[Title 40 CFR 60.49Da]
[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 Da - Standards of Performance for Electric Utility Steam]
[Sec. 60.49da - Emission monitoring.]
[From the U.S. Government Printing Office]
40PROTECTION OF ENVIRONMENT62009-07-012009-07-01falseEmission monitoring.60.49DaSec. 60.49DaPROTECTION OF ENVIRONMENTENVIRONMENTAL PROTECTION AGENCY (CONTINUED)AIR PROGRAMS (CONTINUED)STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES--Standards of Performance for Electric Utility Steam
Sec. 60.49Da Emission monitoring.
(a) 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 applicable requirements in paragraphs (a)(1) through
(3) of this section.
(1) Except as provided for in paragraph (a)(2) of this section, the
owner or operator of an affected facility, 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), or (iii)
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; or
(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 carbon monoxide (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.
(3) The owner or operators of an affected facility that meets the
conditions in paragraph (a)(2) of this section may, as an alternative to
COMS, elect to monitor visible emissions using the applicable procedures
specified in paragraphs (a)(3)(i) through (iv) of this section.
(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
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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)(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.
(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 30
calendar days according to the requirements in Sec. 60.50Da(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 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 Administrator. The
observations shall 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
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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) 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 SO2 emissions, except where natural gas
is the only fuel 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(d), (i), (j), or (k) 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 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
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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, malfunction or
emergency conditions, 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 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:
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------------------------------------------------------------------------
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.
(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 output for sources
demonstrating compliance with the output-based standard under Sec. Sec.
60.42Da(c), 60.43Da(i), 60.43Da(j), 60.44Da(d)(1), and 60.44Da(e).
(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 affected facilities generating process steam in combination
with electrical generation, the gross energy output is determined from
the gross electrical output measured in accordance with paragraph (k)(1)
of this section plus 75 percent of the gross thermal output (measured
relative to ISO conditions) of the process steam measured in accordance
with paragraph (k)(2) of this section.
(l) The owner or operator of an affected facility demonstrating
compliance with an output-based standard under Sec. 60.42Da, Sec.
60.43Da, Sec. 60.44Da, or Sec. 60.45Da 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 CD
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assessment, 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) The owner or operator of an affected facility demonstrating
compliance with an Hg limit in Sec. 60.45Da shall install and operate a
CEMS to measure and record the concentration of Hg in the exhaust gases
from each stack according to the requirements in paragraphs (p)(1)
through (p)(3) of this section. Alternatively, for an affected facility
that is also subject to the requirements of subpart I of part 75 of this
chapter, the owner or operator may install, certify, maintain, operate
and quality-assure the data from a Hg CEMS according to Sec. 75.10 of
this chapter and appendices A and B to part 75 of this chapter, in lieu
of following the procedures in paragraphs (p)(1) through (p)(3) of this
section.
(1) The owner or operator must install, operate, and maintain each
CEMS according to Performance Specification 12A in appendix B to this
part.
(2) The owner or operator must conduct a performance evaluation of
each CEMS according to the requirements of Sec. 60.13 and Performance
Specification 12A in appendix B to this part.
(3) The owner or operator must operate each CEMS according to the
requirements in paragraphs (p)(3)(i) through (iv) of this section.
(i) As specified in Sec. 60.13(e)(2), each CEMS must complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period.
(ii) The owner or operator must reduce CEMS data as specified in
Sec. 60.13(h).
(iii) The owner or operator shall use all valid data points
collected during the hour to calculate the hourly average Hg
concentration.
(iv) The owner or operator must record the results of each required
certification and quality assurance test of the CEMS.
(4) Mercury CEMS data collection must conform to paragraphs
(p)(4)(i) through (iv) of this section.
(i) For each calendar month in which the affected unit operates,
valid hourly Hg concentration data, stack gas volumetric flow rate data,
moisture data (if required), and electrical output data (i.e., valid
data for all of these parameters) shall be obtained for at least 75
percent of the unit operating hours in the month.
(ii) Data reported to meet the requirements of this subpart shall
not include hours of unit startup, shutdown, or malfunction. In
addition, for an affected facility that is also subject to subpart I of
part 75 of this chapter, data reported to meet the requirements of this
subpart 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.
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(iii) If valid data are obtained for less than 75 percent of the
unit operating hours in a month, you must discard the data collected in
that month and replace the data with the mean of the individual monthly
emission rate values determined in the last 12 months. In the 12-month
rolling average calculation, this substitute Hg emission rate shall be
weighted according to the number of unit operating hours in the month
for which the data capture requirement of Sec. 60.49Da(p)(4)(i) was not
met.
(iv) Notwithstanding the requirements of paragraph (p)(4)(iii) of
this section, if valid data are obtained for less than 75 percent of the
unit operating hours in another month in that same 12-month rolling
average cycle, discard the data collected in that month and replace the
data with the highest individual monthly emission rate determined in the
last 12 months. In the 12-month rolling average calculation, this
substitute Hg emission rate shall be weighted according to the number of
unit operating hours in the month for which the data capture requirement
of Sec. 60.49Da(p)(4)(i) was not met.
(q) As an alternative to the CEMS required in paragraph (p) of this
section, the owner or operator may use a sorbent trap monitoring system
(as defined in Sec. 72.2 of this chapter) to monitor Hg concentration,
according to the procedures described in Sec. 75.15 of this chapter and
appendix K to part 75 of this chapter.
(r) For Hg CEMS that measure Hg concentration on a dry basis or for
sorbent trap monitoring systems, the emissions data must be corrected
for the stack gas moisture content. A certified continuous moisture
monitoring system that meets the requirements of Sec. 75.11(b) of this
chapter is acceptable for this purpose. Alternatively, the appropriate
default moisture value, as specified in Sec. 75.11(b) or Sec. 75.12(b)
of this chapter, may be used.
(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.);
(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 limitation under Sec.
60.42Da(c)(1) shall install, certify, operate, and maintain a CEMS for
measuring PM emissions according to the requirements of paragraph (v) of
this section. An owner or operator of an affected facility demonstrating
compliance with the input-based emission limitation in Sec.
60.42Da(a)(1) or Sec. 60.42Da(c)(2) 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.
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(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 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 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) After July 1, 2010 or after Method 202 of appendix M of part 51
has been revised to minimize artifact measurement and notice of that
change has been published in the Federal Register, whichever is later,
for condensable PM emissions, Method 202 of appendix M of part 51 shall
be used; and
(iii) 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) After July 1, 2011, within 90 days after the date of completing
each performance evaluation required by paragraph (v) of this section,
the owner or operator of the affected facility must either submit the
test data to EPA by successfully entering the data electronically into
EPA's WebFIRE data base available at http://cfpub.epa.gov/oarweb/
index.cfm?action=fire.main or
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mail a copy to: United States Environmental Protection Agency; Energy
Strategies Group; 109 TW Alexander DR; Mail Code: D243-01; RTP, NC
27711.
(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 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
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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]