40 CFR 60.104a - Performance tests.

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§ 60.104a Performance tests.
(a) The owner or operator shall conduct a performance test for each FCCU, FCU, sulfur recovery plant, and fuel gas combustion device to demonstrate initial compliance with each applicable emissions limit in § 60.102a according to the requirements of § 60.8. The notification requirements of § 60.8(d) apply to the initial performance test and to subsequent performance tests required by paragraph (b) of this section (or as required by the Administrator), but does not apply to performance tests conducted for the purpose of obtaining supplemental data because of continuous monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments.
(b) The owner or operator of a FCCU or FCU that elects to monitor control device operating parameters according to the requirements in § 60.105a(b), to use bag leak detectors according to the requirements in § 60.105a(c), or to use COMS according to the requirements in § 60.105a(e) shall conduct a PM performance test at least once every 12 months and furnish the Administrator a written report of the results of each test.
(c) In conducting the performance tests required by this subpart (or as requested by the Administrator), the owner or operator shall use the test methods in 40 CFR part 60, Appendices A-1 through A-8 or other methods as specified in this section, except as provided in § 60.8(b).
(d) The owner or operator shall determine compliance with the PM, NO[=E T=8052]X, SO[=E T=8052]2, and CO emissions limits in § 60.102a(b) for FCCU and FCU using the following methods and procedures:
(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses.
(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate.
(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.
(4) Method 5, 5B, or 5F of appendix A-3 to part 60 for determining PM emissions and associated moisture content from a FCCU or FCU without a wet scrubber subject to the emissions limit in § 63.102a(b)(1). Use Method 5 or 5B of appendix A-3 to part 60 for determining PM emissions and associated moisture content from a FCCU or FCU with a wet scrubber subject to the emissions limit in § 63.102a(b)(1).
(i) The PM performance test consists of 3 valid test runs; the duration of each test run must be no less than 60 minutes.
(ii) The emissions rate of PM (EPM) is computed for each run using Equation 3 of this section:
Where:
E = Emission rate of PM, g/kg, lbs per 1,000 lbs (lb/1,000 lbs) of coke burn-off;
cs = Concentration of total PM, grams per dry standard cubic meter (g/dscm), gr/dscf;
Qsd = Volumetric flow rate of effluent gas, dry standard cubic meters per hour, dry standard cubic feet per hour;
Rc = Coke burn-off rate, kilograms per hour (kg/hr), lbs per hour (lbs/hr) coke; and
K = Conversion factor, 1.0 grams per gram (7,000 grains per lb).
(iii) The coke burn-off rate (R[=E T=8052]c) is computed for each run using Equation 4 of this section:
Where:
Rc = Coke burn-off rate, kg/hr (lb/hr);
Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emissions control or energy recovery system that burns auxiliary fuel, dry standard cubic meters per minute (dscm/min), dry standard cubic feet per minute (dscf/min);
Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air to FCCU regenerator or fluid coking unit, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
%O2 = O2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
%Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis);
K1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-dsc-%) [0.0186 (lb-min)/(hr-dscf-%)];
K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lb-min)/(hr-dscf)]; and
K3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].
(iv) During the performance test, the volumetric flow rate of exhaust gas from catalyst regenerator (Q[=E T=8052]r) before any emission control or energy recovery system that burns auxiliary fuel is measured using Method 2 of appendix A-1 to part 60.
(v) For subsequent calculations of coke burn-off rates or exhaust gas flow rates, the volumetric flow rate of Q[=E T=8052]r is calculated using average exhaust gas concentrations as measured by the monitors in § 60.105a(b)(2), if applicable, using Equation 5 of this section:
Where:
Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emission control or energy recovery system that burns auxiliary fuel, dscm/min (dscf/min);
Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air to FCCU regenerator or fluid coking unit, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis). When no auxiliary fuel is burned and a continuous CO monitor is not required in accordance with § 60.105a(g)(3), assume %CO to be zero;
%O2 = O2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis); and
%Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis).
(5) Method 6, 6A, or 6C of appendix A-4 to part 60 for moisture content and for the concentration of SO[=E T=8052]2; the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60.
(6) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the concentration of NO[=E T=8052]X calculated as nitrogen dioxide (NO[=E T=8052]2); the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60.
(7) Method 10, 10A, or 10B of appendix A-4 to part 60 for moisture content and for the concentration of CO. The sampling time for each run must be 60 minutes.
(8) The owner or operator shall adjust PM, NO[=E T=8052]X, SO[=E T=8052]2, and CO pollutant concentrations to 0 percent excess air or 0 percent O[=E T=8052]2 using Equation 6 of this section:
Where:
Cadj = pollutant concentration adjusted to 0 percent excess air or O2, parts per million (ppm) or g/dscm;
Cmeas = pollutant concentration measured on a dry basis, ppm or g/dscm;
20.9c = 20.9 percent O2-0.0 percent O2 (defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry basis, percent.
(e) The owner or operator of a FCCU or FCU that is controlled by an electrostatic precipitator or wet scrubber and that is subject to control device operating parameter limits in § 60.102a(c) shall establish the limits based on the performance test results according to the following procedures:
(1) Reduce the parameter monitoring data to hourly averages for each test run;
(2) Determine the hourly average operating limit for each required parameter as the average of the three test runs.
(f) The owner or operator of an FCCU or FCU that uses cyclones to comply with the PM limit in § 60.102a(b)(1) and elects to comply with the COMS alternative monitoring option in § 60.105a(d) shall establish a site-specific opacity operating limit according to the procedures in paragraphs (f)(1) through (3) of this section.
(1) Collect COMS data every 10 seconds during the entire period of the PM performance test and reduce the data to 6-minute averages.
(2) Determine and record the hourly average opacity from all the 6-minute averages.
(3) Compute the site-specific limit using Equation 7 of this section:
Where:
Opacity limit = Maximum permissible hourly average opacity, percent, or 10 percent, whichever is greater;
Opacityst = Hourly average opacity measured during the source test runs, percent; and
PMEmRst = PM emission rate measured during the source test, lb/1,000 lbs coke burn.
(g) The owner or operator of a FCCU or FCU that is exempt from the requirement to install and operate a CO CEMS pursuant to § 60.105a(h)(3) and that is subject to control device operating parameter limits in § 60.102a(c) shall establish the limits based on the performance test results using the procedures in paragraphs (g)(1) and (2) of this section.
(1) Reduce the temperature and O[=E T=8052]2 concentrations from the parameter monitoring systems to hourly averages for each test run.
(2) Determine the operating limit for temperature and O[=E T=8052]2 concentrations as the average of the average temperature and O[=E T=8052]2 concentration for the three test runs.
(h) The owner or operator shall determine compliance with the SO[=E T=8052]2 and H[=E T=8052]2S emissions limits for sulfur recovery plants in §§ 60.102a(f)(1)(i), 60.102a(f)(1)(iii), 60.102a(f)(1)(iii), 60.102a(f)(2)(i), and 60.102a(f)(2)(iii) and the reduced sulfur compounds and H[=E T=8052]2S emissions limits for sulfur recovery plants in § 60.102a(f)(1)(ii) and § 60.102a(f)(2)(ii) using the following methods and procedures:
(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses.
(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate.
(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.
(4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO[=E T=8052]2 concentration. 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.
(5) Method 15 or 15A of appendix A-5 to part 60 or Method 16 of appendix A-6 to part 60 to determine the reduced sulfur compounds and H[=E T=8052]2S concentrations. 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.
(i) Each run consists of 16 samples taken over a minimum of 3 hours.
(ii) The owner or operator shall calculate the average H[=E T=8052]2S concentration after correcting for moisture and O[=E T=8052]2 as the arithmetic average of the H[=E T=8052]2S concentration for each sample during the run (ppmv, dry basis, corrected to 0 percent excess air).
(iii) The owner or operator shall calculate the SO[=E T=8052]2 equivalent for each run after correcting for moisture and O[=E T=8052]2 as the arithmetic average of the SO[=E T=8052]2 equivalent of reduced sulfur compounds for each sample during the run (ppmv, dry basis, corrected to 0 percent excess air).
(iv) The owner or operator shall use Equation 6 of this section to adjust pollutant concentrations to 0 percent O[=E T=8052]2 or 0 percent excess air.
(i) The owner or operator shall determine compliance with the SO[=E T=8052]2 and NO[=E T=8052]X emissions limits in § 60.102a(g) for a fuel gas combustion device according to the following test methods and procedures:
(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses;
(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate;
(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60;
(4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO2 concentration. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60.
(i) The performance test consists of 3 valid test runs; the duration of each test run must be no less than 1 hour.
(ii) If a single fuel gas combustion device having a common source of fuel gas is monitored as allowed under § 60.107a(a)(1)(v), only one performance test is required. That is, performance tests are not required when a new affected fuel gas combustion device is added to a common source of fuel gas that previously demonstrated compliance.
(5) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the concentration of NO[=E T=8052]X calculated as NO[=E T=8052]2; the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60.
(j) The owner or operator shall determine compliance with the H[=E T=8052]2S emissions limit in § 60.102a(g) for a fuel gas combustion device according to the following test methods and procedures:
(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses;
(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate;
(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60;
(4) Method 11, 15, or 15A of appendix A-5 to part 60 or Method 16 of appendix A-6 to part 60 for determining the H2S concentration for affected plants using an H2S monitor as specified in § 60.107a(a)(2). 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. The owner or operator may demonstrate compliance based on the mixture used in the fuel gas combustion device or for each individual fuel gas stream used in the fuel gas combustion device.
(i) For Method 11 of appendix A-5 to part 60, the sampling time and sample volume must be at least 10 minutes and 0.010 dscm (0.35 dscf). Two samples of equal sampling times must be taken at about 1-hour intervals. The arithmetic average of these two samples constitutes a run. For most fuel gases, sampling times exceeding 20 minutes may result in depletion of the collection solution, although fuel gases containing low concentrations of H[=E T=8052]2S may necessitate sampling for longer periods of time.
(ii) For Method 15 of appendix A-5 to part 60, at least three injects over a 1-hour period constitutes a run.
(iii) For Method 15A of appendix A-5 to part 60, a 1-hour sample constitutes a run. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.
(iv) If monitoring is conducted at a single point in a common source of fuel gas as allowed under § 60.107a(a)(2)(iv), only one performance test is required. That is, performance tests are not required when a new affected fuel gas combustion device is added to a common source of fuel gas that previously demonstrated compliance.

Title 40 published on 2014-07-01

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  • 2014-11-19; vol. 79 # 223 - Wednesday, November 19, 2014
    1. 79 FR 68777 - Reconsideration of Certain Startup/Shutdown Issues: National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units
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      ENVIRONMENTAL PROTECTION AGENCY
      Final rule; notice of final action on reconsideration.
      The effective date of the rule is November 19, 2014.
      40 CFR Parts 60 and 63

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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.

§ 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 - NO

§ 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 2014-07-01

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

  • 2014-12-12; vol. 79 # 239 - Friday, December 12, 2014
    1. 79 FR 73872 - Phosphoric Acid Manufacturing and Phosphate Fertilizer Production RTR and Standards of Performance for Phosphate Processing; Extension of Comment Period
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      ENVIRONMENTAL PROTECTION AGENCY
      Notice of proposed rulemaking; extension of public comment period.
      Comments. The public comment period for the proposed rule published in the Federal Register on November 7, 2014, (79 FR 66512) is being extended for 30 days to January 21, 2015.
      40 CFR Parts 60 and 63