52.1392—Federal Implementation Plan for the Billings/Laurel Area.
(a) Applicability.
This section applies to the owner(s) or operator(s), including any new owner(s) or operator(s) in the event of a change in ownership or operation, of the following facilities in the Billings/Laurel, Montana area: CHS Inc. Petroleum Refinery, Laurel Refinery, 803 Highway 212 South, Laurel, MT; ConocoPhillips Petroleum Refinery, Billings Refinery, 401 South 23rd St., Billings, MT; ExxonMobil Petroleum Refinery, 700 Exxon Road, Billings, MT; and Montana Sulphur & Chemical Company, 627 Exxon Road, Billings, MT.
(b) Scope.
The facilities listed in paragraph (a) of this section are also subject to the Billings/Laurel SO2 SIP, as approved at 40 CFR 52.1370(c)(46) and (52). In cases where the provisions of this FIP address emissions activities differently or establish a different requirement than the provisions of the approved SIP, the provisions of this FIP take precedence.
(c) Definitions.
For the purpose of this section, we are defining certain words or initials as described in this paragraph. Terms not defined below that are defined in the Clean Air Act or regulations implementing the Clean Air Act, shall have the meaning set forth in the Clean Air Act or such regulations.
(2)
Annual Emissions means the amount of SO2 emitted in a calendar year, expressed in pounds per year rounded to the nearest pound, where:
Annual emissions = Σ Daily emissions within the calendar year.
(3)
Calendar Day means a 24-hour period starting at 12 midnight and ending at 12 midnight, 24 hours later.
(4)
Clock Hour means a twenty-fourth ( 1/24) of a calendar day; specifically any of the standard 60-minute periods in a day that are identified and separated on a clock by the whole numbers one (1) through 12.
(5)
Continuous Emission Monitoring System or CEMS means all continuous concentration and volumetric flow rate monitors, associated data acquisition equipment, and all other equipment necessary to meet the requirements of this section for continuous monitoring.
(6)
Daily Emissions means the amount of SO2 emitted in a calendar day, expressed in pounds per day rounded to the nearest tenth ( 1/10) of a pound, where:
Daily emissions = Σ 3-hour emissions within a calendar day.
(8)
Exhibit means for a given facility named in paragraph (a) of this section, exhibit A to the stipulation of the Montana Department of Environmental Quality and that facility, adopted by the Montana Board of Environmental Review on either June 12, 1998, or March 17, 2000.
(9)
1998 Exhibit means for a given facility named in paragraph (a) of this section, the exhibit adopted by the Montana Board of Environmental Review on June 12, 1998.
(10)
2000 Exhibit means for a given facility named in paragraph (a) of this section, the exhibit adopted by the Montana Board of Environmental Review on March 17, 2000.
(11)
Flare means a combustion device that uses an open flame to burn combustible gases with combustion air provided by uncontrolled ambient air around the flame. This term includes both ground and elevated flares.
(14)
Hourly Average means an arithmetic average of all valid and complete 15-minute data blocks in a clock hour. Four (4) valid and complete 15-minute data blocks are required to determine an hourly average for each CEMS per clock hour.
Exclusive of the above definition, an hourly CEMS average may be determined with two (2) valid and complete 15-minute data blocks, for two (2) of the 24 hours in any calendar day. A complete 15-minute data block for each CEMS shall have a minimum of one (1) data point value; however, each CEMS shall be operated such that all valid data points acquired in any 15-minute block shall be used to determine the 15-minute block's reported concentration and flow rate.
(15)
Hourly Emissions means the pounds per clock hour of SO2 emissions from a source (including, but not limited to, a flare, stack, fuel oil system, sour water system, or fuel gas system) determined using hourly averages and rounded to the nearest tenth ( 1/10) of a pound.
(17)
Integrated sampling means an automated method of obtaining a sample from the gas stream to the flare that produces a composite sample of individual aliquots taken over time.
(22)
Pilot gas means the gas used to maintain the presence of a flame for ignition of gases routed to a flare.
(23)
Purge gas means a continuous gas stream introduced into a flare header, flare stack, and/or flare tip for the purpose of maintaining a positive flow that prevents the formation of an explosive mixture due to ambient air ingress.
(27)
Standard Conditions means (a) 20 °C (293.2 °K, 527.7 °R, or 68.0 °F) and one (1) atmosphere pressure (29.92 inches Hg or 760 mm Hg) for stack and flare gas emission calculations, and (b) 15.6 °C (288.7 °K, 520.0 °R, or 60.3 °F) and one (1) atmosphere pressure (29.92 inches Hg or 760 mm Hg) for refinery fuel gas emission calculations.
(30)
The term 3-hour emissions means the amount of SO2 emitted in each of the eight (8) non-overlapping 3-hour periods in a calendar day, expressed in pounds and rounded to the nearest tenth ( 1/10) of a pound, where:
Code of Federal Regulations
(31)
The term 3-hour period means any of the eight (8) non-overlapping 3-hour periods in a calendar day: Midnight to 3 a.m., 3 a.m. to 6 a.m., 6 a.m. to 9 a.m., 9 a.m. to noon, noon to 3 p.m., 3 p.m. to 6 p.m., 6 p.m. to 9 p.m., 9 p.m. to midnight.
(32)
Turnaround means a planned activity involving shutdown and startup of one or several process units for the purpose of performing periodic maintenance, repair, replacement of equipment, or installation of new equipment.
(33)
Valid means data that are obtained from a monitor or meter serving as a component of a CEMS which meets the applicable specifications, operating requirements, and quality assurance and control requirements of section 6 of ConocoPhillips', CHS Inc.'s, ExxonMobil's, and MSCC's 1998 exhibits, respectively, and this section.
(ii)
Combustion sources, which consist of those sources identified in the combustion sources emission limit in section 3(A)(1)(d) of CHS Inc.'s 1998 exhibit.
(i) Emission limit.
The total emissions of SO2 from the flare shall not exceed 150.0 pounds per 3-hour period.
(ii) Compliance determining method.
Compliance with the emission limit in paragraph (d)(2)(i) of this section shall be determined in accordance with paragraph (h) of this section.
(i) Restrictions.
Sour water stripper overheads (ammonia (NH3) and H2 S gases removed from the sour water in the sour water stripper) shall not be burned in the main crude heater. At all times, CHS Inc. shall keep a chain and lock on the valve that supplies sour water stripper overheads from the old sour water stripper to the main crude heater and shall keep such valve closed.
(ii) Compliance determining method.
CHS Inc. shall log and report any noncompliance with the requirements of paragraph (d)(3)(i) of this section.
(i)
CHS Inc. shall submit quarterly reports beginning with the first calendar quarter following May 21, 2008. The quarterly reports shall be submitted within 30 days of the end of each calendar quarter. The quarterly reports shall be submitted to EPA at the following address: Air Program Contact, EPA Montana Operations Office, Federal Building, 10 West 15th Street, Suite 3200, Helena, MT 59626.
The quarterly report shall be certified for accuracy in writing by a responsible CHS Inc. official. The quarterly report shall consist of both a comprehensive electronic-magnetic report and a written hard copy data summary report.
(ii)
The electronic report shall be on magnetic or optical media, and such submittal shall follow the reporting format of electronic data being submitted to the MDEQ. EPA may modify the reporting format delineated in this section, and, thereafter, CHS Inc. shall follow the revised format. In addition to submitting the electronic quarterly reports to EPA, CHS Inc. shall also record, organize, and archive for at least five (5) years the same data, and upon request by EPA, CHS Inc. shall provide EPA with any data archived in accordance with this provision. The electronic report shall contain the following:
(A)
Hourly average total sulfur concentrations as H2 S or SO2 in ppm in the gas stream to the flare;
(E)
Hourly average temperature (in °F) and pressure (in mm or inches of Hg) of the gas stream to the flare;
(B)
Periods in which only natural gas or an inert gas was used as flare pilot gas or purge gas or both;
(C)
The results of all quarterly Cylinder Gas Audits (CGA), Relative Accuracy Audits (RAA), and annual Relative Accuracy Test Audits (RATA) for all total sulfur analyzer(s) and H2 S analyzer(s), and the results of all annual calibrations and verifications for the volumetric flow, temperature, and pressure monitors;
(D)
For all periods of flare volumetric flow rate monitoring system or total sulfur analyzer system downtime, flare pilot gas or purge gas volumetric flow or H2 S analyzer system downtime, or failure to obtain or analyze a grab or integrated sample, the written report shall identify:
(1) Dates and times of downtime or failure;
(2) Reasons for downtime or failure;
(3) Corrective actions taken to mitigate downtime or failure; and
(4) The other methods, approved by EPA in the flare monitoring plan required by paragraph (h)(5) of this section, used to determine flare emissions;
(E)
For all periods that the range of the flare or any pilot or purge gas volumetric flow rate monitor(s), any flare total sulfur analyzer(s), or any pilot or purge gas H2 S analyzer(s) is exceeded, the written report shall identify:
(1) Date and time when the range of the volumetric flow monitor(s), total sulfur analyzer(s), or H2 S analyzer(s) was exceeded; and
(2) The other methods, approved by EPA in the flare monitoring plan required by paragraph (h)(5) of this section, used to determine flare emissions;
(F)
For all periods that the flare volumetric flow monitor or monitors are recording flow, yet any Flare Water Seal Monitoring Device indicates there is no flow, the written report shall identify:
(1) Date, time, and duration when the flare volumetric flow monitor(s) recorded flow, yet any Flare Water Seal Monitoring Device indicated there was no flow;
(G)
For each 3-hour period in which the flare emission limit is exceeded, the written report shall identify:
(1) The date, start time, and end time of the excess emissions;
(2) Total hours of operation with excess emissions, the hourly emissions, and the 3-hour emissions;
(3) All information regarding reasons for operating with excess emissions; and
(4) Corrective actions taken to mitigate excess emissions;
(H)
The date and time of any noncompliance with the requirements of paragraph (d)(3)(i) of this section; and
(I)
When no excess emissions have occurred or the continuous monitoring system(s) or manual system(s) have not been inoperative, repaired, or adjusted, such information shall be stated in the report.
(i)
The main flare, which consists of two flares—the north flare and the south flare—that are operated on alternating schedules. These flares are referred to herein as the north main flare and south main flare, or generically as the main flare.
(ii)
The Jupiter Sulfur SRU flare, which is the flare at Jupiter Sulfur, ConocoPhillips' sulfur recovery unit.
(A)
Combined emissions of SO2 from the main flare (which can be emitted from either the north or south main flare, but not both at the same time) shall not exceed 150.0 pounds per 3-hour period.
(B)
Emissions of SO2 from the Jupiter Sulfur SRU flare and the Jupiter Sulfur SRU/ATS stack (also referred to as the Jupiter Sulfur SRU stack) shall not exceed 75.0 pounds per 3-hour period, 600.0 pounds per calendar day, and 219,000 pounds per calendar year.
(A)
Compliance with the emission limit in paragraph (e)(2)(i)(A) of this section shall be determined in accordance with paragraph (h) of this section. In the event that a single monitoring location cannot be used for both the north and south main flare, ConocoPhillips shall monitor the flow and measure the total sulfur concentration at more than one location in order to determine compliance with the main flare emission limit. ConocoPhillips shall log and report any instances when emissions are vented from the north main flare and south main flare simultaneously.
(B)
Compliance with the emission limits and requirements in paragraph (e)(2)(i)(B) of this section shall be determined by summing the emissions from the Jupiter Sulfur SRU flare and SRU/ATS stack. Emissions from the Jupiter Sulfur SRU flare shall be determined in accordance with paragraph (h) of this section and the emissions from the Jupiter Sulfur SRU/ATS stack shall be determined pursuant to ConocoPhillips' 1998 exhibit (see section 4(A) of the exhibit).
(i)
ConocoPhillips shall submit quarterly reports on a calendar year basis, beginning with the first calendar quarter following May 21, 2008. The quarterly reports shall be submitted within 30 days of the end of each calendar quarter. The quarterly reports shall be submitted to EPA at the following address: Air Program Contact, EPA Montana Operations Office, Federal Building, 10 West 15th Street, Suite 3200, Helena, MT 59626.
The quarterly report shall be certified for accuracy in writing by a responsible ConocoPhillips official. The quarterly report shall consist of both a comprehensive electronic-magnetic report and a written hard copy data summary report.
(ii)
The electronic report shall be on magnetic or optical media, and such submittal shall follow the reporting format of electronic data being submitted to the MDEQ. EPA may modify the reporting format delineated in this section, and, thereafter, ConocoPhillips shall follow the revised format. In addition to submitting the electronic quarterly reports to EPA, ConocoPhillips shall also record, organize, and archive for at least five (5) years the same data, and upon request by EPA, ConocoPhillips shall provide EPA with any data archived in accordance with this provision. The electronic report shall contain the following:
(A)
Hourly average total sulfur concentrations as H2 S or SO2 in ppm in the gas stream to the ConocoPhillips main flare and Jupiter Sulfur SRU flare;
(B)
Hourly average H2 S concentrations of the ConocoPhillips main flare and Jupiter Sulfur SRU flare pilot and purge gases in ppm;
(C)
Hourly average volumetric flow rates in SCFH of the gas streams to the ConocoPhillips main flare and Jupiter Sulfur SRU flare;
(D)
Hourly average volumetric flow rates in SCFH of the ConocoPhillips main flare and Jupiter Sulfur SRU flare pilot and purge gases;
(E)
Hourly average temperature (in °F) and pressure (in mm or inches of Hg) of the gas streams to the ConocoPhillips main flare and Jupiter Sulfur SRU flare;
(F)
Hourly emissions in pounds per clock hour from the ConocoPhillips main flare and Jupiter Sulfur SRU flare; and
(A)
The 3-hour emissions in pounds per 3-hour period from the ConocoPhillips main flare and the sum of the combined 3-hour emissions from the Jupiter Sulfur SRU/ATS stack and Jupiter Sulfur SRU flare in pounds per 3-hour period;
(B)
Periods in which only natural gas or an inert gas was used as flare pilot gas or purge gas or both;
(C)
The results of all quarterly Cylinder Gas Audits (CGA), Relative Accuracy Audits (RAA), and annual Relative Accuracy Test Audits (RATA) for all total sulfur analyzer(s) and H2 S analyzer(s), and the results of all annual calibrations and verifications for the volumetric flow, temperature, and pressure monitors;
(D)
For all periods of flare volumetric flow rate monitoring system or total sulfur analyzer system downtime, flare pilot gas or purge gas volumetric flow or H2 S analyzer system downtime, or failure to obtain or analyze a grab or integrated sample, the written report shall identify:
(1) Dates and times of downtime or failure;
(2) Reasons for downtime or failure;
(3) Corrective actions taken to mitigate downtime or failure; and
(4) The other methods, approved by EPA in the flare monitoring plan required by paragraph (h)(5) of this section, used to determine flare emissions;
(E)
For all periods that the range of the flare or any pilot or purge gas volumetric flow rate monitor(s), any flare total sulfur analyzer(s), or any pilot or purge gas H2 S analyzer(s) is exceeded, the written report shall identify:
(1) Date and time when the range of the volumetric flow monitor(s), total sulfur analyzer(s), or H2 S analyzer(s) was exceeded, and
(2) The other methods, approved by EPA in the flare monitoring plan required by paragraph (h)(5) of this section, used to determine flare emissions;
(F)
For all periods that the flare volumetric flow monitor or monitors are recording flow, yet any Flare Water Seal Monitoring Device indicates there is no flow, the written report shall identify:
(1) Date, time, and duration when the flare volumetric flow monitor(s) recorded flow, yet any Flare Water Seal Monitoring Device indicated there was no flow;
(G)
Identification of dates, times, and duration of any instances when emissions were vented from the north and south main flares simultaneously;
(H)
For each 3-hour period in which a flare emission limit is exceeded, the written report shall identify:
(1) The date, start time, and end time of the excess emissions;
(2) Total hours of operation with excess emissions, the hourly emissions, and the 3-hour emissions;
(3) All information regarding reasons for operating with excess emissions; and
(4) Corrective actions taken to mitigate excess emissions; and
(I)
When no excess emissions have occurred or the continuous monitoring system(s) or manual system(s) have not been inoperative, repaired, or adjusted, such information shall be stated in the report.
(i)
The Primary process flare and the Turnaround flare. The Primary process flare is the flare normally used by ExxonMobil. The Turnaround flare is the flare ExxonMobil uses for about 30 to 40 days every 5 to 6 years when the facility's major SO2 source, the fluid catalytic cracking unit, is not normally operating.
(ii)
The following refinery fuel gas combustion units: The FCC CO Boiler, F-2 crude/vacuum heater, F-3 unit, F-3X unit, F-5 unit, F-700 unit, F-201 unit, F-202 unit, F-402 unit, F-551 unit, F-651 unit, standby boiler house (B-8 boiler), and Coker CO Boiler (only when the Yellowstone Energy Limited Partnership (YELP) facility is receiving ExxonMobil Coker unit flue gas or whenever the ExxonMobil Coker is not operating).
(i) Emission limit.
The total combined emissions of SO2 from the Primary process and Turnaround refinery flares shall not exceed 150.0 pounds per 3-hour period.
(ii) Compliance determining method.
Compliance with the emission limit in paragraph (f)(2)(i) of this section shall be determined in accordance with paragraph (h) of this section. If volumetric flow monitoring device(s) installed and concentration monitoring methods used to measure the gas stream to the Primary Process flare cannot measure the gas stream to the Turnaround flare, ExxonMobil may apply to EPA for alternative measures to determine the volumetric flow rate and total sulfur concentration of the gas stream to the Turnaround flare. Before EPA will approve such alternative measures, ExxonMobil must agree that the Turnaround flare will be used only during refinery turnarounds of limited duration and frequency—no more than 60 days once every five (5) years—which restriction shall be considered an enforceable part of this FIP. Such alternative measures may consist of reliable flow estimation parameters to estimate volumetric flow rate and manual sampling of the gas stream to the flare to determine total sulfur concentrations, or such other measures that EPA finds will provide accurate estimations of SO2 emissions from the Turnaround flare.
(i) Emission limits.
The applicable emission limits are contained in section 3(A)(1) of ExxonMobil's 2000 exhibit and section 3(B)(2) of ExxonMobil's 1998 exhibit.
(ii) Compliance determining method.
For the limits referenced in paragraph (f)(3)(i) of this section, the compliance determining methods specified in section 4(B) of ExxonMobil's 1998 exhibit shall be followed except when the H2 S concentration in the refinery fuel gas stream exceeds 1200 ppmv as measured by the H2 S CEMS required by section 6(B)(3) of ExxonMobil's 1998 exhibit (the H2 S CEMS.) When such value is exceeded, the following compliance monitoring method shall be employed:
(A)
ExxonMobil shall measure the H2 S concentration in the refinery fuel gas according to the procedures in paragraph (f)(3)(ii)(B) of this section and calculate the emissions according to the equations in paragraph (f)(3)(ii)(C) of this section.
(B)
Within four (4) hours after the H2 S CEMS measures an H2 S concentration in the refinery fuel gas stream greater than 1200 ppmv, ExxonMobil shall initiate sampling of the refinery fuel gas stream at the fuel header on a once-per-hour frequency using length-of-stain detector tubes pursuant to ASTM Method D4810-06, “Standard Test Method for Hydrogen Sulfide in Natural Gas Using Length-of-Stain Detector Tubes” (incorporated by reference, see paragraph (j) of this section) with the appropriate sample tube range. If the results exceed the tube's range, another tube of a higher range must be used until results are in the tube's range. ExxonMobil shall continue to use the length-of-stain detector tube method at this frequency until the H2 S CEMS measures an H2 S concentration in the refinery fuel gas stream equal to or less than 1200 ppmv continuously over a 3-hour period.
(C)
When the length-of-stain detector tube method is required, SO2 emissions from refinery fuel gas combustion shall be calculated as follows: the Hourly emissions shall be calculated using equation 1, 3-hour emissions shall be calculated using equation 2, and the Daily emissions shall be calculated using equation 3.
Code of Federal Regulations
Where:
EH = Refinery fuel gas combustion hourly emissions in pounds per hour, rounded to the nearest tenth of a pound;
K= 1.688 × 10−7 in (pounds/standard cubic feet (SCF))/parts per million (ppm);
CH = Hourly refinery fuel gas H2S concentration in ppm determined by the length-of-stain detector tube method as required by paragraph (f)(3)(ii)(B) of this section; and
QH = actual fuel gas firing rate in standard cubic feet per hour (SCFH), as measured by the monitor required by section 6(B)(8) of ExxonMobil's 1998 exhibit.
Code of Federal Regulations
Code of Federal Regulations
(i) Emission limits.
When ExxonMobil's Coker unit is operating and Coker unit flue gases are burned in the Coker CO Boiler, the applicable emission limits are contained in section 3(B)(1) of ExxonMobil's 2000 exhibit.
(A)
Compliance with the emission limits referenced in paragraph (f)(4)(i) of this section shall be determined by measuring the SO2 concentration and flow rate in the Coker CO Boiler stack according to the procedures in paragraphs (f)(4)(ii)(B) and (C) of this section and calculating emissions according to the equations in paragraph (f)(4)(ii)(D) of this section.
(B)
Beginning on May 21, 2008, ExxonMobil shall operate and maintain a CEMS to measure sulfur dioxide concentrations in the Coker CO Boiler stack. Whenever ExxonMobil's Coker unit is operating and Coker unit flue gases are exhausted through the Coker CO Boiler stack, the CEMS shall be operational and shall achieve a temporal sampling resolution of at least one (1) concentration measurement per minute, meet the requirements expressed in the definition of “hourly average” in paragraph (c)(14) of this section, and meet the CEMS Performance Specifications contained in section 6(C) of ExxonMobil's 1998 exhibit, except that ExxonMobil shall perform a Cylinder Gas Audit (CGA) or Relative Accuracy Audit (RAA) which meets the requirements of 40 CFR part 60, Appendix F, within eight (8) hours of when the Coker unit flue gases begin exhausting through the Coker CO Boiler stack. ExxonMobil shall perform an annual Relative Accuracy Test Audit (RATA) on the CEMS and notify EPA in writing of each annual RATA a minimum of 25 working days prior to actual testing.
(C)
Beginning on May 21, 2008, ExxonMobil shall operate and maintain a continuous stack flow rate monitor to measure the stack gas flow rates in the Coker CO Boiler stack. Whenever ExxonMobil's Coker unit is operating and Coker unit flue gases are exhausted through the Coker CO Boiler stack, this CEMS shall be operational and shall achieve a temporal sampling resolution of at least one (1) flow rate measurement per minute, meet the requirements expressed in the definition of “hourly average” in paragraph (c)(14) of this section, and meet the Stack Gas Flow Rate Monitor Performance Specifications of section 6(D) of ExxonMobil's 1998 exhibit, except that ExxonMobil shall perform an annual Relative Accuracy Test Audit (RATA) on the CEMS and notify EPA in writing of each annual RATA a minimum of 25 working days prior to actual testing.
(D)
SO2 emissions from the Coker CO Boiler stack shall be determined in accordance with the equations in sections 2(A)(1), (8), (11)(a), and (16) of ExxonMobil's 1998 exhibit.
(i)
ExxonMobil shall submit quarterly reports beginning with the first calendar quarter following May 21, 2008. The quarterly reports shall be submitted within 30 days of the end of each calendar quarter. The quarterly reports shall be submitted to EPA at the following address: Air Program Contact, EPA Montana Operations Office, Federal Building, 10 West 15th Street, Suite 3200, Helena, MT 59626.
The quarterly report shall be certified for accuracy in writing by a responsible ExxonMobil official. The quarterly report shall consist of both a comprehensive electronic-magnetic report and a written hard copy data summary report.
(ii)
The electronic report shall be on magnetic or optical media, and such submittal shall follow the reporting format of electronic data being submitted to the MDEQ. EPA may modify the reporting format delineated in this section, and, thereafter, ExxonMobil shall follow the revised format. In addition to submitting the electronic quarterly reports to EPA, ExxonMobil shall also record, organize, and archive for at least five (5) years the same data, and upon request by EPA, ExxonMobil shall provide EPA with any data archived in accordance with this provision. The electronic report shall contain the following:
(A)
Hourly average total sulfur concentrations as H2 S or SO2 in ppm in the gas stream to the flare(s);
(E)
Hourly average volumetric flow rates in SCFH in the gas stream to the flare(s) and in the Coker CO Boiler stack;
(H)
Hourly average temperature (in °F) and pressure (in mm or inches of Hg) of the gas stream to the flare(s);
(I)
Hourly emissions in pounds per clock hour from the flare(s), Coker CO Boiler stack, and refinery fuel gas combustion system; and
(J)
Daily calibration data for the CEMS described in paragraphs (f)(2)(ii), (f)(3)(ii) and (f)(4)(ii) of this section.
(A)
The 3-hour emissions in pounds per 3-hour period from the flare(s), Coker CO Boiler stack, and refinery fuel gas combustion system;
(B)
Periods in which only natural gas or an inert gas was used as flare pilot gas or purge gas or both;
(C)
Daily emissions in pounds per calendar day from the Coker CO Boiler stack and refinery fuel gas combustion system;
(D)
The results of all quarterly or other Cylinder Gas Audits (CGA), Relative Accuracy Audits (RAA), and annual Relative Accuracy Test Audits (RATA) for the CEMS described in paragraphs (f)(2)(ii) (flare total sulfur analyzer(s); pilot gas or purge gas H2 S analyzer(s)), (f)(3)(ii), and (f)(4)(ii) of this section, and the results of all annual calibrations and verifications for the volumetric flow, temperature, and pressure monitors;
(E)
For all periods of flare volumetric flow rate monitoring system or total sulfur analyzer system downtime, Coker CO Boiler stack CEMS downtime, refinery fuel gas combustion system CEMS downtime, flare pilot gas or purge gas volumetric flow or H2 S analyzer system downtime, or failure to obtain or analyze a grab or integrated sample, the written report shall identify:
(1) Dates and times of downtime or failure;
(2) Reasons for downtime or failure;
(3) Corrective actions taken to mitigate downtime or failure; and
(4) The other methods, approved by EPA in the flare monitoring plan required by paragraph (h)(5) of this section, used to determine flare emissions;
(F)
For all periods that the range of the flare or any pilot or purge gas volumetric flow rate monitor(s), any flare total sulfur analyzer(s), or any pilot or purge gas H2 S analyzer(s) is exceeded, the written report shall identify:
(1) Date and time when the range of the volumetric flow monitor(s), total sulfur analyzer(s), or H2 S analyzer(s) was exceeded, and
(2) The other methods, approved by EPA in the flare monitoring plan required by paragraph (h)(5) of this section, used to determine flare emissions;
(G)
For all periods that the range of the refinery fuel gas CEMS is exceeded, the written report shall identify:
(1) Date, time, and duration when the range of the refinery fuel gas CEMS was exceeded;
(H)
For all periods that the flare volumetric flow monitor or monitors are recording flow, yet any Flare Water Seal Monitoring Device indicates there is no flow, the written report shall identify:
(1) Date, time, and duration when the flare volumetric flow monitor(s) recorded flow, yet any Flare Water Seal Monitoring Device indicated there was no flow;
(I)
For each 3-hour period and calendar day in which the flare emission limits, the Coker CO Boiler stack emission limits, or the fuel gas combustion system emission limits are exceeded, the written report shall identify:
(1) The date, start time, and end time of the excess emissions;
(2) Total hours of operation with excess emissions, the hourly emissions, the 3-hour emissions, and the daily emissions;
(3) All information regarding reasons for operating with excess emissions; and
(4) Corrective actions taken to mitigate excess emissions; and
(J)
When no excess emissions have occurred or the continuous monitoring system(s) or manual system(s) have not been inoperative, repaired, or adjusted, such information shall be stated in the report.
(iii)
The auxiliary vent stacks and the units that can exhaust through the auxiliary vent stacks, which consist of the Railroad Boiler, the H-1 Unit, the H1-A unit, the H1-1 unit and the H1-2 unit.
(iv)
The SRU 30-meter stack and the units that can exhaust through the SRU 30-meter stack. The units that can exhaust through the SRU 30-meter stack are identified in section 3(A)(2)(d) and (e) of MSCC's 1998 exhibit.
(i) Emission limit.
Total combined emissions of SO2 from the 80-foot west flare, 125-foot east flare, and 100-meter flare shall not exceed 150.0 pounds per 3-hour period.
(ii)
Compliance determining method. Compliance with the emission limit in paragraph (g)(2)(i) of this section shall be determined in accordance with paragraph (h) of this section. In the event MSCC cannot monitor all three flares from a single location, MSCC shall establish multiple monitoring locations.