40 CFR 60.107a - Monitoring of emissions and operations for fuel gas combustion devices.

§ 60.107a Monitoring of emissions and operations for fuel gas combustion devices.
(a) Fuel gas combustion devices subject to SO 2 or H 2 S limit. The owner or operator of a fuel gas combustion device that is subject to the requirements in § 60.102a(g) shall comply with the requirements in paragraph (a)(1) of this section for SO2 emissions or paragraph (a)(2) of this section for H2S emissions.
(1) The owner or operator of a fuel gas combustion device subject to the SO2 emissions limits in § 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 part 60. The span value for the SO2 monitor is 50 ppm SO2.
(ii) The owner or operator shall conduct performance evaluations for the SO2 monitor according to the requirements of § 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 § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60. Samples taken by Method 6 of appendix A-4 to part 60 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.
(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 § 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 § 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 subject to the H2S concentration limits in § 60.102a(g)(1)(ii) 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.
(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 320 ppmv H2S.
(ii) The owner or operator shall conduct performance evaluations for each H2S monitor according to the requirements of § 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 § 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 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.
(3) The owner or operator of a fuel gas combustion device is not required to comply with paragraph (a)(1) or (2) of this section for fuel gas streams that are exempt under § 60.102a(h) and fuel gas streams combusted in a process heater or other fuel gas combustion device 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 H 2 S monitoring requirements for low-sulfur fuel gas streams. The owner or operator of a fuel gas combustion device 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) 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 ppm 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, Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,” 1986 Revision (incorporated by reference—see § 60.17), with ranges 0-10/0-100 ppm (N = 10/1) 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., 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. 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 must determine a rolling 365-day average using the stain sampling results; an average H2S concentration of 5 ppmv must be used for days prior to the operation change.
(c) Process heaters subject to NO X limit. The owner or operator of a process heater subject to the NOX emission limit in § 60.102a(g)(2) 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. 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 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 § 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 § 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 § 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 § 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 low-NOX burners (LNB) or ultra low-NOX burners (ULNB) is not subject to the monitoring requirements in paragraphs (c)(1) through (5) of this section. The owner or operator of such a process heater must conduct biennial performance tests to demonstrate compliance.
(d) Sulfur monitoring for affected flares. The owner or operator of an affected flare subject to § 60.103a(b) shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of reduced sulfur in flare gas. The owner or operator of a modified flare shall install this instrument by no later than 1 year after the flare becomes an affected flare subject to this subpart.
(1) The owner or operator shall install, operate, and maintain each reduced sulfur CEMS according to Performance Specification 5 of appendix B to part 60.
(2) The owner or operator shall conduct performance evaluations of each reduced sulfur monitor according to the requirements in § 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 § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.
(3) The owner or operator shall comply with the applicable quality assurance procedures in appendix F to part 60 for each reduced sulfur monitor.
(e) Flow monitoring for flares. The owner or operator of an affected flare subject to § 60.102a(g)(3) shall install, operate, calibrate, and maintain CPMS to measure and record the exhaust gas flow rate. The owner or operator of a modified flare shall install this instrument by no later than 1 year after the flare becomes an affected flare subject to this subpart.
(1) The CPMS must be able to correct for the temperature and pressure of the system and output flow in standard conditions as defined in § 60.2.
(2) The owner or operator shall install, operate, and maintain each CPMS according to the manufacturer's specifications and requirements.
(f) Excess emissions. For the purpose of reports required by § 60.7(c), periods of excess emissions for fuel gas combustion devices subject to the emissions limitations in § 60.102a(g) are defined as specified in paragraphs (f)(1) through (4) of this section. Note: Determine all averages 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) All rolling 3-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 20 ppmv, and all rolling 365-day periods during which the average concentration as measured by the SO2 continuous monitoring system required under paragraph (a)(1) of this section exceeds 8 ppmv; or
(2) All rolling 3-hour periods 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, all days in which the concentration of H2S as measured by daily stain tube sampling required under paragraph (b)(3)(iii) of this section exceeds 162 ppmv, and all rolling 365-day periods during which the average concentration as measured by the H2S continuous monitoring system under paragraph (a)(2) of this section exceeds 60 ppmv.
(3) All rolling 24-hour periods during which the average concentration of NOX as measured by the NOX continuous monitoring system required under paragraph (c) of this section exceeds 40 ppmv.
(4) All rolling 30-day periods during which the average flow rate to an affected flare as measured by the monitoring system required under paragraph (e) of this section exceeds 250,000 scfd.
Effective Date Note:
At 73 FR 78552, Dec. 22, 2008, in § 60.107a, paragraphs (d) and (e) were stayed from Feb. 24, 2009 until further notice.
Beta! The text on the eCFR tab represents the unofficial eCFR text at ecfr.gov.
§ 60.107a Monitoring of emissions and operations for fuel gas combustion devices and flares.
Link to an amendment published at 80 FR 75235, Dec. 1, 2015.

(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 § 60.102a(g)(1) and elects to comply with the SO2 emission limits in § 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 § 60.102a(g)(1) and elects to comply with the H2S concentration limits in § 60.102a(g)(1)(ii) or a flare that is subject to the H2S concentration requirement in § 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 § 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 part 60. The span value for the SO2 monitor is 50 ppm SO2.

(ii) The owner or operator shall conduct performance evaluations for the SO2 monitor according to the requirements of § 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 § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60. Samples taken by Method 6 of appendix A-4 to part 60 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.

(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 § 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 § 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 § 60.102a(g)(1)(ii) or a flare that is subject to the H2S concentration requirement in § 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 § 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 § 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 § 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 § 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 § 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 § 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 § 60.100a.

(B) The owner or operator had an approved alternative monitoring plan or plans pursuant to § 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 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 §§ 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 H 2 S 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 ppm 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, Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,” 1986 Revision (incorporated by reference - see § 60.17), with ranges 0-10/0-100 ppm (N = 10/1) 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, 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. 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 NO X concentration-based limit. The owner or operator of a process heater subject to the NOX emissions limit in § 60.102a(g)(2) and electing to comply with the applicable emissions limit in § 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 § 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 § 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 § 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 § 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 § 60.104a(i), establish a maximum excess O2 operating limit or operating curve according to the requirements in § 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 NO X heating value-based or mass-based limit. The owner or operator of a process heater subject to the NOX emissions limit in § 60.102a(g)(2) and electing to comply with the applicable emissions limit in § 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 § 60.102a(g)(2) and electing to comply with the heating value-based limit in § 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-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 10 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).

View or download PDF

Where:
Fd = F factor on dry basis at 0-percent 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 § 60.17);

(iii) ASTM D1946-90 (Reapproved 2006)(incorporated by reference-see § 60.17);

(iv) ASTM D6420-99 (Reapproved 2004)(incorporated by reference-see § 60.17);

(v) GPA 2261-00 (incorporated by reference-see § 60.17); or

(vi) ASTM UOP539-97 (incorporated by reference-see § 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 °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 °F and 1 atmosphere). The owner or operator shall conduct performance evaluations of each fuel gas flow monitor according to the requirements in § 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 § 60.17);

(iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008) (incorporated by reference-see § 60.17);

(iv) ASME MFC-6M-1998 (Reaffirmed 2005) (incorporated by reference-see § 60.17);

(v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006) (incorporated by reference-see § 60.17);

(vi) ASME MFC-11M-2006 (incorporated by reference-see § 60.17);

(vii) ASME MFC-14M-2003 (incorporated by reference-see § 60.17);

(viii) ASME MFC-18M-2001 (incorporated by reference-see § 60.17);

(ix) AGA Report No. 3, Part 1 (incorporated by reference-see § 60.17);

(x) AGA Report No. 3, Part 2 (incorporated by reference-see § 60.17);

(xi) AGA Report No. 11 (incorporated by reference-see § 60.17);

(xii) AGA Report No. 7 (incorporated by reference-see § 60.17); and

(xiii) API Manual of Petroleum Measurement Standards, Chapter 22, Section 2 (incorporated by reference-see § 60.17).

(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 § 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 § 60.17);

(iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006) (incorporated by reference-see § 60.17);

(iv) ASME MFC-16-2007 (incorporated by reference-see § 60.17);

(v) ASME MFC-22-2007 (incorporated by reference-see § 60.17); or

(vi) ISO 8316 (incorporated by reference-see § 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 § 60.17).

(ii) ASTM D1826-94 (Reapproved 2003) (incorporated by reference-see § 60.17).

(iii) ASTM D1945-03 (Reapproved 2010) (incorporated by reference-see § 60.17).

(iv) ASTM D1946-90 (Reapproved 2006) (incorporated by reference-see § 60.17).

(v) ASTM D3588-98 (Reapproved 2003) (incorporated by reference-see § 60.17).

(vi) ASTM D4809-06 (incorporated by reference-see § 60.17).

(vii) ASTM D4891-89 (Reapproved 2006) (incorporated by reference-see § 60.17).

(viii) GPA 2172-09 (incorporated by reference-see § 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 § 60.104a(i), establish a maximum excess O2 operating limit or operating curve according to the requirements in § 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 § 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 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 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 § 60.13(c) and Performance Specification 5 of appendix B to part 60. For flares that routinely have flow, the owner or operator of each total reduced sulfur monitor shall use EPA Method 15A of appendix A-5 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference-see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60. The alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of appendix B to part 60 (cylinder gas audits) may be used for conducting the relative accuracy evaluations. For flares that do not receive routine flow, the alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of appendix B to part 60 (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) H 2S monitoring requirements. The owner or operator shall install, operate, calibrate, and maintain an instrument 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 § 60.13(c) and Performance Specification 7 of appendix B to part 60. For flares that routinely have flow, the owner or operator shall use EPA Method 11, 15 or 15A of appendix A-5 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60. The alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of appendix B to part 60 (cylinder gas audits) may be used for conducting the relative accuracy evaluations. For flares that do not receive routine flow, the alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of appendix B to part 60 (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 H2S monitor.

(iv) In the first 10 operating days after the date the flare must begin to comply with § 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 § 60.17) or ASTM Method D5504-08 (incorporated by reference - see § 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 11 of this section.

View or download PDF

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) SO 2 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 12 of this section.

View or download PDF

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 § 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 § 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 with a measurement sensitivity of no more than 5 percent of the flow rate or 10 cubic feet per minute, whichever is greater.

(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 § 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, 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 § 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 § 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 § 60.7(c), periods of excess emissions for fuel gas combustion devices subject to the emissions limitations in § 60.102a(g) and flares subject to the concentration requirement in § 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 H2 S 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 § 60.102a(g)(1)(i), each rolling 3-hour 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 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 § 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 NO X 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 § 60.107a(d), 0.040 lb/MMBtu;

(ii) For a forced draft process heater, 60 ppmv and, if monitored according to § 60.107a(d), 0.060 lb/MMBtu; and

(iii) For a co-fired process heater electing to comply with the NOX limit in § 60.102a(g)(2)(iii)(A) or (g)(2)(iv)(A), 150 ppmv.

(iv) The site-specific limit determined by the Administrator under § 60.102a(i).

(4) Daily NO X 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 § 60.102a(g)(2)(iii)(B) or Equation 4 in § 60.102a(g)(2)(iv)(B).

(5) Daily O 2 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) 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]

This is a list of United States Code sections, Statutes at Large, Public Laws, and Presidential Documents, which provide rulemaking authority for this CFR Part.

This list is taken from the Parallel Table of Authorities and Rules provided by GPO [Government Printing Office].

It is not guaranteed to be accurate or up-to-date, though we do refresh the database weekly. More limitations on accuracy are described at the GPO site.


United States Code
U.S. Code: Title 42 - THE PUBLIC HEALTH AND WELFARE

§ 7401 - Congressional findings and declaration of purpose

§ 7402 - Cooperative activities

§ 7403 - Research, investigation, training, and other activities

§ 7404 - Research relating to fuels and vehicles

§ 7405 - Grants for support of air pollution planning and control programs

§ 7406 - Interstate air quality agencies; program cost limitations

§ 7407 - Air quality control regions

§ 7408 - Air quality criteria and control techniques

§ 7409 - National primary and secondary ambient air quality standards

§ 7410 - State implementation plans for national primary and secondary ambient air quality standards

§ 7411 - Standards of performance for new stationary sources

§ 7412 - Hazardous air pollutants

§ 7413 - Federal enforcement

§ 7414 - Recordkeeping, inspections, monitoring, and entry

§ 7415 - International air pollution

§ 7416 - Retention of State authority

§ 7417 - Advisory committees

§ 7418 - Control of pollution from Federal facilities

§ 7419 - Primary nonferrous smelter orders

§ 7420 - Noncompliance penalty

§ 7421 - Consultation

§ 7422 - Listing of certain unregulated pollutants

§ 7423 - Stack heights

§ 7424 - Assurance of adequacy of State plans

§ 7425 - Measures to prevent economic disruption or unemployment

§ 7426 - Interstate pollution abatement

§ 7427 - Public notification

§ 7428 - State boards

§ 7429 - Solid waste combustion

§ 7430 - Emission factors

§ 7431 - Land use authority

§ 7450 to 7459 - Repealed. Pub. L. 101–549, title VI, § 601, Nov. 15, 1990, 104 Stat. 2648

§ 7470 - Congressional declaration of purpose

§ 7471 - Plan requirements

§ 7472 - Initial classifications

§ 7473 - Increments and ceilings

§ 7474 - Area redesignation

§ 7475 - Preconstruction requirements

§ 7476 - Other pollutants

§ 7477 - Enforcement

§ 7478 - Period before plan approval

§ 7479 - Definitions

§ 7491 - Visibility protection for Federal class I areas

§ 7492 - Visibility

§ 7501 - Definitions

§ 7502 - Nonattainment plan provisions in general

§ 7503 - Permit requirements

§ 7504 - Planning procedures

§ 7505 - Environmental Protection Agency grants

§ 7505a - Maintenance plans

§ 7506 - Limitations on certain Federal assistance

§ 7506a - Interstate transport commissions

§ 7507 - New motor vehicle emission standards in nonattainment areas

§ 7508 - Guidance documents

§ 7509 - Sanctions and consequences of failure to attain

§ 7509a - International border areas

§ 7511 - Classifications and attainment dates

§ 7511a - Plan submissions and requirements

§ 7511b - Federal ozone measures

§ 7511c - Control of interstate ozone air pollution

§ 7511d - Enforcement for Severe and Extreme ozone nonattainment areas for failure to attain

§ 7511e - Transitional areas

§ 7511f - NOx and VOC study

§ 7512 - Classification and attainment dates

§ 7512a - Plan submissions and requirements

§ 7513 - Classifications and attainment dates

§ 7513a - Plan provisions and schedules for plan submissions

§ 7513b - Issuance of RACM and BACM guidance

§ 7514 - Plan submission deadlines

§ 7514a - Attainment dates

§ 7515 - General savings clause

§ 7521 - Emission standards for new motor vehicles or new motor vehicle engines

§ 7522 - Prohibited acts

§ 7523 - Actions to restrain violations

§ 7524 - Civil penalties

§ 7525 - Motor vehicle and motor vehicle engine compliance testing and certification

§ 7541 - Compliance by vehicles and engines in actual use

§ 7542 - Information collection

§ 7543 - State standards

§ 7544 - State grants

§ 7545 - Regulation of fuels

§ 7546 - Renewable fuel

§ 7547 - Nonroad engines and vehicles

§ 7548 - Study of particulate emissions from motor vehicles

§ 7549 - High altitude performance adjustments

§ 7550 - Definitions

§ 7551 - Omitted

§ 7552 - Motor vehicle compliance program fees

§ 7553 - Prohibition on production of engines requiring leaded gasoline

§ 7554 - Urban bus standards

§ 7571 - Establishment of standards

§ 7572 - Enforcement of standards

§ 7573 - State standards and controls

§ 7574 - Definitions

§ 7581 - Definitions

§ 7582 - Requirements applicable to clean-fuel vehicles

§ 7583 - Standards for light-duty clean-fuel vehicles

§ 7584 - Administration and enforcement as per California standards

§ 7585 - Standards for heavy-duty clean-fuel vehicles (GVWR above 8,500 up to 26,000 lbs.)

§ 7586 - Centrally fueled fleets

§ 7587 - Vehicle conversions

§ 7588 - Federal agency fleets

§ 7589 - California pilot test program

§ 7590 - General provisions

§ 7601 - Administration

Title 40 published on 2015-07-01

The following are ALL rules, proposed rules, and notices (chronologically) published in the Federal Register relating to 40 CFR Part 60 after this date.

  • 2015-12-01; vol. 80 # 230 - Tuesday, December 1, 2015
    1. 80 FR 75178 - Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards
      GPO FDSys XML | Text
      ENVIRONMENTAL PROTECTION AGENCY, 40 CFR Parts 60 and 63
      Final rule.
      This final action is effective on February 1, 2016. The incorporation by reference of certain publications for part 63 listed in the rule is approved by the Director of the Federal Register as of February 1, 2016. The incorporation by reference of certain publications for part 60 listed in the rule were approved by the Director of the Federal Register as of June 24, 2008.
      40 CFR Part 60