[Title 40 CFR 60.45]
[Code of Federal Regulations (annual edition) - July 1, 2009 Edition]
[Title 40 - PROTECTION OF ENVIRONMENT]
[Chapter I - ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)]
[Subchapter C - AIR PROGRAMS (CONTINUED)]
[Part 60 - STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES--]
[Subpart D - Standards of Performance for Fossil-Fuel-Fired Steam]
[Sec. 60.45 - Emissions and fuel monitoring.]
[From the U.S. Government Printing Office]
40PROTECTION OF ENVIRONMENT62009-07-012009-07-01falseEmissions and fuel monitoring.60.45Sec. 60.45PROTECTION OF ENVIRONMENTENVIRONMENTAL PROTECTION AGENCY (CONTINUED)AIR PROGRAMS (CONTINUED)STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES--Standards of Performance for Fossil-Fuel-Fired Steam
Sec. 60.45 Emissions and fuel monitoring.
(a) Each owner or operator shall install, calibrate, maintain, and
operate continuous opacity monitoring system (COMS) for measuring
opacity and a 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 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 burns 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, CEMS
for measuring the opacity of emissions and SO2 emissions are not
required if the owner or operator monitors SO2 emissions by fuel
sampling and analysis or fuel receipts.
[[Page 141]]
(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 does not install any CEMS for sulfur
oxides and NOX, as provided under paragraphs (b)(1) and
(b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for
measuring either O2 or CO2 is not required.
(5) An owner or operator may petition the Administrator (in writing)
to install a PM CEMS as an alternative to the CEMS for monitoring
opacity emissions.
(6) A CEMS for measuring the opacity of emissions is not required
for a fossil fuel-fired steam generator 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,
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and the date, time, and description of the corrective action.
(7) The owner or operator of an affected facility subject to an
opacity standard under Sec. 60.42 and that elects to not install 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 and shall comply with either paragraphs (b)(7)(i),
(b)(7)(ii), or (b)(7)(iii) of this section. If during the initial 60
minutes of observation all 6-minute averages are less than 10 percent
and all individual 15-second observations are less than or equal to 20
percent, the observation period may be reduced from 3 hours to 60
minutes.
(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;
(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;
(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
(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 30 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 30
calendar days according to the requirements in Sec. 60.46(b)(3).
(B) If no visible emissions are observed for 30 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during
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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, 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.
(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
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used to convert the continuous monitoring data into units of the
applicable standards (ng/J, lb/MMBtu):
(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 145]]
[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
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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
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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]