all three
performance tests over a 3-year period indicate compliance with the
emissions limit for a pollutant (PM, CO, or HCl), the owner or operator
may forego a performance test for that pollutant for the subsequent 2
years. At a minimum, a performance test for PM, CO, and HCl shall be
conducted every third year (no more than 36 months following the
previous performance test). If a performance test conducted every third
year indicates compliance with the emissions limit for a pollutant (PM,
CO, or HCl), the owner or operator may forego a performance test for
that pollutant for an additional 2 years. If any performance test
indicates noncompliance with the respective emissions limit, a
performance test for that pollutant shall be conducted annually until
all annual performance tests over a 3-year period indicate compliance
with the emissions limit. The use of the bypass stack during a
performance test shall invalidate the performance test.
(3) For an affected facility as defined in Sec. 60.50c(a)(1) and
(2) and utilizing a
[[Page 286]]
large HMIWI, and in Sec. 60.50c(a)(3) and (4), determine compliance
with the visible emissions limits for fugitive emissions from flyash/
bottom ash storage and handling by conducting a performance test using
EPA Reference Method 22 of appendix A-7 on an annual basis (no more than
12 months following the previous performance test).
(4) For an affected facility as defined in Sec. 60.50c(a)(3) and
(4), determine compliance with the CO emissions limit using a CO CEMS
according to paragraphs (c)(4)(i) through (c)(4)(iii) of this section:
(i) Determine compliance with the CO emissions limit using a 24-hour
block average, calculated as specified in section 12.4.1 of EPA
Reference Method 19 of appendix A-7 of this part.
(ii) Operate the CO CEMS in accordance with the applicable
procedures under appendices B and F of this part.
(iii) Use of a CO CEMS may be substituted for the CO annual
performance test and minimum secondary chamber temperature to
demonstrate compliance with the CO emissions limit.
(5) Facilities using CEMS to demonstrate compliance with any of the
emissions limits under Sec. 60.52c shall:
(i) For an affected facility as defined in Sec. 60.50c(a)(1) and
(2), determine compliance with the appropriate emissions limit(s) using
a 12-hour rolling average, calculated each hour as the average of the
previous 12 operating hours.
(ii) For an affected facility as defined in Sec. 60.50c(a)(3) and
(4), determine compliance with the appropriate emissions limit(s) using
a 24-hour block average, calculated as specified in section 12.4.1 of
EPA Reference Method 19 of appendix A-7 of this part.
(iii) Operate all CEMS in accordance with the applicable procedures
under appendices B and F of this part. For those CEMS for which
performance specifications have not yet been promulgated (HCl, multi-
metals), this option for an affected facility as defined in Sec.
60.50c(a)(3) and (4) takes effect on the date a final performance
specification is published in the Federal Register or the date of
approval of a site-specific monitoring plan.
(iv) For an affected facility as defined in Sec. 60.50c(a)(3) and
(4), be allowed to substitute use of an HCl CEMS for the HCl annual
performance test, minimum HCl sorbent flow rate, and minimum scrubber
liquor pH to demonstrate compliance with the HCl emissions limit.
(v) For an affected facility as defined in Sec. 60.50c(a)(3) and
(4), be allowed to substitute use of a PM CEMS for the PM annual
performance test and minimum pressure drop across the wet scrubber, if
applicable, to demonstrate compliance with the PM emissions limit.
(6) An affected facility as defined in Sec. 60.50c(a)(3) and (4)
using a continuous automated sampling system to demonstrate compliance
with the dioxin/furan emissions limits under Sec. 60.52c shall record
the output of the system and analyze the sample according to EPA
Reference Method 23 of appendix A-7 of this part. This option to use a
continuous automated sampling system takes effect on the date a final
performance specification applicable to dioxin/furan from monitors is
published in the Federal Register or the date of approval of a site-
specific monitoring plan. The owner or operator of an affected facility
as defined in Sec. 60.50c(a)(3) and (4) who elects to continuously
sample dioxin/furan emissions instead of sampling and testing using EPA
Reference Method 23 of appendix A-7 shall install, calibrate, maintain,
and operate a continuous automated sampling system and shall comply with
the requirements specified in Sec. 60.58b(p) and (q) of subpart Eb of
this part.
(7) An affected facility as defined in Sec. 60.50c(a)(3) and (4)
using a continuous automated sampling system to demonstrate compliance
with the Hg emissions limits under Sec. 60.52c shall record the output
of the system and analyze the sample at set intervals using any suitable
determinative technique that can meet appropriate performance criteria.
This option to use a continuous automated sampling system takes effect
on the date a final performance specification applicable to Hg from
monitors is published in the Federal Register or the date of approval of
a site-specific monitoring plan. The owner or operator of an affected
facility as defined in Sec. 60.50c(a)(3) and (4) who elects to
continuously sample Hg
[[Page 287]]
emissions instead of sampling and testing using EPA Reference Method 29
of appendix A-8 of this part, or an approved alternative method for
measuring Hg emissions, shall install, calibrate, maintain, and operate
a continuous automated sampling system and shall comply with the
requirements specified in Sec. 60.58b(p) and (q) of subpart Eb of this
part.
(d) Except as provided in paragraphs (c)(4) through (c)(7) of this
section, the owner or operator of an affected facility equipped with a
dry scrubber followed by a fabric filter, a wet scrubber, or a dry
scrubber followed by a fabric filter and wet scrubber shall:
(1) Establish the appropriate maximum and minimum operating
parameters, indicated in table 3 of this subpart for each control
system, as site specific operating parameters during the initial
performance test to determine compliance with the emission limits; and
(2) Following the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, ensure that the affected facility does not operate
above any of the applicable maximum operating parameters or below any of
the applicable minimum operating parameters listed in table 3 of this
subpart and measured as 3-hour rolling averages (calculated each hour as
the average of the previous 3 operating hours) at all times. Operating
parameter limits do not apply during performance tests. Operation above
the established maximum or below the established minimum operating
parameter(s) shall constitute a violation of established operating
parameter(s).
(e) Except as provided in paragraph (i) of this section, for
affected facilities equipped with a dry scrubber followed by a fabric
filter:
(1) Operation of the affected facility above the maximum charge rate
and below the minimum secondary chamber temperature (each measured on a
3-hour rolling average) simultaneously shall constitute a violation of
the CO emission limit.
(2) Operation of the affected facility above the maximum fabric
filter inlet temperature, above the maximum charge rate, and below the
minimum dioxin/furan sorbent flow rate (each measured on a 3-hour
rolling average) simultaneously shall constitute a violation of the
dioxin/furan emission limit.
(3) Operation of the affected facility above the maximum charge rate
and below the minimum HCl sorbent flow rate (each measured on a 3-hour
rolling average) simultaneously shall constitute a violation of the HCl
emission limit.
(4) Operation of the affected facility above the maximum charge rate
and below the minimum Hg sorbent flow rate (each measured on a 3-hour
rolling average) simultaneously shall constitute a violation of the Hg
emission limit.
(5) Use of the bypass stack shall constitute a violation of the PM,
dioxin/furan, HCl, Pb, Cd and Hg emissions limits.
(6) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the CO emissions limit as measured by the CO
CEMS specified in paragraph (c)(4) of this section shall constitute a
violation of the CO emissions limit.
(7) For an affected facility as defined in Sec. 60.50c(a)(3) and
(4), failure to initiate corrective action within 1 hour of a bag leak
detection system alarm; or failure to operate and maintain the fabric
filter such that the alarm is not engaged for more than 5 percent of the
total operating time in a 6-month block reporting period shall
constitute a violation of the PM emissions limit. If inspection of the
fabric filter demonstrates that no corrective action is required, no
alarm time is counted. If corrective action is required, each alarm is
counted as a minimum of 1 hour. If it takes longer than 1 hour to
initiate corrective action, the alarm time is counted as the actual
amount of time taken to initiate corrective action. If the bag leak
detection system is used to demonstrate compliance with the opacity
limit, this would also constitute a violation of the opacity emissions
limit.
(8) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the PM, HCl, Pb, Cd, and/or Hg emissions
limit as measured by the CEMS
[[Page 288]]
specified in paragraph (c)(5) of this section shall constitute a
violation of the applicable emissions limit.
(9) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the dioxin/furan emissions limit as measured
by the continuous automated sampling system specified in paragraph
(c)(6) of this section shall constitute a violation of the dioxin/furan
emissions limit.
(10) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the Hg emissions limit as measured by the
continuous automated sampling system specified in paragraph (c)(7) of
this section shall constitute a violation of the Hg emissions limit.
(f) Except as provided in paragraph (i) of this section, for
affected facilities equipped with a wet scrubber:
(1) Operation of the affected facility above the maximum charge rate
and below the minimum pressure drop across the wet scrubber or below the
minimum horsepower or amperage to the system (each measured on a 3-hour
rolling average) simultaneously shall constitute a violation of the PM
emission limit.
(2) Operation of the affected facility above the maximum charge rate
and below the minimum secondary chamber temperature (each measured on a
3-hour rolling average) simultaneously shall constitute a violation of
the CO emission limit.
(3) Operation of the affected facility above the maximum charge
rate, below the minimum secondary chamber temperature, and below the
minimum scrubber liquor flow rate (each measured on a 3-hour rolling
average) simultaneously shall constitute a violation of the dioxin/furan
emission limit.
(4) Operation of the affected facility above the maximum charge rate
and below the minimum scrubber liquor pH (each measured on a 3-hour
rolling average) simultaneously shall constitute a violation of the HCl
emission limit.
(5) Operation of the affected facility above the maximum flue gas
temperature and above the maximum charge rate (each measured on a 3-hour
rolling average) simultaneously shall constitute a violation of the Hg
emission limit.
(6) Use of the bypass stack shall constitute a violation of the PM,
dioxin/furan, HCl, Pb, Cd and Hg emissions limits.
(7) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the CO emissions limit as measured by the CO
CEMS specified in paragraph (c)(4) of this section shall constitute a
violation of the CO emissions limit.
(8) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the PM, HCl, Pb, Cd, and/or Hg emissions
limit as measured by the CEMS specified in paragraph (c)(5) of this
section shall constitute a violation of the applicable emissions limit.
(9) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the dioxin/furan emissions limit as measured
by the continuous automated sampling system specified in paragraph
(c)(6) of this section shall constitute a violation of the dioxin/furan
emissions limit.
(10) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the Hg emissions limit as measured by the
continuous automated sampling system specified in paragraph (c)(7) of
this section shall constitute a violation of the Hg emissions limit.
(g) Except as provided in paragraph (i) of this section, for
affected facilities equipped with a dry scrubber followed by a fabric
filter and a wet scrubber:
(1) Operation of the affected facility above the maximum charge rate
and below the minimum secondary chamber temperature (each measured on a
3-hour rolling average) simultaneously shall constitute a violation of
the CO emission limit.
(2) Operation of the affected facility above the maximum fabric
filter inlet temperature, above the maximum charge rate, and below the
minimum dioxin/furan sorbent flow rate (each measured on a 3-hour
rolling average) simultaneously shall constitute a violation of the
dioxin/furan emission limit.
(3) Operation of the affected facility above the maximum charge rate
and below the minimum scrubber liquor pH (each measured on a 3-hour
rolling average) simultaneously shall constitute a violation of the HCl
emission limit.
[[Page 289]]
(4) Operation of the affected facility above the maximum charge rate
and below the minimum Hg sorbent flow rate (each measured on a 3-hour
rolling average) simultaneously shall constitute a violation of the Hg
emission limit.
(5) Use of the bypass stack shall constitute a violation of the PM,
dioxin/furan, HCl, Pb, Cd and Hg emissions limits.
(6) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the CO emissions limit as measured by the CO
CEMS specified in paragraph (c)(4) of this section shall constitute a
violation of the CO emissions limit.
(7) For an affected facility as defined in Sec. 60.50c(a)(3) and
(4), failure to initiate corrective action within 1 hour of a bag leak
detection system alarm; or failure to operate and maintain the fabric
filter such that the alarm is not engaged for more than 5 percent of the
total operating time in a 6-month block reporting period shall
constitute a violation of the PM emissions limit. If inspection of the
fabric filter demonstrates that no corrective action is required, no
alarm time is counted. If corrective action is required, each alarm is
counted as a minimum of 1 hour. If it takes longer than 1 hour to
initiate corrective action, the alarm time is counted as the actual
amount of time taken to initiate corrective action. If the bag leak
detection system is used to demonstrate compliance with the opacity
limit, this would also constitute a violation of the opacity emissions
limit.
(8) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the PM, HCl, Pb, Cd, and/or Hg emissions
limit as measured by the CEMS specified in paragraph (c)(5) of this
section shall constitute a violation of the applicable emissions limit.
(9) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the dioxin/furan emissions limit as measured
by the continuous automated sampling system specified in paragraph
(c)(6) of this section shall constitute a violation of the dioxin/furan
emissions limit.
(10) Operation of the affected facility as defined in Sec.
60.50c(a)(3) and (4) above the Hg emissions limit as measured by the
continuous automated sampling system specified in paragraph (c)(7) of
this section shall constitute a violation of the Hg emissions limit.
(h) The owner or operator of an affected facility as defined in
Sec. 60.50c(a)(3) and (4) equipped with selective noncatalytic
reduction technology shall:
(1) Establish the maximum charge rate, the minimum secondary chamber
temperature, and the minimum reagent flow rate as site specific
operating parameters during the initial performance test to determine
compliance with the emissions limits;
(2) Following the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, ensure that the affected facility does not operate
above the maximum charge rate, or below the minimum secondary chamber
temperature or the minimum reagent flow rate measured as 3-hour rolling
averages (calculated each hour as the average of the previous 3
operating hours) at all times. Operating parameter limits do not apply
during performance tests.
(3) Except as provided in paragraph (i) of this section, operation
of the affected facility above the maximum charge rate, below the
minimum secondary chamber temperature, and below the minimum reagent
flow rate simultaneously shall constitute a violation of the
NOX emissions limit.
(i) The owner or operator of an affected facility may conduct a
repeat performance test within 30 days of violation of applicable
operating parameter(s) to demonstrate that the affected facility is not
in violation of the applicable emissions limit(s). Repeat performance
tests conducted pursuant to this paragraph shall be conducted using the
identical operating parameters that indicated a violation under
paragraph (e), (f), (g), or (h) of this section.
(j) The owner or operator of an affected facility using an air
pollution control device other than a dry scrubber followed by a fabric
filter, a wet scrubber, a dry scrubber followed by a fabric filter and a
wet scrubber, or selective noncatalytic reduction technology to comply
with the emissions limits under Sec. 60.52c shall petition the
[[Page 290]]
Administrator for other site-specific operating parameters to be
established during the initial performance test and continuously
monitored thereafter. The owner or operator shall not conduct the
initial performance test until after the petition has been approved by
the Administrator.
(k) The owner or operator of an affected facility may conduct a
repeat performance test at any time to establish new values for the
operating parameters. The Administrator may request a repeat performance
test at any time.
[62 FR 48382, Sept. 15, 1997, as amended at 65 FR 61753, Oct. 17, 2000;
74 FR 51409, Oct. 6, 2009; 78 FR 28066, May 13, 2013]
Sec. 60.57c Monitoring requirements.
(a) Except as provided in Sec. 60.56c(c)(4) through (c)(7), the
owner or operator of an affected facility shall install, calibrate (to
manufacturers' specifications), maintain, and operate devices (or
establish methods) for monitoring the applicable maximum and minimum
operating parameters listed in Table 3 to this subpart (unless CEMS are
used as a substitute for certain parameters as specified) such that
these devices (or methods) measure and record values for these operating
parameters at the frequencies indicated in Table 3 of this subpart at
all times.
(b) The owner or operator of an affected facility as defined in
Sec. 60.50c(a)(3) and (4) that uses selective noncatalytic reduction
technology shall install, calibrate (to manufacturers' specifications),
maintain, and operate devices (or establish methods) for monitoring the
operating parameters listed in Sec. 60.56c(h) such that the devices (or
methods) measure and record values for the operating parameters at all
times. Operating parameter values shall be measured and recorded at the
following minimum frequencies:
(1) Maximum charge rate shall be measured continuously and recorded
once each hour;
(2) Minimum secondary chamber temperature shall be measured
continuously and recorded once each minute; and
(3) Minimum reagent flow rate shall be measured hourly and recorded
once each hour.
(c) The owner or operator of an affected facility shall install,
calibrate (to manufacturers' specifications), maintain, and operate a
device or method for measuring the use of the bypass stack including
date, time, and duration.
(d) The owner or operator of an affected facility using an air
pollution control device other than a dry scrubber followed by a fabric
filter, a wet scrubber, a dry scrubber followed by a fabric filter and a
wet scrubber, or selective noncatalytic reduction technology to comply
with the emissions limits under Sec. 60.52c shall install, calibrate
(to manufacturers' specifications), maintain, and operate the equipment
necessary to monitor the site-specific operating parameters developed
pursuant to Sec. 60.56c(j).
(e) The owner or operator of an affected facility shall obtain
monitoring data at all times during HMIWI operation except during
periods of monitoring equipment malfunction, calibration, or repair. At
a minimum, valid monitoring data shall be obtained for 75 percent of the
operating hours per day for 90 percent of the operating days per
calendar quarter that the affected facility is combusting hospital waste
and/or medical/infectious waste.
(f) The owner or operator of an affected facility as defined in
Sec. 60.50c(a)(3) and (4) shall ensure that each HMIWI subject to the
emissions limits in Sec. 60.52c undergoes an initial air pollution
control device inspection that is at least as protective as the
following:
(1) At a minimum, an inspection shall include the following:
(i) Inspect air pollution control device(s) for proper operation, if
applicable;
(ii) Ensure proper calibration of thermocouples, sorbent feed
systems, and any other monitoring equipment; and
(iii) Generally observe that the equipment is maintained in good
operating condition.
(2) Within 10 operating days following an air pollution control
device inspection, all necessary repairs shall be completed unless the
owner or operator
[[Page 291]]
obtains written approval from the Administrator establishing a date
whereby all necessary repairs of the designated facility shall be
completed.
(g) The owner or operator of an affected facility as defined in
Sec. 60.50c(a)(3) and (4) shall ensure that each HMIWI subject to the
emissions limits under Sec. 60.52c undergoes an air pollution control
device inspection annually (no more than 12 months following the
previous annual air pollution control device inspection), as outlined in
paragraphs (f)(1) and (f)(2) of this section.
(h) For affected facilities as defined in Sec. 60.50c(a)(3) and (4)
that use an air pollution control device that includes a fabric filter
and are not demonstrating compliance using PM CEMS, determine compliance
with the PM emissions limit using a bag leak detection system and meet
the requirements in paragraphs (h)(1) through (h)(12) of this section
for each bag leak detection system.
(1) Each triboelectric bag leak detection system may be installed,
calibrated, operated, and maintained according to the ``Fabric Filter
Bag Leak Detection Guidance,'' (EPA-454/R-98-015, September 1997). This
document is available from the U.S. Environmental Protection Agency
(U.S. EPA); Office of Air Quality Planning and Standards; Sector
Policies and Programs Division; Measurement Policy Group (D-243-02),
Research Triangle Park, NC 27711. This document is also available on the
Technology Transfer Network (TTN) under Emissions Measurement Center
Continuous Emissions Monitoring. Other types of bag leak detection
systems shall be installed, operated, calibrated, and maintained in a
manner consistent with the manufacturer's written specifications and
recommendations.
(2) The bag leak detection system shall be certified by the
manufacturer to be capable of detecting PM emissions at concentrations
of 10 milligrams per actual cubic meter (0.0044 grains per actual cubic
foot) or less.
(3) The bag leak detection system sensor shall provide an output of
relative PM loadings.
(4) The bag leak detection system shall be equipped with a device to
continuously record the output signal from the sensor.
(5) The bag leak detection system shall be equipped with an audible
alarm system that will sound automatically when an increase in relative
PM emissions over a preset level is detected. The alarm shall be located
where it is easily heard by plant operating personnel.
(6) For positive pressure fabric filter systems, a bag leak detector
shall be installed in each baghouse compartment or cell.
(7) For negative pressure or induced air fabric filters, the bag
leak detector shall be installed downstream of the fabric filter.
(8) Where multiple detectors are required, the system's
instrumentation and alarm may be shared among detectors.
(9) The baseline output shall be established by adjusting the range
and the averaging period of the device and establishing the alarm set
points and the alarm delay time according to section 5.0 of the ``Fabric
Filter Bag Leak Detection Guidance.''
(10) Following initial adjustment of the system, the sensitivity or
range, averaging period, alarm set points, or alarm delay time may not
be adjusted. In no case may the sensitivity be increased by more than
100 percent or decreased more than 50 percent over a 365-day period
unless such adjustment follows a complete fabric filter inspection that
demonstrates that the fabric filter is in good operating condition. Each
adjustment shall be recorded.
(11) Record the results of each inspection, calibration, and
validation check.
(12) Initiate corrective action within 1 hour of a bag leak
detection system alarm; operate and maintain the fabric filter such that
the alarm is not engaged for more than 5 percent of the total operating
time in a 6-month block reporting period. If inspection of the fabric
filter demonstrates that no corrective action is required, no alarm time
is counted. If corrective action is required, each alarm is counted as a
minimum of 1 hour. If it takes longer than 1 hour to initiate corrective
action, the alarm time is counted as the
[[Page 292]]
actual amount of time taken to initiate corrective action.
[62 FR 48382, Sept. 15, 1997, as amended at 74 FR 51412, Oct. 6, 2009]
Sec. 60.58c Reporting and recordkeeping requirements.
(a) The owner or operator of an affected facility shall submit
notifications, as provided by Sec. 60.7. In addition, the owner or
operator shall submit the following information:
(1) Prior to commencement of construction;
(i) A statement of intent to construct;
(ii) The anticipated date of commencement of construction; and
(iii) All documentation produced as a result of the siting
requirements of Sec. 60.54c.
(2) Prior to initial startup;
(i) The type(s) of waste to be combusted;
(ii) The maximum design waste burning capacity;
(iii) The anticipated maximum charge rate; and
(iv) If applicable, the petition for site-specific operating
parameters under Sec. 60.56c(j).
(b) The owner or operator of an affected facility shall maintain the
following information (as applicable) for a period of at least 5 years:
(1) Calendar date of each record;
(2) Records of the following data:
(i) Concentrations of any pollutant listed in Sec. 60.52c or
measurements of opacity as determined by the continuous emission
monitoring system (if applicable);
(ii) Results of fugitive emissions (by EPA Reference Method 22)
tests, if applicable;
(iii) HMIWI charge dates, times, and weights and hourly charge
rates;
(iv) Fabric filter inlet temperatures during each minute of
operation, as applicable;
(v) Amount and type of dioxin/furan sorbent used during each hour of
operation, as applicable;
(vi) Amount and type of Hg sorbent used during each hour of
operation, as applicable;
(vii) Amount and type of HCl sorbent used during each hour of
operation, as applicable;
(viii) For affected facilities as defined in Sec. 60.50c(a)(3) and
(4), amount and type of NOX reagent used during each hour of
operation, as applicable;
(ix) Secondary chamber temperatures recorded during each minute of
operation;
(x) Liquor flow rate to the wet scrubber inlet during each minute of
operation, as applicable;
(xi) Horsepower or amperage to the wet scrubber during each minute
of operation, as applicable;
(xii) Pressure drop across the wet scrubber system during each
minute of operation, as applicable,
(xiii) Temperature at the outlet from the wet scrubber during each
minute of operation, as applicable;
(xiv) pH at the inlet to the wet scrubber during each minute of
operation, as applicable,
(xv) Records indicating use of the bypass stack, including dates,
times, and durations, and
(xvi) For affected facilities complying with Sec. 60.56c(j) and
Sec. 60.57c(d), the owner or operator shall maintain all operating
parameter data collected;
(xvii) For affected facilities as defined in Sec. 60.50c(a)(3) and
(4), records of the annual air pollution control device inspections, any
required maintenance, and any repairs not completed within 10 days of an
inspection or the timeframe established by the Administrator.
(xviii) For affected facilities as defined in Sec. 60.50c(a)(3) and
(4), records of each bag leak detection system alarm, the time of the
alarm, the time corrective action was initiated and completed, and a
brief description of the cause of the alarm and the corrective action
taken, as applicable.
(xix) For affected facilities as defined in Sec. 60.50c(a)(3) and
(4), concentrations of CO as determined by the continuous emissions
monitoring system.
(3) Identification of calendar days for which data on emission rates
or operating parameters specified under paragraph (b)(2) of this section
have not been obtained, with an identification of the emission rates or
operating parameters not measured, reasons for not obtaining the data,
and a description of corrective actions taken.
[[Page 293]]
(4) Identification of calendar days, times and durations of
malfunctions, a description of the malfunction and the corrective action
taken.
(5) Identification of calendar days for which data on emission rates
or operating parameters specified under paragraph (b)(2) of this section
exceeded the applicable limits, with a description of the exceedances,
reasons for such exceedances, and a description of corrective actions
taken.
(6) The results of the initial, annual, and any subsequent
performance tests conducted to determine compliance with the emissions
limits and/or to establish or re-establish operating parameters, as
applicable, and a description, including sample calculations, of how the
operating parameters were established or re-established, if applicable.
(7) All documentation produced as a result of the siting
requirements of Sec. 60.54c;
(8) Records showing the names of HMIWI operators who have completed
review of the information in Sec. 60.53c(h) as required by Sec.
60.53c(i), including the date of the initial review and all subsequent
annual reviews;
(9) Records showing the names of the HMIWI operators who have
completed the operator training requirements, including documentation of
training and the dates of the training;
(10) Records showing the names of the HMIWI operators who have met
the criteria for qualification under Sec. 60.53c and the dates of their
qualification; and
(11) Records of calibration of any monitoring devices as required
under Sec. 60.57c(a) through (d).
(c) The owner or operator of an affected facility shall submit the
information specified in paragraphs (c)(1) through (c)(4) of this
section no later than 60 days following the initial performance test.
All reports shall be signed by the facilities manager.
(1) The initial performance test data as recorded under Sec.
60.56c(b)(1) through (b)(14), as applicable.
(2) The values for the site-specific operating parameters
established pursuant to Sec. 60.56c(d), (h), or (j), as applicable, and
a description, including sample calculations, of how the operating
parameters were established during the initial performance test.
(3) The waste management plan as specified in Sec. 60.55c.
(4) For each affected facility as defined in Sec. 60.50c(a)(3) and
(4) that uses a bag leak detection system, analysis and supporting
documentation demonstrating conformance with EPA guidance and
specifications for bag leak detection systems in Sec. 60.57c(h).
(d) An annual report shall be submitted 1 year following the
submissions of the information in paragraph (c) of this section and
subsequent reports shall be submitted no more than 12 months following
the previous report (once the unit is subject to permitting requirements
under title V of the Clean Air Act, the owner or operator of an affected
facility must submit these reports semiannually). The annual report
shall include the information specified in paragraphs (d)(1) through
(11) of this section. All reports shall be signed by the facilities
manager.
(1) The values for the site-specific operating parameters
established pursuant to Sec. 60.56c(d), (h), or (j), as applicable.
(2) The highest maximum operating parameter and the lowest minimum
operating parameter, as applicable, for each operating parameter
recorded for the calendar year being reported, pursuant to Sec.
60.56c(d), (h), or (j), as applicable.
(3) The highest maximum operating parameter and the lowest minimum
operating parameter, as applicable, for each operating parameter
recorded pursuant to Sec. 60.56c(d), (h), or (j) for the calendar year
preceding the year being reported, in order to provide the Administrator
with a summary of the performance of the affected facility over a 2-year
period.
(4) Any information recorded under paragraphs (b)(3) through (b)(5)
of this section for the calendar year being reported.
(5) Any information recorded under paragraphs (b)(3) through (b)(5)
of this section for the calendar year preceding the year being reported,
in order to provide the Administrator with a summary of the performance
of the affected facility over a 2-year period.
[[Page 294]]
(6) If a performance test was conducted during the reporting period,
the results of that test.
(7) If no exceedances or malfunctions were reported under paragraphs
(b)(3) through (b)(5) of this section for the calendar year being
reported, a statement that no exceedances occurred during the reporting
period.
(8) Any use of the bypass stack, the duration, reason for
malfunction, and corrective action taken.
(9) For affected facilities as defined in Sec. 60.50c(a)(3) and
(4), records of the annual air pollution control device inspection, any
required maintenance, and any repairs not completed within 10 days of an
inspection or the timeframe established by the Administrator.
(10) For affected facilities as defined in Sec. 60.50c(a)(3) and
(4), records of each bag leak detection system alarm, the time of the
alarm, the time corrective action was initiated and completed, and a
brief description of the cause of the alarm and the corrective action
taken, as applicable.
(11) For affected facilities as defined in Sec. 60.50c(a)(3) and
(4), concentrations of CO as determined by the continuous emissions
monitoring system.
(e) The owner or operator of an affected facility shall submit
semiannual reports containing any information recorded under paragraphs
(b)(3) through (b)(5) of this section no later than 60 days following
the reporting period. The first semiannual reporting period ends 6
months following the submission of information in paragraph (c) of this
section. Subsequent reports shall be submitted no later than 6 calendar
months following the previous report. All reports shall be signed by the
facilities manager.
(f) All records specified under paragraph (b) of this section shall
be maintained onsite in either paper copy or computer-readable format,
unless an alternative format is approved by the Administrator.
(g) For affected facilities, as defined in Sec. 60.50c(a)(3) and
(4), that choose to submit an electronic copy of stack test reports to
EPA's WebFIRE data base, as of December 31, 2011, the owner or operator
of an affected facility shall enter the test data into EPA's data base
using the Electronic Reporting Tool located at http://www.epa.gov/ttn/
chief/ert/ert--tool.html.
[62 FR 48382, Sept. 15, 1997, as amended at 74 FR 51413, Oct. 6, 2009;
76 FR 18413, Apr. 4, 2011]
Sec. Table 1A to Subpart Ec of Part 60--Emissions Limits for Small,
Medium, and Large HMIWI at Affected Facilities as Defined in Sec.
60.50c(a)(1) and (2)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions limits
------------------------------------------------------------ Method for
Pollutant Units (7 percent HMIWI size Averaging time \1\ demonstrating
oxygen, dry basis) ------------------------------------------------------------ compliance \2\
Small Medium Large
--------------------------------------------------------------------------------------------------------------------------------------------------------
Particulate matter.............. Milligrams per dry 69 (0.03)......... 34 (0.015)........ 34 (0.015)........ 3-run average (1- EPA Reference
standard cubic hour minimum Method 5 of
meter (grains per sample time per appendix A-3 of
dry standard run). part 60, or EPA
cubic foot). Reference Method
M 26A or 29 of
appendix A-8 of
part 60.
Carbon monoxide................. Parts per million 40................ 40................ 40................ 3-run average (1- EPA Reference
by volume. hour minimum Method 10 or 10B
sample time per of appendix A-4
run). of part 60.
[[Page 295]]
Dioxins/furans.................. Nanograms per dry 125 (55) or 2.3 25 (11) or 0.6 25 (11) or 0.6 3-run average (4- EPA Reference
standard cubic (1.0). (0.26). (0.26). hour minimum Method 23 of
meter total sample time per appendix A-7 of
dioxins/furans run). part 60.
(grains per
billion dry
standard cubic
feet) or
nanograms per dry
standard cubic
meter TEQ (grains
per billion dry
standard cubic
feet).
Hydrogen chloride............... Parts per million 15 or 99%......... 15 or 99%......... 15 or 99%......... 3-run average (1- EPA Reference
by volume or hour minimum Method 26 or 26A
percent reduction. sample time per of appendix A-8
run). of part 60.
Sulfur dioxide.................. Parts per million 55................ 55................ 55................ 3-run average (1- EPA Reference
by volume. hour minimum Method 6 or 6C of
sample time per appendix A-4 of
run). part 60.
Nitrogen oxides................. Parts per million 250............... 250............... 250............... 3-run average (1- EPA Reference
by volume. hour minimum Method 7 or 7E of
sample time per appendix A-4 of
run). part 60.
Lead............................ Milligrams per dry 1.2 (0.52) or 70%. 0.07 (0.03) or 98% 0.07 (0.03) or 98% 3-run average (1- EPA Reference
standard cubic hour minimum Method 29 of
meter (grains per sample time per appendix A-8 of
thousand dry run). part 60.
standard cubic
feet) or percent
reduction.
Cadmium......................... Milligrams per dry 0.16 (0.07) or 65% 0.04 (0.02) or 90% 0.04 (0.02) or 90% 3-run average (1- EPA Reference
standard cubic hour minimum Method 29 of
meter (grains per sample time per appendix A-8 of
thousand dry run). part 60.
standard cubic
feet) or percent
reduction.
Mercury......................... Milligrams per dry 0.55 (0.24) or 85% 0.55 (0.24) or 85% 0.55 (0.24) or 85% 3-run average (1- EPA Reference
standard cubic hour minimum Method 29 of
meter (grains per sample time per appendix A-8 of
thousand dry run). part 60.
standard cubic
feet) or percent
reduction.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Except as allowed under Sec. 60.56c(c) for HMIWI equipped with CEMS.
\2\ Does not include CEMS and approved alternative non-EPA test methods allowed under Sec. 60.56c(b).
[74 FR 51414, Oct. 6, 2009, as amended at 76 FR 18414, Apr. 4, 2011]
Sec. Table 1B to Subpart Ec of Part 60--Emissions Limits for Small,
Medium, and Large HMIWI at Affected Facilities as Defined in Sec.
60.50c(a)(3) and (4)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions limits
------------------------------------------------------------ Method for
Pollutant Units (7 percent HMIWI size Averaging time \1\ demonstrating
oxygen, dry basis) ------------------------------------------------------------ compliance \2\
Small Medium Large
--------------------------------------------------------------------------------------------------------------------------------------------------------
Particulate matter.............. Milligrams per dry 66 (0.029)........ 22 (0.0095)....... 18 (0.0080)....... 3-run average (1- EPA Reference
standard cubic hour minimum Method 5 of
meter (grains per sample time per appendix A-3 of
dry standard run). part 60, or EPA
cubic foot). Reference Method
M 26A or 29 of
appendix A-8 of
part 60.
Carbon monoxide................. Parts per million 20................ 1.8............... 11................ 3-run average (1- EPA Reference
by volume. hour minimum Method 10 or 10B
sample time per of appendix A-4
run). of part 60.
[[Page 296]]
Dioxins/furans.................. Nanograms per dry 16 (7.0) or 0.013 0.47 (0.21) or 9.3 (4.1) or 0.035 3-run average (4- EPA Reference
standard cubic (0.0057). 0.014 (0.0061). (0.015). hour minimum Method 23 of
meter total sample time per appendix A-7 of
dioxins/furans run). part 60.
(grains per
billion dry
standard cubic
feet) or
nanograms per dry
standard cubic
meter TEQ (grains
per billion dry
standard cubic
feet).
Hydrogen chloride............... Parts per million 15................ 7.7............... 5.1............... 3-run average (1- EPA Reference
by volume. hour minimum Method 26 or 26A
sample time per of appendix A-8
run). of part 60.
Sulfur dioxide.................. Parts per million 1.4............... 1.4............... 8.1............... 3-run average (1- EPA Reference
by volume. hour minimum Method 6 or 6C of
sample time per appendix A-4 of
run). part 60.
Nitrogen oxides................. Parts per million 67................ 67................ 140............... 3-run average (1- EPA Reference
by volume. hour minimum Method 7 or 7E of
sample time per appendix A-4 of
run). part 60.
Lead............................ Milligrams per dry 0.31 (0.14)....... 0.018 (0.0079).... 0.00069 (0.00030). 3-run average (1- EPA Reference
standard cubic hour minimum Method 29 of
meter (grains per sample time per appendix A-8 of
thousand dry run). part 60.
standard cubic
feet).
Cadmium......................... Milligrams per dry 0.017 (0.0074).... 0.0098 (0.0043)... 0.00013 (0.000057) 3-run average (1- EPA Reference
standard cubic hour minimum Method 29 of
meter (grains per sample time per appendix A-8 of
thousand dry run). part 60.
standard cubic
feet).
Mercury......................... Milligrams per dry 0.014 (0.0061).... 0.0035 (0.0015)... 0.0013 (0.00057).. 3-run average (1- EPA Reference
standard cubic hour minimum Method 29 of
meter (grains per sample time per appendix A-8 of
thousand dry run). part 60.
standard cubic
feet).
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Except as allowed under Sec. 60.56c(c) for HMIWI equipped with CEMS.
\2\ Does not include CEMS and approved alternative non-EPA test methods allowed under Sec. 60.56c(b).
[74 FR 51414, Oct. 6, 2009, as amended at 76 FR 18414, Apr. 4, 2011]
Sec. Table 2 to Subpart Ec of Part 60--Toxic Equivalency Factors
------------------------------------------------------------------------
Toxic
Dioxin/furan congener equivalency
factor
------------------------------------------------------------------------
2,3,7,8-tetrachlorinated dibenzo-p-dioxin................. 1
1,2,3,7,8-pentachlorinated dibenzo-p-dioxin............... 0.5
1,2,3,4,7,8-hexachlorinated dibenzo-p-dioxin.............. 0.1
1,2,3,7,8,9-hexachlorinated dibenzo-p-dioxin.............. 0.1
1,2,3,6,7,8-hexachlorinated dibenzo-p-dioxin.............. 0.1
1,2,3,4,6,7,8-heptachlorinated dibenzo-p-dioxin........... 0.01
octachlorinated dibenzo-p-dioxin.......................... 0.001
2,3,7,8-tetrachlorinated dibenzofuran..................... 0.1
2,3,4,7,8-pentachlorinated dibenzofuran................... 0.5
1,2,3,7,8-pentachlorinated dibenzofuran................... 0.05
1,2,3,4,7,8-hexachlorinated dibenzofuran.................. 0.1
1,2,3,6,7,8-hexachlorinated dibenzofuran.................. 0.1
1,2,3,7,8,9-hexachlorinated dibenzofuran.................. 0.1
2,3,4,6,7,8-hexachlorinated dibenzofuran.................. 0.1
1,2,3,4,6,7,8-heptachlorinated dibenzofuran............... 0.01
1,2,3,4,7,8,9-heptachlorinated dibenzofuran............... 0.01
Octachlorinated dibenzofuran.............................. 0.001
------------------------------------------------------------------------
[[Page 297]]
Sec. Table 3 to Subpart Ec of Part 60--Operating Parameters To Be
Monitored and Minimum Measurement and Recording Frequencies
--------------------------------------------------------------------------------------------------------------------------------------------------------
Minimum frequency Control system
--------------------------------------------------------------------------------------------------------------
Dry scrubber
Operating parameters to be monitored Dry scrubber followed by
Data measurement Data recording followed by Wet scrubber fabric
fabric filter and
filter wet scrubber
--------------------------------------------------------------------------------------------------------------------------------------------------------
Maximum operating parameters:
Maximum charge rate.................. Continuous....................... 1 x hour........................ [bcheck] [bcheck] [bcheck]
Maximum fabric filter inlet Continuous....................... 1 x minute...................... [bcheck] ............ [bcheck]
temperature.
Maximum flue gas temperature......... Continuous....................... 1 x minute...................... [bcheck] [bcheck]
Minimum operating parameters:
Minimum secondary chamber temperature Continuous....................... 1 x minute...................... [bcheck] [bcheck] [bcheck]
Minimum dioxin/furan sorbent flow Hourly........................... 1 x hour........................ [bcheck] ............ [bcheck]
rate.
Minimum HCI sorbent flow rate........ Hourly........................... 1 x hour........................ [bcheck] ............ [bcheck]
Minimum mercury (Hg) sorbent flow Hourly........................... 1 x hour........................ [bcheck] ............ [bcheck]
rate.
Minimum pressure drop across the wet Continuous....................... 1 x minute...................... ............ [bcheck] [bcheck]
scrubber or minimum horsepower or
amperage to wet scrubber.
Minimum scrubber liquor flow rate.... Continuous....................... 1 x minute...................... ............ [bcheck] [bcheck]
Minimum scrubber liquor pH........... Continuous....................... 1 x minute...................... ............ [bcheck] [bcheck]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Subpart F_Standards of Performance for Portland Cement Plants
Sec. 60.60 Applicability and designation of affected facility.
(a) The provisions of this subpart are applicable to the following
affected facilities in portland cement plants: Kiln, clinker cooler, raw
mill system, finish mill system, raw mill dryer, raw material storage,
clinker storage, finished product storage, conveyor transfer points,
bagging and bulk loading and unloading systems.
(b) Any facility under paragraph (a) of this section that commences
construction or modification after August 17, 1971, is subject to the
requirements of this subpart.
[42 FR 37936, July 25, 1977]
Sec. 60.61 Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Act and in subpart A of this part.
(a) Portland cement plant means any facility manufacturing portland
cement by either the wet or dry process.
(b) Bypass means any system that prevents all or a portion of the
kiln or clinker cooler exhaust gases from entering the main control
device and ducts the gases through a separate control device. This does
not include emergency systems designed to duct exhaust gases directly to
the atmosphere in the event of a malfunction of any control device
controlling kiln or clinker cooler emissions.
(c) Bypass stack means the stack that vents exhaust gases to the
atmosphere from the bypass control device.
(d) Monovent means an exhaust configuration of a building or
emission control device (e.g., positive-pressure fabric filter) that
extends the length of the structure and has a width very small in
relation to its length (i.e., length to width ratio is typically greater
than 5:1). The exhaust may be an open vent with or without a roof,
louvered vents, or a combination of such features.
[[Page 298]]
(e) Excess emissions means, with respect to this subpart, results of
any required measurements outside the applicable range (e.g., emissions
limitations, parametric operating limits) that is permitted by this
subpart. The values of measurements will be in the same units and
averaging time as the values specified in this subpart for the
limitations.
(f) Operating day means a 24-hour period beginning at 12:00 midnight
during which the kiln produces clinker at any time. For calculating 30
day rolling average emissions, an operating day does not include the
hours of operation during startup or shutdown.
(g) Rolling average means the weighted average of all data, meeting
QA/QC requirements or otherwise normalized, collected during the
applicable averaging period. The period of a rolling average stipulates
the frequency of data averaging and reporting. To demonstrate compliance
with an operating parameter a 30-day rolling average period requires
calculation of a new average value each operating day and shall include
the average of all the hourly averages of the specific operating
parameter. For demonstration of compliance with an emissions limit based
on pollutant concentration, a 30-day rolling average is comprised of the
average of all the hourly average concentrations over the previous 30
operating days. For demonstration of compliance with an emissions limit
based on lbs-pollutant per production unit, the 30-day rolling average
is calculated by summing the hourly mass emissions over the previous 30
operating days, then dividing that sum by the total production during
the same period.
(h) Run average means the average of the recorded parameter values
for a run.
[36 FR 24877, Dec. 23, 1971, as amended at 39 FR 20793, June 13, 1974;
53 FR 50363, Dec. 14, 1988; 78 FR 10032, Feb. 12, 2013; 80 FR 44776,
July 27, 2015]
Sec. 60.62 Standards.
(a) On and after the date on which the performance test required to
be conducted by Sec. 60.8 is completed, you may not discharge into the
atmosphere from any kiln any gases which:
(1) Contain particulate matter (PM) in excess of:
(i) 0.30 pounds per ton of feed (dry basis) to the kiln for kilns
constructed, reconstructed, or modified after August 17, 1971 but on or
before June 16, 2008.
(ii) 0.02 pound per ton of clinker if construction or reconstruction
of the kiln commenced after June 16, 2008.
(iii) Kilns that have undergone a modification may not discharge
into the atmosphere any gases which contain PM in excess of 0.07 pound
per ton of clinker.
(2) Exhibit greater than 20 percent opacity for kilns constructed,
reconstructed, or modified after August 17, 1971 but on or before June
16, 2008, except that this opacity limit does not apply to any kiln
subject to a PM limit in paragraph (a)(1) of this section that uses a PM
continuous parametric monitoring system (CPMS).
(3) Exceed 1.50 pounds of nitrogen oxide (NOX) per ton of
clinker on a 30-operating day rolling average if construction,
reconstruction, or modification of the kiln commences after June 16,
2008, except this limit does not apply to any alkali bypass installed on
the kiln. An operating day includes all valid data obtained in any daily
24-hour period during which the kiln operates and excludes any
measurements made during the daily 24-hour period when the kiln was not
operating.
(4) Exceed 0.4 pounds of sulfur dioxide (SO2) per ton of
clinker on a 30-operating day rolling average if construction,
reconstruction, or modification commences after June 16, 2008, unless
you are demonstrating a 90 percent SO2 emissions reduction
measured across the SO2 control device. An operating day
includes all valid data obtained in any daily 24-hour period during
which the kiln operates, and excludes any measurements made during the
daily 24-hour period when the kiln was not operating.
(b) On and after the date on which the performance test required to
be conducted by Sec. 60.8 is completed, you may not discharge into the
atmosphere from any clinker cooler any gases which:
(1) Contain PM in excess of:
[[Page 299]]
(i) 0.02 pound per ton of clinker if construction or reconstruction
of the clinker cooler commences after June 16, 2008.
(ii) 0.07 pound per ton of clinker if the clinker cooler has
undergone a modification.
(iii) 0.10 lb per ton of feed (dry basis) for clinker coolers
constructed, reconstructed, or modified after August 17, 1971, but on or
before June 16, 2008.
(iv) 10 percent opacity for clinker coolers constructed,
reconstructed, or modified after August 17, 1971, but on or before June
16, 2008, except that this opacity limit does not apply to any clinker
cooler subject to a PM limit in paragraph (b)(1) of this section that
uses a PM continuous parametric monitoring system (CPMS).
(2) If the kiln and clinker cooler exhaust are combined for energy
efficiency purposes and sent to a single control device, the appropriate
kiln PM limit may be adjusted using the procedures in Sec. 63.1343(b)
of this chapter.
(3) If the kiln has a separated alkali bypass stack and/or an inline
coal mill with a separate stack, you must combine the PM emissions from
the bypass stack and/or the inline coal mill stack with the PM emissions
from the main kiln exhaust to determine total PM emissions.
(c) On and after the date on which the performance test required to
be conducted by Sec. 60.8 is completed, you may not discharge into the
atmosphere from any affected facility other than the kiln and clinker
cooler any gases which exhibit 10 percent opacity, or greater.
(d) If you have an affected source subject to this subpart with a
different emissions limit or requirement for the same pollutant under
another regulation in title 40 of this chapter, once you are in
compliance with the most stringent emissions limit or requirement, you
are not subject to the less stringent requirement. Until you are in
compliance with the more stringent limit, the less stringent limit
continues to apply.
(e) The compliance date for all revised monitoring and recordkeeping
requirements contained in this rule will be the same as listed in
63.1351(c) unless you commenced construction as of June 16, 2008, at
which time the compliance date is November 8, 2010 or upon startup,
whichever is later.
[75 FR 55034, Sept. 9, 2010, as amended at 78 FR 10032, Feb. 12, 2013;
80 FR 44777, July 27, 2015]
Sec. 60.63 Monitoring of operations.
(a) [Reserved]
(b) Clinker production monitoring requirements. For any kiln subject
to an emissions limitation on PM, NOX, or SO2
emissions (lb/ton of clinker), you must:
(1) Determine hourly clinker production by one of two methods:
(i) Install, calibrate, maintain, and operate a permanent weigh
scale system to measure and record weight rates of the amount of clinker
produced in tons of mass per hour. The system of measuring hourly
clinker production must be maintained within 5
percent accuracy or
(ii) Install, calibrate, maintain, and operate a permanent weigh
scale system to measure and record weight rates of the amount of feed to
the kiln in tons of mass per hour. The system of measuring feed must be
maintained within 5 percent accuracy. Calculate
your hourly clinker production rate using a kiln specific feed-to-
clinker ratio based on reconciled clinker production rates determined
for accounting purposes and recorded feed rates. This ratio should be
updated monthly. Note that if this ratio changes at clinker
reconciliation, you must use the new ratio going forward, but you do not
have to retroactively change clinker production rates previously
estimated.
(iii) For each kiln operating hour for which you do not have data on
clinker production or the amount of feed to the kiln, use the value from
the most recent previous hour for which valid data are available.
(2) Determine, record, and maintain a record of the accuracy of the
system of measuring hourly clinker production rates or feed rates before
initial use (for new sources) or by the effective compliance date of
this rule (for existing sources). During each quarter of source
operation, you must determine, record, and maintain a record of the
[[Page 300]]
ongoing accuracy of the system of measuring hourly clinker production
rates or feed rates.
(3) If you measure clinker production directly, record the daily
clinker production rates; if you measure the kiln feed rates and
calculate clinker production, record the daily kiln feed and clinker
production rates.
(c) PM Emissions Monitoring Requirements. (1) For each kiln or
clinker cooler subject to a PM emissions limit in Sec. Sec.
60.62(a)1(ii) and 60.62(a)1(iii) or Sec. Sec. 60.62(b)(1)(i) and
60.62(b)(1)(ii), you must demonstrate compliance through an initial
performance test. You will conduct your performance test using Method 5
or Method 5I at appendix A-3 to part 60 of this chapter. You must also
monitor continuous performance through use of a PM CPMS.
(2) For your PM CPMS, you will establish a site-specific operating
limit. If your PM performance test demonstrates your PM emission levels
to be below 75 percent of your emission limit you will use the average
PM CPMS value recorded during the PM compliance test, the milliamp
equivalent of zero output from your PM CPMS, and the average PM result
of your compliance test to establish your operating limit equivalent to
75 percent of the standard. If your PM compliance test demonstrates your
PM emission levels to be at or above 75 percent of your emission limit
you will use the average PM CPMS value recorded during the PM compliance
test demonstrating compliance with the PM limit to establish your
operating limit. You will use the PM CPMS to demonstrate continuous
compliance with your operating limit. You must repeat the performance
test annually and reassess and adjust the site-specific operating limit
in accordance with the results of the performance test.
(i) Your PM CPMS must provide a 4-20 milliamp or digital signal
output and the establishment of its relationship to manual reference
method measurements must be determined in units of milliamps or the
monitors digital equivalent.
(ii) Your PM CPMS operating range must be capable of reading PM
concentrations from zero to a level equivalent to two times your
allowable emission limit. If your PM CPMS is an auto-ranging instrument
capable of multiple scales, the primary range of the instrument must be
capable of reading PM concentration from zero to a level equivalent to
two times your allowable emission limit.
(iii) During the initial performance test or any such subsequent
performance test that demonstrates compliance with the PM limit, record
and average all milliamp or digital output values from the PM CPMS for
the periods corresponding to the compliance test runs (e.g., average all
your PM CPMS output values for three corresponding 2-hour Method 5I test
runs).
(3) Determine your operating limit as specified in paragraphs
(c)(4)(i) through (c)(5) of this section. If your PM performance test
demonstrates your PM emission levels to be below 75 percent of your
emission limit, you will use the average PM CPMS value recorded during
the PM compliance test, the milliamp or digital equivalent of zero
output from your PM CPMS, and the average PM result of your compliance
test to establish your operating limit. If your PM compliance test
demonstrates your PM emission levels to be at or above 75 percent of
your emission limit, you will use the average PM CPMS value recorded
during the PM compliance test to establish your operating limit. You
must verify an existing or establish a new operating limit after each
repeated performance test. You must repeat the performance test at least
annually and reassess and adjust the site-specific operating limit in
accordance with the results of the performance test.
(4) If the average of your three Method 5 or 5I compliance test runs
are below 75 percent of your PM emission limit, you must calculate an
operating limit by establishing a relationship of PM CPMS signal to PM
concentration using the PM CPMS instrument zero, the average PM CPMS
values corresponding to the three compliance test runs, and the average
PM concentration from the Method 5 or 5I compliance test with the
procedures in (c)(4)(i)(A) through (D) of this section.
(i) Determine your PM CPMS instrument zero output with one of the
following procedures.
[[Page 301]]
(A) Zero point data for in-situ instruments should be obtained by
removing the instrument from the stack and monitoring ambient air on a
test bench.
(B) Zero point data for extractive instruments should be obtained by
removing the extractive probe from the stack and drawing in clean
ambient air.
(C) The zero point can also can be obtained by performing manual
reference method measurements when the flue gas is free of PM emissions
or contains very low PM concentrations (e.g., when your process is not
operating, but the fans are operating or your source is combusting only
natural gas) and plotting these with the compliance data to find the
zero intercept.
(D) If none of the steps in paragraphs (c)(4)(i)(A) through (C) of
this section are possible, you must use a zero output value provided by
the manufacturer.
(ii) Determine your PM CPMS instrument average in milliamps or
digital equivalent and the average of your corresponding three PM
compliance test runs, using equation 1.
[GRAPHIC] [TIFF OMITTED] TR27JY15.006
Where:
X1 = The PM CPMS data points for the three runs constituting
the performance test,
Y1 = The PM concentration value for the three runs
constituting the performance test, and
n = The number of data points.
(iii) With your PM CPMS instrument zero expressed in milliamps or a
digital value, your three run average PM CPMS milliamp or digital signal
value, and your three run average PM concentration from your three PM
performance test runs, determine a relationship of lb/ton-clinker per
milliamp or digital signal with equation 2.
[GRAPHIC] [TIFF OMITTED] TR27JY15.007
Where:
R = The relative lb/ton clinker per milliamp or digital equivalent for
your PM CPMS.
Y1 = The three run average PM lb/ton clinker.
X1 = The three run average milliamp or digital signal output
from your PM CPMS.
z = The milliamp or digital equivalent of your instrument zero
determined from (c)(4)(i) of this section.
(iv) Determine your source specific 30-day rolling average operating
limit using the lb/ton-clinker per milliamp or digital signal value from
Equation 2 above in Equation 3, below. This sets your operating limit at
the PM CPMS output value corresponding to 75 percent of your emission
limit.
[GRAPHIC] [TIFF OMITTED] TR27JY15.008
Where:
Ol = The operating limit for your PM CPMS on a 30-day rolling
average, in milliamps or the digital equivalent.
[[Page 302]]
L = Your source emission limit expressed in lb/ton clinker.
z = Your instrument zero in milliamps or a digital equivalent,
determined from (1)(i).
R = The relative lb/ton-clinker per milliamp or digital equivalent, for
your PM CPMS, from Equation 2.
(5) If the average of your three PM compliance test runs is at or
above 75 percent of your PM emission limit, you must determine your
operating limit by averaging the PM CPMS milliamp or digital equivalent
output corresponding to your three PM performance test runs that
demonstrate compliance with the emission limit using Equation 4.
[GRAPHIC] [TIFF OMITTED] TR27JY15.009
Where:
X1 = The PM CPMS data points for all runs i.
n = The number of data points.
Oh = Your site specific operating limit, in milliamps or
digital equivalent.
(6) To determine continuous compliance, you must record the PM CPMS
output data for all periods when the process is operating, and use all
the PM CPMS data for calculations when the source is not out-of-control.
You must demonstrate continuous compliance by using all quality-assured
hourly average data collected by the PM CPMS for all operating hours to
calculate the arithmetic average operating parameter in units of the
operating limit (milliamps or the digital equivalent) on a 30 operating
day rolling average basis, updated at the end of each new kiln operating
day. Use Equation 5 to determine the 30 kiln operating day average.
[GRAPHIC] [TIFF OMITTED] TR27JY15.010
Where:
Hpvi = The hourly parameter value for hour i.
n = The number of valid hourly parameter values collected over the
previous 30 kiln operating days.
(7) Use EPA Method 5 or Method 5I of appendix A to part 60 of this
chapter to determine PM emissions. For each performance test, conduct at
least three separate runs each while the mill is on and the mill is off
under the conditions that exist when the affected source is operating at
the level reasonably expected to occur. Conduct each test run to collect
a minimum sample volume of 2 dscm for determining compliance with a new
source limit and 1 dscm for determining compliance with an existing
source limit. Calculate the time weighted average of the results from
three consecutive runs to determine compliance. You need not determine
the particulate matter collected in the impingers (``back half'') of the
Method 5 or Method 5I particulate sampling train to demonstrate
compliance with the PM standards of this subpart. This shall not
preclude the permitting authority from requiring a determination of the
``back half'' for other purposes.
(8) For PM performance test reports used to set a PM CPMS operating
limit, the electronic submission of the test report must also include
the make and model of the PM CPMS instrument, serial number of the
instrument, analytical principle of the instrument (e.g. beta
attenuation), span of the instruments primary analytical range, milliamp
or digital signal value equivalent to the instrument zero output,
[[Page 303]]
technique by which this zero value was determined, and the average
milliamp or digital equivalent signals corresponding to each PM
compliance test run.
(d) You must install, operate, calibrate, and maintain a CEMS
continuously monitoring and recording the concentration by volume of
NOX emissions into the atmosphere for any kiln subject to the
NOX emissions limit in Sec. 60.62(a)(3). If the kiln has an
alkali bypass, NOX emissions from the alkali bypass do not
need to be monitored, and NOX emission monitoring of the kiln
exhaust may be done upstream of any commingled alkali bypass gases.
(e) You must install, operate, calibrate, and maintain a CEMS for
continuously monitoring and recording the concentration by volume of
SO2 emissions into the atmosphere for any kiln subject to the
SO2 emissions limit in Sec. 60.62(a)(4). If you are
complying with the alternative 90 percent SO2 emissions
reduction emissions limit, you must also continuously monitor and record
the concentration by volume of SO2 present at the wet
scrubber inlet.
(f) The NOX and SO2 CEMS required under
paragraphs (d) and (e) of this section must be installed, operated and
maintained according to Performance Specification 2 of appendix B of
this part and the requirements in paragraphs (f)(1) through (5) of this
section.
(1) The span value of each NOX CEMS monitor must be set
at 125 percent of the maximum estimated hourly potential NOX
emission concentration that translates to the applicable emissions limit
at full clinker production capacity.
(2) You must conduct performance evaluations of each NOX
CEMS monitor according to the requirements in Sec. 60.13(c) and
Performance Specification 2 of appendix B to this part. You must use
Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to this part for conducting
the relative accuracy evaluations. The method ASME PTC 19.10-1981,
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see Sec.
60.17) is an acceptable alternative to Method 7 or 7C of appendix A-4 to
this part.
(3) The span value for the SO2 CEMS monitor is the
SO2 emission concentration that corresponds to 125 percent of
the applicable emissions limit at full clinker production capacity and
the expected maximum fuel sulfur content.
(4) You must conduct performance evaluations of each SO2
CEMS monitor according to the requirements in Sec. 60.13(c) and
Performance Specification 2 of appendix B to this part. You must use
Methods 6, 6A, or 6C of appendix A-4 to this part for conducting the
relative accuracy evaluations. The method ASME PTC 19.10-1981, ``Flue
and Exhaust Gas Analyses,'' (incorporated by reference--see Sec. 60.17)
is an acceptable alternative to Method 6 or 6A of appendix A-4 to this
part.
(5) You must comply with the quality assurance requirements in
Procedure 1 of appendix F to this part for each NOX and
SO2 CEMS, including quarterly accuracy determinations for
monitors, and daily calibration drift tests.
(g) For each CPMS or CEMS required under paragraphs (c) through (e)
of this section:
(1) You must operate the monitoring system and collect data at all
required intervals at all times the affected source is operating, except
for periods of monitoring system malfunctions, repairs associated with
monitoring system malfunctions, and required monitoring system quality
assurance or quality control activities (including, as applicable,
calibration checks and required zero and span adjustments).
(2) You may not use data recorded during the monitoring system
malfunctions, repairs associated with monitoring system malfunctions, or
required monitoring system quality assurance or control activities in
calculations used to report emissions or operating levels. A monitoring
system malfunction is any sudden, infrequent, not reasonably preventable
failure of the monitoring system to provide valid data. Monitoring
system failures that are caused in part by poor maintenance or careless
operation are not malfunctions. An owner or operator must use all the
data collected during all other periods in reporting emissions or
operating levels.
(3) You must meet the requirements of Sec. 60.13(h) when
determining the 1-hour averages of emissions data.
[[Page 304]]
(h) You must install, operate, calibrate, and maintain instruments
for continuously measuring and recording the stack gas flow rate to
allow determination of the pollutant mass emissions rate to the
atmosphere for each kiln subject to the PM emissions limits in Sec.
60.62(a)(1)(ii) and (iii) and (b)(1)(i) and (ii), the NOX
emissions limit in Sec. 60.62(a)(3), or the SO2 emissions
limit in Sec. 60.62(a)(4) according to the requirements in paragraphs
(h)(1) through (10), where appropriate, of this section.
(1) The owner or operator must install each sensor of the flow rate
monitoring system in a location that provides representative measurement
of the exhaust gas flow rate at the sampling location of the
NOX and/or SO2 CEMS, taking into account the
manufacturer's recommendations. The flow rate sensor is that portion of
the system that senses the volumetric flow rate and generates an output
proportional to that flow rate.
(2) The flow rate monitoring system must be designed to measure the
exhaust gas flow rate over a range that extends from a value of at least
20 percent less than the lowest expected exhaust flow rate to a value of
at least 20 percent greater than the highest expected exhaust gas flow
rate.
(3) The flow rate monitoring system must have a minimum accuracy of
5 percent of the flow rate.
(4) The flow rate monitoring system must be equipped with a data
acquisition and recording system that is capable of recording values
over the entire range specified in paragraph (h)(2) of this section.
(5) The signal conditioner, wiring, power supply, and data
acquisition and recording system for the flow rate monitoring system
must be compatible with the output signal of the flow rate sensors used
in the monitoring system.
(6) The flow rate monitoring system must be designed to measure a
minimum of one cycle of operational flow for each successive 15-minute
period.
(7) The flow rate sensor must be able to determine the daily zero
and upscale calibration drift (CD) (see sections 3.1 and 8.3 of
Performance Specification 2 in appendix B to this part for a discussion
of CD).
(i) Conduct the CD tests at two reference signal levels, zero (e.g.,
0 to 20 percent of span) and upscale (e.g., 50 to 70 percent of span).
(ii) The absolute value of the difference between the flow monitor
response and the reference signal must be equal to or less than 3
percent of the flow monitor span.
(8) You must perform an initial relative accuracy test of the flow
rate monitoring system according to section 8.2 of Performance
Specification 6 of appendix B to this part, with the exceptions noted in
paragraphs (h)(8)(i) and (ii) of this section.
(i) The relative accuracy test is to evaluate the flow rate
monitoring system alone rather than a continuous emission rate
monitoring system.
(ii) The relative accuracy of the flow rate monitoring system shall
be no greater than 10 percent of the mean value of the reference method
data.
(9) You must verify the accuracy of the flow rate monitoring system
at least once per year by repeating the relative accuracy test specified
in paragraph (h)(8) of this section.
(10) You must operate the flow rate monitoring system and record
data during all periods of operation of the affected facility including
periods of startup, shutdown, and malfunction, except for periods of
monitoring system malfunctions, repairs associated with monitoring
system malfunctions, and required monitoring system quality assurance or
quality control activities (including, as applicable, calibration checks
and required zero and span adjustments.
(i) Development and Submittal (Upon Request) of Monitoring Plans. To
demonstrate compliance with any applicable emissions limit through
performance stack testing or other emissions monitoring (including PM
CPMS), you must develop a site-specific monitoring plan according to the
requirements in paragraphs (i)(1) through (4) of this section. This
requirement also applies to you if you petition the EPA Administrator
for alternative monitoring parameters under Sec. 60.13(3)(i). If you
use a bag leak detector system (BLDS), you must also meet the
requirements specified in paragraph Sec. 63.1350(m)(10) of this
chapter.
[[Page 305]]
(1) For each continuous monitoring system (CMS) required in this
section, you must develop, and submit to the permitting authority for
approval upon request, a site-specific monitoring plan that addresses
paragraphs (i)(1)(i) through (iii) of this section. You must submit this
site-specific monitoring plan, if requested, at least 30 days before the
initial performance evaluation of your CMS.
(i) Installation of the CMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of control of the exhaust emissions
(e.g., on or downstream of the last control device);
(ii) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems; and
(iii) Performance evaluation procedures and acceptance criteria
(e.g., calibrations).
(2) In your site-specific monitoring plan, you must also address
paragraphs (i)(2)(i) through (iii) of this section.
(i) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec. 63.8(c)(1), (c)(3), and (c)(4)(ii);
(ii) Ongoing data quality assurance procedures in accordance with
the general requirements of Sec. 63.8(d); and
(iii) Ongoing recordkeeping and reporting procedures in accordance
with the general requirements of Sec. 63.10(c), (e)(1), and (e)(2)(i).
(3) You must conduct a performance evaluation of each CMS in
accordance with your site-specific monitoring plan.
(4) You must operate and maintain the CMS in continuous operation
according to the site-specific monitoring plan.
[75 FR 55035, Sept. 9, 2010, as amended at 78 FR 10032, Feb. 12, 2013;
80 FR 44777, July 27, 2015]
Sec. 60.64 Test methods and procedures.
(a) In conducting the performance tests and relative accuracy tests
required in Sec. 60.8, you must use reference methods and procedures
and the test methods in appendix A of this part or other methods and
procedures as specified in this section, except as provided in Sec.
60.8(b).
(b)(1)You must demonstrate compliance with the PM standards in Sec.
60.62 using EPA method 5 or method 5I.
(2) Use Method 9 and the procedures in Sec. 60.11 to determine
opacity.
(3) Any sources other than kilns (including associated alkali bypass
and clinker cooler) that are subject to the 10 percent opacity limit
must follow the appropriate monitoring procedures in Sec. 63.1350(f),
(m)(1)through (4), (10) and (11), (o), and (p) of this chapter.
(c) Calculate and record the rolling 30 kiln operating day average
emission rate daily of NOX and SO2 according to
the procedures in paragraph (c)(1) of this section.
(1) Calculate the rolling 30 kiln operating day average emissions
according to equation 6:
[GRAPHIC] [TIFF OMITTED] TR12FE13.005
Where:
E30D = 30 kiln operating day average emission rate of
NOX or SO2, lb/ton of clinker.
Ci = Concentration of NOX or SO2 for
hour i, ppm.
Qi = Volumetric flow rate of effluent gas for hour i, where
Ci and Qi are on the same basis (either wet or
dry), scf/hr.
P = 30 days of clinker production during the same time period as the
NOX or SO2 emissions measured, tons.
k = Conversion factor, 1.194 x 10-7 for NOX and
1.660 x 10-7 for SO2, lb/scf/ppm.
n = Number of kiln operating hours over 30 kiln operating days.
(2) [Reserved]
[[Page 306]]
(d)(1) Within 60 days after the date of completing each performance
test (see Sec. 60.8) as required by this subpart you must submit the
results of the performance tests conducted to demonstrate compliance
under this subpart to the EPA's WebFIRE database by using the Compliance
and Emissions Data Reporting Interface (CEDRI) that is accessed through
the EPA's Central Data Exchange (CDX) (http://www.epa.gov/cdx).
Performance test data must be submitted in the file format generated
through use of the EPA's Electronic Reporting Tool (ERT) (see http://
www.epa.gov/ttn/chief/ert/index.html). Only data collected using test
methods on the ERT Web site are subject to this requirement for
submitting reports electronically to WebFIRE. Owners or operators who
claim that some of the information being submitted for performance tests
is confidential business information (CBI) must submit a complete ERT
file including information claimed to be CBI on a compact disk, flash
drive or other commonly used electronic storage media to the EPA. The
electronic media must be clearly marked as CBI and mailed to U.S. EPA/
OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02,
4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI
omitted must be submitted to the EPA via CDX as described earlier in
this paragraph. At the discretion of the delegated authority, you must
also submit these reports, including the CBI, to the delegated authority
in the format specified by the delegated authority. For any performance
test conducted using test methods that are not listed on the ERT Web
site, you must submit the results of the performance test to the
Administrator at the appropriate address listed in Sec. 63.13.
(2) Within 60 days after the date of completing each CEMS
performance evaluation test as defined in Sec. 63.2, you must submit
relative accuracy test audit (RATA) data to the EPA's CDX by using CEDRI
in accordance with paragraph (d)(1) of this section. Only RATA
pollutants that can be documented with the ERT (as listed on the ERT Web
site) are subject to this requirement. For any performance evaluations
with no corresponding RATA pollutants listed on the ERT Web site, you
must submit the results of the performance evaluation to the
Administrator at the appropriate address listed in Sec. 63.13.
(3) For PM performance test reports used to set a PM CPMS operating
limit, the electronic submission of the test report must also include
the make and model of the PM CPMS instrument, serial number of the
instrument, analytical principle of the instrument (e.g. beta
attenuation), span of the instruments primary analytical range, milliamp
value equivalent to the instrument zero output, technique by which this
zero value was determined, and the average milliamp signals
corresponding to each PM compliance test run.
(4) All reports required by this subpart not subject to the
requirements in paragraphs (d)(1) and (2) of this section must be sent
to the Administrator at the appropriate address listed in Sec. 63.13.
The Administrator or the delegated authority may request a report in any
form suitable for the specific case (e.g., by commonly used electronic
media such as Excel spreadsheet, on CD or hard copy). The Administrator
retains the right to require submittal of reports subject to paragraph
(d)(1) and (2) of this section in paper format.
[78 FR 10035, Feb. 12, 2013, as amended at 80 FR 44778, July 27, 2015]
Sec. 60.65 Recordkeeping and reporting requirements.
(a) Each owner or operator required to install a CPMS or CEMS under
sections Sec. 60.63(c) through (e) shall submit reports of excess
emissions. The content of these reports must comply with the
requirements in Sec. 60.7(c). Notwithstanding the provisions of Sec.
60.7(c), such reports shall be submitted semiannually.
(b) Each owner or operator of facilities subject to the provisions
of Sec. 60.63(c) through (e) shall submit semiannual reports of the
malfunction information required to be recorded by Sec. 60.7(b). These
reports shall include the frequency, duration, and cause of any incident
resulting in deenergization of any device controlling kiln emissions
[[Page 307]]
or in the venting of emissions directly to the atmosphere.
(c) The requirements of this section remain in force until and
unless the Agency, in delegating enforcement authority to a State under
section 111(c) of the Clean Air Act, 42 U.S.C. 7411, approves reporting
requirements or an alternative means of compliance surveillance adopted
by such States. In that event, affected sources within the State will be
relieved of the obligation to comply with this section, provided that
they comply with the requirements established by the State.
[78 FR 10035, Feb. 12, 2013]
Sec. 60.66 Delegation of authority.
(a) This subpart can be implemented and enforced by the U.S. EPA or
a delegated authority such as a State, local, or Tribal agency. You
should contact your U.S. EPA Regional Office to find out if this subpart
is delegated to a State, local, or Tribal agency within your State.
(b) In delegating implementation and enforcement authority to a
State, local, or Tribal agency, the approval authorities contained
paragraphs (b)(1) through (4) of this section are retained by the
Administrator of the U.S EPA and are not transferred to the State,
local, or Tribal agency.
(1) Approval of an alternative to any non-opacity emissions
standard.
(2) Approval of a major change to test methods under Sec. 60.8(b).
A ``major change to test method'' is defined in 40 CFR 63.90.
(3) Approval of a major change to monitoring under Sec. 60.13(i). A
``major change to monitoring'' is defined in 40 CFR 63.90.
(4) Approval of a major change to recordkeeping/reporting under
Sec. 60.7(b) through (f). A ``major change to recordkeeping/reporting''
is defined in 40 CFR 63.90.
[75 FR 55037, Sept. 9, 2010]
Subpart G_Standards of Performance for Nitric Acid Plants
Sec. 60.70 Applicability and designation of affected facility.
(a) The provisions of this subpart are applicable to each nitric
acid production unit, which is the affected facility.
(b) Any facility under paragraph (a) of this section that commences
construction or modification after August 17, 1971, and on or before
October 14, 2011 is subject to the requirements of this subpart. Any
facility that commences construction or modification after October 14,
2011 is subject to subpart Ga of this part.
[42 FR 37936, July 25, 1977, as amended at 77 FR 48445, Aug. 14, 2012]
Sec. 60.71 Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Act and in subpart A of this part.
(a) Nitric acid production unit means any facility producing weak
nitric acid by either the pressure or atmospheric pressure process.
(b) Weak nitric acid means acid which is 30 to 70 percent in
strength.
Sec. 60.72 Standard for nitrogen oxides.
(a) On and after the date on which the performance test required to
be conducted by Sec. 60.8 is completed, no owner or operator subject to
the provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases which:
(1) Contain nitrogen oxides, expressed as NO2, in excess
of 1.5 kg per metric ton of acid produced (3.0 lb per ton), the
production being expressed as 100 percent nitric acid.
(2) Exhibit 10 percent opacity, or greater.
[39 FR 20794, June 14, 1974, as amended at 40 FR 46258, Oct. 6, 1975]
Sec. 60.73 Emission monitoring.
(a) The source owner or operator shall install, calibrate, maintain,
and operate a continuous monitoring system for measuring nitrogen oxides
(NOX). The pollutant gas mixtures under Performance
Specification 2 and for calibration checks under Sec. 60.13(d) of
[[Page 308]]
this part shall be nitrogen dioxide (NO2). The span value
shall be 500 ppm of NO2. Method 7 shall be used for the
performance evaluations under Sec. 60.13(c). Acceptable alternative
methods to Method 7 are given in Sec. 60.74(c).
(b) The owner or operator shall establish a conversion factor for
the purpose of converting monitoring data into units of the applicable
standard (kg/metric ton, lb/ton). The conversion factor shall be
established by measuring emissions with the continuous monitoring system
concurrent with measuring emissions with the applicable reference method
tests. Using only that portion of the continuous monitoring emission
data that represents emission measurements concurrent with the reference
method test periods, the conversion factor shall be determined by
dividing the reference method test data averages by the monitoring data
averages to obtain a ratio expressed in units of the applicable standard
to units of the monitoring data, i.e., kg/metric ton per ppm (lb/ton per
ppm). The conversion factor shall be reestablished during any
performance test under Sec. 60.8 or any continuous monitoring system
performance evaluation under Sec. 60.13(c).
(c) The owner or operator shall record the daily production rate and
hours of operation.
(d) [Reserved]
(e) For the purpose of reports required under Sec. 60.7(c), periods
of excess emissions that shall be reported are defined as any 3-hour
period during which the average nitrogen oxides emissions (arithmetic
average of three contiguous 1-hour periods) as measured by a continuous
monitoring system exceed the standard under Sec. 60.72(a).
[39 FR 20794, June 14, 1974, as amended at 40 FR 46258, Oct. 6, 1975; 50
FR 15894, Apr. 22, 1985; 54 FR 6666, Feb. 14, 1989]
Sec. 60.74 Test methods and procedures.
(a) In conducting the performance tests required in Sec. 60.8, the
owner or operator shall use as reference methods and procedures the test
methods in appendix A of this part or other methods and procedures as
specified in this section, except as provided in Sec. 60.8(b).
Acceptable alternative methods and procedures are given in paragraph (c)
of this section.
(b) The owner or operator shall determine compliance with the
NOX standard in Sec. 60.72 as follows:
(1) The emission rate (E) of NOX shall be computed for
each run using the following equation:
E = (Cs Qsd)/(P K)
where:
E = emission rate of NOX as NO2, kg/metric ton
(lb/ton) of 100 percent nitric acid.
Cs = concentration of NOX as NO2, g/
dscm (lb/dscf).
Qsd = volumetric flow rate of effluent gas, dscm/hr (dscf/
hr).
P = acid production rate, metric ton/hr (ton/hr) or 100 percent nitric
acid.
K = conversion factor, 1000 g/kg (1.0 lb/lb).
(2) Method 7 shall be used to determine the NOX
concentration of each grab sample. Method 1 shall be used to select the
sampling site, and the sampling point shall be the centroid of the stack
or duct or at a point no closer to the walls than 1 m (3.28 ft). Four
grab samples shall be taken at approximately 15-minute intervals. The
arithmetic mean of the four sample concentrations shall constitute the
run value (Cs).
(3) Method 2 shall be used to determine the volumetric flow rate
(Qsd) of the effluent gas. The measurement site shall be the
same as for the NOX sample. A velocity traverse shall be made
once per run within the hour that the NOX samples are taken.
(4) The methods of Sec. 60.73(c) shall be used to determine the
production rate (P) of 100 percent nitric acid for each run. Material
balance over the production system shall be used to confirm the
production rate.
(c) The owner or operator may use the following as alternatives to
the reference methods and procedures specified in this section:
(1) For Method 7, Method 7A, 7B, 7C, or 7D may be used. If Method 7C
or 7D is used, the sampling time shall be at least 1 hour.
(d) The owner or operator shall use the procedure in Sec. 60.73(b)
to determine the conversion factor for converting the monitoring data to
the units of the standard.
[54 FR 6666, Feb. 14, 1989]
[[Page 309]]
Subpart Ga_Standards of Performance for Nitric Acid Plants for Which
Construction, Reconstruction, or Modification Commenced After October
14, 2011
Source: 77 FR 48445, Aug. 14, 2012, unless otherwise noted.
Sec. 60.70a Applicability and designation of affected facility.
(a) The provisions of this subpart are applicable to each nitric
acid production unit, which is the affected facility.
(b) This subpart applies to any nitric acid production unit that
commences construction or modification after October 14, 2011.
Sec. 60.71a Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Act and in subpart A of this part.
Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which are
independently and objectively evaluated in a judicial or administrative
proceeding.
Monitoring system malfunction means a sudden, infrequent, not
reasonably preventable failure of the monitoring system to provide valid
data. Monitoring system failures that are caused in part by poor
maintenance or careless operation are not malfunctions. You are required
to implement monitoring system repairs in response to monitoring system
malfunctions or out-of-control periods, and to return the monitoring
system to operation as expeditiously as practicable.
Nitric acid production unit means any facility producing weak nitric
acid by either the pressure or atmospheric pressure process.
Operating day means a 24-hour period beginning at 12:00 a.m. during
which the nitric acid production unit operated at any time during this
period.
Weak nitric acid means acid which is 30 to 70 percent in strength.
Sec. 60.72a Standards.
Nitrogen oxides. On and after the date on which the performance test
required to be conducted by Sec. 60.73a(e) is completed, you may not
discharge into the atmosphere from any affected facility any gases which
contain NOX, expressed as NO2, in excess of 0.50
pounds (lb) per ton of nitric acid produced, as a 30-day emission rate
calculated based on 30 consecutive operating days, the production being
expressed as 100 percent nitric acid. The emission standard applies at
all times.
Sec. 60.73a Emissions testing and monitoring.
(a) General emissions monitoring requirements. You must install and
operate a NOX concentration (ppmv) continuous emissions
monitoring system (CEMS). You must also install and operate a stack gas
flow rate monitoring system. With measurements of stack gas
NOX concentration and stack gas flow rate, you will determine
hourly NOX emissions rate (e.g., lb/hr) and with measured
data of the hourly nitric acid production (tons), calculate emissions in
units of the applicable emissions limit (lb/ton of 100 percent acid
produced). You must operate the monitoring system and report emissions
during all operating periods including unit startup and shutdown, and
malfunction.
(b) Nitrogen oxides concentration continuous emissions monitoring
system. (1) You must install, calibrate, maintain, and operate a CEMS
for measuring and recording the concentration of NOX
emissions in accordance with the provisions of Sec. 60.13 and
Performance Specification 2 of appendix B and Procedure 1 of appendix F
of this part. You must use cylinder gas audits to fulfill the quarterly
auditing requirement at section 5.1 of Procedure 1 of appendix F of this
part for the NOX concentration CEMS.
(2) For the NOX concentration CEMS, use a span value, as
defined in Performance Specification 2, section 3.11, of appendix B of
this part, of 500 ppmv (as NO2). If you emit NOX
at concentrations higher than 600 ppmv (e.g., during startup or shutdown
periods), you must apply a second CEMS or dual range CEMS and a second
span value equal to
[[Page 310]]
125 percent of the maximum estimated NOX emission
concentration to apply to the second CEMS or to the higher of the dual
analyzer ranges during such periods.
(3) For conducting the relative accuracy test audits, per
Performance Specification 2, section 8.4, of appendix B of this part and
Procedure 1, section 5.1.1, of appendix F of this part, use either EPA
Reference Method 7, 7A, 7C, 7D, or 7E of appendix A-4 of this part; EPA
Reference Method 320 of appendix A of part 63 of this chapter; or ASTM
D6348-03 (incorporated by reference, see Sec. 60.17). To verify the
operation of the second CEMS or the higher range of a dual analyzer CEMS
described in paragraph (b)(2) of this section, you need not conduct a
relative accuracy test audit but only the calibration drift test
initially (found in Performance Specification 2, section 8.3.1, of
appendix B of this part) and the cylinder gas audit thereafter (found in
Procedure 1, section 5.1.2, of appendix F of this part).
(4) If you use EPA Reference Method 7E of appendix A-4 of this part,
you must mitigate loss of NO2 in water according to the
requirements in paragraphs (b)(4)(i), (ii), or (iii) of this section and
verify performance by conducting the system bias checks required in EPA
Reference Method 7E, section 8, of appendix A-4 of this part according
to (b)(4)(iv) of this section, or follow the dynamic spike procedure
according to paragraph (b)(4)(v) of this section.
(i) For a wet-basis measurement system, you must measure and report
temperature of sample line and components (up to analyzer inlet) to
demonstrate that the temperatures remain above the sample gas dew point
at all times during the sampling.
(ii) You may use a dilution probe to reduce the dew point of the
sample gas.
(iii) You may use a refrigerated-type condenser or similar device
(e.g., permeation dryer) to remove condensate continuously from sample
gas while maintaining minimal contact between condensate and sample gas.
(iv) If your analyzer measures nitric oxide (NO) and nitrogen
dioxide (NO2) separately, you must use both NO and
NO2 calibration gases. Otherwise, you must substitute
NO2 calibration gas for NO calibration gas in the performance
of system bias checks.
(v) You must conduct dynamic spiking according to EPA Reference
Method 7E, section 16.1, of appendix A-4 of this part using
NO2 as the spike gas.
(5) Instead of a NOX concentration CEMS meeting
Performance Specification 2, you may apply an FTIR CEMS meeting the
requirements of Performance Specification 15 of appendix B of this part
to measure NOX concentrations. Should you use an FTIR CEMS,
you must replace the Relative Accuracy Test Audit requirements of
Procedure 1 of appendix F of this part with the validation requirements
and criteria of Performance Specification 15, sections 11.1.1 and 12.0,
of appendix B of this part.
(c) Determining NOX mass emissions rate values. You must use the
NOX concentration CEMS, acid production, gas flow rate
monitor and other monitoring data to calculate emissions data in units
of the applicable limit (lb NOX/ton of acid produced
expressed as 100 percent nitric acid).
(1) You must install, calibrate, maintain, and operate a CEMS for
measuring and recording the stack gas flow rates to use in combination
with data from the CEMS for measuring emissions concentrations of
NOX to produce data in units of mass rate (e.g., lb/hr) of
NOX on an hourly basis. You will operate and certify the
continuous emissions rate monitoring system (CERMS) in accordance with
the provisions of Sec. 60.13 and Performance Specification 6 of
appendix B of this part. You must comply with the following provisions
in (c)(1)(i) through (iii) of this section.
(i) You must use a stack gas flow rate sensor with a full scale
output of at least 125 percent of the maximum expected exhaust
volumetric flow rate (see Performance Specification 6, section 8, of
appendix B of this part).
(ii) For conducting the relative accuracy test audits, per
Performance Specification 6, section 8.2 of appendix B of this part and
Procedure 1, section 5.1.1, of appendix F of this part, you must use
either EPA Reference Method 2, 2F, or 2G of appendix A-4 of this part.
You may also apply Method 2H in conjunction with other velocity
measurements.
[[Page 311]]
(iii) You must verify that the CERMS complies with the quality
assurance requirements in Procedure 1 of appendix F of this part. You
must conduct relative accuracy testing to provide for calculating the
relative accuracy for RATA and RAA determinations in units of lb/hour.
(2) You must determine the nitric acid production parameters
(production rate and concentration) by installing, calibrating,
maintaining, and operating a permanent monitoring system (e.g., weigh
scale, volume flow meter, mass flow meter, tank volume) to measure and
record the weight rates of nitric acid produced in tons per hour. If
your nitric acid production rate measurements are for periods longer
than hourly (e.g., daily values), you will determine average hourly
production values, tons acid/hr, by dividing the total acid production
by the number of hours of process operation for the subject measurement
period. You must comply with the following provisions in (c)(2)(i)
through (iv) of this section.
(i) You must verify that each component of the monitoring system has
an accuracy and precision of no more than 5
percent of full scale.
(ii) You must analyze product concentration via titration or by
determining the temperature and specific gravity of the nitric acid. You
may also use ASTM E1584-11 (incorporated by reference, see Sec. 60.17),
for determining the concentration of nitric acid in percent. You must
determine product concentration daily.
(iii) You must use the acid concentration to express the nitric acid
production as 100 percent nitric acid.
(iv) You must record the nitric acid production, expressed as 100
percent nitric acid, and the hours of operation.
(3) You must calculate hourly NOX emissions rates in
units of the standard (lb/ton acid) for each hour of process operation.
For process operating periods for which there is little or no acid
production (e.g., startup or shutdown), you must use the average hourly
acid production rate determined from the data collected over the
previous 30 days of normal acid production periods (see Sec. 60.75a).
(d) Continuous monitoring system. For each continuous monitoring
system, including NOX concentration measurement, volumetric
flow rate measurement, and nitric acid production measurement equipment,
you must meet the requirements in paragraphs (d)(1) through (3) of this
section.
(1) You must operate the monitoring system and collect data at all
required intervals at all times the affected facility is operating
except for periods of monitoring system malfunctions or out-of-control
periods as defined in appendix F, sections 4 and 5, of this part,
repairs associated with monitoring system malfunctions or out-of-control
periods, and required monitoring system quality assurance or quality
control activities including, as applicable, calibration checks and
required zero and span adjustments.
(2) You may not use data recorded during monitoring system
malfunctions or out-of-control periods, repairs associated with
monitoring system malfunctions or out-of-control periods, or required
monitoring system quality assurance or control activities in
calculations used to report emissions or operating levels. You must use
all the data collected during all other periods in calculating emissions
and the status of compliance with the applicable emissions limit in
accordance with Sec. 60.72a(a).
(e) Initial performance testing. You must conduct an initial
performance test to demonstrate compliance with the NOX
emissions limit under Sec. 60.72a(a) beginning in the calendar month
following initial certification of the NOX and flow rate
monitoring CEMS. The initial performance test consists of collection of
hourly NOX average concentration, mass flow rate recorded
with the certified NOX concentration and flow rate CEMS and
the corresponding acid generation (tons) data for all of the hours of
operation for the first 30 days beginning on the first day of the first
month following completion of the CEMS installation and certification as
described above. You must assure that the CERMS meets all of the data
quality assurance requirements as per Sec. 60.13 and appendix F,
Procedure 1, of this part and you must use the data from the CERMS for
this compliance determination.
[[Page 312]]
Sec. 60.74a Affirmative defense for violations of emission standards
during malfunction.
In response to an action to enforce the standards set forth in Sec.
60.72a, you may assert an affirmative defense to a claim for civil
penalties for violations of such standards that are caused by
malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be
assessed, however, if you fail to meet your burden of proving all of the
requirements in the affirmative defense. The affirmative defense shall
not be available for claims for injunctive relief.
(a) To establish the affirmative defense in any action to enforce
such a standard, you must timely meet the reporting requirements in
paragraph (b) of this section, and must prove by a preponderance of
evidence that:
(1) The violation:
(i) Was caused by a sudden, infrequent, and unavoidable failure of
air pollution control equipment, process equipment, or a process to
operate in a normal or usual manner; and
(ii) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
(iii) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
(iv) Was not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(2) Repairs were made as expeditiously as possible when a violation
occurred. Off-shift and overtime labor were used, to the extent
practicable to make these repairs; and
(3) The frequency, amount, and duration of the violation (including
any bypass) were minimized to the maximum extent practicable; and
(4) If the violation resulted from a bypass of control equipment or
a process, then the bypass was unavoidable to prevent loss of life,
personal injury, or severe property damage; and
(5) All possible steps were taken to minimize the impact of the
violation on ambient air quality, the environment, and human health; and
(6) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
(7) All of the actions in response to the violation were documented
by properly signed, contemporaneous operating logs; and
(8) At all times, the affected facility was operated in a manner
consistent with good practices for minimizing emissions; and
(9) A written root cause analysis has been prepared, the purpose of
which is to determine, correct, and eliminate the primary causes of the
malfunction and the violation resulting from the malfunction event at
issue. The analysis shall also specify, using best monitoring methods
and engineering judgment, the amount of any emissions that were the
result of the malfunction.
(b) Report. The owner or operator seeking to assert an affirmative
defense shall submit a written report to the Administrator with all
necessary supporting documentation, that it has met the requirements set
forth in paragraph (a) of this section. This affirmative defense report
shall be included in the first periodic compliance, deviation report or
excess emission report otherwise required after the initial occurrence
of the violation of the relevant standard (which may be the end of any
applicable averaging period). If such compliance, deviation report or
excess emission report is due less than 45 days after the initial
occurrence of the violation, the affirmative defense report may be
included in the second compliance, deviation report or excess emission
report due after the initial occurrence of the violation of the relevant
standard.
Sec. 60.75a Calculations.
(a) You must calculate the 30 operating day rolling arithmetic
average emissions rate in units of the applicable emissions standard (lb
NOX/ton 100 percent acid produced) at the end of each
operating day using all of the quality assured hourly average CEMS data
for the previous 30 operating days.
(b) You must calculate the 30 operating day average emissions rate
according to Equation 1:
[[Page 313]]
[GRAPHIC] [TIFF OMITTED] TR06MY14.000
Where:
E30 = 30 operating day average emissions rate of
NOX, lb NOX/ton of 100 percent
HNO3;
Ci = concentration of NOX for hour i, ppmv;
Qi = volumetric flow rate of effluent gas for hour i, where
Ci and Qi are on the same basis (either
wet or dry), scf/hr;
Pi = total acid produced during production hour i, tons 100
percent HNO3;
k = conversion factor, 1.194 x 10-\7\ for NOX; and
n = number of operating hours in the 30 operating day period, i.e., n is
between 30 and 720.
[77 FR 48445, Aug. 14, 2012; 79 FR 25681, May 6, 2014]
Sec. 60.76a Recordkeeping.
(a) For the NOX emissions rate, you must keep records for
and results of the performance evaluations of the continuous emissions
monitoring systems.
(b) You must maintain records of the following information for each
30 operating day period:
(1) Hours of operation.
(2) Production rate of nitric acid, expressed as 100 percent nitric
acid.
(3) 30 operating day average NOX emissions rate values.
(c) You must maintain records of the following time periods:
(1) Times when you were not in compliance with the emissions
standards.
(2) Times when the pollutant concentration exceeded full span of the
NOX monitoring equipment.
(3) Times when the volumetric flow rate exceeded the high value of
the volumetric flow rate monitoring equipment.
(d) You must maintain records of the reasons for any periods of
noncompliance and description of corrective actions taken.
(e) You must maintain records of any modifications to CEMS which
could affect the ability of the CEMS to comply with applicable
performance specifications.
(f) For each malfunction, you must maintain records of the following
information:
(1) Records of the occurrence and duration of each malfunction of
operation (i.e., process equipment) or the air pollution control and
monitoring equipment.
(2) Records of actions taken during periods of malfunction to
minimize emissions in accordance with Sec. 60.11(d), including
corrective actions to restore malfunctioning process and air pollution
control and monitoring equipment to its normal or usual manner of
operation.
Sec. 60.77a Reporting.
(a) The performance test data from the initial and subsequent
performance tests and from the performance evaluations of the continuous
monitors must be submitted to the Administrator at the appropriate
address as shown in 40 CFR 60.4.
(b) The following information must be reported to the Administrator
for each 30 operating day period where you were not in compliance with
the emissions standard:
(1) Time period;
(2) NOX emission rates (lb/ton of acid produced);
(3) Reasons for noncompliance with the emissions standard; and
(4) Description of corrective actions taken.
(c) You must also report the following whenever they occur:
(1) Times when the pollutant concentration exceeded full span of the
NOX pollutant monitoring equipment.
(2) Times when the volumetric flow rate exceeded the high value of
the volumetric flow rate monitoring equipment.
[[Page 314]]
(d) You must report any modifications to CERMS which could affect
the ability of the CERMS to comply with applicable performance
specifications.
(e) Within 60 days of completion of the relative accuracy test audit
(RATA) required by this subpart, you must submit the data from that
audit to EPA's WebFIRE database by using the Compliance and Emissions
Data Reporting Interface (CEDRI) that is accessed through EPA's Central
Data Exchange (CDX) (https://cdx.epa.gov/SSL/cdx/EPA--Home.asp). You
must submit performance test data in the file format generated through
use of EPA's Electronic Reporting Tool (ERT) (http://www.epa.gov/ttn/
chief/ert/index.html). Only data collected using test methods listed on
the ERT Web site are subject to this requirement for submitting reports
electronically to WebFIRE. Owners or operators who claim that some of
the information being submitted for performance tests is confidential
business information (CBI) must submit a complete ERT file including
information claimed to be CBI on a compact disk or other commonly used
electronic storage media (including, but not limited to, flash drives)
by registered letter to EPA and the same ERT file with the CBI omitted
to EPA via CDX as described earlier in this paragraph. Mark the compact
disk or other commonly used electronic storage media clearly as CBI and
mail to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE
Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. At the
discretion of the delegated authority, you must also submit these
reports to the delegated authority in the format specified by the
delegated authority. You must submit the other information as required
in the performance evaluation as described in Sec. 60.2 and as required
in this chapter.
(f) If a malfunction occurred during the reporting period, you must
submit a report that contains the following:
(1) The number, duration, and a brief description for each type of
malfunction which occurred during the reporting period and which caused
or may have caused any applicable emission limitation to be exceeded.
(2) A description of actions taken by an owner or operator during a
malfunction of an affected facility to minimize emissions in accordance
with Sec. 60.11(d), including actions taken to correct a malfunction.
Subpart H_Standards of Performance for Sulfuric Acid Plants
Sec. 60.80 Applicability and designation of affected facility.
(a) The provisions of this subpart are applicable to each sulfuric
acid production unit, which is the affected facility.
(b) Any facility under paragraph (a) of this section that commences
construction or modification after August 17, 1971, is subject to the
requirements of this subpart.
[42 FR 37936, July 25, 1977]
Sec. 60.81 Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Act and in subpart A of this part.
(a) Sulfuric acid production unit means any facility producing
sulfuric acid by the contact process by burning elemental sulfur,
alkylation acid, hydrogen sulfide, organic sulfides and mercaptans, or
acid sludge, but does not include facilities where conversion to
sulfuric acid is utilized primarily as a means of preventing emissions
to the atmosphere of sulfur dioxide or other sulfur compounds.
(b) Acid mist means sulfuric acid mist, as measured by Method 8 of
appendix A to this part or an equivalent or alternative method.
[36 FR 24877, Dec. 23, 1971, as amended at 39 FR 20794, June 14, 1974]
Sec. 60.82 Standard for sulfur dioxide.
(a) On and after the date on which the performance test required to
be conducted by Sec. 60.8 is completed, no owner or operator subject to
the provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases which contain sulfur
dioxide in excess of 2 kg per metric ton of acid produced (4 lb
[[Page 315]]
per ton), the production being expressed as 100 percent
H2SO4.
[39 FR 20794, June 14, 1974]
Sec. 60.83 Standard for acid mist.
(a) On and after the date on which the performance test required to
be conducted by Sec. 60.8 is completed, no owner or operator subject to
the provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases which:
(1) Contain acid mist, expressed as H2SO4, in
excess of 0.075 kg per metric ton of acid produced (0.15 lb per ton),
the production being expressed as 100 percent
H2SO4.
(2) Exhibit 10 percent opacity, or greater.
[39 FR 20794, June 14, 1974, as amended at 40 FR 46258, Oct. 6, 1975]
Sec. 60.84 Emission monitoring.
(a) A continuous monitoring system for the measurement of sulfur
dioxide shall be installed, calibrated, maintained, and operated by the
owner or operator. The pollutant gas used to prepare calibration gas
mixtures under Performance Specification 2 and for calibration checks
under Sec. 60.13(d), shall be sulfur dioxide (SO2). Method 8
shall be used for conducting monitoring system performance evaluations
under Sec. 60.13(c) except that only the sulfur dioxide portion of the
Method 8 results shall be used. The span value shall be set at 1000 ppm
of sulfur dioxide.
(b) The owner or operator shall establish a conversion factor for
the purpose of converting monitoring data into units of the applicable
standard (kg/metric ton, lb/ton). The conversion factor shall be
determined, as a minimum, three times daily by measuring the
concentration of sulfur dioxide entering the converter using suitable
methods (e.g., the Reich test, National Air Pollution Control
Administration Publication No. 999-AP-13) and calculating the
appropriate conversion factor for each eight-hour period as follows:
CF = k[(1.000-0.015r)/(r-s)]
where:
CF = conversion factor (kg/metric ton per ppm, lb/ton per ppm).
k = constant derived from material balance. For determining CF in metric
units, k = 0.0653. For determining CF in English units, k =
0.1306.
r = percentage of sulfur dioxide by volume entering the gas converter.
Appropriate corrections must be made for air injection plants
subject to the Administrator's approval.
s = percentage of sulfur dioxide by volume in the emissions to the
atmosphere determined by the continuous monitoring system
required under paragraph (a) of this section.
(c) The owner or operator shall record all conversion factors and
values under paragraph (b) of this section from which they were computed
(i.e., CF, r, and s).
(d) Alternatively, a source that processes elemental sulfur or an
ore that contains elemental sulfur and uses air to supply oxygen may use
the following continuous emission monitoring approach and calculation
procedures in determining SO2 emission rates in terms of the
standard. This procedure is not required, but is an alternative that
would alleviate problems encountered in the measurement of gas
velocities or production rate. Continuous emission monitoring systems
for measuring SO2, O2, and CO2 (if
required) shall be installed, calibrated, maintained, and operated by
the owner or operator and subjected to the certification procedures in
Performance Specifications 2 and 3. The calibration procedure and span
value for the SO2 monitor shall be as specified in paragraph
(b) of this section. The span value for CO2 (if required)
shall be 10 percent and for O2 shall be 20.9 percent (air). A
conversion factor based on process rate data is not necessary. Calculate
the SO2 emission rate as follows:
Es = (Cs S)/[0.265 - (0.0126 %O2) - (A
%CO2)]
where:
Es = emission rate of SO2, kg/metric ton (lb/ton)
of 100 percent of H2SO4 produced.
Cs = concentration of SO2, kg/dscm (lb/dscf).
S = acid production rate factor, 368 dscm/metric ton (11,800 dscf/ton)
of 100 percent H2SO4 produced.
%O2 = oxygen concentration, percent dry basis.
A = auxiliary fuel factor,
= 0.00 for no fuel.
= 0.0226 for methane.
= 0.0217 for natural gas.
[[Page 316]]
= 0.0196 for propane.
= 0.0172 for No 2 oil.
= 0.0161 for No 6 oil.
= 0.0148 for coal.
= 0.0126 for coke.
%CO2 = carbon dioxide concentration, percent dry basis.
Note: It is necessary in some cases to convert measured
concentration units to other units for these calculations:
Use the following table for such conversions:
------------------------------------------------------------------------
From-- To-- Multiply by--
------------------------------------------------------------------------
g/scm............................. kg/scm.............. 10-3
mg/scm............................ kg/scm.............. 10-6
ppm (SO2)......................... kg/scm.............. 2.660 x 10-6
ppm (SO2)......................... lb/scf.............. 1.660 x 10-7
------------------------------------------------------------------------
(e) For the purpose of reports under Sec. 60.7(c), periods of
excess emissions shall be all three-hour periods (or the arithmetic
average of three consecutive one-hour periods) during which the
integrated average sulfur dioxide emissions exceed the applicable
standards under Sec. 60.82.
[39 FR 20794, June 14, 1974, as amended at 40 FR 46258, Oct. 6, 1975; 48
FR 23611, May 25, 1983; 48 FR 4700, Sept. 29, 1983; 48 FR 48669, Oct.
20, 1983; 54 FR 6666, Feb. 14, 1989; 65 FR 61753, Oct. 17, 2000; 79 FR
11250, Feb. 27, 2014]
Sec. 60.85 Test methods and procedures.
(a) In conducting the performance tests required in Sec. 60.8, the
owner or operator shall use as reference methods and procedures the test
methods in appendix A of this part or other methods and procedures as
specified in this section, except as provided in Sec. 60.8(b).
Acceptable alternative methods and procedures are given in paragraph (c)
of this section.
(b) The owner or operator shall determine compliance with the
SO2 acid mist, and visible emission standards in Sec. Sec.
60.82 and 60.83 as follows:
(1) The emission rate (E) of acid mist or SO2 shall be
computed for each run using the following equation:
E = (CQsd) / (PK)
where:
E = emission rate of acid mist or SO2 kg/metric ton (lb/ton)
of 100 percent H2SO4 produced.
C = concentration of acid mist or SO2, g/dscm (lb/dscf).
Qsd = volumetric flow rate of the effluent gas, dscm/hr
(dscf/hr).
P = production rate of 100 percent H2SO4, metric
ton/hr (ton/hr).
K = conversion factor, 1000 g/kg (1.0 lb/lb).
(2) Method 8 shall be used to determine the acid mist and
SO2 concentrations (C's) and the volumetric flow rate
(Qsd) of the effluent gas. The moisture content may be
considered to be zero. The sampling time and sample volume for each run
shall be at least 60 minutes and 1.15 dscm (40.6 dscf).
(3) Suitable methods shall be used to determine the production rate
(P) of 100 percent H2SO4 for each run. Material
balance over the production system shall be used to confirm the
production rate.
(4) Method 9 and the procedures in Sec. 60.11 shall be used to
determine opacity.
(c) The owner or operator may use the following as alternatives to
the reference methods and procedures specified in this section:
(1) If a source processes elemental sulfur or an ore that contains
elemental sulfur and uses air to supply oxygen, the following procedure
may be used instead of determining the volumetric flow rate and
production rate:
(i) The integrated technique of Method 3 is used to determine the
O2 concentration and, if required, CO2
concentration.
(ii) The SO2 or acid mist emission rate is calculated as
described in Sec. 60.84(d), substituting the acid mist concentration
for Cs as appropriate.
[54 FR 6666, Feb. 14, 1989]
Subpart I_Standards of Performance for Hot Mix Asphalt Facilities
Sec. 60.90 Applicability and designation of affected facility.
(a) The affected facility to which the provisions of this subpart
apply is each hot mix asphalt facility. For the purpose of this subpart,
a hot mix asphalt facility is comprised only of any combination of the
following: dryers; systems for screening, handling, storing, and
weighing hot aggregate; systems for loading, transferring, and storing
mineral filler, systems for mixing hot mix asphalt; and the loading,
transfer,
[[Page 317]]
and storage systems associated with emission control systems.
(b) Any facility under paragraph (a) of this section that commences
construction or modification after June 11, 1973, is subject to the
requirements of this subpart.
[42 FR 37936, July 25, 1977, as amended at 51 FR 12325, Apr. 10, 1986]
Sec. 60.91 Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Act and in subpart A of this part.
(a) Hot mix asphalt facility means any facility, as described in
Sec. 60.90, used to manufacture hot mix asphalt by heating and drying
aggregate and mixing with asphalt cements.
[51 FR 12325, Apr. 10, 1986]
Sec. 60.92 Standard for particulate matter.
(a) On and after the date on which the performance test required to
be conducted by Sec. 60.8 is completed, no owner or operator subject to
the provisions of this subpart shall discharge or cause the discharge
into the atmosphere from any affected facility any gases which:
(1) Contain particulate matter in excess of 90 mg/dscm (0.04 gr/
dscf).
(2) Exhibit 20 percent opacity, or greater.
[39 FR 9314, Mar. 8, 1974, as amended at 40 FR 46259, Oct. 6, 1975]
Sec. 60.93 Test methods and procedures.
(a) In conducting the performance tests required in Sec. 60.8, the
owner or operator shall use as reference methods and procedures the test
methods in appendix A of this part or other methods and procedures as
specified in this section, except as provided in Sec. 60.8(b).
(b) The owner or operator shall determine compliance with the
particulate matter standards in Sec. 60.92 as follows:
(1) Method 5 shall be used to determine the particulate matter
concentration. The sampling time and sample volume for each run shall be
at least 60 minutes and 0.90 dscm (31.8 dscf).
(2) Method 9 and the procedures in Sec. 60.11 shall be used to
determine opacity.
[54 FR 6667, Feb. 14, 1989]
Subpart J_Standards of Performance for Petroleum Refineries
Sec. 60.100 Applicability, designation of affected facility, and
reconstruction.
(a) The provisions of this subpart are applicable to the following
affected facilities in petroleum refineries: fluid catalytic cracking
unit catalyst regenerators, fuel gas combustion devices, and all Claus
sulfur recovery plants except Claus plants with a design capacity for
sulfur feed of 20 long tons per day (LTD) or less. The Claus sulfur
recovery plant need not be physically located within the boundaries of a
petroleum refinery to be an affected facility, provided it processes
gases produced within a petroleum refinery.
(b) Any fluid catalytic cracking unit catalyst regenerator or fuel
gas combustion device under paragraph (a) of this section other than a
flare which commences construction, reconstruction or modification after
June 11, 1973, and on or before May 14, 2007, or any fuel gas combustion
device under paragraph (a) of this section that is also a flare which
commences construction, reconstruction or modification after June 11,
1973, and on or before June 24, 2008, or any Claus sulfur recovery plant
under paragraph (a) of this section which commences construction,
reconstruction or modification after October 4, 1976, and on or before
May 14, 2007, is subject to the requirements of this subpart except as
provided under paragraphs (c) through (e) of this section.
(c) Any fluid catalytic cracking unit catalyst regenerator under
paragraph (b) of this section which commences construction,
reconstruction, or modification on or before January 17, 1984, is
exempted from Sec. 60.104(b).
(d) Any fluid catalytic cracking unit in which a contact material
reacts with petroleum derivatives to improve feedstock quality and in
which the contact material is regenerated by burning off coke and/or
other deposits and that
[[Page 318]]
commences construction, reconstruction, or modification on or before
January 17, 1984, is exempt from this subpart.
(e) Owners or operators may choose to comply with the applicable
provisions of subpart Ja of this part to satisfy the requirements of
this subpart for an affected facility.
(f) For purposes of this subpart, under Sec. 60.15, the ``fixed
capital cost of the new components'' includes the fixed capital cost of
all depreciable components which are or will be replaced pursuant to all
continuous programs of component replacement which are commenced within
any 2-year period following January 17, 1984. For purposes of this
paragraph, ``commenced'' means that an owner or operator has undertaken
a continuous program of component replacement or that an owner or
operator has entered into a contractual obligation to undertake and
complete, within a reasonable time, a continuous program of component
replacement.
[43 FR 10868, Mar. 15, 1978, as amended at 44 FR 61543, Oct. 25, 1979;
54 FR 34026, Aug. 17, 1989; 73 FR 35865, June 24, 2008; 77 FR 56463,
Sep. 12, 2012]
Sec. 60.101 Definitions.
As used in this subpart, all terms not defined herein shall have the
meaning given them in the Act and in subpart A.
(a) Petroleum refinery means any facility engaged in producing
gasoline, kerosene, distillate fuel oils, residual fuel oils,
lubricants, or other products through distillation of petroleum or
through redistillation, cracking or reforming of unfinished petroleum
derivatives.
(b) Petroleum means the crude oil removed from the earth and the
oils derived from tar sands, shale, and coal.
(c) Process gas means any gas generated by a petroleum refinery
process unit, except fuel gas and process upset gas as defined in this
section.
(d) Fuel gas means any gas which is generated at a petroleum
refinery and which is combusted. Fuel gas includes natural gas when the
natural gas is combined and combusted in any proportion with a gas
generated at a refinery. Fuel gas does not include gases generated by
catalytic cracking unit catalyst regenerators and fluid coking burners.
Fuel gas does not include vapors that are collected and combusted in a
thermal oxidizer or flare installed to control emissions from wastewater
treatment units or marine tank vessel loading operations.
(e) Process upset gas means any gas generated by a petroleum
refinery process unit as a result of start-up, shut-down, upset or
malfunction.
(f) Refinery process unit means any segment of the petroleum
refinery in which a specific processing operation is conducted.
(g) Fuel gas combustion device means any equipment, such as process
heaters, boilers and flares used to combust fuel gas, except facilities
in which gases are combusted to produce sulfur or sulfuric acid.
(h) Coke burn-off means the coke removed from the surface of the
fluid catalytic cracking unit catalyst by combustion in the catalyst
regenerator. The rate of coke burn-off is calculated by the formula
specified in Sec. 60.106.
(i) Claus sulfur recovery plant means a process unit which recovers
sulfur from hydrogen sulfide by a vapor-phase catalytic reaction of
sulfur dioxide and hydrogen sulfide.
(j) Oxidation control system means an emission control system which
reduces emissions from sulfur recovery plants by converting these
emissions to sulfur dioxide.
(k) Reduction control system means an emission control system which
reduces emissions from sulfur recovery plants by converting these
emissions to hydrogen sulfide.
(l) Reduced sulfur compounds means hydrogen sulfide
(H2S), carbonyl sulfide (COS) and carbon disulfide
(CS2).
(m) Fluid catalytic cracking unit means a refinery process unit in
which petroleum derivatives are continuously charged; hydrocarbon
molecules in the presence of a catalyst suspended in a fluidized bed are
fractured into smaller molecules, or react with a contact material
suspended in a fluidized bed to improve feedstock quality for additional
processing; and the catalyst or contact material is continuously
regenerated by burning off coke and
[[Page 319]]
other deposits. The unit includes the riser, reactor, regenerator, air
blowers, spent catalyst or contact material stripper, catalyst or
contact material recovery equipment, and regenerator equipment for
controlling air pollutant emissions and for heat recovery.
(n) Fluid catalytic cracking unit catalyst regenerator means one or
more regenerators (multiple regenerators) which comprise that portion of
the fluid catalytic cracking unit in which coke burn-off and catalyst or
contact material regeneration occurs, and includes the regenerator
combustion air blower(s).
(o) Fresh feed means any petroleum derivative feedstock stream
charged directly into the riser or reactor of a fluid catalytic cracking
unit except for petroleum derivatives recycled within the fluid
catalytic cracking unit, fractionator, or gas recovery unit.
(p) Contact material means any substance formulated to remove
metals, sulfur, nitrogen, or any other contaminant from petroleum
derivatives.
(q) Valid day means a 24-hour period in which at least 18 valid
hours of data are obtained. A ``valid hour'' is one in which at least 2
valid data points are obtained.
[39 FR 9315, Mar. 8, 1974, as amended at 43 FR 10868, Mar. 15, 1978; 44
FR 13481, Mar. 12, 1979; 45 FR 79453, Dec. 1, 1980; 54 FR 34027, Aug.
17, 1989; 73 FR 35865, June 24, 2008; 77 FR 56463, Sep. 12, 2012]
Sec. 60.102 Standard for particulate matter.
Each owner or operator of any fluid catalytic cracking unit catalyst
regenerator that is subject to the requirements of this subpart shall
comply with the emission limitations set forth in this section on and
after the date on which the initial performance test, required by Sec.
60.8, is completed, but not later than 60 days after achieving the
maximum production rate at which the fluid catalytic cracking unit
catalyst regenerator will be operated, or 180 days after initial
startup, whichever comes first.
(a) No owner or operator subject to the provisions of this subpart
shall discharge or cause the discharge into the atmosphere from any
fluid catalytic cracking unit catalyst regenerator:
(1) Particulate matter in excess of 1.0 kg/Mg (2.0 lb/ton) of coke
burn-off in the catalyst regenerator.
(2) Gases exhibiting greater than 30 percent opacity, except for one
six-minute average opacity reading in any one hour period.
(b) Where the gases discharged by the fluid catalytic cracking unit
catalyst regenerator pass through an incinerator or waste heat boiler in
which auxiliary or supplemental liquid or solid fossil fuel is burned,
particulate matter in excess of that permitted by paragraph (a)(1) of
this section may be emitted to the atmosphere, except that the
incremental rate of particulate matter emissions shall not exceed 43
grams per Gigajoule (g/GJ) (0.10 lb/million British thermal units (Btu))
of heat input attributable to such liquid or solid fossil fuel.
[39 FR 9315, Mar. 8, 1974, as amended at 42 FR 32427, June 24, 1977; 42
FR 39389, Aug. 4, 1977; 43 FR 10868, Feb. 15, 1978; 54 FR 34027, Aug.
17, 1989; 65 FR 61753, Oct. 17, 2000; 73 FR 35866, June 24, 2008]
Sec. 60.103 Standard for carbon monoxide.
Each owner or operator of any fluid catalytic cracking unit catalyst
regenerator that is subject to the requirements of this subpart shall
comply with the emission limitations set forth in this section on and
after the date on which the initial performance test, required by Sec.
60.8, is completed, but not later than 60 days after achieving the
maximum production rate at which the fluid catalytic cracking unit
catalyst regenerator will be operated, or 180 days after initial
startup, whichever comes first.
(a) No owner or operator subject to the provisions of this subpart
shall discharge or cause the discharge into the atmosphere from any
fluid catalytic cracking unit catalyst regenerator any gases that
contain carbon monoxide (CO) in excess of 500 ppm by volume (dry basis).
[54 FR 34027, Aug. 17, 1989, as amended at 55 FR 40175, Oct. 2, 1990]
Sec. 60.104 Standards for sulfur oxides.
Each owner or operator that is subject to the requirements of this
subpart
[[Page 320]]
shall comply with the emission limitations set forth in this section on
and after the date on which the initial performance test, required by
Sec. 60.8, is completed, but not later than 60 days after achieving the
maximum production rate at which the affected facility will be operated,
or 180 days after initial startup, whichever comes first.
(a) No owner or operator subject to the provisions of this subpart
shall:
(1) Burn in any fuel gas combustion device any fuel gas that
contains hydrogen sulfide (H2S) in excess of 230 mg/dscm
(0.10 gr/dscf). The combustion in a flare of process upset gases or fuel
gas that is released to the flare as a result of relief valve leakage or
other emergency malfunctions is exempt from this paragraph.
(2) Discharge or cause the discharge of any gases into the
atmosphere from any Claus sulfur recovery plant containing in excess of:
(i) For an oxidation control system or a reduction control system
followed by incineration, 250 ppm by volume (dry basis) of sulfur
dioxide (SO2) at zero percent excess air.
(ii) For a reduction control system not followed by incineration,
300 ppm by volume of reduced sulfur compounds and 10 ppm by volume of
hydrogen sulfide (H2S), each calculated as ppm SO2
by volume (dry basis) at zero percent excess air.
(b) Each owner or operator that is subject to the provisions of this
subpart shall comply with one of the following conditions for each
affected fluid catalytic cracking unit catalyst regenerator:
(1) With an add-on control device, reduce SO2 emissions
to the atmosphere by 90 percent or maintain SO2 emissions to
the atmosphere less than or equal to 50 ppm by volume (ppmv), whichever
is less stringent; or
(2) Without the use of an add-on control device to reduce
SO2 emission, maintain sulfur oxides emissions calculated as
SO2 to the atmosphere less than or equal to 9.8 kg/Mg (20 lb/
ton) coke burn-off; or
(3) Process in the fluid catalytic cracking unit fresh feed that has
a total sulfur content no greater than 0.30 percent by weight.
(c) Compliance with paragraph (b)(1), (b)(2), or (b)(3) of this
section is determined daily on a 7-day rolling average basis using the
appropriate procedures outlined in Sec. 60.106.
(d) A minimum of 22 valid days of data shall be obtained every 30
rolling successive calendar days when complying with paragraph (b)(1) of
this section.
[43 FR 10869, Mar. 15, 1978, as amended at 54 FR 34027, Aug. 17, 1989;
55 FR 40175, Oct. 2, 1990; 65 FR 61754, Oct. 17, 2000; 73 FR 35866, June
24, 2008]
Sec. 60.105 Monitoring of emissions and operations.
(a) Continuous monitoring systems shall be installed, calibrated,
maintained, and operated by the owner or operator subject to the
provisions of this subpart as follows:
(1) For fluid catalytic cracking unit catalyst regenerators subject
to Sec. 60.102(a)(2), an instrument for continuously monitoring and
recording the opacity of emissions into the atmosphere. The instrument
shall be spanned at 60, 70, or 80 percent opacity.
(2) For fluid catalytic cracking unit catalyst regenerators subject
to Sec. 60.103(a), an instrument for continuously monitoring and
recording the concentration by volume (dry basis) of CO emissions into
the atmosphere, except as provided in paragraph (a)(2) (ii) of this
section.
(i) The span value for this instrument is 1,000 ppm CO.
(ii) A CO continuous monitoring system need not be installed if the
owner or operator demonstrates that the average CO emissions are less
than 50 ppm (dry basis) and also files a written request for exemption
to the Administrator and receives such an exemption. The demonstration
shall consist of continuously monitoring CO emissions for 30 days using
an instrument that shall meet the requirements of Performance
Specification 4 of appendix B of this part. The span value shall be 100
ppm CO instead of 1,000 ppm, and the relative accuracy limit shall be 10
percent of the average CO emissions or 5 ppm CO, whichever is greater.
For instruments that are identical to Method 10 and employ the sample
conditioning system of Method 10A, the alternative
[[Page 321]]
relative accuracy test procedure in Sec. 10.1 of Performance
Specification 2 may be used in place of the relative accuracy test.
(3) For fuel gas combustion devices subject to Sec. 60.104(a)(1),
either an instrument for continuously monitoring and recording the
concentration by volume (dry basis, zero percent excess air) of
SO2 emissions into the atmosphere or monitoring as provided
in paragraph (a)(4) of this section). The monitor shall include an
oxygen monitor for correcting the data for excess.
(i) The span values for this monitor are 50 ppm SO2 and
25 percent oxygen (O2).
(ii) The SO2 monitoring level equivalent to the
H2S standard under Sec. 60.104(a)(1) shall be 20 ppm (dry
basis, zero percent excess air).
(iii) The performance evaluations for this SO2 monitor
under Sec. 60.13(c) shall use Performance Specification 2. Methods 6 or
6C and 3 or 3A shall be used for conducting the relative accuracy
evaluations. Method 6 samples shall be taken at a flow rate of
approximately 2 liters/min for at least 30 minutes. The relative
accuracy limit shall be 20 percent or 4 ppm, whichever is greater, and
the calibration drift limit shall be 5 percent of the established span
value.
(iv) Fuel gas combustion devices having a common source of fuel gas
may be monitored at only one location (i.e., after one of the combustion
devices), if monitoring at this location accurately represents the
SO2 emissions into the atmosphere from each of the combustion
devices.
(4) Instead of the SO2 monitor in paragraph (a)(3) of
this section for fuel gas combustion devices subject to Sec.
60.104(a)(1), an instrument for continuously monitoring and recording
the concentration (dry basis) of H2S in fuel gases before
being burned in any fuel gas combustion device.
(i) The span value for this instrument is 425 mg/dscm
H2S.
(ii) Fuel gas combustion devices having a common source of fuel gas
may be monitored at only one location, if monitoring at this location
accurately represents the concentration of H2S in the fuel
gas being burned.
(iii) The performance evaluations for this H2S monitor
under Sec. 60.13(c) shall use Performance Specification 7. Method 11,
15, 15A, or 16 shall be used for conducting the relative accuracy
evaluations.
(iv) The owner or operator of a fuel gas combustion device is not
required to comply with paragraph (a)(3) or (4) of this section for fuel
gas streams that are exempt under Sec. 60.104(a)(1) and fuel gas
streams combusted in a fuel gas combustion device that are inherently
low in sulfur content. Fuel gas streams meeting one of the requirements
in paragraphs (a)(4)(iv)(A) through (D) of this section will be
considered inherently low in sulfur content. If the composition of a
fuel gas stream changes such that it is no longer exempt under Sec.
60.104(a)(1) or it no longer meets one of the requirements in paragraphs
(a)(4)(iv)(A) through (D) of this section, the owner or operator must
begin continuous monitoring under paragraph (a)(3) or (4) of this
section within 15 days of the change.
(A) Pilot gas for heaters and flares.
(B) Fuel gas streams that meet a commercial-grade product
specification for sulfur content of 30 ppmv or less. In the case of a
liquefied petroleum gas (LPG) product specification in the pressurized
liquid state, the gas phase sulfur content should be evaluated assuming
complete vaporization of the LPG and sulfur containing-compounds at the
product specification concentration.
(C) Fuel gas streams produced in process units that are intolerant
to sulfur contamination, such as fuel gas streams produced in the
hydrogen plant, the catalytic reforming unit, the isomerization unit,
and HF alkylation process units.
(D) Other fuel gas streams that an owner or operator demonstrates
are low-sulfur according to the procedures in paragraph (b) of this
section.
(5) For Claus sulfur recovery plants with oxidation control systems
or reduction control systems followed by incineration subject to Sec.
60.104(a)(2)(i), an instrument for continuously monitoring and recording
the concentration (dry basis, zero percent excess air) of SO2
emissions into the atmosphere. The monitor shall include an oxygen
monitor for correcting the data for excess air.
[[Page 322]]
(i) The span values for this monitor are 500 ppm SO2 and
25 percent O2.
(ii) The performance evaluations for this SO2 monitor
under Sec. 60.13(c) shall use Performance Specification 2. Methods 6 or
6C and 3 or 3A shall be used for conducting the relative accuracy
evaluations.
(6) For Claus sulfur recovery plants with reduction control systems
not followed by incineration subject to Sec. 60.104(a)(2)(ii), an
instrument for continuously monitoring and recording the concentration
of reduced sulfur and O2 emissions into the atmosphere. The
reduced sulfur emissions shall be calculated as SO2 (dry
basis, zero percent excess air).
(i) The span values for this monitor are 450 ppm reduced sulfur and
25 percent O2.
(ii) The performance evaluations for this reduced sulfur (and
O2) monitor under Sec. 60.13(c) shall use Performance
Specification 5 of appendix B of this part(and Performance Specification
3 of appendix B of this partfor the O2 analyzer). Methods 15
or 15A and Method 3 shall be used for conducting the relative accuracy
evaluations. If Method 3 yields O2 concentrations below 0.25
percent during the performance specification test, the O2
concentration may be assumed to be zero and the reduced sulfur CEMS need
not include an O2 monitor.
(7) In place of the reduced sulfur monitor under paragraph (a)(6) of
this section, an instrument using an air or O2 dilution and
oxidation system to convert the reduced sulfur to SO2 for
continuously monitoring and recording the concentration (dry basis, zero
percent excess air) of the resultant SO2. The monitor shall
include an oxygen monitor for correcting the data for excess oxygen.
(i) The span values for this monitor are 375 ppm SO2 and
25 percent O2.
(ii) For reporting purposes, the SO2 exceedance level for
this monitor is 250 ppm (dry basis, zero percent excess air).
(iii) The performance evaluations for this SO2 (and
O2) monitor under Sec. 60.13(c) shall use Performance
Specification 5. Methods 15 or 15A and Method 3 shall be used for
conducting the relative accuracy evaluations.
(8) An instrument for continuously monitoring and recording
concentrations of SO2 in the gases at both the inlet and
outlet of the SO2 control device from any fluid catalytic
cracking unit catalyst regenerator for which the owner or operator seeks
to comply specifically with the 90 percent reduction option under Sec.
60.104(b)(1).
(i) The span value of the inlet monitor shall be set at 125 percent
of the maximum estimated hourly potential SO2 emission
concentration entering the control device, and the span value of the
outlet monitor shall be set at 50 percent of the maximum estimated
hourly potential SO2 emission concentration entering the
control device.
(ii) The performance evaluations for these SO2 monitors
under Sec. 60.13(c) shall use Performance Specification 2. Methods 6 or
6C and 3 or 3A shall be used for conducting the relative accuracy
evaluations.
(9) An instrument for continuously monitoring and recording
concentrations of SO2 in the gases discharged into the
atmosphere from any fluid catalytic cracking unit catalyst regenerator
for which the owner or operator seeks to comply specifically with the 50
ppmv emission limit under Sec. 60.104 (b)(1).
(i) The span value of the monitor shall be set at 50 percent of the
maximum hourly potential SO2 emission concentration of the
control device.
(ii) The performance evaluations for this SO2 monitor
under Sec. 60.13 (c) shall use Performance Specification 2. Methods 6
or 6C and 3 or 3A shall be used for conducting the relative accuracy
evaluations.
(10) An instrument for continuously monitoring and recording
concentrations of oxygen (O2) in the gases at both the inlet
and outlet of the sulfur dioxide control device (or the outlet only if
specifically complying with the 50 ppmv standard) from any fluid
catalytic cracking unit catalyst regenerator for which the owner or
operator has elected to comply with Sec. 60.104(b)(1). The span of this
continuous monitoring system shall be set at 10 percent.
(11) The continuous monitoring systems under paragraphs (a)(8),
(a)(9), and (a)(10) of this section are operated
[[Page 323]]
and data recorded during all periods of operation of the affected
facility including periods of startup, shutdown, or malfunction, except
for continuous monitoring system breakdowns, repairs, calibration
checks, and zero and span adjustments.
(12) The owner or operator shall use the following procedures to
evaluate the continuous monitoring systems under paragraphs (a)(8),
(a)(9), and (a)(10) of this section.
(i) Method 3 or 3A and Method 6 or 6C for the relative accuracy
evaluations under the Sec. 60.13(e) performance evaluation.
(ii) Appendix F, Procedure 1, including quarterly accuracy
determinations and daily calibration drift tests.
(13) When seeking to comply with Sec. 60.104(b)(1), when emission
data are not obtained because of continuous monitoring system
breakdowns, repairs, calibration checks and zero and span adjustments,
emission data will be obtained by using one of the following methods to
provide emission data for a minimum of 18 hours per day in at least 22
out of 30 rolling successive calendar days.
(i) The test methods as described in Sec. 60.106(k);
(ii) A spare continuous monitoring system; or
(iii) Other monitoring systems as approved by the Administrator.
(b) An owner or operator may demonstrate that a fuel gas stream
combusted in a fuel gas combustion device subject to Sec. 60.104(a)(1)
that is not specifically exempted in Sec. 60.105(a)(4)(iv) is
inherently low in sulfur. A fuel gas stream that is determined to be
low-sulfur is exempt from the monitoring requirements in paragraphs
(a)(3) and (4) of this section until there are changes in operating
conditions or stream composition.
(1) The owner or operator shall submit to the Administrator a
written application for an exemption from monitoring. The application
must contain the following information:
(i) A description of the fuel gas stream/system to be considered,
including submission of a portion of the appropriate piping diagrams
indicating the boundaries of the fuel gas stream/system, and the
affected fuel gas combustion device(s) to be considered;
(ii) A statement that there are no crossover or entry points for
sour gas (high H2S content) to be introduced into the fuel
gas stream/system (this should be shown in the piping diagrams);
(iii) An explanation of the conditions that ensure low amounts of
sulfur in the fuel gas stream (i.e., control equipment or product
specifications) at all times;
(iv) The supporting test results from sampling the requested fuel
gas stream/system demonstrating that the sulfur content is less than 5
ppmv. Sampling data must include, at minimum, 2 weeks of daily
monitoring (14 grab samples) for frequently operated fuel gas streams/
systems; for infrequently operated fuel gas streams/systems, seven grab
samples must be collected unless other additional information would
support reduced sampling. The owner or operator shall use detector tubes
(``length-of-stain tube'' type measurement) following the ``Gas
Processors Association Standard 2377-86 (incorporated by reference--see
Sec. 60.17), using tubes with a maximum span between 10 and 40 ppmv
inclusive when 1<=N<=10, where N = number of pump strokes, to test the
applicant fuel gas stream for H2S; and
(v) A description of how the 2 weeks (or seven samples for
infrequently operated fuel gas streams/systems) of monitoring results
compares to the typical range of H2S concentration (fuel
quality) expected for the fuel gas stream/system going to the affected
fuel gas combustion device (e.g., the 2 weeks of daily detector tube
results for a frequently operated loading rack included the entire range
of products loaded out, and, therefore, should be representative of
typical operating conditions affecting H2S content in the
fuel gas stream going to the loading rack flare).
(2) The effective date of the exemption is the date of submission of
the information required in paragraph (b)(1) of this section).
(3) No further action is required unless refinery operating
conditions change in such a way that affects the exempt fuel gas stream/
system (e.g.,
[[Page 324]]
the stream composition changes). If such a change occurs, the owner or
operator will follow the procedures in paragraph (b)(3)(i), (b)(3)(ii),
or (b)(3)(iii) of this section.
(i) If the operation change results in a sulfur content that is
still within the range of concentrations included in the original
application, the owner or operator shall conduct an H2S test
on a grab sample and record the results as proof that the concentration
is still within the range.
(ii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application, the owner or operator may submit new information following
the procedures of paragraph (b)(1) of this section within 60 days (or
within 30 days after the seventh grab sample is tested for infrequently
operated process units).
(iii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original application
and the owner or operator chooses not to submit new information to
support an exemption, the owner or operator must begin H2S
monitoring using daily stain sampling to demonstrate compliance using
length-of stain tubes with a maximum span between 200 and 400 ppmv
inclusive when 1<=N<=5, where N = number of pump strokes. The owner or
operator must begin monitoring according to the requirements in
paragraph (a)(1) or (2) of this section as soon as practicable but in no
case later than 180 days after the operation change. During daily stain
tube sampling, a daily sample exceeding 162 ppmv is an exceedance of the
3-hour H2S concentration limit.
(c) The average coke burn-off rate (Mg (tons) per hour) and hours of
operation shall be recorded daily for any fluid catalytic cracking unit
catalyst regenerator subject to Sec. 60.102, Sec. 60.103, or Sec.
60.104(b)(2).
(d) For any fluid catalytic cracking unit catalyst regenerator under
Sec. 60.102 that uses an incinerator-waste heat boiler to combust the
exhaust gases from the catalyst regenerator, the owner or operator shall
record daily the rate of combustion of liquid or solid fossil-fuels and
the hours of operation during which liquid or solid fossil-fuels are
combusted in the incinerator-waste heat boiler.
(e) For the purpose of reports under Sec. 60.7(c), periods of
excess emissions that shall be determined and reported are defined as
follows:
Note: All averages, except for opacity, shall be determined as the
arithmetic average of the applicable 1-hour averages, e.g., the rolling
3-hour average shall be determined as the arithmetic average of three
contiguous 1-hour averages.
(1) Opacity. All 1-hour periods that contain two or more 6-minute
periods during which the average opacity as measured by the continuous
monitoring system under Sec. 60.105(a)(1) exceeds 30 percent.
(2) Carbon monoxide. All 1-hour periods during which the average CO
concentration as measured by the CO continuous monitoring system under
Sec. 60.105(a)(2) exceeds 500 ppm.
(3) Sulfur dioxide from fuel gas combustion. (i) All rolling 3-hour
periods during which the average concentration of SO2 as
measured by the SO2 continuous monitoring system under Sec.
60.105(a)(3) exceeds 20 ppm (dry basis, zero percent excess air); or
(ii) All rolling 3-hour periods during which the average
concentration of H2S as measured by the H2S
continuous monitoring system under Sec. 60.105(a)(4) exceeds 230 mg/
dscm (0.10 gr/dscf).
(4) Sulfur dioxide from Claus sulfur recovery plants. (i) All 12-
hour periods during which the average concentration of SO2 as
measured by the SO2 continuous monitoring system under Sec.
60.105(a)(5) exceeds 250 ppm (dry basis, zero percent excess air); or
(ii) All 12-hour periods during which the average concentration of
reduced sulfur (as SO2) as measured by the reduced sulfur
continuous monitoring system under Sec. 60.105(a)(6) exceeds 300 ppm;
or
(iii) All 12-hour periods during which the average concentration of
SO2 as
[[Page 325]]
measured by the SO2 continuous monitoring system under Sec.
60.105(a)(7) exceeds 250 ppm (dry basis, zero percent excess air).
[39 FR 9315, Mar. 8, 1974, as amended at 40 FR 46259, Oct. 6, 1975; 42
FR 32427, June 24, 1977; 42 FR 39389, Aug. 4, 1977; 43 FR 10869, Mar.
15, 1978; 48 FR 23611, May 25, 1983; 50 FR 31701, Aug. 5, 1985; 54 FR
34028, Aug. 17, 1989; 55 FR 40175, Oct. 2, 1990; 65 FR 61754, Oct. 17,
2000; 73 FR 35866, June 24, 2008; 80 FR 75229, Dec. 1, 2015]
Sec. 60.106 Test methods and procedures.
(a) In conducting the performance tests required in Sec. 60.8, the
owner or operator shall use as reference methods and procedures the test
methods in appendix A of this part or other methods and procedures as
specified in this section, except as provided in Sec. 60.8(b).
(b) The owner or operator shall determine compliance with the
particulate matter (PM) standards in Sec. 60.102(a) as follows:
(1) The emission rate (E) of PM shall be computed for each run using
the following equation:
[GRAPHIC] [TIFF OMITTED] TR17OC00.000
Where:
E = Emission rate of PM, kg/Mg (lb/ton) of coke burn-off.
cs = Concentration of PM, g/dscm (gr/dscf).
Qsd = Volumetric flow rate of effluent gas, dscm/hr (dscf/
hr).
Rc = Coke burn-off rate, Mg/hr (ton/hr) coke.
K = Conversion factor, 1,000 g/kg (7,000 gr/lb).
(2) Method 5B or 5F is to be used to determine particulate matter
emissions and associated moisture content from affected facilities
without wet FGD systems; only Method 5B is to be used after wet FGD
systems. The sampling time for each run shall be at least 60 minutes and
the sampling rate shall be at least 0.015 dscm/min (0.53 dscf/min),
except that shorter sampling times may be approved by the Administrator
when process variables or other factors preclude sampling for at least
60 minutes.
(3) The coke burn-off rate (Rc) shall be computed for
each run using the following equation:
Rc = K1Qr (%CO2 + %CO) +
K2Qa-K3Qr (%CO/2 +
%CO2 + %O2) + K3Qoxy
(%Ooxy)
Where:
Rc = Coke burn-off rate, kilograms per hour (kg/hr) (lb/hr).
Qr = Volumetric flow rate of exhaust gas from fluid catalytic
cracking unit regenerator before entering the emission control
system, dscm/min (dscf/min).
Qa = Volumetric flow rate of air to fluid catalytic cracking
unit regenerator, as determined from the fluid catalytic
cracking unit control room instrumentation, dscm/min (dscf/
min).
Qoxy = Volumetric flow rate of O2 enriched air to
fluid catalytic cracking unit regenerator, as determined from
the fluid catalytic cracking unit control room
instrumentation, dscm/min (dscf/min).
%CO2 = Carbon dioxide concentration in fluid catalytic
cracking unit regenerator exhaust, percent by volume (dry
basis).
%CO = CO concentration in FCCU regenerator exhaust, percent by volume
(dry basis).
%O2 = O2 concentration in fluid catalytic cracking
unit regenerator exhaust, percent by volume (dry basis).
%Ooxy = O2 concentration in O2 enriched
air stream inlet to the fluid catalytic cracking unit
regenerator, percent by volume (dry basis).
K1 = Material balance and conversion factor, 0.2982 (kg-min)/
(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)].
K2 = Material balance and conversion factor, 2.088 (kg-min)/
(hr-dscm) [0.1303 (lb-min)/(hr-dscf)].
K3 = Material balance and conversion factor, 0.0994 (kg-min)/
(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].
(i) Method 2 shall be used to determine the volumetric flow rate
(Qr).
(ii) The emission correction factor, integrated sampling and
analysis procedure of Method 3B shall be used to determine
CO2, CO, and O2 concentrations.
(4) Method 9 and the procedures of Sec. 60.11 shall be used to
determine opacity.
(c) If auxiliary liquid or solid fossil-fuels are burned in an
incinerator-waste heat boiler, the owner or operator shall determine the
emission rate of PM permitted in Sec. 60.102(b) as follows:
(1) The allowable emission rate (Es) of PM shall be
computed for each run using the following equation:
Es = F + A (H/Rc)
[[Page 326]]
Where:
Es = Emission rate of PM allowed, kg/Mg (lb/ton) of coke
burn-off in catalyst regenerator.
F = Emission standard, 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in
catalyst regenerator.
A = Allowable incremental rate of PM emissions, 43 g/GJ (0.10 lb/million
Btu).
H = Heat input rate from solid or liquid fossil fuel, GJ/hr (million
Btu/hr).
Rc = Coke burn-off rate, Mg coke/hr (ton coke/hr).
(2) Procedures subject to the approval of the Administrator shall be
used to determine the heat input rate.
(3) The procedure in paragraph (b)(3) of this section shall be used
to determine the coke burn-off rate (Rc).
(d) The owner or operator shall determine compliance with the CO
standard in Sec. 60.103(a) by using the integrated sampling technique
of Method 10 to determine the CO concentration (dry basis). The sampling
time for each run shall be 60 minutes.
(e)(1) The owner or operator shall determine compliance with the
H2S standard in Sec. 60.104(a)(1) as follows: Method 11, 15,
15A, or 16 shall be used to determine the H2S concentration.
The gases entering the sampling train should be at about atmospheric
pressure. If the pressure in the refinery fuel gas lines is relatively
high, a flow control valve may be used to reduce the pressure. If the
line pressure is high enough to operate the sampling train without a
vacuum pump, the pump may be eliminated from the sampling train. The
sample shall be drawn from a point near the centroid of the fuel gas
line.
(i) For Method 11, the sampling time and sample volume shall be at
least 10 minutes and 0.010 dscm (0.35 dscf). Two samples of equal
sampling times shall be taken at about 1-hour intervals. The arithmetic
average of these two samples shall constitute a run. For most fuel
gases, sampling times exceeding 20 minutes may result in depletion of
the collection solution, although fuel gases containing low
concentrations of H2S may necessitate sampling for longer
periods of time.
(ii) For Method 15 or 16, at least three injects over a 1-hour
period shall constitute a run.
(iii) For Method 15A, a 1-hour sample shall constitute a run.
(2) Where emissions are monitored by Sec. 60.105(a)(3), compliance
with Sec. 60.104(a)(1) shall be determined using Method 6 or 6C and
Method 3 or 3A. The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust
Gas Analyses,'' (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 6. A 1-hour sample shall constitute
a run. Method 6 samples shall be taken at a rate of approximately 2
liters/min. The ppm correction factor (Method 6) and the sampling
location in paragraph (f)(1) of this section apply. Method 4 shall be
used to determine the moisture content of the gases. The sampling point
for Method 4 shall be adjacent to the sampling point for Method 6 or 6C.
(f) The owner or operator shall determine compliance with the
SO2 and the H2S and reduced sulfur standards in
Sec. 60.104(a)(2) as follows:
(1) Method 6 shall be used to determine the SO2
concentration. The concentration in mg/dscm obtained by Method 6 or 6C
is multiplied by 0.3754 to obtain the concentration in ppm. The sampling
point in the duct shall be the centroid of the cross section if the
cross-sectional area is less than 5.00 m\2\ (53.8 ft\2\) or at a point
no closer to the walls than 1.00 m (39.4 in.) if the cross-sectional
area is 5.00 m\2\ or more and the centroid is more than 1 m from the
wall. The sampling time and sample volume shall be at least 10 minutes
and 0.010 dscm (0.35 dscf) for each sample. Eight samples of equal
sampling times shall be taken at about 30-minute intervals. The
arithmetic average of these eight samples shall constitute a run. For
Method 6C, a run shall consist of the arithmetic average of four 1-hour
samples. Method 4 shall be used to determine the moisture content of the
gases. The sampling point for Method 4 shall be adjacent to the sampling
point for Method 6 or 6C. The sampling time for each sample shall be
equal to the time it takes for two Method 6 samples. The moisture
content from this sample shall be used to correct the corresponding
Method 6 samples for moisture. For documenting the oxidation efficiency
of the control device for reduced sulfur compounds, Method 15 shall be
used following the procedures of paragraph (f)(2) of this section.
[[Page 327]]
(2) Method 15 shall be used to determine the reduced sulfur and
H2 S concentrations. Each run shall consist of 16 samples
taken over a minimum of 3 hours. The sampling point shall be the same as
that described for Method 6 in paragraph (f)(1) of this section. To
ensure minimum residence time for the sample inside the sample lines,
the sampling rate shall be at least 3.0 lpm (0.10 cfm). The
SO2 equivalent for each run shall be calculated after being
corrected for moisture and oxygen as the arithmetic average of the
SO2 equivalent for each sample during the run. Method 4 shall
be used to determine the moisture content of the gases as the paragraph
(f)(1) of this section. The sampling time for each sample shall be equal
to the time it takes for four Method 15 samples.
(3) The oxygen concentration used to correct the emission rate for
excess air shall be obtained by the integrated sampling and analysis
procedure of Method 3 or 3A. The samples shall be taken simultaneously
with the SO2, reduced sulfur and H2S, or moisture
samples. The SO2, reduced sulfur, and H2S samples
shall be corrected to zero percent excess air using the equation in
paragraph (h)(6) of this section.
(g) Each performance test conducted for the purpose of determining
compliance under Sec. 60.104(b) shall consist of all testing performed
over a 7-day period using Method 6 or 6C and Method 3 or 3A. To
determine compliance, the arithmetic mean of the results of all the
tests shall be compared with the applicable standard.
(h) For the purpose of determining compliance with Sec.
60.104(b)(1), the following calculation procedures shall be used:
(1) Calculate each 1-hour average concentration (dry, zero percent
oxygen, ppmv) of sulfur dioxide at both the inlet and the outlet to the
add-on control device as specified in Sec. 60.13(h). These calculations
are made using the emission data collected under Sec. 60.105(a).
(2) Calculate a 7-day average (arithmetic mean) concentration of
sulfur dioxide for the inlet and for the outlet to the add-on control
device using all of the 1-hour average concentration values obtained
during seven successive 24-hour periods.
(3) Calculate the 7-day average percent reduction using the
following equation:
Rso2 = 100(Cso2(i) - Cso2(o)) /
Cso2(i)
where:
Rso2 = 7-day average sulfur dioxide emission reduction,
percent
Cso2(i) = sulfur dioxide emission concentration determined in
Sec. 60.106(h)(2) at the inlet to the add-on control device,
ppmv
Cso2(o) = sulfur dioxide emission concentration determined in
Sec. 60.106(h)(2) at the outlet to the add-on control device,
ppmv
100 = conversion factor, decimal to percent
(4) Outlet concentrations of sulfur dioxide from the add-on control
device for compliance with the 50 ppmv standard, reported on a dry,
O2-free basis, shall be calculated using the procedures
outlined in Sec. 60.106(h)(1) and (2) above, but for the outlet monitor
only.
(5) If supplemental sampling data are used for determining the 7-day
averages under paragraph (h) of this section and such data are not
hourly averages, then the value obtained for each supplemental sample
shall be assumed to represent the hourly average for each hour over
which the sample was obtained.
(6) For the purpose of adjusting pollutant concentrations to zero
percent oxygen, the following equation shall be used:
Cadj = Cmeas[20.9c/(20.9-
%O2)]
where:
Cadj = pollutant concentration adjusted to zero percent
oxygen, ppm or g/dscm
Cmeas = pollutant concentration measured on a dry basis, ppm
or g/dscm
20.9c = 20.9 percent oxygen-0.0 percent oxygen (defined
oxygen correction basis), percent
20.9 = oxygen concentration in air, percent
%O2 = oxygen concentration measured on a dry basis, percent
(i) For the purpose of determining compliance with Sec.
60.104(b)(2), the following reference methods and calculation procedures
shall be used except as provided in paragraph (i)(12) of this section:
(1) One 3-hour test shall be performed each day.
[[Page 328]]
(2) For gases released to the atmosphere from the fluid catalytic
cracking unit catalyst regenerator:
(i) Method 8 as modified in Sec. 60.106(i)(3) for moisture content
and for the concentration of sulfur oxides calculated as sulfur dioxide,
(ii) Method 1 for sample and velocity traverses,
(iii) Method 2 calculation procedures (data obtained from Methods 3
and 8) for velocity and volumetric flow rate, and
(iv) Method 3 for gas analysis.
(3) Method 8 shall be modified by the insertion of a heated glass
fiber filter between the probe and first impinger. The probe liner and
glass fiber filter temperature shall be maintained above 160 [deg]C (320
[deg]F). The isopropanol impinger shall be eliminated. Sample recovery
procedures described in Method 8 for container No. 1 shall be
eliminated. The heated glass fiber filter also shall be excluded;
however, rinsing of all connecting glassware after the heated glass
fiber filter shall be retained and included in container No. 2. Sampled
volume shall be at least 1 dscm.
(4) For Method 3, the integrated sampling technique shall be used.
(5) Sampling time for each run shall be at least 3 hours.
(6) All testing shall be performed at the same location. Where the
gases discharged by the fluid catalytic cracking unit catalyst
regenerator pass through an incinerator-waste heat boiler in which
auxiliary or supplemental gaseous, liquid, or solid fossil fuel is
burned, testing shall be conducted at a point between the regenerator
outlet and the incinerator-waste heat boiler. An alternative sampling
location after the waste heat boiler may be used if alternative coke
burn-off rate equations, and, if requested, auxiliary/supplemental fuel
SOX credits, have been submitted to and approved by the
Administrator prior to sampling.
(7) Coke burn-off rate shall be determined using the procedures
specified under paragraph (b)(3) of this section, unless paragraph
(i)(6) of this section applies.
(8) Calculate the concentration of sulfur oxides as sulfur dioxide
using equation 8-3 in Section 6.5 of Method 8 to calculate and report
the total concentration of sulfur oxides as sulfur dioxide (Cso
x).
(9) Sulfur oxides emission rate calculated as sulfur dioxide shall
be determined for each test run by the following equation:
[GRAPHIC] [TIFF OMITTED] TR17OC00.003
Where:
ESOx = sulfur oxides emission rate calculated as sulfur
dioxide, kg/hr (lb/hr)
CSOx = sulfur oxides emission concentration calculated as
sulfur dioxide, g/dscm (gr/dscf)
Qsd = dry volumetric stack gas flow rate corrected to
standard conditions, dscm/hr (dscf/hr)
K = 1,000 g/kg (7,000 gr/lb)
(10) Sulfur oxides emissions calculated as sulfur dioxide shall be
determined for each test run by the following equation:
[GRAPHIC] [TIFF OMITTED] TR17OC00.004
Where:
RSOx = Sulfur oxides emissions calculated as kg sulfur
dioxide per Mg (lb/ton) coke burn-off.
ESOx = Sulfur oxides emission rate calculated as sulfur
dioxide, kg/hr (lb/hr).
Rc = Coke burn-off rate, Mg/hr (ton/hr).
(11) Calculate the 7-day average sulfur oxides emission rate as
sulfur dioxide per Mg (ton) of coke burn-off by dividing the sum of the
individual daily rates by the number of daily rates summed.
(12) An owner or operator may, upon approval by the Administrator,
use an alternative method for determining compliance with Sec.
60.104(b)(2), as provided in Sec. 60.8(b). Any requests for approval
must include data to demonstrate to the Administrator that the
alternative method would produce results adequate for the determination
of compliance.
(j) For the purpose of determining compliance with Sec.
60.104(b)(3), the following analytical methods and calculation
procedures shall be used:
(1) One fresh feed sample shall be collected once per 8-hour period.
(2) Fresh feed samples shall be analyzed separately by using any one
of the following applicable analytical test methods: ASTM D129-64, 78,
or 95,
[[Page 329]]
ASTM D1552-83 or 95, ASTM D2622-87, 94, or 98, or ASTM D1266-87, 91, or
98. (These methods are incorporated by reference: see Sec. 60.17.) The
applicable range of some of these ASTM methods is not adequate to
measure the levels of sulfur in some fresh feed samples. Dilution of
samples prior to analysis with verification of the dilution ratio is
acceptable upon prior approval of the Administrator.
(3) If a fresh feed sample cannot be collected at a single location,
then the fresh feed sulfur content shall be determined as follows:
(i) Individual samples shall be collected once per 8-hour period for
each separate fresh feed stream charged directly into the riser or
reactor of the fluid catalytic cracking unit. For each sample location
the fresh feed volumetric flow rate at the time of collecting the fresh
feed sample shall be measured and recorded. The same method for
measuring volumetric flow rate shall be used at all locations.
(ii) Each fresh feed sample shall be analyzed separately using the
methods specified under paragraph (j)(2) of this section.
(iii) Fresh feed sulfur content shall be calculated for each 8-hour
period using the following equation:
[GRAPHIC] [TIFF OMITTED] TC16NO91.005
where:
Sf = fresh feed sulfur content expressed in percent by weight
of fresh feed.
n = number of separate fresh feed streams charged directly to the riser
or reactor of the fluid catalytic cracking unit.
Qf = total volumetric flow rate of fresh feed charged to the
fluid catalytic cracking unit.
Si = fresh feed sulfur content expressed in percent by weight
of fresh feed for the ``ith'' sampling location.
Qi = volumetric flow rate of fresh feed stream for the
``ith'' sampling location.
(4) Calculate a 7-day average (arithmetic mean) sulfur content of
the fresh feed using all of the fresh feed sulfur content values
obtained during seven successive 24-hour periods.
(k) The test methods used to supplement continuous monitoring system
data to meet the minimum data requirements in Sec. 60.104(d) will be
used as described below or as otherwise approved by the Administrator.
(1) Methods 6, 6B, or 8 are used. The sampling location(s) are the
same as those specified for the monitor.
(2) For Method 6, the minimum sampling time is 20 minutes and the
minimum sampling volume is 0.02 dscm (0.71 dscf) for each sample.
Samples are taken at approximately 60-minute intervals. Each sample
represents a 1-hour average. A minimum of 18 valid samples is required
to obtain one valid day of data.
(3) For Method 6B, collection of a sample representing a minimum of
18 hours is required to obtain one valid day of data.
(4) For Method 8, the procedures as outlined in this section are
used. The equivalent of 16 hours of sampling is required to obtain one
valid day of data.
[39 FR 9315, Mar. 8, 1974, as amended at 43 FR 10869, Mar. 15, 1978; 51
FR 42842, Nov. 26, 1986; 52 FR 20392, June 1, 1987; 53 FR 41333, Oct.
21, 1988; 54 FR 34028, Aug. 17, 1989; 55 FR 40176, Oct. 2, 1990; 56 FR
4176, Feb. 4, 1991; 65 FR 61754, Oct. 17, 2000; 71 FR 55127, Sept. 21,
2006; 73 FR 35867, June 24, 2008; 77 FR 56463, Sep. 12, 2012]
Sec. 60.107 Reporting and recordkeeping requirements.
(a) Each owner or operator subject to Sec. 60.104(b) shall notify
the Administrator of the specific provisions of Sec. 60.104(b) with
which the owner or operator seeks to comply. Notification shall be
submitted with the notification of initial startup required by Sec.
60.7(a)(3). If an owner or operator elects at a later date to comply
with an alternative provision of Sec. 60.104(b), then the Administrator
shall be notified by the owner or operator in the report described in
paragraph (c) of this section.
(b) Each owner or operator subject to Sec. 60.104(b) shall record
and maintain the following information:
(1) If subject to Sec. 60.104(b)(1),
(i) All data and calibrations from continuous monitoring systems
located at the inlet and outlet to the control device, including the
results of the daily drift tests and quarterly accuracy assessments
required under appendix F, Procedure 1;
(ii) Measurements obtained by supplemental sampling (refer to
[[Page 330]]
Sec. 60.105(a)(13) and Sec. 60.106(k)) for meeting minimum data
requirements; and
(iii) The written procedures for the quality control program
required by appendix F, Procedure 1.
(2) If subject to Sec. 60.104(b)(2), measurements obtained in the
daily Method 8 testing, or those obtained by alternative measurement
methods, if Sec. 60.106(i)(12) applies.
(3) If subject to Sec. 60.104(b)(3), data obtained from the daily
feed sulfur tests.
(4) Each 7-day rolling average compliance determination.
(c) Each owner or operator subject to Sec. 60.104(b) shall submit a
report except as provided by paragraph (d) of this section. The
following information shall be contained in the report:
(1) Any 7-day period during which:
(i) The average percent reduction and average concentration of
sulfur dioxide on a dry, O2-free basis in the gases
discharged to the atmosphere from any fluid cracking unit catalyst
regenerator for which the owner or operator seeks to comply with Sec.
60.104(b)(1) is below 90 percent and above 50 ppmv, as measured by the
continuous monitoring system prescribed under Sec. 60.105(a)(8), or
above 50 ppmv, as measured by the outlet continuous monitoring system
prescribed under Sec. 60.105(a)(9). The average percent reduction and
average sulfur dioxide concentration shall be determined using the
procedures specified under Sec. 60.106(h);
(ii) The average emission rate of sulfur dioxide in the gases
discharged to the atmosphere from any fluid catalytic cracking unit
catalyst regenerator for which the owner or operator seeks to comply
with Sec. 60.104(b)(2) exceeds 9.8 kg SOX per 1,000 kg coke
burn-off, as measured by the daily testing prescribed under Sec.
60.106(i). The average emission rate shall be determined using the
procedures specified under Sec. 60.106(i); and
(iii) The average sulfur content of the fresh feed for which the
owner or operator seeks to comply with Sec. 60.104(b)(3) exceeds 0.30
percent by weight. The fresh feed sulfur content, a 7-day rolling
average, shall be determined using the procedures specified under Sec.
60.106(j).
(2) Any 30-day period in which the minimum data requirements
specified in Sec. 60.104(d) are not obtained.
(3) For each 7-day period during which an exceedance has occurred as
defined in paragraphs (c)(1)(i) through (c)(1)(iii) and (c)(2) of this
section:
(i) The date that the exceedance occurred;
(ii) An explanation of the exceedance;
(iii) Whether the exceedance was concurrent with a startup,
shutdown, or malfunction of the fluid catalytic cracking unit or control
system; and
(iv) A description of the corrective action taken, if any.
(4) If subject to Sec. 60.104(b)(1),
(i) The dates for which and brief explanations as to why fewer than
18 valid hours of data were obtained for the inlet continuous monitoring
system;
(ii) The dates for which and brief explanations as to why fewer than
18 valid hours of data were obtained for the outlet continuous
monitoring system;
(iii) Identification of times when hourly averages have been
obtained based on manual sampling methods;
(iv) Identification of the times when the pollutant concentration
exceeded full span of the continuous monitoring system; and
(v) Description of any modifications to the continuous monitoring
system that could affect the ability of the continuous monitoring system
to comply with Performance Specifications 2 or 3.
(vi) Results of daily drift tests and quarterly accuracy assessments
as required under appendix F, Procedure 1.
(5) If subject to Sec. 60.104(b)(2), for each day in which a Method
8 sample result required by Sec. 60.106(i) was not obtained, the date
for which and brief explanation as to why a Method 8 sample result was
not obtained, for approval by the Administrator.
(6) If subject to Sec. 60.104(b)(3), for each 8-hour period in
which a feed sulfur measurement required by Sec. 60.106(j) was not
obtained, the date for which and brief explanation as to why a feed
sulfur measurement was not obtained, for approval by the Administrator.
(d) For any periods for which sulfur dioxide or oxides emissions
data are not available, the owner or operator of
[[Page 331]]
the affected facility shall submit a signed statement indicating if any
changes were made in operation of the emission control system during the
period of data unavailability which could affect the ability of the
system to meet the applicable emission limit. Operations of the control
system and affected facility during periods of data unavailability are
to be compared with operation of the control system and affected
facility before and following the period of data unavailability.
(e) For each fuel gas stream combusted in a fuel gas combustion
device subject to Sec. 60.104(a)(1), if an owner or operator determines
that one of the exemptions listed in Sec. 60.105(a)(4)(iv) applies to
that fuel gas stream, the owner or operator shall maintain records of
the specific exemption chosen for each fuel gas stream. If the owner or
operator applies for the exemption described in Sec.
60.105(a)(4)(iv)(D), the owner or operator must keep a copy of the
application as well as the letter from the Administrator granting
approval of the application.
(f) The owner or operator of an affected facility shall submit the
reports required under this subpart to the Administrator semiannually
for each six-month period. All semiannual reports shall be postmarked by
the 30th day following the end of each six-month period.
(g) The owner or operator of the affected facility shall submit a
signed statement certifying the accuracy and completeness of the
information contained in the report.
[54 FR 34029, Aug. 17, 1989, as amended at 55 FR 40178, Oct. 2, 1990; 64
FR 7465, Feb. 12, 1999; 65 FR 61755, Oct. 17, 2000; 73 FR 35867, June
24, 2008]
Sec. 60.108 Performance test and compliance provisions.
(a) Section 60.8(d) shall apply to the initial performance test
specified under paragraph (c) of this section, but not to the daily
performance tests required thereafter as specified in Sec. 60.108(d).
Section 60.8(f) does not apply when determining compliance with the
standards specified under Sec. 60.104(b). Performance tests conducted
for the purpose of determining compliance under Sec. 60.104(b) shall be
conducted according to the applicable procedures specified under Sec.
60.106.
(b) Owners or operators who seek to comply with Sec. 60.104(b)(3)
shall meet that standard at all times, including periods of startup,
shutdown, and malfunctions.
(c) The initial performance test shall consist of the initial 7-day
average calculated for compliance with Sec. 60.104(b)(1), (b)(2), or
(b)(3).
(d) After conducting the initial performance test prescribed under
Sec. 60.8, the owner or operator of a fluid catalytic cracking unit
catalyst regenerator subject to Sec. 60.104(b) shall conduct a
performance test for each successive 24-hour period thereafter. The
daily performance tests shall be conducted according to the appropriate
procedures specified under Sec. 60.106. In the event that a sample
collected under Sec. 60.106(i) or (j) is accidentally lost or
conditions occur in which one of the samples must be discontinued
because of forced shutdown, failure of an irreplaceable portion of the
sample train, extreme meteorological conditions, or other circumstances,
beyond the owner or operators' control, compliance may be determined
using available data for the 7-day period.
(e) Each owner or operator subject to Sec. 60.104(b) who has
demonstrated compliance with one of the provisions of Sec. 60.104(b)
but a later date seeks to comply with another of the provisions of Sec.
60.104(b) shall begin conducting daily performance tests as specified
under paragraph (d) of this section immediately upon electing to become
subject to one of the other provisions of Sec. 60.104(b). The owner or
operator shall furnish the Administrator with a written notification of
the change in the semiannual report required by Sec. 60.107(f).
[54 FR 34030, Aug. 17, 1989, as amended at 55 FR 40178, Oct. 2, 1990; 64
FR 7466, Feb. 12, 1999; 73 FR 35867, June 24, 2008]
Sec. 60.109 Delegation of authority.
(a) In delegating implementation and enforcement authority to a
State under section 111(c) of the Act, the authorities contained in
paragraph (b) of this section shall be retained by the Administrator and
not transferred to a State.
[[Page 332]]
(b) Authorities which shall not be delegated to States:
(1) Section 60.105(a)(13)(iii),
(2) Section 60.106(i)(12).
[54 FR 34031, Aug. 17, 1989, as amended at 55 FR 40178, Oct. 2, 1990]
Subpart Ja_Standards of Performance for Petroleum Refineries for Which
Construction, Reconstruction, or Modification Commenced After May 14,
2007
Source: 73 FR 35867, June 24, 2008, unless otherwise noted.
Sec. 60.100a Applicability, designation of affected facility, and
reconstruction.
(a) The provisions of this subpart apply to the following affected
facilities in petroleum refineries: fluid catalytic cracking units
(FCCU), fluid coking units (FCU), delayed coking units, fuel gas
combustion devices (including process heaters), flares and sulfur
recovery plants. The sulfur recovery plant need not be physically
located within the boundaries of a petroleum refinery to be an affected
facility, provided it processes gases produced within a petroleum
refinery.
(b) Except for flares and delayed coking units, the provisions of
this subpart apply only to affected facilities under paragraph (a) of
this section which either commence construction, modification or
reconstruction after May 14, 2007, or elect to comply with the
provisions of this subpart in lieu of complying with the provisions in
subpart J of this part. For flares, the provisions of this subpart apply
only to flares which commence construction, modification or
reconstruction after June 24, 2008. For the purposes of this subpart, a
modification to a flare commences when a project that includes any of
the activities in paragraphs (c)(1) or (2) of this section is commenced.
For delayed coking units, the provisions of this subpart apply to
delayed coking units that commence construction, reconstruction or
modification on the earliest of the following dates:
(1) May 14, 2007, for such activities that involve a ``delayed
coking unit'' defined as follows: one or more refinery process units in
which high molecular weight petroleum derivatives are thermally cracked
and petroleum coke is produced in a series of closed, batch system
reactors;
(2) December 22, 2008, for such activities that involve a ``delayed
coking unit'' defined as follows: a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is produced in a series of closed, batch system reactors.
A delayed coking unit consists of the coke drums and associated
fractionator;
(3) September 12, 2012, for such activities that involve a ``delayed
coking unit'' as defined in Sec. 60.101a.
(c) For all affected facilities other than flares, the provisions in
Sec. 60.14 regarding modification apply. As provided in Sec. 60.14(f),
the special provisions set forth under this subpart shall supersede the
provisions in Sec. 60.14 with respect to flares. For the purposes of
this subpart, a modification to a flare occurs as provided in paragraphs
(c)(1) or (2) of this section.
(1) Any new piping from a refinery process unit, including ancillary
equipment, or a fuel gas system is physically connected to the flare
(e.g., for direct emergency relief or some form of continuous or
intermittent venting). However, the connections described in paragraphs
(c)(1)(i) through (vii) of this section are not considered modifications
of a flare.
(i) Connections made to install monitoring systems to the flare.
(ii) Connections made to install a flare gas recovery system or
connections made to upgrade or enhance components of a flare gas
recovery system (e.g., addition of compressors or recycle lines).
(iii) Connections made to replace or upgrade existing pressure
relief or safety valves, provided the new pressure relief or safety
valve has a set point opening pressure no lower and an internal diameter
no greater than the existing equipment being replaced or upgraded.
(iv) Connections made for flare gas sulfur removal.
[[Page 333]]
(v) Connections made to install back-up (redundant) equipment
associated with the flare (such as a back-up compressor) that does not
increase the capacity of the flare.
(vi) Replacing piping or moving an existing connection from a
refinery process unit to a new location in the same flare, provided the
new pipe diameter is less than or equal to the diameter of the pipe/
connection being replaced/moved.
(vii) Connections that interconnect two or more flares.
(2) A flare is physically altered to increase the flow capacity of
the flare.
(d) For purposes of this subpart, under Sec. 60.15, the ``fixed
capital cost of the new components'' includes the fixed capital cost of
all depreciable components which are or will be replaced pursuant to all
continuous programs of component replacement which are commenced within
any 2-year period following the relevant applicability date specified in
paragraph (b) of this section.
[73 FR 35867, June 24, 2008, as amended at 77 FR 56464, Sep. 12, 2012;
80 FR 75230, Dec. 1, 2015]
Sec. 60.101a Definitions.
Terms used in this subpart are defined in the Clean Air Act (CAA),
in Sec. 60.2 and in this section.
Air preheat means a device used to heat the air supplied to a
process heater generally by use of a heat exchanger to recover the
sensible heat of exhaust gas from the process heater.
Ancillary equipment means equipment used in conjunction with or that
serve a refinery process unit. Ancillary equipment includes, but is not
limited to, storage tanks, product loading operations, wastewater
treatment systems, steam- or electricity-producing units (including coke
gasification units), pressure relief valves, pumps, sampling vents and
continuous analyzer vents.
Cascaded flare system means a series of flares connected to one
flare gas header system arranged with increasing pressure set points so
that discharges will be initially directed to the first flare in the
series (i.e., the primary flare). If the discharge pressure exceeds a
set point at which the flow to the primary flare would exceed the
primary flare's capacity, flow will be diverted to the second flare in
the series. Similarly, flow would be diverted to a third (or fourth)
flare if the pressure in the flare gas header system exceeds a threshold
where the flow to the first two (or three) flares would exceed their
capacities.
Co-fired process heater means a process heater that employs burners
that are designed to be supplied by both gaseous and liquid fuels on a
routine basis. Process heaters that have gas burners with emergency oil
back-up burners are not considered co-fired process heaters.
Coke burn-off means the coke removed from the surface of the FCCU
catalyst by combustion in the catalyst regenerator. The rate of coke
burn-off is calculated by the formula specified in Sec. 60.104a.
Contact material means any substance formulated to remove metals,
sulfur, nitrogen, or any other contaminant from petroleum derivatives.
Corrective action means the design, operation and maintenance
changes that one takes consistent with good engineering practice to
reduce or eliminate the likelihood of the recurrence of the primary
cause and any other contributing cause(s) of an event identified by a
root cause analysis as having resulted in a discharge of gases from an
affected facility in excess of specified thresholds.
Corrective action analysis means a description of all reasonable
interim and long-term measures, if any, that are available, and an
explanation of why the selected corrective action(s) is/are the best
alternative(s), including, but not limited to, considerations of cost
effectiveness, technical feasibility, safety and secondary impacts.
Delayed coking unit means a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is produced in a series of closed, batch system reactors.
A delayed coking unit includes, but is not limited to, all of the coke
drums associated with a single fractionator; the fractionator, including
the bottoms receiver and the overhead condenser; the coke drum cutting
water and quench system, including the jet pump and coker quench
[[Page 334]]
water tank; and the coke drum blowdown recovery compressor system.
Emergency flare means a flare that combusts gas exclusively released
as a result of malfunctions (and not startup, shutdown, routine
operations or any other cause) on four or fewer occasions in a rolling
365-day period. For purposes of this rule, a flare cannot be categorized
as an emergency flare unless it maintains a water seal.
Flare means a combustion device that uses an uncontrolled volume of
air to burn gases. The flare includes the foundation, flare tip,
structural support, burner, igniter, flare controls, including air
injection or steam injection systems, flame arrestors and the flare gas
header system. In the case of an interconnected flare gas header system,
the flare includes each individual flare serviced by the interconnected
flare gas header system and the interconnected flare gas header system.
Flare gas header system means all piping and knockout pots,
including those in a subheader system, used to collect and transport gas
to a flare either from a process unit or a pressure relief valve from
the fuel gas system, regardless of whether or not a flare gas recovery
system draws gas from the flare gas header system. The flare gas header
system includes piping inside the battery limit of a process unit if the
purpose of the piping is to transport gas to a flare or knockout pot
that is part of the flare.
Flare gas recovery system means a system of one or more compressors,
piping and the associated water seal, rupture disk or similar device
used to divert gas from the flare and direct the gas to the fuel gas
system or to a fuel gas combustion device.
Flexicoking unit means a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is continuously produced and then gasified to produce a
synthetic fuel gas.
Fluid catalytic cracking unit means a refinery process unit in which
petroleum derivatives are continuously charged and hydrocarbon molecules
in the presence of a catalyst suspended in a fluidized bed are fractured
into smaller molecules, or react with a contact material suspended in a
fluidized bed to improve feedstock quality for additional processing and
the catalyst or contact material is continuously regenerated by burning
off coke and other deposits. The unit includes the riser, reactor,
regenerator, air blowers, spent catalyst or contact material stripper,
catalyst or contact material recovery equipment, and regenerator
equipment for controlling air pollutant emissions and for heat recovery.
When fluid catalyst cracking unit regenerator exhaust from two separate
fluid catalytic cracking units share a common exhaust treatment (e.g.,
CO boiler or wet scrubber), the fluid catalytic cracking unit is a
single affected facility.
Fluid coking unit means a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is continuously produced in a fluidized bed system. The
fluid coking unit includes the coking reactor, the coking burner, and
equipment for controlling air pollutant emissions and for heat recovery
on the fluid coking burner exhaust vent.
Forced draft process heater means a process heater in which the
combustion air is supplied under positive pressure produced by a fan at
any location in the inlet air line prior to the point where the
combustion air enters the process heater or air preheat. For the
purposes of this subpart, a process heater that uses fans at both the
inlet air side and the exhaust air side (i.e., balanced draft system) is
considered to be a forced draft process heater.
Fuel gas means any gas which is generated at a petroleum refinery
and which is combusted. Fuel gas includes natural gas when the natural
gas is combined and combusted in any proportion with a gas generated at
a refinery. Fuel gas does not include gases generated by catalytic
cracking unit catalyst regenerators, coke calciners (used to make
premium grade coke) and fluid coking burners, but does include gases
from flexicoking unit gasifiers and other gasifiers. Fuel gas does not
include vapors that are collected and combusted in a thermal oxidizer or
flare installed to control emissions from wastewater treatment units
other than those processing sour water, marine tank vessel loading
operations or
[[Page 335]]
asphalt processing units (i.e., asphalt blowing stills).
Fuel gas combustion device means any equipment, such as process
heaters and boilers, used to combust fuel gas. For the purposes of this
subpart, fuel gas combustion device does not include flares or
facilities in which gases are combusted to produce sulfur or sulfuric
acid.
Fuel gas system means a system of compressors, piping, knock-out
pots, mix drums, and units used to remove sulfur contaminants from the
fuel gas (e.g., amine scrubbers) that collects refinery fuel gas from
one or more sources for treatment as necessary prior to combusting in
process heaters or boilers. A fuel gas system may have an overpressure
vent to a flare but the primary purpose for a fuel gas system is to
provide fuel to the refinery.
Natural draft process heater means any process heater in which the
combustion air is supplied under ambient or negative pressure without
the use of an inlet air (forced draft) fan. For the purposes of this
subpart, a natural draft process heater is any process heater that is
not a forced draft process heater, including induced draft systems.
Non-emergency flare means any flare that is not an emergency flare
as defined in this subpart.
Oxidation control system means an emission control system which
reduces emissions from sulfur recovery plants by converting these
emissions to sulfur dioxide (SO2) and recycling the
SO2 to the reactor furnace or the first-stage catalytic
reactor of the Claus sulfur recovery plant or converting the
SO2 to a sulfur product.
Petroleum means the crude oil removed from the earth and the oils
derived from tar sands, shale, and coal.
Petroleum refinery means any facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt
(bitumen) or other products through distillation of petroleum or through
redistillation, cracking or reforming of unfinished petroleum
derivatives. A facility that produces only oil shale or tar sands-
derived crude oil for further processing at a petroleum refinery using
only solvent extraction and/or distillation to recover diluent is not a
petroleum refinery.
Primary flare means the first flare in a cascaded flare system.
Process heater means an enclosed combustion device used to transfer
heat indirectly to process stream materials (liquids, gases, or solids)
or to a heat transfer material for use in a process unit instead of
steam.
Process upset gas means any gas generated by a petroleum refinery
process unit or by ancillary equipment as a result of startup, shutdown,
upset or malfunction.
Purge gas means gas introduced between a flare's water seal and a
flare's tip to prevent oxygen infiltration (backflow) into the flare
tip. For flares with no water seals, the function of purge gas is
performed by sweep gas (i.e., flares without water seals do not use
purge gas).
Reduced sulfur compounds means hydrogen sulfide (H2S),
carbonyl sulfide, and carbon disulfide.
Reduction control system means an emission control system which
reduces emissions from sulfur recovery plants by converting these
emissions to H2S and either recycling the H2S to
the reactor furnace or the first-stage catalytic reactor of the Claus
sulfur recovery plant or converting the H2S to a sulfur
product.
Refinery process unit means any segment of the petroleum refinery in
which a specific processing operation is conducted.
Root cause analysis means an assessment conducted through a process
of investigation to determine the primary cause, and any other
contributing cause(s), of a discharge of gases in excess of specified
thresholds.
Secondary flare means a flare in a cascaded flare system that
provides additional flare capacity and pressure relief to a flare gas
system when the flare gas flow exceeds the capacity of the primary
flare. For purposes of this subpart, a secondary flare is characterized
by infrequent use and must maintain a water seal.
Sour water means water that contains sulfur compounds (usually
H2S) at concentrations of 10 parts per million by weight or
more.
[[Page 336]]
Sulfur pit means the storage vessel in which sulfur that is
condensed after each Claus catalytic reactor is initially accumulated
and stored. A sulfur pit does not include secondary sulfur storage
vessels downstream of the initial Claus reactor sulfur pits.
Sulfur recovery plant means all process units which recover sulfur
from H2S and/or SO2 from a common source of sour
gas produced at a petroleum refinery. The sulfur recovery plant also
includes sulfur pits used to store the recovered sulfur product, but it
does not include secondary sulfur storage vessels or loading facilities
downstream of the sulfur pits. For example, a Claus sulfur recovery
plant includes: Reactor furnace and waste heat boiler, catalytic
reactors, sulfur pits and, if present, oxidation or reduction control
systems or incinerator, thermal oxidizer or similar combustion device.
Multiple sulfur recovery units are a single affected facility only when
the units share the same source of sour gas. Sulfur recovery plants that
receive source gas from completely segregated sour gas treatment systems
are separate affected facilities.
Sweep gas means the gas introduced in a flare gas header system to
maintain a constant flow of gas to prevent oxygen buildup in the flare
header. For flares with no water seals, sweep gas also performs the
function of preventing oxygen infiltration (backflow) into the flare
tip.
[73 FR 35867, June 24, 2008, as amended at 77 FR 56464, Sep. 12, 2012;
78 FR 76756, Dec. 19, 2013; 80 FR 75230, Dec. 1, 2015]
Sec. 60.102a Emissions limitations.
(a) Each owner or operator that is subject to the requirements of
this subpart shall comply with the emissions limitations in paragraphs
(b) through (i) of this section on and after the date on which the
initial performance test, required by Sec. 60.8, is completed, but not
later than 60 days after achieving the maximum production rate at which
the affected facility will be operated or 180 days after initial
startup, whichever comes first.
(b) An owner or operator subject to the provisions of this subpart
shall not discharge or cause the discharge into the atmosphere from any
FCCU or FCU:
(1) Particulate matter (PM) in excess of the limits in paragraphs
(b)(1)(i), (ii), or (iii) of this section.
(i) 1.0 gram per kilogram (g/kg) (1 pound (lb) per 1,000 lb) coke
burn-off or, if a PM continuous emission monitoring system (CEMS) is
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0
percent excess air for each modified or reconstructed FCCU.
(ii) 0.5 gram per kilogram (g/kg) coke burn-off (0.5 lb PM/1,000 lb
coke burn-off) or, if a PM CEMS is used, 0.020 gr/dscf corrected to 0
percent excess air for each newly constructed FCCU.
(iii) 1.0 g/kg (1 lb/1,000 lb) coke burn-off or, if a PM CEMS is
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0
percent excess air for each affected FCU.
(2) Nitrogen oxides (NOX) in excess of 80 parts per
million by volume (ppmv), dry basis corrected to 0 percent excess air,
on a 7-day rolling average basis.
(3) Sulfur dioxide (SO2) in excess of 50 ppmv dry basis
corrected to 0 percent excess air, on a 7-day rolling average basis and
25 ppmv, dry basis corrected to 0 percent excess air, on a 365-day
rolling average basis.
(4) Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected
to 0 percent excess air, on an hourly average basis.
(c) The owner or operator of a FCCU or FCU that uses a continuous
parameter monitoring system (CPMS) according to Sec. 60.105a(b)(1)
shall comply with the applicable control device parameter operating
limit in paragraph (c)(1) or (2) of this section.
(1) If the FCCU or FCU is controlled using an electrostatic
precipitator:
(i) The 3-hour rolling average total power and secondary current to
the entire system must not fall below the level established during the
most recent performance test; and
(ii) The daily average exhaust coke burn-off rate must not exceed
the level established during the most recent performance test.
(2) If the FCCU or FCU is controlled using a wet scrubber:
(i) The 3-hour rolling average pressure drop must not fall below the
level
[[Page 337]]
established during the most recent performance test; and
(ii) The 3-hour rolling average liquid-to-gas ratio must not fall
below the level established during the most recent performance test.
(d) If an FCCU or FCU uses a continuous opacity monitoring system
(COMS) according to the alternative monitoring option in Sec.
60.105a(e), the 3-hour rolling average opacity of emissions from the
FCCU or FCU as measured by the COMS must not exceed the site-specific
opacity limit established during the most recent performance test.
(e) The owner or operator of a FCCU or FCU that is exempted from the
requirement for a CO continuous emissions monitoring system under Sec.
60.105a(h)(3) shall comply with the parameter operating limits in
paragraph (e)(1) or (2) of this section.
(1) For a FCCU or FCU with no post-combustion control device:
(i) The hourly average temperature of the exhaust gases exiting the
FCCU or FCU must not fall below the level established during the most
recent performance test.
(ii) The hourly average oxygen (O2) concentration of the
exhaust gases exiting the FCCU or FCU must not fall below the level
established during the most recent performance test.
(2) For a FCCU or FCU with a post-combustion control device:
(i) The hourly average temperature of the exhaust gas vent stream
exiting the control device must not fall below the level established
during the most recent performance test.
(ii) The hourly average O2 concentration of the exhaust
gas vent stream exiting the control device must not fall below the level
established during the most recent performance test.
(f) Except as provided in paragraph (f)(3) of this section, each
owner or operator of an affected sulfur recovery plant shall comply with
the applicable emission limits in paragraph (f)(1) or (2) of this
section.
(1) For a sulfur recovery plant with a design production capacity
greater than 20 long tons per day (LTD), the owner or operator shall
comply with the applicable emission limit in paragraph (f)(1)(i) or (ii)
of this section. If the sulfur recovery plant consists of multiple
process trains or release points, the owner or operator shall comply
with the applicable emission limit for each process train or release
point individually or comply with the applicable emission limit in
paragraph (f)(1)(i) or (ii) as a flow rate weighted average for a group
of release points from the sulfur recovery plant provided that flow is
monitored as specified in Sec. 60.106a(a)(7); if flow is not monitored
as specified in Sec. 60.106a(a)(7), the owner or operator shall comply
with the applicable emission limit in paragraph (f)(1)(i) or (ii) for
each process train or release point individually. For a sulfur recovery
plant with a design production capacity greater than 20 long LTD and a
reduction control system not followed by incineration, the owner or
operator shall also comply with the H2S emission limit in
paragraph (f)(1)(iii) of this section for each individual release point.
(i) For a sulfur recovery plant with an oxidation control system or
a reduction control system followed by incineration, the owner or
operator shall not discharge or cause the discharge of any gases into
the atmosphere (SO2) in excess of the emission limit
calculated using Equation 1 of this section. For Claus units that use
only ambient air in the Claus burner or that elect not to monitor
O2 concentration of the air/oxygen mixture used in the Claus
burner or for non-Claus sulfur recovery plants, this SO2
emissions limit is 250 ppmv (dry basis) at zero percent excess air.
[GRAPHIC] [TIFF OMITTED] TR01DE15.000
Where:
ELS = Emission limit for large sulfur recovery plant, ppmv
(as SO2, dry basis at zero percent excess air);
[[Page 338]]
k1 = Constant factor for emission limit conversion:
k1 = 1 for converting to the SO2 limit
for a sulfur recovery plant with an oxidation control system
or a reduction control system followed by incineration and
k1 = 1.2 for converting to the reduced sulfur
compounds limit for a sulfur recovery plant with a reduction
control system not followed by incineration; and
%O2 = O2 concentration of the air/oxygen mixture
supplied to the Claus burner, percent by volume (dry basis).
If only ambient air is used for the Claus burner or if the
owner or operator elects not to monitor O2
concentration of the air/oxygen mixture used in the Claus
burner or for non-Claus sulfur recovery plants, use 20.9% for
%O2.
(ii) For a sulfur recovery plant with a reduction control system not
followed by incineration, the owner or operator shall not discharge or
cause the discharge of any gases into the atmosphere containing reduced
sulfur compounds in excess of the emission limit calculated using
Equation 1 of this section. For Claus units that use only ambient air in
the Claus burner or for non-Claus sulfur recovery plants, this reduced
sulfur compounds emission limit is 300 ppmv calculated as ppmv
SO2 (dry basis) at 0-percent excess air.
(iii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
hydrogen sulfide (H2S) in excess of 10 ppmv calculated as
ppmv SO2 (dry basis) at zero percent excess air.
(2) For a sulfur recovery plant with a design production capacity of
20 LTD or less, the owner or operator shall comply with the applicable
emission limit in paragraph (f)(2)(i) or (ii) of this section. If the
sulfur recovery plant consists of multiple process trains or release
points, the owner or operator may comply with the applicable emission
limit for each process train or release point individually or comply
with the applicable emission limit in paragraph (f)(2)(i) or (ii) as a
flow rate weighted average for a group of release points from the sulfur
recovery plant provided that flow is monitored as specified in Sec.
60.106a(a)(7); if flow is not monitored as specified in Sec.
60.106a(a)(7), the owner or operator shall comply with the applicable
emission limit in paragraph (f)(2)(i) or (ii) for each process train or
release point individually. For a sulfur recovery plant with a design
production capacity of 20 LTD or less and a reduction control system not
followed by incineration, the owner or operator shall also comply with
the H2S emission limit in paragraph (f)(2)(iii) of this
section for each individual release point.
(i) For a sulfur recovery plant with an oxidation control system or
a reduction control system followed by incineration, the owner or
operator shall not discharge or cause the discharge of any gases into
the atmosphere containing SO2 in excess of the emission limit
calculated using Equation 2 of this section. For Claus units that use
only ambient air in the Claus burner or that elect not to monitor
O2 concentration of the air/oxygen mixture used in the Claus
burner or for non-Claus sulfur recovery plants, this SO2
emission limit is 2,500 ppmv (dry basis) at zero percent excess air.
[GRAPHIC] [TIFF OMITTED] TR01DE15.001
Where:
ESS = Emission limit for small sulfur recovery plant, ppmv
(as SO2, dry basis at zero percent excess air);
k1 = Constant factor for emission limit conversion:
k1 = 1 for converting to the SO2 limit
for a sulfur recovery plant with an oxidation control system
or a reduction control system followed by incineration and
k1 = 1.2 for converting to the reduced sulfur
compounds limit for a sulfur recovery plant with a reduction
control system not followed by incineration; and
%O2 = O2 concentration of the air/oxygen mixture
supplied to the Claus burner, percent by volume (dry basis).
If only ambient air is used in the Claus burner or if the
owner or operator elects not to monitor O2
concentration of the air/oxygen mixture used in the Claus
burner or
[[Page 339]]
for non-Claus sulfur recovery plants, use 20.9% for
%O2.
(ii) For a sulfur recovery plant with a reduction control system not
followed by incineration, the owner or operator shall not discharge or
cause the discharge of any gases into the atmosphere containing reduced
sulfur compounds in excess of the emission limit calculated using
Equation 2 of this section. For Claus units that use only ambient air in
the Claus burner or for non-Claus sulfur recovery plants, this reduced
sulfur compounds emission limit is 3,000 ppmv calculated as ppmv
SO2 (dry basis) at zero percent excess air.
(iii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
H2S in excess of 100 ppmv calculated as ppmv SO2
(dry basis) at zero percent excess air.
(3) The emission limits in paragraphs (f)(1) and (2) of this section
shall not apply during periods of maintenance of the sulfur pit, which
shall not exceed 240 hours per year. The owner or operator must document
the time periods during which the sulfur pit vents were not controlled
and measures taken to minimize emissions during these periods. Examples
of these measures include not adding fresh sulfur or shutting off vent
fans.
(g) Each owner or operator of an affected fuel gas combustion device
shall comply with the emissions limits in paragraphs (g)(1) and (2) of
this section.
(1) Except as provided in (g)(1)(iii) of this section, for each fuel
gas combustion device, the owner or operator shall comply with either
the emission limit in paragraph (g)(1)(i) of this section or the fuel
gas concentration limit in paragraph (g)(1)(ii) of this section. For CO
boilers or furnaces that are part of a fluid catalytic cracking unit or
fluid coking unit affected facility, the owner or operator shall comply
with the fuel gas concentration limit in paragraph (g)(1)(ii) for all
fuel gas streams combusted in these units.
(i) The owner or operator shall not discharge or cause the discharge
of any gases into the atmosphere that contain SO2 in excess
of 20 ppmv (dry basis, corrected to 0-percent excess air) determined
hourly on a 3-hour rolling average basis and SO2 in excess of
8 ppmv (dry basis, corrected to 0-percent excess air), determined daily
on a 365 successive calendar day rolling average basis; or
(ii) The owner or operator shall not burn in any fuel gas combustion
device any fuel gas that contains H2S in excess of 162 ppmv
determined hourly on a 3-hour rolling average basis and H2S
in excess of 60 ppmv determined daily on a 365 successive calendar day
rolling average basis.
(iii) The combustion in a portable generator of fuel gas released as
a result of tank degassing and/or cleaning is exempt from the emissions
limits in paragraphs (g)(1)(i) and (ii) of this section.
(2) For each process heater with a rated capacity of greater than 40
million British thermal units per hour (MMBtu/hr) on a higher heating
value basis, the owner or operator shall not discharge to the atmosphere
any emissions of NOX in excess of the applicable limits in
paragraphs (g)(2)(i) through (iv) of this section.
(i) For each natural draft process heater, comply with the limit in
either paragraph (g)(2)(i)(A) or (B) of this section. The owner or
operator may comply with either limit at any time, provided that the
appropriate parameters for each alternative are monitored as specified
in Sec. 60.107a; if fuel gas composition is not monitored as specified
in Sec. 60.107a(d), the owner or operator must comply with the
concentration limits in paragraph (g)(2)(i)(A) of this section.
(A) 40 ppmv (dry basis, corrected to 0-percent excess air)
determined daily on a 30-day rolling average basis; or
(B) 0.040 pounds per million British thermal units (lb/MMBtu) higher
heating value basis determined daily on a 30-day rolling average basis.
(ii) For each forced draft process heater, comply with the limit in
either paragraph (g)(2)(ii)(A) or (B) of this section. The owner or
operator may comply with either limit at any time, provided that the
appropriate parameters for each alternative are monitored as specified
in Sec. 60.107a; if fuel gas composition is not monitored as
[[Page 340]]
specified in Sec. 60.107a(d), the owner or operator must comply with
the concentration limits in paragraph (g)(2)(ii)(A) of this section.
(A) 60 ppmv (dry basis, corrected to 0-percent excess air)
determined daily on a 30-day rolling average basis; or
(B) 0.060 lb/MMBtu higher heating value basis determined daily on a
30-day rolling average basis.
(iii) For each co-fired natural draft process heater, comply with
the limit in either paragraph (g)(2)(iii)(A) or (B) of this section. The
owner or operator must choose one of the emissions limits with which to
comply at all times:
(A) 150 ppmv (dry basis, corrected to 0-percent excess air)
determined daily on a 30 successive operating day rolling average basis;
or
(B) The daily average emissions limit calculated using Equation 3 of
this section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.001
Where:
ERNOx = Daily allowable average emission rate of
NOX, lb/MMBtu (higher heating value basis);
Qgas = Daily average volumetric flow rate of fuel gas,
standard cubic feet per day (scf/day);
Qoil = Daily average volumetric flow rate of fuel oil, scf/
day;
HHVgas = Daily average higher heating value of gas fired to
the process heater, MMBtu/scf; and
HHVoil = Daily average higher heating value of fuel oil fired
to the process heater, MMBtu/scf.
(iv) For each co-fired forced draft process heater, comply with the
limit in either paragraph (g)(2)(iv)(A) or (B) of this section. The
owner or operator must choose one of the emissions limits with which to
comply at all times:
(A) 150 ppmv (dry basis, corrected to 0-percent excess air)
determined daily on a 30 successive operating day rolling average basis;
or
(B) The daily average emissions limit calculated using Equation 4 of
this section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.002
Where:
ERNOx = Daily allowable average emission rate of
NOX, lb/MMBtu (higher heating value basis);
Qgas = Daily average volumetric flow rate of fuel gas, scf/
day;
Qoil = Daily average volumetric flow rate of fuel oil, scf/
day;
HHVgas = Daily average higher heating value of gas fired to
the process heater, MMBtu/scf; and
HHVoil = Daily average higher heating value of fuel oil fired
to the process heater, MMBtu/scf.
(h) [Reserved]
(i) For a process heater that meets any of the criteria of
paragraphs (i)(1)(i) through (iv) of this section, an owner or operator
may request approval from the Administrator for a NOX
emissions limit which shall apply specifically to that affected
facility. The request shall include information as described in
paragraph (i)(2) of this section. The request shall be submitted and
followed as described in paragraph (i)(3) of this section.
(1) A process heater that meets one of the criteria in paragraphs
(i)(1)(i) through (iv) of this section may apply for a site-specific
NOX emissions limit:
(i) A modified or reconstructed process heater that lacks sufficient
space
[[Page 341]]
to accommodate installation and proper operation of combustion
modification-based technology (e.g., ultra-low NOX burners);
or
(ii) A modified or reconstructed process heater that has downwardly
firing induced draft burners; or
(iii) A co-fired process heater; or
(iv) A process heater operating at reduced firing conditions for an
extended period of time (i.e., operating in turndown mode). The site-
specific NOX emissions limit will only apply for those
operating conditions.
(2) The request shall include sufficient and appropriate data, as
determined by the Administrator, to allow the Administrator to confirm
that the process heater is unable to comply with the applicable
NOX emissions limit in paragraph (g)(2) of this section. At a
minimum, the request shall contain the information described in
paragraphs (i)(2)(i) through (iv) of this section.
(i) The design and dimensions of the process heater, evaluation of
available combustion modification-based technology, description of fuel
gas and, if applicable, fuel oil characteristics, information regarding
the combustion conditions (temperature, oxygen content, firing rates)
and other information needed to demonstrate that the process heater
meets one of the four classes of process heaters listed in paragraph
(i)(1) of this section.
(ii) An explanation of how the data in paragraph (i)(2)(i)
demonstrate that ultra-low NOX burners, flue gas
recirculation, control of excess air or other combustion modification-
based technology (including combinations of these combustion
modification-based technologies) cannot be used to meet the applicable
emissions limit in paragraph (g)(2) of this section.
(iii) Results of a performance test conducted under representative
conditions using the applicable methods specified in Sec. 60.104a(i) to
demonstrate the performance of the technology the owner or operator will
use to minimize NOX emissions.
(iv) The means by which the owner or operator will document
continuous compliance with the site-specific emissions limit.
(3) The request shall be submitted and followed as described in
paragraphs (i)(3)(i) through (iii) of this section.
(i) The owner or operator of a process heater that meets one of the
criteria in paragraphs (i)(1)(i) through (iv) of this section may
request approval from the Administrator within 180 days after initial
startup of the process heater for a NOX emissions limit which
shall apply specifically to that affected facility.
(ii) The request must be submitted to the Administrator for
approval. The owner or operator must comply with the request as
submitted until it is approved.
(iii) The request shall also be submitted to the following address:
U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards, Sector Policies and Programs Division, U.S. EPA Mailroom
(E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive,
Research Triangle Park, NC 27711. Electronic copies in lieu of hard
copies may also be submitted to [email protected].
(4) The approval process for a request for a facility-specific
NOX emissions limit is described in paragraphs (i)(4)(i)
through (iii) of this section.
(i) Approval by the Administrator of a facility-specific
NOX emissions limit request will be based on the
completeness, accuracy and reasonableness of the request. Factors that
the EPA will consider in reviewing the request for approval include, but
are not limited to, the following:
(A) A demonstration that the process heater meets one of the four
classes of process heaters outlined in paragraphs (i)(1) of this
section;
(B) A description of the low-NOX burner designs and other
combustion modifications considered for reducing NOX
emissions;
(C) The combustion modification option selected; and
(D) The operating conditions (firing rate, heater box temperature
and excess oxygen concentration) at which the NOX emission
level was established.
(ii) If the request is approved by the Administrator, a facility-
specific NOX emissions limit will be established at the
NOX emission level demonstrated in the approved request.
[[Page 342]]
(iii) If the Administrator finds any deficiencies in the request,
the request must be revised to address the deficiencies and be re-
submitted for approval.
[73 FR 35867, June 24, 2008, as amended at 77 FR 56466, Sep. 12, 2012;
80 FR 75230, Dec. 1, 2015]
Sec. 60.103a Design, equipment, work practice or operational standards.
(a) Except as provided in paragraph (g) of this section, each owner
or operator that operates a flare that is subject to this subpart shall
develop and implement a written flare management plan no later than the
date specified in paragraph (b) of this section. The flare management
plan must include the information described in paragraphs (a)(1) through
(7) of this section.
(1) A listing of all refinery process units, ancillary equipment,
and fuel gas systems connected to the flare for each affected flare.
(2) An assessment of whether discharges to affected flares from
these process units, ancillary equipment and fuel gas systems can be
minimized. The flare minimization assessment must (at a minimum)
consider the items in paragraphs (a)(2)(i) through (iv) of this section.
The assessment must provide clear rationale in terms of costs (capital
and annual operating), natural gas offset credits (if applicable),
technical feasibility, secondary environmental impacts and safety
considerations for the selected minimization alternative(s) or a
statement, with justifications, that flow reduction could not be
achieved. Based upon the assessment, each owner or operator of an
affected flare shall identify the minimization alternatives that it has
implemented by the due date of the flare management plan and shall
include a schedule for the prompt implementation of any selected
measures that cannot reasonably be completed as of that date.
(i) Elimination of process gas discharge to the flare through
process operating changes or gas recovery at the source.
(ii) Reduction of the volume of process gas to the flare through
process operating changes.
(iii) Installation of a flare gas recovery system or, for facilities
that are fuel gas rich, a flare gas recovery system and a co-generation
unit or combined heat and power unit.
(iv) Minimization of sweep gas flow rates and, for flares with water
seals, purge gas flow rates.
(3) A description of each affected flare containing the information
in paragraphs (a)(3)(i) through (vii) of this section.
(i) A general description of the flare, including the information in
paragraphs (a)(3)(i)(A) through (G) of this section.
(A) Whether it is a ground flare or elevated (including height).
(B) The type of assist system (e.g., air, steam, pressure, non-
assisted).
(C) Whether it is simple or complex flare tip (e.g., staged,
sequential).
(D) Whether the flare is part of a cascaded flare system (and if so,
whether the flare is primary or secondary).
(E) Whether the flare serves as a backup to another flare.
(F) Whether the flare is an emergency flare or a non-emergency
flare.
(G) Whether the flare is equipped with a flare gas recovery system.
(ii) Description and simple process flow diagram showing the
interconnection of the following components of the flare: flare tip
(date installed, manufacturer, nominal and effective tip diameter, tip
drawing); knockout or surge drum(s) or pot(s) (including dimensions and
design capacities); flare header(s) and subheader(s); assist system; and
ignition system.
(iii) Flare design parameters, including the maximum vent gas flow
rate; minimum sweep gas flow rate; minimum purge gas flow rate (if any);
maximum supplemental gas flow rate; maximum pilot gas flow rate; and, if
the flare is steam-assisted, minimum total steam rate.
(iv) Description and simple process flow diagram showing all gas
lines (including flare, purge (if applicable), sweep, supplemental and
pilot gas) that are associated with the flare. For purge, sweep,
supplemental and pilot gas, identify the type of gas used. Designate
which lines are exempt from sulfur, H2S or flow monitoring
and why (e.g., natural gas, inherently low sulfur, pilot gas). Designate
which lines
[[Page 343]]
are monitored and identify on the process flow diagram the location and
type of each monitor.
(v) For each flow rate, H2S, sulfur content, pressure or
water seal monitor identified in paragraph (a)(3)(iv) of this section,
provide a detailed description of the manufacturer's specifications,
including, but not limited to, make, model, type, range, precision,
accuracy, calibration, maintenance and quality assurance procedures.
(vi) For emergency flares, secondary flares and flares equipped with
a flare gas recovery system designed, sized and operated to capture all
flows except those resulting from startup, shutdown or malfunction:
(A) Description of the water seal, including the operating range for
the liquid level.
(B) Designation of the monitoring option elected (flow and sulfur
monitoring or pressure and water seal liquid level monitoring).
(vii) For flares equipped with a flare gas recovery system:
(A) A description of the flare gas recovery system, including number
of compressors and capacity of each compressor.
(B) A description of the monitoring parameters used to quantify the
amount of flare gas recovered.
(C) For systems with staged compressors, the maximum time period
required to begin gas recovery with the secondary compressor(s), the
monitoring parameters and procedures used to minimize the duration of
releases during compressor staging and a justification for why the
maximum time period cannot be further reduced.
(4) An evaluation of the baseline flow to the flare. The baseline
flow to the flare must be determined after implementing the minimization
assessment in paragraph (a)(2) of this section. Baseline flows do not
include pilot gas flow or purge gas flow (i.e., gas introduced after the
flare's water seal) provided these gas flows remain reasonably constant
(i.e., separate flow monitors for these streams are not required).
Separate baseline flow rates may be established for different operating
conditions provided that the management plan includes:
(i) A primary baseline flow rate that will be used as the default
baseline for all conditions except those specifically delineated in the
plan;
(ii) A description of each special condition for which an alternate
baseline is established, including the rationale for each alternate
baseline, the daily flow for each alternate baseline and the expected
duration of the special conditions for each alternate baseline; and
(iii) Procedures to minimize discharges to the affected flare during
each special condition described in paragraph (a)(4)(ii) of this
section, unless procedures are already developed for these cases under
paragraph (a)(5) through (7) of this section, as applicable.
(5) Procedures to minimize or eliminate discharges to the flare
during the planned startup and shutdown of the refinery process units
and ancillary equipment that are connected to the affected flare,
together with a schedule for the prompt implementation of any procedures
that cannot reasonably be implemented as of the date of the submission
of the flare management plan.
(6) Procedures to reduce flaring in cases of fuel gas imbalance
(i.e., excess fuel gas for the refinery's energy needs), together with a
schedule for the prompt implementation of any procedures that cannot
reasonably be implemented as of the date of the submission of the flare
management plan.
(7) For flares equipped with flare gas recovery systems, procedures
to minimize the frequency and duration of outages of the flare gas
recovery system and procedures to minimize the volume of gas flared
during such outages, together with a schedule for the prompt
implementation of any procedures that cannot reasonably be implemented
as of the date of the submission of the flare management plan.
(b) Except as provided in paragraph (g) of this section, each owner
or operator required to develop and implement a written flare management
plan as described in paragraph (a) of this section must submit the plan
to the Administrator as described in paragraphs (b)(1) through (3) of
this section.
(1) The owner or operator of a newly constructed or reconstructed
flare must develop and implement the flare
[[Page 344]]
management plan by no later than the date that the flare becomes an
affected facility subject to this subpart, except for the selected
minimization alternatives in paragraph (a)(2) and/or the procedures in
paragraphs (a)(5) though (a)(7) of this section that cannot reasonably
be implemented by that date, which the owner or operator must implement
in accordance with the schedule in the flare management plan. The owner
or operator of a modified flare must develop and implement the flare
management plan by no later than November 11, 2015 or upon startup of
the modified flare, whichever is later.
(2) The owner or operator must comply with the plan as submitted by
the date specified in paragraph (b)(1) of this section. The plan should
be updated periodically to account for changes in the operation of the
flare, such as new connections to the flare or the installation of a
flare gas recovery system, but the plan need be re-submitted to the
Administrator only if the owner or operator adds an alternative baseline
flow rate, revises an existing baseline as described in paragraph (a)(4)
of this section, installs a flare gas recovery system or is required to
change flare designations and monitoring methods as described in Sec.
60.107a(g). The owner or operator must comply with the updated plan as
submitted.
(3) All versions of the plan submitted to the Administrator shall
also be submitted to the following address: U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards, Sector
Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention:
Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park,
NC 27711. Electronic copies in lieu of hard copies may also be submitted
to [email protected].
(c) Except as provided in paragraphs (f) and (g) of this section,
each owner or operator that operates a fuel gas combustion device, flare
or sulfur recovery plant subject to this subpart shall conduct a root
cause analysis and a corrective action analysis for each of the
conditions specified in paragraphs (c)(1) through (3) of this section.
(1) For a flare:
(i) Any time the SO2 emissions exceed 227 kilograms (kg)
(500 lb) in any 24-hour period; or
(ii) Any discharge to the flare in excess of 14,160 standard cubic
meters (m\3\) (500,000 standard cubic feet (scf)) above the baseline,
determined in paragraph (a)(4) of this section, in any 24-hour period;
or
(iii) If the monitoring alternative in Sec. 60.107a(g) is elected,
any period when the flare gas line pressure exceeds the water seal
liquid depth, except for periods attributable to compressor staging that
do not exceed the staging time specified in paragraph (a)(3)(vii)(C) of
this section.
(2) For a fuel gas combustion device, each exceedance of an
applicable short-term emissions limit in Sec. 60.102a(g)(1) if the
SO2 discharge to the atmosphere is 227 kg (500 lb) greater
than the amount that would have been emitted if the emissions limits had
been met during one or more consecutive periods of excess emissions or
any 24-hour period, whichever is shorter.
(3) For a sulfur recovery plant, each time the SO2
emissions are more than 227 kg (500 lb) greater than the amount that
would have been emitted if the SO2 or reduced sulfur
concentration was equal to the applicable emissions limit in Sec.
60.102a(f)(1) or (2) during one or more consecutive periods of excess
emissions or any 24-hour period, whichever is shorter.
(d) Except as provided in paragraphs (f) and (g) of this section, a
root cause analysis and corrective action analysis must be completed as
soon as possible, but no later than 45 days after a discharge meeting
one of the conditions specified in paragraphs (c)(1) through (3) of this
section. Special circumstances affecting the number of root cause
analyses and/or corrective action analyses are provided in paragraphs
(d)(1) through (5) of this section.
(1) If a single continuous discharge meets any of the conditions
specified in paragraphs (c)(1) through (3) of this section for 2 or more
consecutive 24-hour periods, a single root cause analysis and corrective
action analysis may be conducted.
(2) If a single discharge from a flare triggers a root cause
analysis based on
[[Page 345]]
more than one of the conditions specified in paragraphs (c)(1)(i)
through (iii) of this section, a single root cause analysis and
corrective action analysis may be conducted.
(3) If the discharge from a flare is the result of a planned startup
or shutdown of a refinery process unit or ancillary equipment connected
to the affected flare and the procedures in paragraph (a)(5) of this
section were followed, a root cause analysis and corrective action
analysis is not required; however, the discharge must be recorded as
described in Sec. 60.108a(c)(6) and reported as described in Sec.
60.108a(d)(5).
(4) If both the primary and secondary flare in a cascaded flare
system meet any of the conditions specified in paragraphs (c)(1)(i)
through (iii) of this section in the same 24-hour period, a single root
cause analysis and corrective action analysis may be conducted.
(5) Except as provided in paragraph (d)(4) of this section, if
discharges occur that meet any of the conditions specified in paragraphs
(c)(1) through (3) of this section for more than one affected facility
in the same 24-hour period, initial root cause analyses shall be
conducted for each affected facility. If the initial root cause analyses
indicate that the discharges have the same root cause(s), the initial
root cause analyses can be recorded as a single root cause analysis and
a single corrective action analysis may be conducted.
(e) Except as provided in paragraphs (f) and (g) of this section,
each owner or operator of a fuel gas combustion device, flare or sulfur
recovery plant subject to this subpart shall implement the corrective
action(s) identified in the corrective action analysis conducted
pursuant to paragraph (d) of this section in accordance with the
applicable requirements in paragraphs (e)(1) through (3) of this
section.
(1) All corrective action(s) must be implemented within 45 days of
the discharge for which the root cause and corrective action analyses
were required or as soon thereafter as practicable. If an owner or
operator concludes that corrective action should not be conducted, the
owner or operator shall record and explain the basis for that conclusion
no later than 45 days following the discharge as specified in Sec.
60.108a(c)(6)(ix).
(2) For corrective actions that cannot be fully implemented within
45 days following the discharge for which the root cause and corrective
action analyses were required, the owner or operator shall develop an
implementation schedule to complete the corrective action(s) as soon as
practicable.
(3) No later than 45 days following the discharge for which a root
cause and corrective action analyses were required, the owner or
operator shall record the corrective action(s) completed to date, and,
for action(s) not already completed, a schedule for implementation,
including proposed commencement and completion dates as specified in
Sec. 60.108a(c)(6)(x).
(f) Modified flares shall comply with the requirements of paragraphs
(c) through (e) of this section by November 11, 2015 or at startup of
the modified flare, whichever is later. Modified flares that were not
affected facilities subject to subpart J of this part prior to becoming
affected facilities under Sec. 60.100a shall comply with the
requirements of paragraph (h) of this section and the requirements of
Sec. 60.107a(a)(2) by November 11, 2015 or at startup of the modified
flare, whichever is later. Modified flares that were affected facilities
subject to subpart J of this part prior to becoming affected facilities
under Sec. 60.100a shall comply with the requirements of paragraph (h)
of this section and the requirements of Sec. 60.107a(a)(2) by November
13, 2012 or at startup of the modified flare, whichever is later, except
that modified flares that have accepted applicability of subpart J under
a federal consent decree shall comply with the subpart J requirements as
specified in the consent decree, but shall comply with the requirements
of paragraph (h) of this section and the requirements of Sec.
60.107a(a)(2) by no later than November 11, 2015.
(g) An affected flare subject to this subpart located in the Bay
Area Air Quality Management District (BAAQMD) may elect to comply with
both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as
an alternative to complying with the requirements of paragraphs (a)
through
[[Page 346]]
(e) of this section. An affected flare subject to this subpart located
in the South Coast Air Quality Management District (SCAQMD) may elect to
comply with SCAQMD Rule 1118 as an alternative to complying with the
requirements of paragraphs (a) through (e) of this section. The owner or
operator of an affected flare must notify the Administrator that the
flare is in compliance with BAAQMD Regulation 12, Rule 11 and BAAQMD
Regulation 12, Rule 12 or SCAQMD Rule 1118. The owner or operator of an
affected flare shall also submit the existing flare management plan to
the following address: U.S. Environmental Protection Agency, Office of
Air Quality Planning and Standards, Sector Policies and Programs
Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead,
109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic
copies in lieu of hard copies may also be submitted to
[email protected].
(h) Each owner or operator shall not burn in any affected flare any
fuel gas that contains H2S in excess of 162 ppmv determined
hourly on a 3-hour rolling average basis. The combustion in a flare of
process upset gases or fuel gas that is released to the flare as a
result of relief valve leakage or other emergency malfunctions is exempt
from this limit.
(i) Each owner or operator of a delayed coking unit shall depressure
each coke drum to 5 lb per square inch gauge (psig) or less prior to
discharging the coke drum steam exhaust to the atmosphere. Until the
coke drum pressure reaches 5 psig, the coke drum steam exhaust must be
managed in an enclosed blowdown system and the uncondensed vapor must
either be recovered (e.g., sent to the delayed coking unit
fractionators) or vented to the fuel gas system, a fuel gas combustion
device or a flare.
(j) Alternative means of emission limitation. (1) Each owner or
operator subject to the provisions of this section may apply to the
Administrator for a determination of equivalence for any means of
emission limitation that achieves a reduction in emissions of a
specified pollutant at least equivalent to the reduction in emissions of
that pollutant achieved by the controls required in this section.
(2) Determination of equivalence to the design, equipment, work
practice or operational requirements of this section will be evaluated
by the following guidelines:
(i) Each owner or operator applying for a determination of
equivalence shall be responsible for collecting and verifying test data
to demonstrate the equivalence of the alternative means of emission
limitation.
(ii) For each affected facility for which a determination of
equivalence is requested, the emission reduction achieved by the design,
equipment, work practice or operational requirements shall be
demonstrated.
(iii) For each affected facility for which a determination of
equivalence is requested, the emission reduction achieved by the
alternative means of emission limitation shall be demonstrated.
(iv) Each owner or operator applying for a determination of
equivalence to a work practice standard shall commit in writing to work
practice(s) that provide for emission reductions equal to or greater
than the emission reductions achieved by the required work practice.
(v) The Administrator will compare the demonstrated emission
reduction for the alternative means of emission limitation to the
demonstrated emission reduction for the design, equipment, work practice
or operational requirements and, if applicable, will consider the
commitment in paragraph (j)(2)(iv) of this section.
(vi) The Administrator may condition the approval of the alternative
means of emission limitation on requirements that may be necessary to
ensure operation and maintenance to achieve the same emissions reduction
as the design, equipment, work practice or operational requirements.
(3) An owner or operator may offer a unique approach to demonstrate
the equivalence of any equivalent means of emission limitation.
(4) Approval of the application for equivalence to the design,
equipment, work practice or operational requirements of this section
will be evaluated by the following guidelines:
[[Page 347]]
(i) After a request for determination of equivalence is received,
the Administrator will publish a notice in the Federal Register and
provide the opportunity for public hearing if the Administrator judges
that the request may be approved.
(ii) After notice and opportunity for public hearing, the
Administrator will determine the equivalence of a means of emission
limitation and will publish the determination in the Federal Register.
(iii) Any equivalent means of emission limitations approved under
this section shall constitute a required work practice, equipment,
design or operational standard within the meaning of section 111(h)(1)
of the CAA.
(5) Manufacturers of equipment used to control emissions may apply
to the Administrator for determination of equivalence for any
alternative means of emission limitation that achieves a reduction in
emissions achieved by the equipment, design and operational requirements
of this section. The Administrator will make an equivalence
determination according to the provisions of paragraphs (j)(2) through
(4) of this section.
[77 FR 56467, Sep. 12, 2012]
Sec. 60.104a Performance tests.
(a) The owner or operator shall conduct a performance test for each
FCCU, FCU, sulfur recovery plant and fuel gas combustion device to
demonstrate initial compliance with each applicable emissions limit in
Sec. 60.102a and conduct a performance test for each flare to
demonstrate initial compliance with the H2S concentration
requirement in Sec. 60.103a(h) according to the requirements of Sec.
60.8. The notification requirements of Sec. 60.8(d) apply to the
initial performance test and to subsequent performance tests required by
paragraph (b) of this section (or as required by the Administrator), but
does not apply to performance tests conducted for the purpose of
obtaining supplemental data because of continuous monitoring system
breakdowns, repairs, calibration checks and zero and span adjustments.
(b) The owner or operator of a FCCU or FCU that elects to monitor
control device operating parameters according to the requirements in
Sec. 60.105a(b), to use bag leak detectors according to the
requirements in Sec. 60.105a(c), or to use COMS according to the
requirements in Sec. 60.105a(e) shall conduct a PM performance test at
least annually (i.e., once per calendar year, with an interval of at
least 8 months but no more than 16 months between annual tests) and
furnish the Administrator a written report of the results of each test.
(c) In conducting the performance tests required by this subpart (or
as requested by the Administrator), the owner or operator shall use the
test methods in 40 CFR part 60, Appendices A-1 through A-8 or other
methods as specified in this section, except as provided in Sec.
60.8(b).
(d) The owner or operator shall determine compliance with the PM,
NOX, SO2, and CO emissions limits in Sec.
60.102a(b) for FCCU and FCU using the following methods and procedures:
(1) Method 1 of appendix A-1 to part 60 for sample and velocity
traverses.
(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric
flow rate.
(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis.
The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 3B of appendix A-2 to part 60.
(4) Method 5, 5B, or 5F of appendix A-3 to part 60 for determining
PM emissions and associated moisture content from a FCCU or FCU without
a wet scrubber subject to the emissions limit in Sec. 63.102a(b)(1).
Use Method 5 or 5B of appendix A-3 to part 60 for determining PM
emissions and associated moisture content from a FCCU or FCU with a wet
scrubber subject to the emissions limit in Sec. 63.102a(b)(1).
(i) The PM performance test consists of 3 valid test runs; the
duration of each test run must be no less than 60 minutes.
(ii) The emissions rate of PM (EPM) is computed for each
run using Equation 5 of this section:
[[Page 348]]
[GRAPHIC] [TIFF OMITTED] TR12SE12.003
Where:
E = Emission rate of PM, g/kg (lb/1,000 lb) of coke burn-off;
cs = Concentration of total PM, grams per dry standard cubic
meter (g/dscm) (gr/dscf);
Qsd = Volumetric flow rate of effluent gas, dry standard
cubic meters per hour (dry standard cubic feet per hour);
Rc = Coke burn-off rate, kilograms per hour (kg/hr) [lb per
hour (lb/hr)] coke; and
K = Conversion factor, 1.0 grams per gram (7,000 grains per lb).
(iii) The coke burn-off rate (Rc) is computed for each
run using Equation 6 of this section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.004
Where:
Rc = Coke burn-off rate, kg/hr (lb/hr);
Qr = Volumetric flow rate of exhaust gas from FCCU
regenerator or fluid coking burner before any emissions
control or energy recovery system that burns auxiliary fuel,
dry standard cubic meters per minute (dscm/min) [dry standard
cubic feet per minute (dscf/min)];
Qa = Volumetric flow rate of air to FCCU regenerator or fluid
coking burner, as determined from the unit's control room
instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air to
FCCU regenerator or fluid coking unit, as determined from the
unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide (CO2) concentration in FCCU
regenerator or fluid coking burner exhaust, percent by volume
(dry basis);
%CO = CO concentration in FCCU regenerator or fluid coking burner
exhaust, percent by volume (dry basis);
%O2 = O2 concentration in FCCU regenerator or
fluid coking burner exhaust, percent by volume (dry basis);
%Ooxy = O2 concentration in O2 enriched
air stream inlet to the FCCU regenerator or fluid coking
burner, percent by volume (dry basis);
K1 = Material balance and conversion factor, 0.2982 (kg-min)/
(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)];
K2 = Material balance and conversion factor, 2.088 (kg-min)/
(hr-dscm) [0.1303 (lb-min)/(hr-dscf)]; and
K3 = Material balance and conversion factor, 0.0994 (kg-min)/
(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].
(iv) During the performance test, the volumetric flow rate of
exhaust gas from catalyst regenerator (Qr) before any
emission control or energy recovery system that burns auxiliary fuel is
measured using Method 2 of appendix A-1 to part 60.
(v) For subsequent calculations of coke burn-off rates or exhaust
gas flow rates, the volumetric flow rate of Qr is calculated
using average exhaust gas concentrations as measured by the monitors
required in Sec. 60.105a(b)(2), if applicable, using Equation 7 of this
section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.005
[[Page 349]]
Where:
Qr = Volumetric flow rate of exhaust gas from FCCU
regenerator or fluid coking burner before any emission control
or energy recovery system that burns auxiliary fuel, dscm/min
(dscf/min);
Qa = Volumetric flow rate of air to FCCU regenerator or fluid
coking burner, as determined from the unit's control room
instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air to
FCCU regenerator or fluid coking unit, as determined from the
unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in FCCU regenerator or
fluid coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration FCCU regenerator or fluid coking burner exhaust,
percent by volume (dry basis). When no auxiliary fuel is
burned and a continuous CO monitor is not required in
accordance with Sec. 60.105a(h)(3), assume %CO to be zero;
%O2 = O2 concentration in FCCU regenerator or
fluid coking burner exhaust, percent by volume (dry basis);
and
%Ooxy = O2 concentration in O2 enriched
air stream inlet to the FCCU regenerator or fluid coking
burner, percent by volume (dry basis).
(5) Method 6, 6A, or 6C of appendix A-4 to part 60 for moisture
content and for the concentration of SO2; the duration of
each test run must be no less than 4 hours. The method ANSI/ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method 6
or 6A of appendix A-4 to part 60.
(6) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for
moisture content and for the concentration of NOX calculated
as nitrogen dioxide (NO2); the duration of each test run must
be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, ``Flue and
Exhaust Gas Analyses,'' (incorporated by reference--see Sec. 60.17) is
an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part
60.
(7) Method 10, 10A, or 10B of appendix A-4 to part 60 for moisture
content and for the concentration of CO. The sampling time for each run
must be 60 minutes.
(8) The owner or operator shall adjust PM, NOX,
SO2 and CO pollutant concentrations to 0-percent excess air
or 0-percent O2 using Equation 8 of this section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.006
Where:
Cadj = pollutant concentration adjusted to 0-percent excess
air or O2, parts per million (ppm) or g/dscm;
Cmeas = pollutant concentration measured on a dry basis, ppm
or g/dscm;
20.9c = 20.9 percent O2-0.0 percent O2
(defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry basis,
percent.
(e) The owner or operator of a FCCU or FCU that is controlled by an
electrostatic precipitator or wet scrubber and that is subject to
control device operating parameter limits in Sec. 60.102a(c) shall
establish the limits based on the performance test results according to
the following procedures:
(1) Reduce the parameter monitoring data to hourly averages for each
test run;
(2) Determine the hourly average operating limit for each required
parameter as the average of the three test runs.
(f) The owner or operator of an FCCU or FCU that uses cyclones to
comply with the PM per coke burn-off emissions limit in Sec.
60.102a(b)(1) shall establish a site-specific opacity operating limit
according to the procedures in paragraphs (f)(1) through (3) of this
section.
(1) Collect COMS data every 10 seconds during the entire period of
the PM performance test and reduce the data to 6-minute averages.
(2) Determine and record the hourly average opacity from all the 6-
minute averages.
(3) Compute the site-specific limit using Equation 9 of this
section:
[[Page 350]]
[GRAPHIC] [TIFF OMITTED] TR12SE12.007
Where:
Opacity limit = Maximum permissible 3-hour average opacity, percent, or
10 percent, whichever is greater;
Opacityst = Hourly average opacity measured during the source
test, percent; and
PMEmRst = PM emission rate measured during the source test,
lb/1,000 lb coke burn.
(g) The owner or operator of a FCCU or FCU that is exempt from the
requirement to install and operate a CO CEMS pursuant to Sec.
60.105a(h)(3) and that is subject to control device operating parameter
limits in Sec. 60.102a(c) shall establish the limits based on the
performance test results using the procedures in paragraphs (g)(1) and
(2) of this section.
(1) Reduce the temperature and O2 concentrations from the
parameter monitoring systems to hourly averages for each test run.
(2) Determine the operating limit for temperature and O2
concentrations as the average of the average temperature and
O2 concentration for the three test runs.
(h) The owner or operator shall determine compliance with the
SO2 emissions limits for sulfur recovery plants in Sec.
60.102a(f)(1)(i) and (f)(2)(i) and the reduced sulfur compounds and
H2S emissions limits for sulfur recovery plants in Sec.
60.102a(f)(1)(ii), (f)(1)(iii), (f)(2)(ii), and (f)(2)(iii) using the
following methods and procedures:
(1) Method 1 of appendix A-1 to part 60 for sample and velocity
traverses.
(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric
flow rate.
(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis.
The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 3B of appendix A-2 to part 60.
(4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the
SO2 concentration. The method ANSI/ASME PTC 19.10-1981,
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see Sec.
60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-
4 to part 60.
(5) Method 15 or 15A of appendix A-5 to part 60 or Method 16 of
appendix A-6 to part 60 to determine the reduced sulfur compounds and
H2S concentrations. The method ANSI/ASME PTC 19.10-1981,
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see Sec.
60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to
part 60.
(i) Each run consists of 16 samples taken over a minimum of 3 hours.
(ii) The owner or operator shall calculate the average
H2S concentration after correcting for moisture and
O2 as the arithmetic average of the H2S
concentration for each sample during the run (ppmv, dry basis, corrected
to 0 percent excess air).
(iii) The owner or operator shall calculate the SO2
equivalent for each run after correcting for moisture and O2
as the arithmetic average of the SO2 equivalent of reduced
sulfur compounds for each sample during the run (ppmv, dry basis,
corrected to 0 percent excess air).
(iv) The owner or operator shall use Equation 8 of this section to
adjust pollutant concentrations to 0-percent O2 or 0- percent
excess air.
(6) If oxygen or oxygen-enriched air is used in the Claus burner and
either Equation 1 or 2 of this subpart is used to determine the
applicable emissions limit, determine the average O2
concentration of the air/oxygen mixture supplied to the Claus burner, in
percent by volume (dry basis), for the performance test using all hourly
average O2 concentrations determined during the test runs
using the procedures in Sec. 60.106a(a)(5) or (6).
(i) The owner or operator shall determine compliance with the
SO2 and NOX emissions limits in Sec. 60.102a(g)
for a fuel gas combustion device according to the following test methods
and procedures:
(1) Method 1 of appendix A-1 to part 60 for sample and velocity
traverses;
[[Page 351]]
(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric
flow rate;
(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis.
The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 3B of appendix A-2 to part 60;
(4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the
SO2 concentration. The method ANSI/ASME PTC 19.10-1981,
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see Sec.
60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-
4 to part 60.
(i) The performance test consists of 3 valid test runs; the duration
of each test run must be no less than 1 hour.
(ii) If a single fuel gas combustion device having a common source
of fuel gas is monitored as allowed under Sec. 60.107a(a)(1)(v), only
one performance test is required. That is, performance tests are not
required when a new affected fuel gas combustion device is added to a
common source of fuel gas that previously demonstrated compliance.
(5) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for
moisture content and for the concentration of NOX calculated
as NO2; the duration of each test run must be no less than 4
hours. The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas
Analyses,'' (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60.
(6) For process heaters with a rated heat capacity between 40 and
100 MMBtu/hr that elect to demonstrate continuous compliance with a
maximum excess oxygen limit as provided in Sec. 60.107a(c)(6) or
(d)(8), the owner or operator shall establish the O2
operating limit or O2 operating curve based on the
performance test results according to the requirements in paragraph
(i)(6)(i) or (ii) of this section, respectively.
(i) If a single O2 operating limit will be used:
(A) Conduct the performance test following the methods provided in
paragraphs (i)(1), (2), (3) and (5) of this section when the process
heater is firing at no less than 70 percent of the rated heat capacity.
For co-fired process heaters, conduct at least one of the test runs
while the process heater is being supplied by both fuel gas and fuel oil
and conduct at least one of the test runs while the process heater is
being supplied solely by fuel gas.
(B) Each test will consist of three test runs. Calculate the
NOX concentration for the performance test as the average of
the NOX concentrations from each of the three test runs. If
the NOX concentration for the performance test is less than
or equal to the numerical value of the applicable NOX
emissions limit (regardless of averaging time), then the test is
considered to be a valid test.
(C) Determine the average O2 concentration for each test
run of a valid test.
(D) Calculate the O2 operating limit as the average
O2 concentration of the three test runs from a valid test.
(ii) If an O2 operating curve will be used:
(A) Conduct a performance test following the methods provided in
paragraphs (i)(1), (2), (3) and (5) of this section at a representative
condition for each operating range for which different O2
operating limits will be established. Different operating conditions may
be defined as different firing rates (e.g., above 50 percent of rated
heat capacity and at or below 50 percent of rated heat capacity) and/or,
for co-fired process heaters, different fuel mixtures (e.g., primarily
gas fired, primarily oil fired, and equally co-fired, i.e.,
approximately 50 percent of the input heating value is from fuel gas and
approximately 50 percent of the input heating value is from fuel oil).
Performance tests for different operating ranges may be conducted at
different times.
(B) Each test will consist of three test runs. Calculate the
NOX concentration for the performance test as the average of
the NOX concentrations from each of the three test runs. If
the NOX concentration for the performance test is less than
or equal to the numerical value of the applicable NOX
emissions limit (regardless of averaging time),
[[Page 352]]
then the test is considered to be a valid test.
(C) If an operating curve is developed for different firing rates,
conduct at least one test when the process heater is firing at no less
than 70 percent of the rated heat capacity and at least one test under
turndown conditions (i.e., when the process heater is firing at 50
percent or less of the rated heat capacity). If O2 operating
limits are developed for co-fired process heaters based only on overall
firing rates (and not by fuel mixtures), conduct at least one of the
test runs for each test while the process heater is being supplied by
both fuel gas and fuel oil and conduct at least one of the test runs
while the process heater is being supplied solely by fuel gas.
(D) Determine the average O2 concentration for each test
run of a valid test.
(E) Calculate the O2 operating limit for each operating
range as the average O2 concentration of the three test runs
from a valid test conducted at the representative conditions for that
given operating range.
(F) Identify the firing rates for which the different operating
limits apply. If only two operating limits are established based on
firing rates, the O2 operating limits established when the
process heater is firing at no less than 70 percent of the rated heat
capacity must apply when the process heater is firing above 50 percent
of the rated heat capacity and the O2 operating limits
established for turndown conditions must apply when the process heater
is firing at 50 percent or less of the rated heat capacity.
(G) Operating limits associated with each interval will be valid for
2 years or until another operating limit is established for that
interval based on a more recent performance test specific for that
interval, whichever occurs first. Owners and operators must use the
operating limits determined for a given interval based on the most
recent performance test conducted for that interval.
(7) The owner or operator of a process heater complying with a
NOX limit in terms of lb/MMBtu as provided in Sec.
60.102a(g)(2)(i)(B), (g)(2)(ii)(B), (g)(2)(iii)(B) or (g)(2)(iv)(B) or a
process heater with a rated heat capacity between 40 and 100 MMBtu/hr
that elects to demonstrate continuous compliance with a maximum excess
O2 limit, as provided in Sec. 60.107a(c)(6) or (d)(8), shall
determine heat input to the process heater in MMBtu/hr during each
performance test run by measuring fuel gas flow rate, fuel oil flow rate
(as applicable) and heating value content according to the methods
provided in Sec. 60.107a(d)(5), (d)(6), and (d)(4) or (d)(7),
respectively.
(8) The owner or operator shall use Equation 8 of this section to
adjust pollutant concentrations to 0-percent O2 or 0- percent
excess air.
(j) The owner or operator shall determine compliance with the
applicable H2S emissions limit in Sec. 60.102a(g)(1) for a
fuel gas combustion device or the concentration requirement in Sec.
60.103a(h) for a flare according to the following test methods and
procedures:
(1)--(3) [Reserved]
(4) EPA Method 11, 15 or 15A of appendix A-5 to part 60 or EPA
Method 16 of appendix A-6 to part 60 for determining the H2S
concentration for affected facilities using an H2S monitor as
specified in Sec. 60.107a(a)(2). The method ANSI/ASME PTC 19.10-1981
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 15A of appendix A-5 to part 60. The owner or
operator may demonstrate compliance based on the mixture used in the
fuel gas combustion device or flare or for each individual fuel gas
stream used in the fuel gas combustion device or flare.
(i) For Method 11 of appendix A-5 to part 60, the sampling time and
sample volume must be at least 10 minutes and 0.010 dscm (0.35 dscf).
Two samples of equal sampling times must be taken at about 1-hour
intervals. The arithmetic average of these two samples constitutes a
run. For most fuel gases, sampling times exceeding 20 minutes may result
in depletion of the collection solution, although fuel gases containing
low concentrations of H2S may necessitate sampling for longer
periods of time.
(ii) For Method 15 of appendix A-5 to part 60, at least three
injects over a 1-hour period constitutes a run.
[[Page 353]]
(iii) For Method 15A of appendix A-5 to part 60, a 1-hour sample
constitutes a run. The method ANSI/ASME PTC 19.10-1981, ``Flue and
Exhaust Gas Analyses,'' (incorporated by reference--see Sec. 60.17) is
an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.
(iv) If monitoring is conducted at a single point in a common source
of fuel gas as allowed under Sec. 60.107a(a)(2)(iv), only one
performance test is required. That is, performance tests are not
required when a new affected fuel gas combustion device or flare is
added to a common source of fuel gas that previously demonstrated
compliance.
[73 FR 35867, June 24, 2008, as amended at 77 FR 56470, Sep. 12, 2012;
80 FR 75231, Dec. 1, 2015]
Sec. 60.105a Monitoring of emissions and operations for fluid catalytic
cracking units (FCCU) and fluid coking units (FCU).
(a) FCCU and FCU subject to PM emissions limit. Each owner or
operator subject to the provisions of this subpart shall monitor each
FCCU and FCU subject to the PM emissions limit in Sec. 60.102a(b)(1)
according to the requirements in paragraph (b), (c), (d), or (e) of this
section.
(b) Control device operating parameters. Each owner or operator of a
FCCU or FCU subject to the PM per coke burn-off emissions limit in Sec.
60.102a(b)(1) that uses a control device other than fabric filter or
cyclone shall comply with the requirements in paragraphs (b)(1) and (2)
of this section.
(1) The owner or operator shall install, operate and maintain
continuous parameter monitor systems (CPMS) to measure and record
operating parameters for each control device according to the applicable
requirements in paragraphs (b)(1)(i) through (v) of this section.
(i) For units controlled using an electrostatic precipitator, the
owner or operator shall use CPMS to measure and record the hourly
average total power input and secondary current to the entire system.
(ii) For units controlled using a wet scrubber, the owner or
operator shall use CPMS to measure and record the hourly average
pressure drop, liquid feed rate, and exhaust gas flow rate. As an
alternative to a CPMS, the owner or operator must comply with the
requirements in either paragraph (b)(1)(ii)(A) or (B) of this section.
(A) As an alternative to pressure drop, the owner or operator of a
jet ejector type wet scrubber or other type of wet scrubber equipped
with atomizing spray nozzles must conduct a daily check of the air or
water pressure to the spray nozzles and record the results of each
check. Faulty (e.g., leaking or plugged) air or water lines must be
repaired within 12 hours of identification of an abnormal pressure
reading.
(B) As an alternative to exhaust gas flow rate, the owner or
operator shall comply with the approved alternative for monitoring
exhaust gas flow rate in 40 CFR 63.1573(a) of the National Emission
Standards for Hazardous Air Pollutants for Petroleum Refineries:
Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery
Units.
(iii) The owner or operator shall install, operate, and maintain
each CPMS according to the manufacturer's specifications and
requirements.
(iv) The owner or operator shall determine and record the average
coke burn-off rate and hours of operation for each FCCU or FCU using the
procedures in Sec. 60.104a(d)(4)(iii).
(v) If you use a control device other than an electrostatic
precipitator, wet scrubber, fabric filter, or cyclone, you may request
approval to monitor parameters other than those required in paragraph
(b)(1) of this section by submitting an alternative monitoring plan to
the Administrator. The request must include the information in
paragraphs (b)(1)(v)(A) through (E) of this section.
(A) A description of each affected facility and the parameter(s) to
be monitored to determine whether the affected facility will
continuously comply with the emission limitations and an explanation of
the criteria used to select the parameter(s).
(B) A description of the methods and procedures that will be used to
demonstrate that the parameter(s) can be used to determine whether the
affected facility will continuously comply with
[[Page 354]]
the emission limitations and the schedule for this demonstration. The
owner or operator must certify that an operating limit will be
established for the monitored parameter(s) that represents the
conditions in existence when the control device is being properly
operated and maintained to meet the emission limitation.
(C) The frequency and content of the recordkeeping, recording, and
reporting, if monitoring and recording are not continuous. The owner or
operator also must include the rationale for the proposed monitoring,
recording, and reporting requirements.
(D) Supporting calculations.
(E) Averaging time for the alternative operating parameter.
(2) For use in determining the coke burn-off rate for an FCCU or
FCU, the owner or operator shall install, operate, calibrate, and
maintain an instrument for continuously monitoring the concentrations of
CO2, O2 (dry basis), and if needed, CO in the
exhaust gases prior to any control or energy recovery system that burns
auxiliary fuels. A CO monitor is not required for determining coke burn-
off rate when no auxiliary fuel is burned and a continuous CO monitor is
not required in accordance with paragraph (h)(3) of this section.
(i) The owner or operator shall install, operate, and maintain each
CO2 and O2 monitor according to Performance
Specification 3 of appendix B to this part.
(ii) The owner or operator shall conduct performance evaluations of
each CO2 and O2 monitor according to the
requirements in Sec. 60.13(c) and Performance Specification 3 of
appendix B to this part. The owner or operator shall use Method 3 of
appendix A-3 to this part for conducting the relative accuracy
evaluations.
(iii) If a CO monitor is required, the owner or operator shall
install, operate, and maintain each CO monitor according to Performance
Specification 4 or 4A of appendix B to this part. If this CO monitor
also serves to demonstrate compliance with the CO emissions limit in
Sec. 60.102a(b)(4), the span value for this instrument is 1,000 ppm;
otherwise, the span value for this instrument should be set at
approximately 2 times the typical CO concentration expected in the FCCU
of FCU flue gas prior to any emission control or energy recovery system
that burns auxiliary fuels.
(iv) If a CO monitor is required, the owner or operator shall
conduct performance evaluations of each CO monitor according to the
requirements in Sec. 60.13(c) and Performance Specification 4 of
appendix B to this part. The owner or operator shall use Method 10, 10A,
or 10B of appendix A-3 to this part for conducting the relative accuracy
evaluations.
(v) The owner or operator shall comply with the quality assurance
requirements of procedure 1 of appendix F to this part, including
quarterly accuracy determinations for CO2 and CO monitors,
annual accuracy determinations for O2 monitors, and daily
calibration drift tests.
(c) Bag leak detection systems. Each owner or operator shall
install, operate, and maintain a bag leak detection system for each
baghouse or similar fabric filter control device that is used to comply
with the PM per coke burn-off emissions limit in Sec. 60.102a(b)(1) for
an FCCU or FCU according to paragraph (c)(1) of this section; prepare
and operate by a site-specific monitoring plan according to paragraph
(c)(2) of this section; take action according to paragraph (c)(3) of
this section; and record information according to paragraph (c)(4) of
this section.
(1) Each bag leak detection system must meet the specifications and
requirements in paragraphs (c)(1)(i) through (viii) of this section.
(i) The bag leak detection system must be certified by the
manufacturer to be capable of detecting PM emissions at concentrations
of 0.00044 grains per actual cubic foot or less.
(ii) The bag leak detection system sensor must provide output of
relative PM loadings. The owner or operator shall continuously record
the output from the bag leak detection system using electronic or other
means (e.g., using a strip chart recorder or a data logger).
(iii) The bag leak detection system must be equipped with an alarm
system that will sound when the system
[[Page 355]]
detects an increase in relative particulate loading over the alarm set
point established according to paragraph (c)(1)(iv) of this section, and
the alarm must be located such that it can be heard by the appropriate
plant personnel.
(iv) In the initial adjustment of the bag leak detection system, the
owner or operator must establish, at a minimum, the baseline output by
adjusting the sensitivity (range) and the averaging period of the
device, the alarm set points, and the alarm delay time.
(v) Following initial adjustment, the owner or operator shall not
adjust the averaging period, alarm set point, or alarm delay time
without approval from the Administrator or delegated authority except as
provided in paragraph (c)(1)(vi) of this section.
(vi) Once per quarter, the owner or operator may adjust the
sensitivity of the bag leak detection system to account for seasonal
effects, including temperature and humidity, according to the procedures
identified in the site-specific monitoring plan required by paragraph
(c)(2) of this section.
(vii) The owner or operator shall install the bag leak detection
sensor downstream of the baghouse and upstream of any wet scrubber.
(viii) Where multiple detectors are required, the system's
instrumentation and alarm may be shared among detectors.
(2) The owner or operator shall develop and submit to the
Administrator for approval a site-specific monitoring plan for each
baghouse and bag leak detection system. The owner or operator shall
operate and maintain each baghouse and bag leak detection system
according to the site-specific monitoring plan at all times. Each
monitoring plan must describe the items in paragraphs (c)(2)(i) through
(vii) of this section.
(i) Installation of the bag leak detection system;
(ii) Initial and periodic adjustment of the bag leak detection
system, including how the alarm set-point will be established;
(iii) Operation of the bag leak detection system, including quality
assurance procedures;
(iv) How the bag leak detection system will be maintained, including
a routine maintenance schedule and spare parts inventory list;
(v) How the bag leak detection system output will be recorded and
stored;
(vi) Procedures as specified in paragraph (c)(3) of this section. In
approving the site-specific monitoring plan, the Administrator or
delegated authority may allow owners and operators more than 3 hours to
alleviate a specific condition that causes an alarm if the owner or
operator identifies in the monitoring plan this specific condition as
one that could lead to an alarm, adequately explains why it is not
feasible to alleviate this condition within 3 hours of the time the
alarm occurs, and demonstrates that the requested time will ensure
alleviation of this condition as expeditiously as practicable; and
(vii) How the baghouse system will be operated and maintained,
including monitoring of pressure drop across baghouse cells and
frequency of visual inspections of the baghouse interior and baghouse
components such as fans and dust removal and bag cleaning mechanisms.
(3) For each bag leak detection system, the owner or operator shall
initiate procedures to determine the cause of every alarm within 1 hour
of the alarm. Except as provided in paragraph (c)(2)(vi) of this
section, the owner or operator shall alleviate the cause of the alarm
within 3 hours of the alarm by taking whatever action(s) are necessary.
Actions may include, but are not limited to the following:
(i) Inspecting the baghouse for air leaks, torn or broken bags or
filter media, or any other condition that may cause an increase in
particulate emissions;
(ii) Sealing off defective bags or filter media;
(iii) Replacing defective bags or filter media or otherwise
repairing the control device;
(iv) Sealing off a defective baghouse compartment;
(v) Cleaning the bag leak detection system probe or otherwise
repairing the bag leak detection system; or
(vi) Shutting down the process producing the particulate emissions.
[[Page 356]]
(4) The owner or operator shall maintain records of the information
specified in paragraphs (c)(4)(i) through (iii) of this section for each
bag leak detection system.
(i) Records of the bag leak detection system output;
(ii) Records of bag leak detection system adjustments, including the
date and time of the adjustment, the initial bag leak detection system
settings, and the final bag leak detection system settings; and
(iii) The date and time of all bag leak detection system alarms, the
time that procedures to determine the cause of the alarm were initiated,
the cause of the alarm, an explanation of the actions taken, the date
and time the cause of the alarm was alleviated, and whether the alarm
was alleviated within 3 hours of the alarm.
(d) Continuous emissions monitoring systems (CEMS). An owner or
operator subject to the PM concentration emission limit (in gr/dscf) in
Sec. 60.102a(b)(1) for an FCCU or FCU shall install, operate,
calibrate, and maintain an instrument for continuously monitoring and
recording the concentration (0 percent excess air) of PM in the exhaust
gases prior to release to the atmosphere. The monitor must include an
O2 monitor for correcting the data for excess air.
(1) The owner or operator shall install, operate, and maintain each
PM monitor according to Performance Specification 11 of appendix B to
part 60. The span value of this PM monitor is 0.08 gr/dscf PM.
(2) The owner or operator shall conduct performance evaluations of
each PM monitor according to the requirements in Sec. 60.13(c) and
Performance Specification 11 of appendix B to part 60. The owner or
operator shall use EPA Methods 5 or 5I of appendix A-3 to part 60 or
Method 17 of appendix A-6 to part 60 for conducting the relative
accuracy evaluations.
(3) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to part 60. The span value of this O2 monitor must
be selected between 10 and 25 percent, inclusive.
(4) The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 3 of appendix B to part 60.
Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for
conducting the relative accuracy evaluations. The method ANSI/ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B of appendix A-2 to part 60.
(5) The owner or operator shall comply with the quality assurance
requirements of Procedure 2 of appendix B to part 60 for each PM CEMS
and Procedure 1 of appendix F to part 60 for each O2 monitor,
including quarterly accuracy determinations for each PM monitor, annual
accuracy determinations for each O2 monitor, and daily
calibration drift tests.
(e) Alternative monitoring option for FCCU and FCU--COMS. Each owner
or operator of an FCCU or FCU that uses cyclones to comply with the PM
emission limit in Sec. 60.102a(b)(1) shall monitor the opacity of
emissions according to the requirements in paragraphs (e)(1) through (3)
of this section.
(1) The owner or operator shall install, operate, and maintain an
instrument for continuously monitoring and recording the opacity of
emissions from the FCCU or the FCU exhaust vent.
(2) The owner or operator shall install, operate, and maintain each
COMS according to Performance Specification 1 of appendix B to part 60.
The instrument shall be spanned at 20 to 60 percent opacity.
(3) The owner or operator shall conduct performance evaluations of
each COMS according to Sec. 60.13(c) and Performance Specification 1 of
appendix B to part 60.
(f) FCCU and FCU subject to NOX limit. Each owner or operator
subject to the NOX emissions limit in Sec. 60.102a(b)(2) for
an FCCU or FCU shall install, operate, calibrate, and maintain an
instrument for continuously monitoring and recording the concentration
by volume (dry basis, 0 percent excess air) of NOX emissions
into the atmosphere. The monitor must include an O2 monitor
for correcting the data for excess air.
(1) The owner or operator shall install, operate, and maintain each
NOX
[[Page 357]]
monitor according to Performance Specification 2 of appendix B to part
60. The span value of this NOX monitor is 200 ppmv
NOX.
(2) The owner or operator shall conduct performance evaluations of
each NOX monitor according to the requirements in Sec.
60.13(c) and Performance Specification 2 of appendix B to part 60. The
owner or operator shall use Methods 7, 7A, 7C, 7D, or 7E of appendix A-4
to part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 7 or 7C of appendix A-4 to part 60.
(3) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to part 60. The span value of this O2 monitor must
be selected between 10 and 25 percent, inclusive.
(4) The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 3 of appendix B to part 60.
Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for
conducting the relative accuracy evaluations. The method ANSI/ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B of appendix A-2 to part 60.
(5) The owner or operator shall comply with the quality assurance
requirements of Procedure 1 of appendix F to part 60 for each
NOX and O2 monitor, including quarterly accuracy
determinations for NOX monitors, annual accuracy
determinations for O2 monitors, and daily calibration drift
tests.
(g) FCCU and FCU subject to SO2 limit. The owner or operator subject
to the SO2 emissions limit in Sec. 60.102a(b)(3) for an FCCU
or an FCU shall install, operate, calibrate, and maintain an instrument
for continuously monitoring and recording the concentration by volume
(dry basis, corrected to 0 percent excess air) of SO2
emissions into the atmosphere. The monitor shall include an
O2 monitor for correcting the data for excess air.
(1) The owner or operator shall install, operate, and maintain each
SO2 monitor according to Performance Specification 2 of
appendix B to part 60. The span value of this SO2 monitor is
200 ppmv SO2.
(2) The owner or operator shall conduct performance evaluations of
each SO2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 2 of appendix B to part 60. The
owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to part
60 for conducting the relative accuracy evaluations. The method ANSI /
ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method 6
or 6A of appendix A-4 to part 60.
(3) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to part 60. The span value of this O2 monitor must
be selected between 10 and 25 percent, inclusive.
(4) The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 3 of appendix B to part 60.
Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for
conducting the relative accuracy evaluations. The method ANSI/ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B of appendix A-2 to part 60.
(5) The owner or operator shall comply with the quality assurance
requirements in Procedure 1 of appendix F to part 60 for each
SO2 and O2 monitor, including quarterly accuracy
determinations for SO2 monitors, annual accuracy
determinations for O2 monitors, and daily calibration drift
tests.
(h) FCCU and fluid coking units subject to CO emissions limit.
Except as specified in paragraph (h)(3) of this section, the owner or
operator shall install, operate, calibrate, and maintain an instrument
for continuously monitoring and recording the concentration by volume
(dry basis) of CO emissions into the atmosphere from each FCCU and FCU
subject to the CO emissions limit in Sec. 60.102a(b)(4).
[[Page 358]]
(1) The owner or operator shall install, operate, and maintain each
CO monitor according to Performance Specification 4 or 4A of appendix B
to this part. The span value for this instrument is 1,000 ppmv CO.
(2) The owner or operator shall conduct performance evaluations of
each CO monitor according to the requirements in Sec. 60.13(c) and
Performance Specification 4 or 4A of appendix B to part 60. The owner or
operator shall use Methods 10, 10A, or 10B of appendix A-4 to part 60
for conducting the relative accuracy evaluations.
(3) A CO CEMS need not be installed if the owner or operator
demonstrates that all hourly average CO emissions are and will remain
less than 50 ppmv (dry basis) corrected to 0 percent excess air. The
Administrator may revoke this exemption from monitoring upon a
determination that CO emissions on an hourly average basis have exceeded
50 ppmv (dry basis) corrected to 0 percent excess air, in which case a
CO CEMS shall be installed within 180 days.
(i) The demonstration shall consist of continuously monitoring CO
emissions for 30 days using an instrument that meets the requirements of
Performance Specification 4 or 4A of appendix B to this part. The span
value shall be 100 ppmv CO instead of 1,000 ppmv, and the relative
accuracy limit shall be 10 percent of the average CO emissions or 5 ppmv
CO, whichever is greater. For instruments that are identical to Method
10 of appendix A-4 to this part and employ the sample conditioning
system of Method 10A of appendix A-4 to this part, the alternative
relative accuracy test procedure in section 10.1 of Performance
Specification 2 of appendix B to this part may be used in place of the
relative accuracy test.
(ii) The owner or operator must submit the following information to
the Administrator:
(A) The measurement data specified in paragraph (h)(3)(i) of this
section along with all other operating data known to affect CO
emissions; and
(B) Descriptions of the CPMS for exhaust gas temperature and
O2 monitor required in paragraph (h)(4) of this section and
operating limits for those parameters to ensure combustion conditions
remain similar to those that exist during the demonstration period.
(iii) The effective date of the exemption from installation and
operation of a CO CEMS is the date of submission of the information and
data required in paragraph (h)(3)(ii) of this section.
(4) The owner or operator of a FCCU or FCU that is exempted from the
requirement to install and operate a CO CEMS in paragraph (h)(3) of this
section shall install, operate, calibrate, and maintain CPMS to measure
and record the operating parameters in paragraph (h)(4)(i) or (ii) of
this section. The owner or operator shall install, operate, and maintain
each CPMS according to the manufacturer's specifications.
(i) For a FCCU or FCU with no post-combustion control device, the
temperature and O2 concentration of the exhaust gas stream
exiting the unit.
(ii) For a FCCU or FCU with a post-combustion control device, the
temperature and O2 concentration of the exhaust gas stream
exiting the control device.
(i) Excess emissions. For the purpose of reports required by Sec.
60.7(c), periods of excess emissions for a FCCU or FCU subject to the
emissions limitations in Sec. 60.102a(b) are defined as specified in
paragraphs (i)(1) through (6) of this section. Note: Determine all
averages, except for opacity, as the arithmetic average of the
applicable 1-hour averages, e.g., determine the rolling 3-hour average
as the arithmetic average of three contiguous 1-hour averages.
(1) If a CPMS is used according to paragraph (b)(1) of this section,
all 3-hour periods during which the average PM control device operating
characteristics, as measured by the continuous monitoring systems under
paragraph (b)(1), fall below the levels established during the
performance test. If the alternative to pressure drop CPMS is used for
the owner or operator of a jet ejector type wet scrubber or other type
of wet scrubber equipped with atomizing spray nozzles, each day in which
abnormal pressure readings are not corrected within 12 hours of
identification.
(2) If a bag leak detection system is used according to paragraph
(c) of this section, each day in which the cause of
[[Page 359]]
an alarm is not alleviated within the time period specified in paragraph
(c)(3) of this section.
(3) If a PM CEMS is used according to Sec. 60.105a(d), all 7-day
periods during which the average PM emission rate, as measured by the
continuous PM monitoring system under Sec. 60.105a(d) exceeds 0.040 gr/
dscf corrected to 0 percent excess air for a modified or reconstructed
FCCU, 0.020 gr/dscf corrected to 0 percent excess air for a newly
constructed FCCU, or 0.040 gr/dscf for an affected fluid coking unit.
(4) If a COMS is used according to Sec. 60.105a(e), all 3-hour
periods during which the average opacity, as measured by the COMS under
Sec. 60.105a(e), exceeds the site-specific limit established during the
most recent performance test.
(5) All rolling 7-day periods during which the average concentration
of NOX as measured by the NOX CEMS under Sec.
60.105a(f) exceeds 80 ppmv for an affected FCCU or FCU.
(6) All rolling 7-day periods during which the average concentration
of SO2 as measured by the SO2 CEMS under Sec.
60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods during which
the average concentration of SO2 as measured by the
SO2 CEMS exceeds 25 ppmv.
(7) All 1-hour periods during which the average CO concentration as
measured by the CO continuous monitoring system under paragraph (h) of
this section exceeds 500 ppmv or, if applicable, all 1-hour periods
during which the average temperature and O2 concentration as
measured by the continuous monitoring systems under paragraph (h)(4) of
this section fall below the operating limits established during the
performance test.
[73 FR 35867, June 24, 2008, as amended at 77 FR 56473, Sep. 12, 2012;
80 FR 75232, Dec. 1, 2015]
Sec. 60.106a Monitoring of emissions and operations for sulfur
recovery plants.
(a) The owner or operator of a sulfur recovery plant that is subject
to the emissions limits in Sec. 60.102a(f)(1) or Sec. 60.102a(f)(2)
shall:
(1) For sulfur recovery plants subject to the SO2
emission limit in Sec. 60.102a(f)(1)(i) or Sec. 60.102a(f)(2)(i), the
owner or operator shall install, operate, calibrate, and maintain an
instrument for continuously monitoring and recording the concentration
(dry basis, zero percent excess air) of any SO2 emissions
into the atmosphere. The monitor shall include an oxygen monitor for
correcting the data for excess air.
(i) The span value for the SO2 monitor is two times the
applicable SO2 emission limit at the highest O2
concentration in the air/oxygen stream used in the Claus burner, if
applicable.
(ii) The owner or operator shall install, operate, and maintain each
SO2 CEMS according to Performance Specification 2 of appendix
B to part 60.
(iii) The owner or operator shall conduct performance evaluations of
each SO2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 2 of appendix B to part 60. The
owner or operator shall use Methods 6 or 6C of appendix A-4 to part 60
and Method 3 or 3A of appendix A-2 of part 60 for conducting the
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981,
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see Sec.
60.17) is an acceptable alternative to EPA Method 6.
(iv) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to this part.
(v) The span value for the O2 monitor must be selected
between 10 and 25 percent, inclusive.
(vi) The owner or operator shall conduct performance evaluations for
the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to this part. The
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to this
part for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981 (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 3B of appendix A-2 to this part.
(vii) The owner or operator shall comply with the applicable quality
assurance procedures of appendix F to this part for each monitor,
including annual accuracy determinations for
[[Page 360]]
each O2 monitor, and daily calibration drift determinations.
(2) For sulfur recovery plants that are subject to the reduced
sulfur compounds emission limit in Sec. 60.102a(f)(1)(ii) or
(f)(2)(ii), the owner or operator shall install, operate, calibrate, and
maintain an instrument for continuously monitoring and recording the
concentration of reduced sulfur compounds and O2 emissions
into the atmosphere. The reduced sulfur compounds emissions shall be
calculated as SO2 (dry basis, zero percent excess air).
(i) The span value for the reduced sulfur compounds monitor is two
times the applicable reduced sulfur compounds emission limit as
SO2 at the highest O2 concentration in the air/
oxygen stream used in the Claus burner, if applicable.
(ii) The owner or operator shall install, operate, and maintain each
reduced sulfur compounds CEMS according to Performance Specification 5
of appendix B to this part.
(iii) The owner or operator shall conduct performance evaluations of
each reduced sulfur compounds monitor according to the requirements in
Sec. 60.13(c) and Performance Specification 5 of appendix B to this
part. The owner or operator shall use Methods 15 or 15A of appendix A-5
to part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 15A of appendix A-5 to part 60.
(iv) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to part 60.
(v) The span value for the O2 monitor must be selected
between 10 and 25 percent, inclusive.
(vi) The owner or operator shall conduct performance evaluations for
the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to part 60. The
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part
60 for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B of appendix A-2 to part 60.
(vii) The owner or operator shall comply with the applicable quality
assurance procedures of appendix F to part 60 for each monitor,
including annual accuracy determinations for each O2 monitor,
and daily calibration drift determinations.
(3) In place of the reduced sulfur compounds monitor required in
paragraph (a)(2) of this section, the owner or operator may install,
calibrate, operate, and maintain an instrument using an air or
O2 dilution and oxidation system to convert any reduced
sulfur to SO2 for continuously monitoring and recording the
concentration (dry basis, 0 percent excess air) of the total resultant
SO2. The monitor must include an O2 monitor for
correcting the data for excess O2.
(i) The span value for this monitor is two times the applicable
reduced sulfur compounds emission limit as SO2 at the highest
O2 concentration in the air/oxygen stream used in the Claus
burner, if applicable.
(ii) The owner or operator shall conduct performance evaluations of
each SO2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 5 of appendix B to part 60. The
owner or operator shall use Methods 15 or 15A of appendix A-5 to part 60
for conducting the relative accuracy evaluations. The method ANSI/ASME
PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
15A of appendix A-5 to part 60.
(iii) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 of
appendix B to part 60.
(iv) The span value for the O2 monitor must be selected
between 10 and 25 percent, inclusive.
(v) The owner or operator shall conduct performance evaluations for
the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to part 60. The
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part
60 for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981, ``Flue and Exhaust Gas
[[Page 361]]
Analyses,'' (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 3B of appendix A-2 to part 60.
(vi) The owner or operator shall comply with the applicable quality
assurance procedures of appendix F to part 60 for each monitor,
including quarterly accuracy determinations for each SO2
monitor, annual accuracy determinations for each O2 monitor,
and daily calibration drift determinations.
(4) For sulfur recovery plants that are subject to the
H2S emission limit in Sec. 60.102a(f)(1)(iii) or
(f)(2)(iii), the owner or operator shall install, operate, calibrate,
and maintain an instrument for continuously monitoring and recording the
concentration of H2S, and O2 emissions into the
atmosphere. The H2S emissions shall be calculated as
SO2 (dry basis, zero percent excess air).
(i) The span value for this monitor is two times the applicable
H2S emission limit.
(ii) The owner or operator shall install, operate, and maintain each
H2S CEMS according to Performance Specification 7 of appendix
B to this part.
(iii) The owner or operator shall conduct performance evaluations
for each H2S monitor according to the requirements of Sec.
60.13(c) and Performance Specification 7 of appendix B to this part. The
owner or operator shall use Methods 11 or 15 of appendix A-5 to this
part or Method 16 of appendix A-6 to this part for conducting the
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 15A of appendix A-5 to this part.
(iv) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to this part.
(v) The span value for the O2 monitor must be selected
between 10 and 25 percent, inclusive.
(vi) The owner or operator shall conduct performance evaluations for
the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to this part. The
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to this
part for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981 (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 3B of appendix A-2 to this part.
(vii) The owner or operator shall comply with the applicable quality
assurance procedures of appendix F to this part for each monitor,
including annual accuracy determinations for each O2 monitor,
and daily calibration drift determinations.
(5) For sulfur recovery plants that use oxygen or oxygen enriched
air in the Claus burner and that elects to monitor O2
concentration of the air/oxygen mixture supplied to the Claus burner,
the owner or operator shall install, operate, calibrate, and maintain an
instrument for continuously monitoring and recording the O2
concentration of the air/oxygen mixture supplied to the Claus burner in
order to determine the allowable emissions limit.
(i) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to this part.
(ii) The span value for the O2 monitor shall be 100
percent.
(iii) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to this part. The
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to this
part for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981 (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 3B of appendix A-2 to this part.
(iv) The owner or operator shall comply with the applicable quality
assurance procedures of appendix F to this part for each monitor,
including annual accuracy determinations for each O2 monitor,
and daily calibration drift determinations.
(v) The owner or operator shall use the hourly average O2
concentration from this monitor for use in Equation 1 or 2 of Sec.
60.102a(f), as applicable, for each hour and determine the allowable
emission limit as the arithmetic average of 12 contiguous 1-hour
averages (i.e., the rolling 12-hour average).
[[Page 362]]
(6) As an alternative to the O2 monitor required in
paragraph (a)(5) of this section, the owner or operator may install,
calibrate, operate, and maintain a CPMS to measure and record the
volumetric gas flow rate of ambient air and oxygen-enriched gas supplied
to the Claus burner and calculate the hourly average O2
concentration of the air/oxygen mixture used in the Claus burner as
specified in paragraphs (a)(6)(i) through (iv) of this section in order
to determine the allowable emissions limit as specified in paragraphs
(a)(6)(v) of this section.
(i) The owner or operator shall install, calibrate, operate and
maintain each flow monitor according to the manufacturer's procedures
and specifications and the following requirements.
(A) Locate the monitor in a position that provides a representative
measurement of the total gas flow rate.
(B) Use a flow sensor meeting an accuracy requirement of 5 percent over the normal range of flow measured or 10
cubic feet per minute, whichever is greater.
(C) Use a flow monitor that is maintainable online, is able to
continuously correct for temperature, pressure and, for ambient air flow
monitor, moisture content, and is able to record dry flow in standard
conditions (as defined in Sec. 60.2) over one-minute averages.
(D) At least quarterly, perform a visual inspection of all
components of the monitor for physical and operational integrity and all
electrical connections for oxidation and galvanic corrosion if the flow
monitor is not equipped with a redundant flow sensor.
(E) Recalibrate the flow monitor in accordance with the
manufacturer's procedures and specifications biennially (every two
years) or at the frequency specified by the manufacturer.
(ii) The owner or operator shall use 20.9 percent as the oxygen
content of the ambient air.
(iii) The owner or operator shall use product specifications (e.g.,
as reported in material safety data sheets) for percent oxygen for
purchased oxygen. For oxygen produced onsite, the percent oxygen shall
be determined by periodic measurements or process knowledge.
(iv) The owner or operator shall calculate the hourly average
O2 concentration of the air/oxygen mixture used in the Claus
burner using Equation 10 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.002
Where:
%O2 = O2 concentration of the air/oxygen mixture
used in the Claus burner, percent by volume (dry basis);
20.9 = O2 concentration in air, percent dry basis;
Qair = Volumetric flow rate of ambient air used in the Claus
burner, dscfm;
%O2,oxy = O2 concentration in the enriched oxygen
stream, percent dry basis; and
Qoxy = Volumetric flow rate of enriched oxygen stream used in
the Claus burner, dscfm.
(v) The owner or operator shall use the hourly average O2
concentration determined using Equation 8 of Sec. 60.104a(d)(8) for use
in Equation 1 or 2 of Sec. 60.102a(f), as applicable, for each hour and
determine the allowable emission limit as the arithmetic average of 12
contiguous 1-hour averages (i.e., the rolling 12-hour average).
(7) Owners or operators of a sulfur recovery plant that elects to
comply with the SO2 emission limit in Sec. 60.102a(f)(1)(i)
or (f)(2)(i) or the reduced sulfur compounds emission limit in Sec.
60.102a(f)(1)(ii) or (f)(2)(ii) as a flow rate weighted average for a
group of release points from the sulfur recovery plant rather than for
each process train or release point individually shall install,
calibrate, operate, and maintain a CPMS to measure and record the
volumetric gas flow rate of each release point within the group of
release points from the sulfur recovery plant as specified in paragraphs
(a)(7)(i) through (iv) of this section.
[[Page 363]]
(i) The owner or operator shall install, calibrate, operate and
maintain each flow monitor according to the manufacturer's procedures
and specifications and the following requirements.
(A) Locate the monitor in a position that provides a representative
measurement of the total gas flow rate.
(B) Use a flow sensor meeting an accuracy requirement of 5 percent over the normal range of flow measured or 10
cubic feet per minute, whichever is greater.
(C) Use a flow monitor that is maintainable online, is able to
continuously correct for temperature, pressure, and moisture content,
and is able to record dry flow in standard conditions (as defined in
Sec. 60.2) over one-minute averages.
(D) At least quarterly, perform a visual inspection of all
components of the monitor for physical and operational integrity and all
electrical connections for oxidation and galvanic corrosion if the flow
monitor is not equipped with a redundant flow sensor.
(E) Recalibrate the flow monitor in accordance with the
manufacturer's procedures and specifications biennially (every two
years) or at the frequency specified by the manufacturer.
(ii) The owner or operator shall correct the flow to 0 percent
excess air using Equation 11 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.003
Where:
Qadj = Volumetric flow rate adjusted to 0 percent excess air,
dry standard cubic feet per minute (dscfm);
Cmeas = Volumetric flow rate measured by the flow meter
corrected to dry standard conditions, dscfm;
20.9c = 20.9 percent O2-0.0 percent O2
(defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry basis,
percent.
(iii) The owner or operator shall calculate the flow weighted
average SO2 or reduced sulfur compounds concentration for
each hour using Equation 12 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.004
Where:
Cave = Flow weighted average concentration of the pollutant,
ppmv (dry basis, zero percent excess air). The pollutant is
either SO2 (if complying with the SO2
emission limit in Sec. 60.102a(f)(1)(i) or (f)(2)(i)) or
reduced sulfur compounds (if complying with the reduced sulfur
compounds emission limit in Sec. 60.102a(f)(1)(ii) or
(f)(2)(ii));
N = Number of release points within the group of release points from the
sulfur recovery plant for which emissions averaging is
elected;
Cn = Pollutant concentration in the nth release
point within the group of release points from the sulfur
recovery plant for which emissions averaging is elected, ppmv
(dry basis, zero percent excess air);
Qadj,n = Volumetric flow rate of the nth release
point within the group of release points from the sulfur
recovery plant for which emissions averaging is elected, dry
standard cubic feet per minute (dscfm, adjusted to 0 percent
excess air).
(iv) For sulfur recovery plants that use oxygen or oxygen enriched
air in
[[Page 364]]
the Claus burner, the owner or operator shall use Equation 10 of this
section and the hourly emission limits determined in paragraph (a)(5)(v)
or (a)(6)(v) of this section in-place of the pollutant concentration to
determine the flow weighted average hourly emission limit for each hour.
The allowable emission limit shall be calculated as the arithmetic
average of 12 contiguous 1-hour averages (i.e., the rolling 12-hour
average).
(b) Excess emissions. For the purpose of reports required by Sec.
60.7(c), periods of excess emissions for sulfur recovery plants subject
to the emissions limitations in Sec. 60.102a(f) are defined as
specified in paragraphs (b)(1) through (3) of this section.
Note: Determine all averages as the arithmetic average of the
applicable 1-hour averages, e.g., determine the rolling 12-hour average
as the arithmetic average of 12 contiguous 1-hour averages.
(1) All 12-hour periods during which the average concentration of
SO2 as measured by the SO2 continuous monitoring
system required under paragraph (a)(1) of this section exceeds the
applicable emission limit (dry basis, zero percent excess air); or
(2) All 12-hour periods during which the average concentration of
reduced sulfur compounds (as SO2) as measured by the reduced
sulfur compounds continuous monitoring system required under paragraph
(a)(2) or (3) of this section exceeds the applicable emission limit; or
(3) All 12-hour periods during which the average concentration of
H2S as measured by the H2S continuous monitoring
system required under paragraph (a)(4) of this section exceeds the
applicable emission limit (dry basis, 0 percent excess air).
[73 FR 35867, June 24, 2008, as amended at 80 FR 75232, Dec. 1, 2015]
Sec. 60.107a Monitoring of emissions and operations for fuel gas
combustion devices and flares.
(a) Fuel gas combustion devices subject to SO2 or
H2S limit and flares subject to H2S concentration
requirements. The owner or operator of a fuel gas combustion device that
is subject to Sec. 60.102a(g)(1) and elects to comply with the
SO2 emission limits in Sec. 60.102a(g)(1)(i) shall comply
with the requirements in paragraph (a)(1) of this section. The owner or
operator of a fuel gas combustion device that is subject to Sec.
60.102a(g)(1) and elects to comply with the H2S concentration
limits in Sec. 60.102a(g)(1)(ii) or a flare that is subject to the
H2S concentration requirement in Sec. 60.103a(h) shall
comply with paragraph (a)(2) of this section.
(1) The owner or operator of a fuel gas combustion device that
elects to comply with the SO2 emissions limits in Sec.
60.102a(g)(1)(i) shall install, operate, calibrate and maintain an
instrument for continuously monitoring and recording the concentration
(dry basis, 0-percent excess air) of SO2 emissions into the
atmosphere. The monitor must include an O2 monitor for
correcting the data for excess air.
(i) The owner or operator shall install, operate, and maintain each
SO2 monitor according to Performance Specification 2 of
appendix B to this part. The span value for the SO2 monitor
is 50 ppmv SO2.
(ii) The owner or operator shall conduct performance evaluations for
the SO2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 2 of appendix B to this part. The
owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to this
part for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981 (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 6 or 6A of appendix A-4 to this
part. Samples taken by Method 6 of appendix A-4 to this part shall be
taken at a flow rate of approximately 2 liters/min for at least 30
minutes. The relative accuracy limit shall be 20 percent or 4 ppmv,
whichever is greater, and the calibration drift limit shall be 5 percent
of the established span value.
(iii) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 of
appendix B to part 60. The span value for the O2 monitor must
be selected between 10 and 25 percent, inclusive.
(iv) The owner or operator shall conduct performance evaluations for
the O2 monitor according to the requirements of Sec.
60.13(c) and Performance
[[Page 365]]
Specification 3 of appendix B to part 60. The owner or operator shall
use Methods 3, 3A, or 3B of appendix A-2 to part 60 for conducting the
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981,
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see Sec.
60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to
part 60.
(v) The owner or operator shall comply with the applicable quality
assurance procedures in appendix F to part 60, including quarterly
accuracy determinations for SO2 monitors, annual accuracy
determinations for O2 monitors, and daily calibration drift
tests.
(vi) Fuel gas combustion devices having a common source of fuel gas
may be monitored at only one location (i.e., after one of the combustion
devices), if monitoring at this location accurately represents the
SO2 emissions into the atmosphere from each of the combustion
devices.
(2) The owner or operator of a fuel gas combustion device that
elects to comply with the H2S concentration limits in Sec.
60.102a(g)(1)(ii) or a flare that is subject to the H2S
concentration requirement in Sec. 60.103a(h) shall install, operate,
calibrate and maintain an instrument for continuously monitoring and
recording the concentration by volume (dry basis) of H2S in
the fuel gases before being burned in any fuel gas combustion device or
flare.
(i) The owner or operator shall install, operate and maintain each
H2S monitor according to Performance Specification 7 of
appendix B to part 60. The span value for this instrument is 300 ppmv
H2S.
(ii) The owner or operator shall conduct performance evaluations for
each H2S monitor according to the requirements of Sec.
60.13(c) and Performance Specification 7 of appendix B to part 60. The
owner or operator shall use Method 11, 15, or 15A of appendix A-5 to
part 60 or Method 16 of appendix A-6 to part 60 for conducting the
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981,
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see Sec.
60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to
part 60.
(iii) The owner or operator shall comply with the applicable quality
assurance procedures in appendix F to part 60 for each H2S
monitor.
(iv) Fuel gas combustion devices or flares having a common source of
fuel gas may be monitored at only one location, if monitoring at this
location accurately represents the concentration of H2S in
the fuel gas being burned in the respective fuel gas combustion devices
or flares.
(v) The owner or operator of a flare subject to Sec. 60.103a(c)
through (e) may use the instrument required in paragraph (e)(1) of this
section to demonstrate compliance with the H2S concentration
requirement in Sec. 60.103a(h) if the owner or operator complies with
the requirements of paragraph (e)(1)(i) through (iv) and if the
instrument has a span (or dual span, if necessary) capable of accurately
measuring concentrations between 20 and 300 ppmv. If the instrument
required in paragraph (e)(1) of this section is used to demonstrate
compliance with the H2S concentration requirement, the
concentration directly measured by the instrument must meet the numeric
concentration in Sec. 60.103a(h).
(vi) The owner or operator of modified flare that meets all three
criteria in paragraphs (a)(2)(vi)(A) through (C) of this section shall
comply with the requirements of paragraphs (a)(2)(i) through (v) of this
section no later than November 11, 2015. The owner or operator shall
comply with the approved alternative monitoring plan or plans pursuant
to Sec. 60.13(i) until the flare is in compliance with requirements of
paragraphs (a)(2)(i) through (v) of this section.
(A) The flare was an affected facility subject to subpart J of this
part prior to becoming an affected facility under Sec. 60.100a.
(B) The owner or operator had an approved alternative monitoring
plan or plans pursuant to Sec. 60.13(i) for all fuel gases combusted in
the flare.
(C) The flare did not have in place on or before September 12, 2012
an instrument for continuously monitoring and recording the
concentration by volume (dry basis) of H2S in the fuel gases
that
[[Page 366]]
is capable of complying with the requirements of paragraphs (a)(2)(i)
through (v) of this section.
(3) The owner or operator of a fuel gas combustion device or flare
is not required to comply with paragraph (a)(1) or (2) of this section
for fuel gas streams that are exempt under Sec. Sec. 60.102a(g)(1)(iii)
or 60.103a(h) or, for fuel gas streams combusted in a process heater,
other fuel gas combustion device or flare that are inherently low in
sulfur content. Fuel gas streams meeting one of the requirements in
paragraphs (a)(3)(i) through (iv) of this section will be considered
inherently low in sulfur content.
(i) Pilot gas for heaters and flares.
(ii) Fuel gas streams that meet a commercial-grade product
specification for sulfur content of 30 ppmv or less. In the case of a
liquefied petroleum gas (LPG) product specification in the pressurized
liquid state, the gas phase sulfur content should be evaluated assuming
complete vaporization of the LPG and sulfur containing-compounds at the
product specification concentration.
(iii) Fuel gas streams produced in process units that are intolerant
to sulfur contamination, such as fuel gas streams produced in the
hydrogen plant, catalytic reforming unit, isomerization unit, and HF
alkylation process units.
(iv) Other fuel gas streams that an owner or operator demonstrates
are low-sulfur according to the procedures in paragraph (b) of this
section.
(4) If the composition of an exempt fuel gas stream changes, the
owner or operator must follow the procedures in paragraph (b)(3) of this
section.
(b) Exemption from H2S monitoring requirements for low-
sulfur fuel gas streams. The owner or operator of a fuel gas combustion
device or flare may apply for an exemption from the H2S
monitoring requirements in paragraph (a)(2) of this section for a fuel
gas stream that is inherently low in sulfur content. A fuel gas stream
that is demonstrated to be low-sulfur is exempt from the monitoring
requirements of paragraphs (a)(1) and (2) of this section until there
are changes in operating conditions or stream composition.
(1) The owner or operator shall submit to the Administrator a
written application for an exemption from monitoring. The application
must contain the following information:
(i) A description of the fuel gas stream/system to be considered,
including submission of a portion of the appropriate piping diagrams
indicating the boundaries of the fuel gas stream/system and the affected
fuel gas combustion device(s) or flare(s) to be considered;
(ii) A statement that there are no crossover or entry points for
sour gas (high H2S content) to be introduced into the fuel
gas stream/system (this should be shown in the piping diagrams);
(iii) An explanation of the conditions that ensure low amounts of
sulfur in the fuel gas stream (i.e., control equipment or product
specifications) at all times;
(iv) The supporting test results from sampling the requested fuel
gas stream/system demonstrating that the sulfur content is less than 5
ppmv H2S. Sampling data must include, at minimum, 2 weeks of
daily monitoring (14 grab samples) for frequently operated fuel gas
streams/systems; for infrequently operated fuel gas streams/systems,
seven grab samples must be collected unless other additional information
would support reduced sampling. The owner or operator shall use detector
tubes (``length-of-stain tube'' type measurement) following the ``Gas
Processors Association Standard 2377-86 (incorporated by reference--see
Sec. 60.17), using tubes with a maximum span between 10 and 40 ppmv
inclusive when 1<=N<=10, where N = number of pump strokes, to test the
applicant fuel gas stream for H2S; and
(v) A description of how the 2 weeks (or seven samples for
infrequently operated fuel gas streams/systems) of monitoring results
compares to the typical range of H2S concentration (fuel
quality) expected for the fuel gas stream/system going to the affected
fuel gas combustion device or flare (e.g., the 2 weeks of daily detector
tube results for a frequently operated loading rack included the entire
range of products loaded out and, therefore,
[[Page 367]]
should be representative of typical operating conditions affecting
H2S content in the fuel gas stream going to the loading rack
flare).
(2) The effective date of the exemption is the date of submission of
the information required in paragraph (b)(1) of this section.
(3) No further action is required unless refinery operating
conditions change in such a way that affects the exempt fuel gas stream/
system (e.g., the stream composition changes). If such a change occurs,
the owner or operator shall follow the procedures in paragraph
(b)(3)(i), (b)(3)(ii), or (b)(3)(iii) of this section.
(i) If the operation change results in a sulfur content that is
still within the range of concentrations included in the original
application, the owner or operator shall conduct an H2S test
on a grab sample and record the results as proof that the concentration
is still within the range.
(ii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application, the owner or operator may submit new information following
the procedures of paragraph (b)(1) of this section within 60 days (or
within 30 days after the seventh grab sample is tested for infrequently
operated process units).
(iii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original application
and the owner or operator chooses not to submit new information to
support an exemption, the owner or operator must begin H2S
monitoring using daily stain sampling to demonstrate compliance using
length-of-stain tubes with a maximum span between 200 and 400 ppmv
inclusive when 1<=N<=5, where N = number of pump strokes. The owner or
operator must begin monitoring according to the requirements in
paragraphs (a)(1) or (a)(2) of this section as soon as practicable, but
in no case later than 180 days after the operation change. During daily
stain tube sampling, a daily sample exceeding 162 ppmv is an exceedance
of the 3-hour H2S concentration limit. The owner or operator
of a fuel gas combustion device must also determine a rolling 365-day
average using the stain sampling results; an average H2S
concentration of 5 ppmv must be used for days within the rolling 365-day
period prior to the operation change.
(c) Process heaters complying with the NOX concentration-
based limit. The owner or operator of a process heater subject to the
NOX emissions limit in Sec. 60.102a(g)(2) and electing to
comply with the applicable emissions limit in Sec. 60.102a(g)(2)(i)(A),
(g)(2)(ii)(A), (g)(2)(iii)(A) or (g)(2)(iv)(A) shall install, operate,
calibrate and maintain an instrument for continuously monitoring and
recording the concentration (dry basis, 0-percent excess air) of
NOX emissions into the atmosphere according to the
requirements in paragraphs (c)(1) through (5) of this section, except as
provided in paragraph (c)(6) of this section. The monitor must include
an O2 monitor for correcting the data for excess air.
(1) Except as provided in paragraph (c)(6) of this section, the
owner or operator shall install, operate and maintain each
NOX monitor according to Performance Specification 2 of
appendix B to part 60. The span value of this NOX monitor
must be between 2 and 3 times the applicable emissions limit, inclusive.
(2) The owner or operator shall conduct performance evaluations of
each NOX monitor according to the requirements in Sec.
60.13(c) and Performance Specification 2 of appendix B to part 60. The
owner or operator shall use Methods 7, 7A, 7C, 7D, or 7E of appendix A-4
to part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 7 or 7C of appendix A-4 to part 60.
(3) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to part 60. The span value of this O2 monitor must
be selected between 10 and 25 percent, inclusive.
(4) The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 3 of appendix B to part 60.
[[Page 368]]
Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for
conducting the relative accuracy evaluations. The method ANSI/ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B of appendix A-2 to part 60.
(5) The owner or operator shall comply with the quality assurance
requirements in Procedure 1 of appendix F to part 60 for each
NOX and O2 monitor, including quarterly accuracy
determinations for NOX monitors, annual accuracy
determinations for O2 monitors, and daily calibration drift
tests.
(6) The owner or operator of a process heater that has a rated
heating capacity of less than 100 MMBtu and is equipped with combustion
modification-based technology to reduce NOX emissions (i.e.,
low-NOX burners, ultra-low-NOX burners) may elect
to comply with the monitoring requirements in paragraphs (c)(1) through
(5) of this section or, alternatively, the owner or operator of such a
process heater shall conduct biennial performance tests according to the
requirements in Sec. 60.104a(i), establish a maximum excess
O2 operating limit or operating curve according to the
requirements in Sec. 60.104a(i)(6) and comply with the O2
monitoring requirements in paragraphs (c)(3) through (5) of this section
to demonstrate compliance. If an O2 operating curve is used
(i.e., if different O2 operating limits are established for
different operating ranges), the owner or operator of the process heater
must also monitor fuel gas flow rate, fuel oil flow rate (as applicable)
and heating value content according to the methods provided in
paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7) of this section,
respectively.
(d) Process heaters complying with the NOX heating value-
based or mass-based limit. The owner or operator of a process heater
subject to the NOX emissions limit in Sec. 60.102a(g)(2) and
electing to comply with the applicable emissions limit in Sec.
60.102a(g)(2)(i)(B) or (g)(2)(ii)(B) shall install, operate, calibrate
and maintain an instrument for continuously monitoring and recording the
concentration (dry basis, 0-percent excess air) of NOX
emissions into the atmosphere and shall determine the F factor of the
fuel gas stream no less frequently than once per day according to the
monitoring requirements in paragraphs (d)(1) through (4) of this
section. The owner or operator of a co-fired process heater subject to
the NOX emissions limit in Sec. 60.102a(g)(2) and electing
to comply with the heating value-based limit in Sec.
60.102a(g)(2)(iii)(B) or (g)(2)(iv)(B) shall install, operate, calibrate
and maintain an instrument for continuously monitoring and recording the
concentration (dry basis, 0-percent excess air) of NOX
emissions into the atmosphere according to the monitoring requirements
in paragraph (d)(1) of this section; install, operate, calibrate and
maintain an instrument for continuously monitoring and recording the
flow rate of the fuel gas and fuel oil fed to the process heater
according to the monitoring requirements in paragraph (d)(5) and (6) of
this section; for fuel gas streams, determine gas composition according
to the requirements in paragraph (d)(4) of this section or the higher
heating value according to the requirements in paragraph (d)(7) of this
section; and for fuel oil streams, determine the heating value according
to the monitoring requirements in paragraph (d)(7) of this section.
(1) Except as provided in paragraph (d)(8) of this section, the
owner or operator shall install, operate and maintain each
NOX monitor according to the requirements in paragraphs
(c)(1) through (5) of this section. The monitor must include an
O2 monitor for correcting the data for excess air.
(2) Except as provided in paragraph (d)(3) of this section, the
owner or operator shall sample and analyze each fuel stream fed to the
process heater using the methods and equations in section 12.3.2 of EPA
Method 19 of appendix A-7 to part 60 to determine the F factor on a dry
basis. If a single fuel gas system provides fuel gas to several process
heaters, the F factor may be determined at a single location in the fuel
gas system provided it is representative of the fuel gas fed to the
affected process heater(s).
(3) As an alternative to the requirements in paragraph (d)(2) of
this section, the owner or operator of a gas-
[[Page 369]]
fired process heater shall install, operate and maintain a gas
composition analyzer and determine the average F factor of the fuel gas
using the factors in Table 1 of this subpart and Equation 13 of this
section. If a single fuel gas system provides fuel gas to several
process heaters, the F factor may be determined at a single location in
the fuel gas system provided it is representative of the fuel gas fed to
the affected process heater(s).
[GRAPHIC] [TIFF OMITTED] TR01DE15.005
Where:
Fd = F factor on dry basis at 0% excess air, dscf/MMBtu.
Xi = mole or volume fraction of each component in the
fuel gas.
MEVi = molar exhaust volume, dry standard cubic feet per
mole (dscf/mol).
MHCi = molar heat content, Btu per mole (Btu/mol).
1,000,000 = unit conversion, Btu per MMBtu.
(4) The owner or operator shall conduct performance evaluations of
each compositional monitor according to the requirements in Performance
Specification 9 of appendix B to part 60. Any of the following methods
shall be used for conducting the relative accuracy evaluations:
(i) EPA Method 18 of appendix A-6 to part 60;
(ii) ASTM D1945-03 (Reapproved 2010)(incorporated by reference-see
Sec. 60.17);
(iii) ASTM D1946-90 (Reapproved 2006)(incorporated by reference-see
Sec. 60.17);
(iv) ASTM D6420-99 (Reapproved 2004)(incorporated by reference-see
Sec. 60.17);
(v) GPA 2261-00 (incorporated by reference-see Sec. 60.17); or
(vi) ASTM UOP539-97 (incorporated by reference-see Sec. 60.17).
(5) The owner or operator shall install, operate and maintain fuel
gas flow monitors according to the manufacturer's recommendations. For
volumetric flow meters, temperature and pressure monitors must be
installed in conjunction with the flow meter or in a representative
location to correct the measured flow to standard conditions (i.e., 68
[deg]F and 1 atmosphere). For mass flow meters, use gas compositions
determined according to paragraph (d)(4) of this section to determine
the average molecular weight of the fuel gas and convert the mass flow
to a volumetric flow at standard conditions (i.e., 68 [deg]F and 1
atmosphere). The owner or operator shall conduct performance evaluations
of each fuel gas flow monitor according to the requirements in Sec.
60.13 and Performance Specification 6 of appendix B to part 60. Any of
the following methods shall be used for conducting the relative accuracy
evaluations:
(i) EPA Method 2, 2A, 2B, 2C or 2D of appendix A-2 to part 60;
(ii) ASME MFC-3M-2004 (incorporated by reference-see Sec. 60.17);
(iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008) (incorporated by
reference-see Sec. 60.17);
(iv) ASME MFC-6M-1998 (Reaffirmed 2005) (incorporated by reference-
see Sec. 60.17);
(v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006) (incorporated by
reference-see Sec. 60.17);
(vi) ASME MFC-11M-2006 (incorporated by reference-see Sec. 60.17);
(vii) ASME MFC-14M-2003 (incorporated by reference-see Sec. 60.17);
(viii) ASME MFC-18M-2001 (incorporated by reference-see Sec.
60.17);
(ix) AGA Report No. 3, Part 1 (incorporated by reference-see Sec.
60.17);
(x) AGA Report No. 3, Part 2 (incorporated by reference-see Sec.
60.17);
(xi) AGA Report No. 11 (incorporated by reference-see Sec. 60.17);
(xii) AGA Report No. 7 (incorporated by reference-see Sec. 60.17);
and
(xiii) API Manual of Petroleum Measurement Standards, Chapter 22,
Section 2 (incorporated by reference-see Sec. 60.17).
[[Page 370]]
(6) The owner or operator shall install, operate and maintain each
fuel oil flow monitor according to the manufacturer's recommendations.
The owner or operator shall conduct performance evaluations of each fuel
oil flow monitor according to the requirements in Sec. 60.13 and
Performance Specification 6 of appendix B to part 60. Any of the
following methods shall be used for conducting the relative accuracy
evaluations:
(i) Any one of the methods listed in paragraph (d)(5) of this
section that are applicable to fuel oil (i.e., ``fluids'');
(ii) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006) (incorporated by
reference-see Sec. 60.17);
(iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006) (incorporated by
reference-see Sec. 60.17);
(iv) ASME MFC-16-2007 (incorporated by reference-see Sec. 60.17);
(v) ASME MFC-22-2007 (incorporated by reference-see Sec. 60.17); or
(vi) ISO 8316 (incorporated by reference-see Sec. 60.17).
(7) The owner or operator shall determine the higher heating value
of each fuel fed to the process heater using any of the applicable
methods included in paragraphs (d)(7)(i) through (ix) of this section.
If a common fuel supply system provides fuel gas or fuel oil to several
process heaters, the higher heating value of the fuel in each fuel
supply system may be determined at a single location in the fuel supply
system provided it is representative of the fuel fed to the affected
process heater(s). The higher heating value of each fuel fed to the
process heater must be determined no less frequently than once per day
except as provided in paragraph (d)(7)(x) of this section.
(i) ASTM D240-02 (Reapproved 2007) (incorporated by reference-see
Sec. 60.17).
(ii) ASTM D1826-94 (Reapproved 2003) (incorporated by reference-see
Sec. 60.17).
(iii) ASTM D1945-03 (Reapproved 2010) (incorporated by reference-see
Sec. 60.17).
(iv) ASTM D1946-90 (Reapproved 2006) (incorporated by reference-see
Sec. 60.17).
(v) ASTM D3588-98 (Reapproved 2003) (incorporated by reference-see
Sec. 60.17).
(vi) ASTM D4809-06 (incorporated by reference-see Sec. 60.17).
(vii) ASTM D4891-89 (Reapproved 2006) (incorporated by reference-see
Sec. 60.17).
(viii) GPA 2172-09 (incorporated by reference-see Sec. 60.17).
(ix) Any of the methods specified in section 2.2.7 of appendix D to
part 75.
(x) If the fuel oil supplied to the affected co-fired process heater
originates from a single storage tank, the owner or operator may elect
to use the storage tank sampling method in section 2.2.4.2 of appendix D
to part 75 instead of daily sampling, except that the most recent value
for heating content must be used.
(8) The owner or operator of a process heater that has a rated
heating capacity of less than 100 MMBtu and is equipped with combustion
modification based technology to reduce NOX emissions (i.e.,
low-NOX burners or ultra-low NOX burners) may
elect to comply with the monitoring requirements in paragraphs (d)(1)
through (7) of this section or, alternatively, the owner or operator of
such a process heater shall conduct biennial performance tests according
to the requirements in Sec. 60.104a(i), establish a maximum excess
O2 operating limit or operating curve according to the
requirements in Sec. 60.104a(i)(6) and comply with the O2
monitoring requirements in paragraphs (c)(3) through (5) of this section
to demonstrate compliance. If an O2 operating curve is used
(i.e., if different O2 operating limits are established for
different operating ranges), the owner or operator of the process heater
must also monitor fuel gas flow rate, fuel oil flow rate (as applicable)
and heating value content according to the methods provided in
paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7) of this section,
respectively.
(e) Sulfur monitoring for assessing root cause analysis threshold
for affected flares. Except as described in paragraphs (e)(4) and (h) of
this section, the owner or operator of an affected flare subject to
Sec. 60.103a(c) through (e) shall determine the total reduced sulfur
concentration for each gas line directed to the affected flare in
accordance with either paragraph (e)(1), (e)(2) or (e)(3) of this
section. Different options may be
[[Page 371]]
elected for different gas lines. If a monitoring system is in place that
is capable of complying with the requirements related to either
paragraph (e)(1), (e)(2) or (e)(3) of this section, the owner or
operator of a modified flare must comply with the requirements related
to either paragraph (e)(1), (e)(2) or (e)(3) of this section upon
startup of the modified flare. If a monitoring system is not in place
that is capable of complying with the requirements related to either
paragraph (e)(1), (e)(2) or (e)(3) of this section, the owner or
operator of a modified flare must comply with the requirements related
to either paragraph (e)(1), (e)(2) or (e)(3) of this section no later
than November 11, 2015 or upon startup of the modified flare, whichever
is later.
(1) Total reduced sulfur monitoring requirements. The owner or
operator shall install, operate, calibrate and maintain an instrument or
instruments for continuously monitoring and recording the concentration
of total reduced sulfur in gas discharged to the flare.
(i) The owner or operator shall install, operate and maintain each
total reduced sulfur monitor according to Performance Specification 5 of
appendix B to part 60. The span value should be determined based on the
maximum sulfur content of gas that can be discharged to the flare (e.g.,
roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration),
but may be no less than 5,000 ppmv. A single dual range monitor may be
used to comply with the requirements of this paragraph and paragraph
(a)(2) of this section provided the applicable span specifications are
met.
(ii) The owner or operator shall conduct performance evaluations of
each total reduced sulfur monitor according to the requirements in Sec.
60.13(c) and Performance Specification 5 of appendix B to this part. The
owner or operator of each total reduced sulfur monitor shall use EPA
Method 15A of appendix A-5 to this part for conducting the relative
accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated
by reference-see Sec. 60.17) is an acceptable alternative to EPA Method
15A of appendix A-5 to this part. The alternative relative accuracy
procedures described in section 16.0 of Performance Specification 2 of
appendix B to this part (cylinder gas audits) may be used for conducting
the relative accuracy evaluations, except that it is not necessary to
include as much of the sampling probe or sampling line as practical.
(iii) The owner or operator shall comply with the applicable quality
assurance procedures in appendix F to part 60 for each total reduced
sulfur monitor.
(2) H2S monitoring requirements. The owner or operator shall
install, operate, calibrate, and maintain an instrument or instruments
for continuously monitoring and recording the concentration of
H2S in gas discharged to the flare according to the
requirements in paragraphs (e)(2)(i) through (iii) of this section and
shall collect and analyze samples of the gas and calculate total sulfur
concentrations as specified in paragraphs (e)(2)(iv) through (ix) of
this section.
(i) The owner or operator shall install, operate and maintain each
H2S monitor according to Performance Specification 7 of
appendix B to part 60. The span value should be determined based on the
maximum sulfur content of gas that can be discharged to the flare (e.g.,
roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration),
but may be no less than 5,000 ppmv. A single dual range H2S
monitor may be used to comply with the requirements of this paragraph
and paragraph (a)(2) of this section provided the applicable span
specifications are met.
(ii) The owner or operator shall conduct performance evaluations of
each H2S monitor according to the requirements in Sec.
60.13(c) and Performance Specification 7 of appendix B to this part. The
owner or operator shall use EPA Method 11, 15 or 15A of appendix A-5 to
this part for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec. 60.17) is
an acceptable alternative to EPA Method 15A of appendix A-5 to this
part. The alternative relative accuracy procedures described in section
16.0 of Performance Specification 2 of appendix B to this part (cylinder
gas audits) may
[[Page 372]]
be used for conducting the relative accuracy evaluations, except that it
is not necessary to include as much of the sampling probe or sampling
line as practical.
(iii) The owner or operator shall comply with the applicable quality
assurance procedures in appendix F to part 60 for each H2S
monitor.
(iv) In the first 10 operating days after the date the flare must
begin to comply with Sec. 60.103a(c)(1), the owner or operator shall
collect representative daily samples of the gas discharged to the flare.
The samples may be grab samples or integrated samples. The owner or
operator shall take subsequent representative daily samples at least
once per week or as required in paragraph (e)(2)(ix) of this section.
(v) The owner or operator shall analyze each daily sample for total
sulfur using either EPA Method 15A of appendix A-5 to part 60, EPA
Method 16A of appendix A-6 to part 60, ASTM Method D4468-85 (Reapproved
2006) (incorporated by reference--see Sec. 60.17) or ASTM Method D5504-
08 (incorporated by reference--see Sec. 60.17).
(vi) The owner or operator shall develop a 10-day average total
sulfur-to-H2S ratio and 95-percent confidence interval as
follows:
(A) Calculate the ratio of the total sulfur concentration to the
H2S concentration for each day during which samples are
collected.
(B) Determine the 10-day average total sulfur-to-H2S
ratio as the arithmetic average of the daily ratios calculated in
paragraph (e)(2)(vi)(A) of this section.
(C) Determine the acceptable range for subsequent weekly samples
based on the 95-percent confidence interval for the distribution of
daily ratios based on the 10 individual daily ratios using Equation 14
of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE15.006
Where:
AR = Acceptable range of subsequent ratio determinations, unitless.
RatioAvg = 10-day average total sulfur-to-H2S
concentration ratio, unitless.
2.262 = t-distribution statistic for 95-percent 2-sided confidence
interval for 10 samples (9 degrees of freedom).
SDev = Standard deviation of the 10 daily average total sulfur-to-
H2S concentration ratios used to develop the 10-day average
total sulfur-to-H2S concentration ratio, unitless.
(vii) For each day during the period when data are being collected
to develop a 10-day average, the owner or operator shall estimate the
total sulfur concentration using the measured total sulfur concentration
measured for that day.
(viii) For all days other than those during which data are being
collected to develop a 10-day average, the owner or operator shall
multiply the most recent 10-day average total sulfur-to-H2S
ratio by the daily average H2S concentrations obtained using
the monitor as required by paragraph (e)(2)(i) through (iii) of this
section to estimate total sulfur concentrations.
(ix) If the total sulfur-to-H2S ratio for a subsequent
weekly sample is outside the acceptable range for the most recent
distribution of daily ratios, the owner or operator shall develop a new
10-day average ratio and acceptable range based on data for the outlying
weekly sample plus data collected over the following 9 operating days.
(3) SO2 monitoring requirements. The owner or operator shall
install, operate, calibrate, and maintain an instrument for continuously
monitoring and recording the concentration of SO2 from a
process heater or other fuel gas combustion device that is combusting
gas representative of the fuel gas in the flare gas line according to
the requirements in paragraph (a)(1) of this section, determine the F
factor of the fuel gas at least daily according to the requirements in
paragraphs (d)(2) through (4) of this section, determine the higher
heating value of the fuel gas at least daily according to the
requirements in paragraph (d)(7) of this section, and calculate the
total sulfur content (as SO2) in the fuel gas using Equation
15 of this section.
[[Page 373]]
[GRAPHIC] [TIFF OMITTED] TR01DE15.007
Where:
TSFG = Total sulfur concentration, as SO2, in
the fuel gas, ppmv.
CSO2 = Concentration of SO2 in the exhaust
gas, ppmv (dry basis at 0-percent excess air).
Fd = F factor gas on dry basis at 0-percent excess air,
dscf/MMBtu.
HHVFG = Higher heating value of the fuel gas, MMBtu/scf.
(4) Exemptions from sulfur monitoring requirements. Flares
identified in paragraphs (e)(4)(i) through (iv) of this section are
exempt from the requirements in paragraphs (e)(1) through (3) of this
section. For each such flare, except as provided in paragraph
(e)(4)(iv), engineering calculations shall be used to calculate the
SO2 emissions in the event of a discharge that may trigger a
root cause analysis under Sec. 60.103a(c)(1).
(i) Flares that can only receive:
(A) Fuel gas streams that are inherently low in sulfur content as
described in paragraph (a)(3)(i) through (iv) of this section; and/or
(B) Fuel gas streams that are inherently low in sulfur content for
which the owner or operator has applied for an exemption from the
H2S monitoring requirements as described in paragraph (b) of
this section.
(ii) Emergency flares, provided that for each such flare, the owner
or operator complies with the monitoring alternative in paragraph (g) of
this section.
(iii) Flares equipped with flare gas recovery systems designed,
sized and operated to capture all flows except those resulting from
startup, shutdown or malfunction, provided that for each such flare, the
owner or operator complies with the monitoring alternative in paragraph
(g) of this section.
(iv) Secondary flares that receive gas diverted from the primary
flare. In the event of a discharge from the secondary flare, the sulfur
content measured by the sulfur monitor on the primary flare should be
used to calculate SO2 emissions, regardless of whether or not
the monitoring alternative in paragraph (g) of this section is selected
for the secondary flare.
(f) Flow monitoring for flares. Except as provided in paragraphs
(f)(2) and (h) of this section, the owner or operator of an affected
flare subject to Sec. 60.103a(c) through (e) shall install, operate,
calibrate and maintain, in accordance with the specifications in
paragraph (f)(1) of this section, a CPMS to measure and record the flow
rate of gas discharged to the flare. If a flow monitor is not already in
place, the owner or operator of a modified flare shall comply with the
requirements of this paragraph by no later than November 11, 2015 or
upon startup of the modified flare, whichever is later.
(1) The owner or operator shall install, calibrate, operate and
maintain each flow monitor according to the manufacturer's procedures
and specifications and the following requirements.
(i) Locate the monitor in a position that provides a representative
measurement of the total gas flow rate.
(ii) Use a flow sensor meeting an accuracy requirement of 20 percent of the flow rate at velocities ranging from
0.1 to 1 feet per second and an accuracy of 5
percent of the flow rate for velocities greater than 1 feet per second.
(iii) Use a flow monitor that is maintainable online, is able to
continuously correct for temperature and pressure and is able to record
flow in standard conditions (as defined in Sec. 60.2) over one-minute
averages.
(iv) At least quarterly, perform a visual inspection of all
components of the monitor for physical and operational integrity and all
electrical connections for oxidation and galvanic corrosion if the flow
monitor is not equipped with a redundant flow sensor.
(v) Recalibrate the flow monitor in accordance with the
manufacturer's procedures and specifications biennially (every two
years) or at the frequency specified by the manufacturer.
(2) Emergency flares, secondary flares and flares equipped with
flare gas recovery systems designed, sized and operated to capture all
flows except those resulting from startup,
[[Page 374]]
shutdown or malfunction are not required to install continuous flow
monitors; provided, however, that for any such flare, the owner or
operator shall comply with the monitoring alternative in paragraph (g)
of this section.
(g) Alternative monitoring for certain flares equipped with water
seals. The owner or operator of an affected flare subject to Sec.
60.103a(c) through (e) that can be classified as either an emergency
flare, a secondary flare or a flare equipped with a flare gas recovery
system designed, sized and operated to capture all flows except those
resulting from startup, shutdown or malfunction may, as an alternative
to the sulfur and flow monitoring requirements of paragraphs (e) and (f)
of this section, install, operate, calibrate and maintain, in accordance
with the requirements in paragraphs (g)(1) through (7) of this section,
a CPMS to measure and record the pressure in the flare gas header
between the knock-out pot and water seal and to measure and record the
water seal liquid level. If the required monitoring systems are not
already in place, the owner or operator of a modified flare shall comply
with the requirements of this paragraph by no later than November 11,
2015 or upon startup of the modified flare, whichever is later.
(1) Locate the pressure sensor(s) in a position that provides a
representative measurement of the pressure and locate the liquid seal
level monitor in a position that provides a representative measurement
of the water column height.
(2) Minimize or eliminate pulsating pressure, vibration and internal
and external corrosion.
(3) Use a pressure sensor and level monitor with a minimum tolerance
of 1.27 centimeters of water.
(4) Using a manometer, check pressure sensor calibration quarterly.
(5) Conduct calibration checks any time the pressure sensor exceeds
the manufacturer's specified maximum operating pressure range or install
a new pressure sensor.
(6) In a cascaded flare system that employs multiple secondary
flares, pressure and liquid level monitoring is required only on the
first secondary flare in the system (i.e., the secondary flare with the
lowest pressure release set point).
(7) This alternative monitoring option may be elected only for
flares with four or fewer pressure exceedances required to be reported
under Sec. 60.108a(d)(5) (``reportable pressure exceedances'') in any
365 consecutive calendar days. Following the fifth reportable pressure
exceedance in a 365-day period, the owner or operator must comply with
the sulfur and flow monitoring requirements of paragraphs (e) and (f) of
this section as soon as practical, but no later than 180 days after the
fifth reportable pressure exceedance in a 365-day period.
(h) Alternative monitoring for flares located in the BAAQMD or
SCAQMD. An affected flare subject to this subpart located in the BAAQMD
may elect to comply with the monitoring requirements in both BAAQMD
Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an
alternative to complying with the requirements of paragraphs (e) and (f)
of this section. An affected flare subject to this subpart located in
the SCAQMD may elect to comply with the monitoring requirements in
SCAQMD Rule 1118 as an alternative to complying with the requirements of
paragraphs (e) and (f) of this section.
(i) Excess emissions. For the purpose of reports required by Sec.
60.7(c), periods of excess emissions for fuel gas combustion devices
subject to the emissions limitations in Sec. 60.102a(g) and flares
subject to the concentration requirement in Sec. 60.103a(h) are defined
as specified in paragraphs (i)(1) through (5) of this section. Determine
a rolling 3-hour or a rolling daily average as the arithmetic average of
the applicable 1-hour averages (e.g., a rolling 3-hour average is the
arithmetic average of three contiguous 1-hour averages). Determine a
rolling 30-day or a rolling 365-day average as the arithmetic average of
the applicable daily averages (e.g., a rolling 30-day average is the
arithmetic average of 30 contiguous daily averages).
(1) SO 2 or H2S limits for fuel gas combustion devices. (i) If the
owner or operator of a fuel gas combustion device elects to comply with
the SO2 emission limits in Sec. 60.102a(g)(1)(i), each
rolling 3-hour period during which the average concentration of
SO2 as measured by
[[Page 375]]
the SO2 continuous monitoring system required under paragraph
(a)(1) of this section exceeds 20 ppmv, and each rolling 365-day period
during which the average concentration of SO2 as measured by
the SO2 continuous monitoring system required under paragraph
(a)(1) of this section exceeds 8 ppmv.
(ii) If the owner or operator of a fuel gas combustion device elects
to comply with the H2S concentration limits in Sec.
60.102a(g)(1)(ii), each rolling 3-hour period during which the average
concentration of H2S as measured by the H2S
continuous monitoring system required under paragraph (a)(2) of this
section exceeds 162 ppmv and each rolling 365-day period during which
the average concentration as measured by the H2S continuous
monitoring system under paragraph (a)(2) of this section exceeds 60
ppmv.
(iii) If the owner or operator of a fuel gas combustion device
becomes subject to the requirements of daily stain tube sampling in
paragraph (b)(3)(iii) of this section, each day during which the daily
concentration of H2S exceeds 162 ppmv and each rolling 365-
day period during which the average concentration of H2S
exceeds 60 ppmv.
(2) H2S concentration limits for flares. (i) Each rolling
3-hour period during which the average concentration of H2S
as measured by the H2S continuous monitoring system required
under paragraph (a)(2) of this section exceeds 162 ppmv.
(ii) If the owner or operator of a flare becomes subject to the
requirements of daily stain tube sampling in paragraph (b)(3)(iii) of
this section, each day during which the daily concentration of
H2S exceeds 162 ppmv.
(3) Rolling 30-day average NOX limits for fuel gas
combustion devices. Each rolling 30-day period during which the average
concentration of NOX as measured by the NOX
continuous monitoring system required under paragraph (c) or (d) of this
section exceeds:
(i) For a natural draft process heater, 40 ppmv and, if monitored
according to Sec. 60.107a(d), 0.040 lb/MMBtu;
(ii) For a forced draft process heater, 60 ppmv and, if monitored
according to Sec. 60.107a(d), 0.060 lb/MMBtu; and
(iii) For a co-fired process heater electing to comply with the
NOX limit in Sec. 60.102a(g)(2)(iii)(A) or (g)(2)(iv)(A),
150 ppmv.
(iv) The site-specific limit determined by the Administrator under
Sec. 60.102a(i).
(4) Daily NOX limits for fuel gas combustion devices.
Each day during which the concentration of NOX as measured by
the NOX continuous monitoring system required under paragraph
(d) of this section exceeds the daily average emissions limit calculated
using Equation 3 in Sec. 60.102a(g)(2)(iii)(B) or Equation 4 in Sec.
60.102a(g)(2)(iv)(B).
(5) Daily O2 limits for fuel gas combustion devices. Each day during
which the concentration of O2 as measured by the
O2 continuous monitoring system required under paragraph
(c)(6) or (d)(8) of this section exceeds the O2 operating
limit or operating curve determined during the most recent biennial
performance test.
[73 FR 35867, June 24, 2008, as amended at 77 FR 56473, Sep. 12, 2012;
80 FR 75235, Dec. 1, 2015]
Sec. 60.108a Recordkeeping and reporting requirements.
(a) Each owner or operator subject to the emissions limitations in
Sec. 60.102a shall comply with the notification, recordkeeping, and
reporting requirements in Sec. 60.7 and other requirements as specified
in this section.
(b) Each owner or operator subject to an emissions limitation in
Sec. 60.102a shall notify the Administrator of the specific monitoring
provisions of Sec. Sec. 60.105a, 60.106a and 60.107a with which the
owner or operator intends to comply. Each owner or operator of a co-
fired process heater subject to an emissions limitation in Sec.
60.102a(g)(2)(iii) or (iv) shall submit to the Administrator
documentation showing that the process heater meets the definition of a
co-fired process heater in Sec. 60.101a. Notifications required by this
paragraph shall be submitted with the notification of initial startup
required by Sec. 60.7(a)(3).
(c) The owner or operator shall maintain the following records:
(1) A copy of the flare management plan.
[[Page 376]]
(2) Records of information to document conformance with bag leak
detection system operation and maintenance requirements in Sec.
60.105a(c).
(3) Records of bag leak detection system alarms and actions
according to Sec. 60.105a(c).
(4) For each FCCU and fluid coking unit subject to the monitoring
requirements in Sec. 60.105a(b)(1), records of the average coke burn-
off rate and hours of operation.
(5) For each fuel gas stream to which one of the exemptions listed
in Sec. 60.107a(a)(3) applies, records of the specific exemption
determined to apply for each fuel stream. If the owner or operator
applies for the exemption described in Sec. 60.107a(a)(3)(iv), the
owner or operator must keep a copy of the application as well as the
letter from the Administrator granting approval of the application.
(6) Records of discharges greater than 500 lb SO2 in any
24-hour period from any affected flare, discharges greater than 500 lb
SO2 in excess of the allowable limits from a fuel gas
combustion device or sulfur recovery plant and discharges to an affected
flare in excess of 500,000 scf above baseline in any 24-hour period as
required by Sec. 60.103a(c). If the monitoring alternative provided in
Sec. 60.107a(g) is selected, the owner or operator shall record any
instance when the flare gas line pressure exceeds the water seal liquid
depth, except for periods attributable to compressor staging that do not
exceed the staging time specified in Sec. 60.103a(a)(3)(vii)(C). The
following information shall be recorded no later than 45 days following
the end of a discharge exceeding the thresholds:
(i) A description of the discharge.
(ii) The date and time the discharge was first identified and the
duration of the discharge.
(iii) The measured or calculated cumulative quantity of gas
discharged over the discharge duration. If the discharge duration
exceeds 24 hours, record the discharge quantity for each 24-hour period.
For a flare, record the measured or calculated cumulative quantity of
gas discharged to the flare over the discharge duration. If the
discharge duration exceeds 24 hours, record the quantity of gas
discharged to the flare for each 24-hour period. Engineering
calculations are allowed for fuel gas combustion devices, but are not
allowed for flares, except for those complying with the alternative
monitoring requirements in Sec. 60.107a(g).
(iv) For each discharge greater than 500 lb SO2 in any
24-hour period from a flare, the measured total sulfur concentration or
both the measured H2S concentration and the estimated total
sulfur concentration in the fuel gas at a representative location in the
flare inlet.
(v) For each discharge greater than 500 lb SO2 in excess
of the applicable short-term emissions limit in Sec. 60.102a(g)(1) from
a fuel gas combustion device, either the measured concentration of
H2S in the fuel gas or the measured concentration of
SO2 in the stream discharged to the atmosphere. Process
knowledge can be used to make these estimates for fuel gas combustion
devices, but cannot be used to make these estimates for flares, except
as provided in Sec. 60.107a(e)(4).
(vi) For each discharge greater than 500 lb SO2 in excess
of the allowable limits from a sulfur recovery plant, either the
measured concentration of reduced sulfur or SO2 discharged to
the atmosphere.
(vii) For each discharge greater than 500 lb SO2 in any
24-hour period from any affected flare or discharge greater than 500 lb
SO2 in excess of the allowable limits from a fuel gas
combustion device or sulfur recovery plant, the cumulative quantity of
H2S and SO2 released into the atmosphere. For
releases controlled by flares, assume 99-percent conversion of reduced
sulfur or total sulfur to SO2. For fuel gas combustion
devices, assume 99-percent conversion of H2S to
SO2.
(viii) The steps that the owner or operator took to limit the
emissions during the discharge.
(ix) The root cause analysis and corrective action analysis
conducted as required in Sec. 60.103a(d), including an identification
of the affected facility, the date and duration of the discharge, a
statement noting whether the discharge resulted from the same root
cause(s) identified in a previous analysis and either a description of
the recommended corrective action(s) or an
[[Page 377]]
explanation of why corrective action is not necessary under Sec.
60.103a(e).
(x) For any corrective action analysis for which corrective actions
are required in Sec. 60.103a(e), a description of the corrective
action(s) completed within the first 45 days following the discharge
and, for action(s) not already completed, a schedule for implementation,
including proposed commencement and completion dates.
(xi) For each discharge from any affected flare that is the result
of a planned startup or shutdown of a refinery process unit or ancillary
equipment connected to the affected flare, a statement that a root cause
analysis and corrective action analysis are not necessary because the
owner or operator followed the flare management plan.
(7) If the owner or operator elects to comply with Sec.
60.107a(e)(2) for a flare, records of the H2S and total
sulfur analyses of each grab or integrated sample, the calculated daily
total sulfur-to-H2S ratios, the calculated 10-day average
total sulfur-to-H2S ratios and the 95-percent confidence
intervals for each 10-day average total sulfur-to-H2S ratio.
(d) Each owner or operator subject to this subpart shall submit an
excess emissions report for all periods of excess emissions according to
the requirements of Sec. 60.7(c) except that the report shall contain
the information specified in paragraphs (d)(1) through (7) of this
section.
(1) The date that the exceedance occurred;
(2) An explanation of the exceedance;
(3) Whether the exceedance was concurrent with a startup, shutdown,
or malfunction of an affected facility or control system; and
(4) A description of the action taken, if any.
(5) The information described in paragraph (c)(6) of this section
for all discharges listed in paragraph (c)(6) of this section. For a
flare complying with the monitoring alternative under Sec. 60.107a(g),
following the fifth discharge required to be recorded under paragraph
(c)(6) of this section and reported under this paragraph, the owner or
operator shall include notification that monitoring systems will be
installed according to Sec. 60.107a(e) and (f) within 180 days
following the fifth discharge.
(6) For any periods for which monitoring data are not available, any
changes made in operation of the emission control system during the
period of data unavailability which could affect the ability of the
system to meet the applicable emission limit. Operations of the control
system and affected facility during periods of data unavailability are
to be compared with operation of the control system and affected
facility before and following the period of data unavailability.
(7) A written statement, signed by a responsible official,
certifying the accuracy and completeness of the information contained in
the report.
[73 FR 35867, June 24, 2008, as amended at 77 FR 56479, Sep. 12, 2012]
Sec. 60.109a Delegation of authority.
(a) This subpart can be implemented and enforced by the U.S. EPA or
a delegated authority such as a State, local, or tribal agency. You
should contact your U.S. EPA Regional Office to find out if this subpart
is delegated to a State, local, or tribal agency within your State.
(b) In delegating implementation and enforcement authority of this
subpart to a state, local or tribal agency, the approval authorities
contained in paragraphs (b)(1) through (4) of this section are retained
by the Administrator of the U.S. EPA and are not transferred to the
state, local or tribal agency.
(1) Approval of a major change to test methods under Sec. 60.8(b).
A ``major change to test method'' is defined in 40 CFR 63.90.
(2) Approval of a major change to monitoring under Sec. 60.13(i). A
``major change to monitoring'' is defined in 40 CFR 63.90.
(3) Approval of a major change to recordkeeping/reporting under
Sec. 60.7(b) through (f). A ``major change to recordkeeping/reporting''
is defined in 40 CFR 63.90.
(4) Approval of an application for an alternative means of emission
limitation under Sec. 60.103a(j) of this subpart.
[73 FR 35867, June 24, 2008, as amended at 77 FR 56480, Sep. 12, 2012]
[[Page 378]]
Sec. Table 1 to Subpart Ja of Part 60--Molar Exhaust Volumes and Molar
Heat Content of Fuel Gas Constituents
------------------------------------------------------------------------
MEV\a\ MHC\b\
Constituent dscf/mol Btu/mol
------------------------------------------------------------------------
Methane (CH4)..................................... 7.29 842
Ethane (C2H6)..................................... 12.96 1,475
Hydrogen (H2)..................................... 1.61 269
Ethene (C2H4)..................................... 11.34 1,335
Propane (C3H8).................................... 18.62 2,100
Propene (C3H6).................................... 17.02 1,947
Butane (C4H10).................................... 24.30 2,717
Butene (C4H8)..................................... 22.69 2,558
Inerts............................................ 0.85 0
------------------------------------------------------------------------
\a\ MEV = molar exhaust volume, dry standard cubic feet per gram-mole
(dscf/g-mol) at standard conditions of 68 [deg]F and 1 atmosphere.
\b\ MHC = molar heat content (higher heating value basis), Btu per gram-
mole (Btu/g-mol).
[77 FR 56480, Sep. 12, 2012]