Ken Hustvedt/RTP/ USEPA/US

01/29/2009 01:44 PM To: eric scheaffer, Jim Pew, John Walke, mdouglas@4cleanair.org cc Subject: Fw: Red-Line Version of NSPS Ja Re-Proposal

Industry had asked for a complied amended nsps subpart Ja and I wanted to make it available to you also since the docket isn't always the best way to communicate info quickly, Please pass along to others.

kc hustvedt

----- Forwarded by Ken Hustvedt/RTP/USEPA/US on 01/ 29/2009 01:32 PM -----

Ken Hustvedt/RTP/ USEPA/US

01/29/2009 01:32 PM To: "Ron Chittim" <Chittim@api.org>, John Wagner, Bill Wehrum cc: Bob Lucas/RTP/USEPA/US@EPA, Brenda Shine/RTP/USEPA/US@EPA Subject: Re: Red-Line Version of NSPS Ja Re-Proposal

better late than never? we pulled this together and did some review - we believe it is an accurate compilation but cannot guarantee it.

kch

"Ron Chittim" <Chittim@api.org>

12/19/2008 11:07 AM To: Ken Hustvedt/RTP/USEPA/US@EPA, Brenda Shine/RTP/USEPA/US@EPA, Bob Lucas/RTP/USEPA/US@EPA cc: Subject: Red-Line Version of NSPS Ja Re-Proposal

Is there a chance that you have the June 24, 2008 final rule with the Dec. 2008 proposal revisions incorporated (e.g., in a red-line or track changes form at)? Or a version that has all the re-proposal revisions incorporated? Such a document would make the review process easier. Thanks. Happy Holidays!

Ron Chittim API 1220 L Street, NW Washington, D.C. 20005 202/682-8176 chittim@api.orgTitle 40: Protection of Environment PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES Subpart Ja—Standards of Performance for Petr oleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007

Source: 73 FR 35867, June 24, 2008, unless otherwise noted. § 60.100a Applicability, designation of affected facility, and reconstruction. (a) The provisions of this subpart apply to the following affected facilities in petroleum refineries: fluid catalytic cracking units (FCCU), fluid coking units (FCU), delayed coking units, fuel gas combustion devices, including flares and process heaters, and sulfur recovery plants. The sulfur recovery plant need not be physically located within the boundaries of a petroleum refinery to be an affected facility, provided it processes gases produced within a petroleum refinery. (b) Except for flares, the provisions of this subpart apply only to affected facilities under paragraph (a) of this section which commence cons truction, modification, or reconstruction after May 14, 2007. For flares, the provisions of this subpart apply only to flares which commence construction, modification, or reconstruction, after June 24, 2008. (c) For all affected facilities other than flares, th e provisions in §60.14 regarding modification apply. As provided in §60.14(f), the special provisions set forth under this subpart shall supersede the provisions in §60.14 with respect to flares. For the purposes of this subpart, a modification to a flare occurs as provided in paragraphs (c)(1) or (2) of this section. (1) Any new piping from a refinery process unit or fuel gas system is physically connected to the flare (e.g., for direct emergency relief or some form of continuous or intermittent venting)

. However, the connections described in paragraphs (c)(1)(i) through (iv) of this section are not considered modifications of a flare. (i) Connections made to install monitoring systems to the flare. (ii) Connections made to install a flare gas recovery system. (iii) Connections made to replace or upgrade existing pressure relief or safety valves, provided the new pressure relief or safety valve has a set point opening pressure no lower and an internal diameter no greater than the existing equipment being replaced or upgraded. (iv) Replacing piping or moving an existing connection from a refinery process unit to a new location in the same flare, provided the new pipe diameter is less than or equal to the diameter of the pipe/connection being replaced/moved. (2) A flare is physically altered to increase the flow capacity of the flare. (d) For purposes of this subpart, under §60.15, the “fixed capital cost of the new components” includes the fixed capital cost of all depreciable components which are or will be replaced Deleted: under §60.14, Deleted: if:

Deleted: ; orpursuant to all continuous programs of component replacement which are commenced within any 2-year period following May 14, 2007. For purposes of this paragraph, “commenced” means that an owner or operator has undertaken a continuous program of component replacement or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of component replacement.

§ 60.101a Definitions. Terms used in this subpart are defined in the Clean Air Act, in §60.2, and in this section. Air preheat means a device used to heat the air supplied to a process heater generally by use of a heat exchanger to recover the latent heat of exhaust gas from the process heater. Co-fired process heater means a process heater that employs burners that are designed to be supplied by both gaseous and liquid fuels. Coke burn-off means the coke removed from the surface of the FCCU catalyst by combustion in the catalyst regenerator. The rate of coke bu rn-off is calculated by the formula specified in §60.104a.

Contact material means any substance formulated to remove metals, sulfur, nitrogen, or any other contaminant from petroleum derivatives.

Corrective action means the design, operation, and maintenance changes consistent with good engineering practice to reduce or eliminate the li kelihood of recurrence of an event identified by a root cause analysis as having caused a discharge of gases to an affected flare in excess of the flow rate threshold in §60.103a(a)(4) or the discharge of gases from an affected fuel gas combustion device or sulfur recovery plant in excess of the applicable SO 2 threshold in §60.103a(b). Corrective action analysis means a description of all reasonable interim and long-term measures, if any, that are available, and an explanation of why the selected corrective action is the best alternative, including any consideration of cost-effectiveness. Delayed coking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum c oke is produced in a series of closed, batch system reactors. A delayed coking unit consists of the coke drums and associated fractionator.

Flare means an open-flame fuel gas combustion device used for burning off unwanted gas or flammable gas and liquids. The flare includes the found ation, flare tip, structural support, burner, igniter, flare controls including air injection or steam injection systems, flame arrestors, knockout pots, piping and header systems. Flare gas recovery system means a system of one or more compressors, piping, and associated water seal, rupture disk, or similar device used to divert gas from the flare and direct the gas to the fuel gas system or to a fuel gas combustion device other than a flare. Deleted: one or more Deleted: sFlexicoking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum c oke is continuously produced and then gasified to produce a synthetic fuel gas. Fluid catalytic cracking unit means a refinery process unit in which petroleum derivatives are continuously charged and hydrocarbon molecules in the presence of a catalyst suspended in a fluidized bed are fractured into smaller molecules, or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, catalyst or contact material recovery equipment, and rege nerator equipment for controlling air pollutant emissions and for heat recovery. When fluid catalyst cracking unit regenerator exhaust from two separate fluid catalytic cracking units share a common exhaust treatment (e.g., CO boiler or wet scrubber), the fluid catalytic cracking unit is a single affected facility. Fluid coking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum c oke is continuously produced in a fluidized bed system. The fluid coking unit includes the coking reactor, the coking burner, and equipment for controlling air pollutant emissions and for heat recovery on the fluid coking burner exhaust vent. Forced draft process heater means a process heater in which the combustion air is supplied under positive pressure produced by a fan at any location in the inlet air line prior to the point where the combustion air enters the process heater or air preheat. Fuel gas means any gas which is generated at a petroleum refinery and which is combusted. Fuel gas includes natural gas when natural gas is combusted in any proportion with a gas generated at a refinery. Fuel gas does not include gases generated by catalytic cracking unit catalyst regenerators , coke calciners (used to make anode grade coke) and fluid coking burners, but does include gases from flexicoking unit gasifiers and other gasifiers

. Fuel gas does not include vapors that are collected and combusted to comply with the wastewater provisions in 40 CFR 61.343 though 61.348, 40 CFR 63.647 or the marine tank vessel loading provisions in 40 CFR 63. 652 or 40 CFR 63.651. Fuel gas combustion device means any equipment, such as process heaters, boilers, and flares, used to combust fuel gas, except facilities in which gases are combusted to produce sulfur or sulfuric acid. Fuel gas system means a system of compressors, piping, knock-out pots, mix drums, and units used to remove sulfur contaminants from the fuel gas (e.g., amine scrubbers) that collects refinery fuel gas from one or more sources for treatment as necessary prior to combusting in process heaters or boilers. A fuel gas system may have an overpressure vent to a flare but the primary purpose for a fuel gas system is to provide fuel to the refinery. Natural draft process heater means any process heater in whic h the combustion air is supplied under ambient pressure without the use of an inlet air (forced draft) fan. For the purposes of this subpart, a natural draft process heater is any process heater that is not a forced draft process heater. Deleted: one or more Deleted: s

Deleted: one or more Deleted: units

Deleted: the Deleted: combined and

Deleted: §60.692, Deleted: through Deleted: , Deleted: 562Oxidation control system means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to sulfur dioxide (SO 2 ) and recycling the SO 2 to the reactor furnace or the first-stage catalytic reactor of the Claus sulfur recovery plant or converting the SO 2 to a sulfur product.

Petroleum means the crude oil removed from the earth and the oils derived from tar sands, shale, and coal. Petroleum refinery means any facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives. A facility that produces only oil shale or tar sand s-derived crude oil for further processing at a petroleum refinery using only solvent extraction and/or distillation to recover diluent is not a petroleum refinery

. Process heater means an enclosed combustion device used to transfer heat indirectly to process stream materials (liquids, gases, or solids) or to a heat transfer material for use in a process unit instead of steam. Process upset gas means any gas generated by a petroleum refinery process unit as a result of start-up, shutdown, upset or malfunction. Reduced sulfur compounds means hydrogen sulfide (H 2 S), carbonyl sulfide, and carbon disulfide. Reduction control system means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to H 2 S and either recycling the H 2 S to the reactor furnace or the first-stage catalytic reactor of the Claus sulfur recovery plant or converting the H 2 S to a sulfur product. Refinery process unit means any segment of the petroleum refinery in which a specific processing operation is conducted , including but not limited to distillation, cracking, coking, reforming, alkylation, isomerizat ion, coke gasification, product loading, sulfur recovery, and wastewater treatment

. Root cause analysis means an assessment to determine the primary cause and any other significant contributing cause(s), as determined through a process of investigation, of discharge of gases to an affected flare in excess of the flow rate threshold in §60.103a(a)(4) or in excess of the applicable SO 2 threshold in §60.103a(b)(1), or the discharge of gases from an affected fuel gas combustion device or sulfur recovery plant in excess of the applicable SO 2 thresholds in §60.103a(b)(2) and (3). Sulfur pit means the storage vessel in which sulfur that is condensed after each Claus catalytic reactor is initially accumulated and stored. A sulfur pit does not include secondary sulfur storage vessels downstream of the initial Claus reactor sulfur pits. Sulfur recovery plant means all refinery process units which recover sulfur from H 2 S and/or SO 2 from a common source of sour gas at a petroleum refinery. The sulfur recovery plant also Deleted: HS 2includes sulfur pits used to store the recovered sulfur product, but it does not include secondary sulfur storage vessels downstream of the sulfur pits. For example, a Claus sulfur recovery plant includes: Reactor furnace and waste heat boiler, ca talytic reactors, sulfur pits, and, if present, oxidation or reduction control systems, or inci nerator, thermal oxidizer, or similar combustion device. Multiple sulfur recovery plants are a single affected facility only when the units share the same source of sour gas. Sulfur recovery plants that receive source gas from completely segregated sour gas treatment systems are separate affected facilities.

§ 60.102a Emissions limitations. (a) Each owner or operator that is subject to the requirements of this subpart shall comply with the emissions limitations in paragraphs (b) through ( i ) of this section on and after the date on which the initial performance test, required by §60.8, is completed, but not later than 60 days after achieving the maximum production rate at which the affected facility will be operated, or 180 days after initial startup, whichever comes first. (b) An owner or operator subject to the provisions of this subpart shall not discharge or cause the discharge into the atmosphere from any FCCU or FCU: (1) Particulate matter (PM) in excess of the limits in paragraphs (b)(1)(i), (ii), or (iii) of this section. (i) 1.0 kilogram per Megagram (kg/Mg)(1 pound (lb) per 1,000 lb) coke burn-off or, if a PM continuous emission monitoring system (CEMS) is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air for each modified or reconstructed FCCU. (ii) 0.5 gram per kilogram (g/kg) coke burn-off (0.5 lb PM/1,000 lb coke burn-off) or, if a PM CEMS is used, 0.020 gr/dscf corrected to 0 percent excess air for each newly constructed FCCU. (iii) 1.0 kg/Mg (1 lb/1,000 lb) coke burn-off; or if a PM CEMS is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air for each affected FCU. (2) Nitrogen oxides (NO X ) in excess of 80 parts per million by volume (ppmv), dry basis corrected to 0 percent excess air, on a 7-day rolling average basis. (3) Sulfur dioxide (SO 2 ) in excess of 50 ppmv dry basis corrected to 0 percent excess air, on a 7- day rolling average basis and 25 ppmv, dry basis corrected to 0 percent excess air, on a 365-day rolling average basis. (4) Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected to 0 percent excess air, on an hourly average basis. (c) The owner or operator of a FCCU or FCU that uses a continuous parameter monitoring system (CPMS) according to §60.105a(b)(1) shall comply with the applicable control device parameter operating limit in paragraph (c)(1) or (2) of this section. (1) If the FCCU or FCU is controlled using an electrostatic precipitator: Deleted: units

Deleted: h(i) The 3-hour rolling average total power and secondary current to the entire system must not fall below the level established during the most recent performance test; and (ii) The daily average exhaust coke burn-off rate must not exceed the level established during the most recent performance test. (2) If the FCCU or FCU is controlled using a wet scrubber: (i) The 3-hour rolling average pressure drop must not fall below the level established during the most recent performance test; and (ii) The 3-hour rolling average liquid-to-gas ratio must not fall below the level established during the most recent performance test. (d) If an FCCU or FCU uses a continuous opac ity monitoring system (COMS) according to the alternative monitoring option in §60.105a(e), the 3-hour rolling average opacity of emissions from the FCCU or FCU as measured by the COMS must not exceed the site-specific opacity limit established during the most recent performance test. (e) The owner or operator of a FCCU or FCU th at is exempted from the requirement for a CO continuous emissions monitoring system under §60.105a(h)(3) shall comply with the parameter operating limits in paragraph (e)(1) or (2) of this section. (1) For a FCCU or FCU with no post-combustion control device: (i) The hourly average temperature of the exhaust gases exiting the FCCU or FCU must not fall below the level established during the most recent performance test. (ii) The hourly average oxygen (O 2 ) concentration of the exhaust gases exiting the FCCU or FCU must not fall below the level established during the most recent performance test. (2) For a FCCU or FCU with a post-combustion control device: (i) The hourly average temperature of the exhaust gas vent stream exiting the control device must not fall below the level established during the most recent performance test. (ii) The hourly average O 2 concentration of the exhaust gas vent stream exiting the control device must not fall below the level established during the most recent performance test. (f) Except as provided in paragraph (f)(3), each ow ner or operator of an affected sulfur recovery plant shall comply with the applicable emission limi ts in paragraphs (f)(1) or (2) of this section. (1) For a sulfur recovery plant with a capaci ty greater than 20 long tons per day (LTD): (i) For a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere in excess of 250 ppm by volume (dry basis) of sulfur dioxide (SO 2 ) at zero percent excess air. If the sulfur recovery plant consists of multiple process trains or releasepoints the owner or operator shall comply with the 250 ppmv limit for each process train or release point or comply with a flow rate weighted average of 250 ppmv for all release points from the sulfur recovery plant; or (ii) For sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere in excess of 300 ppmv of reduced sulfur compounds and 10 ppmv of hydrogen sulfide ( H 2 S ), each calculated as ppmv SO 2 (dry basis) at 0 percent excess air; or (iii) For systems using oxygen enrichment, the owner or operator shall calculate the applicable emission limit using Equation 1 of this section:

Where:

E LS = Emission rate of SO 2 for large sulfur recovery plant, ppmv;

k 1 = Constant factor for emission limit conversion: k 1 = 1 for converting to SO 2 limit and k 1 = 1.2 for converting to the reduced sulfur compounds limit; and

%O 2 = O 2 concentration to the SRP, percent by volume (dry basis). (2) For a sulfur recovery plant with a capacity of 20 LTD or less: (i) For a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere in excess of 2,500 ppm by volume (dry basis) of SO 2 at zero percent excess air. If the sulfur recovery plant consists of multiple process trains or release points the owner or operator shall comply with the 2,500 ppmv limit for each process train or release point or comply with a flow rate weighted average of 2,500 ppmv for all release points from the sulfur recovery plant; or (ii) For sulfur recovery plant with a reduction co ntrol system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere in excess of 3,000 ppm by volume of reduced sulfur compounds and 100 ppm by volume of hydrogen sulfide (H 2 S), each calculated as ppm SO 2 by volume (dry basis) at zero percent excess air; or (iii) For systems using oxygen enrichment, the owner or operator shall calculate the applicable emission limit using Equation 2 of this section:

Where:

E SS = Emission rate of SO 2 for small sulfur recovery plant, ppmv. Deleted: ppm by volume Deleted: ppm by volume Deleted: HS 2 Deleted: p pm Deleted: by volume Deleted: zero(3) Periods of maintenance of the sulfur pit, during which the emission limits in paragraphs (f)(1) and (2) shall not apply, shall not exceed 240 hours per year. The owner or operator must document the time periods during which the sulfur pit vents were not controlled and measures taken to minimize emissions during these periods. Examples of these measures include not adding fresh sulfur or shutting off vent fans. (g) Each owner or operator of an affected fuel gas combustion device shall comply with the emission limits in paragraphs (g)(1) and (2 ) of this section. (1) For each fuel gas combustion device, the owner or operator shall comply with either the emission limit in paragraph (g)(1)(i) of this section or the fuel gas concentration limit in paragraph (g)(1)(ii) of this section. (i) The owner or operator shall not discharge or cause the discharge of any gases into the atmosphere that contain SO 2 in excess of 20 ppmv (dry basis, corrected to 0 percent excess air) determined hourly on a 3-hour rolling average basis and SO 2 in excess of 8 ppmv (dry basis, corrected to 0 percent excess air), determined daily on a 365 successive day rolling average basis; or (ii) The owner or operator shall not burn in any fuel gas combustion device any fuel gas that contains H 2 S in excess of 162 ppmv determined hourly on a 3-hour rolling average basis and H 2 S in excess of 60 ppmv determined daily on a 365 successive calendar day rolling average basis. An owner or operator of a modified flare that needs to install additional amine scrubbing and amine stripping columns to comply with the long-term H 2 S limit shall comply with the 60 ppmv 365-day H 2 S concentration limit no later than 2 years after that flare becomes an affected facility subject to this subpart. (2) For each process heater with a rated capacity of greater than 40 million British thermal units per hour (MMBtu/hr) on a higher heating value basis , the owner or operator shall not discharge to the atmosphere any emissions of NO X in excess of the applicable limits in paragraphs (g)(2)(i) through (g)(2)(iv). (i) For each newly constructed, modified, or reconstructed natural draft process heater: (A) 40 ppmv (dry basis, corrected to 0 percent excess air) determined daily on a 365 successive operating day rolling average basis ; or (B) 0.035 pounds per million British thermal units (lb/MMBtu) determined daily on a 365 successive operating day rolling average basis. (ii) For each new forced draft process heater: (A) 40 ppmv (dry basis, corrected to 0 percent excess air) determined daily on a 365 successive operating day rolling average basis; or (B) 0.035 lb/MMBtu determined daily on a 365 successive operating day rolling average basis. (iii) For each modified or reconstructed forced draft process heater: Deleted: through (3

Deleted: 24-hour Deleted:

.(A) 60 ppmv (dry basis, corrected to 0 percent excess air) determined daily on a 365 successive operating day rolling average basis; or (B) 0.055 lb/MMBtu determined daily on a 365 successive operating day rolling average basis. (iv) For each co-fired process heater: (A) 150 ppmv (dry basis, corrected to 0 percent excess air) determined daily on a 365 successive operating day rolling average basis (applicable only when the process heater is being co-fired);

or (B) The daily average emission limit calc ulated using Equation 3 of this section:

oil oil gas gas oil oil gas gas hour NOx 

## HHV Q HHV Q HHV Q HHV Q E + +

= 27

. 0 08

. 0

, (Eq. 3)

Where:

E NOx, hour = Daily average emission rate of NO X , lb/MMBtu (higher heating value basis); Q gas = Daily average volumetric flow rate of fuel gas, scf/hr; Q oil = Daily average volumetric flow rate of fuel oil, scf/hr;

HHV gas = Daily average higher heating value of gas fired to the process heater, MMBtu/scf; and

HHV oil = Daily average higher heating value of fuel oil fired to the process heater, MMBtu/scf. (h) The combustion in a flare of process upset gases or fuel gas that is released to the flare as a result of relief valve leakage or other emergency malfunctions is exempt from paragraph (g) of this section. (i) For a modified or reconstructed process heater that lacks sufficient space to accommodate combustion modification-based technology, or for a co-fired process heater, the owner or operator may petition the Administrator within 90 da ys after initial startup of the process heater for approval of a NO X emissions limit which shall apply specifically to that affected facility. The petition shall include sufficient and appropriate data, as determined by the Administrator, to allow the Administrator to confirm that the process heater is unable to comply with the applicable NO X mission limit in paragraph (g)(2) of this section. If the petition is approved by the Administrator, a facility-specific NO X emissions limit will be established at the NO X emission level achievable when the affected facility is operating in a manner that the Administrator determines to be consistent with minimizing NO X emissions. At a minimum, the petition shall contain the information described in paragraphs (i)(1) through (4) of this section. (1) The design and dimensions of the process heater, evaluation of available combustion modification-based technology, description of fuel ga s and, if applicable, fu el oil characteristics and combustion conditions, and any other data determined by the Administrator as appropriate. Deleted: (3) Except as provided in paragraphs (h) and (i) of this section, the owner or operator of an affected flare shall not allow flow to each affected flare during normal operations of more than 7,080 standard cubic meters per day (m3 /day) (250,000 standard cubic feet per day (scfd)) on a 30-day rolling average. The owner or operator of a newly constructed or reconstructed flare shall comply with the emission limit in this paragraph by no later than the date that flare becomes an affected flare subject to this subpart. The ow ner or operator of a modified flare shall comply with the emission limit in this paragraph by no later than 1 year after that flare becomes an affected flare subject to this subpart.¶ Deleted: In periods of fuel gas imbalance that are described in the flare management plan required in section 60.103a(a), compliance with the emission limit in paragraph (g)(3) of this section is demonstrated by following the procedures and maintaining records described in the flare management plan to document the periods of excess fuel gas.¶(2) An explanation of how the data in para graph (i)(1) demonstrate that ultra-low NO X burners or other means cannot be used to meet the applicable emission limit in paragraph (g)(2) of this section. (3) Results of a performance test conducted under representative conditions using the applicable methods specified in §60.104a(i) to demonstrate the performance of the technology the owner or operator will use to minimize NO X emissions. (4) The means by which the owner or operator will document continuous compliance with the site-specific emissions limit. § 60.103a Work practice standards. (a) Each owner or operator that operates a flare that is subject to this subpart shall develop and implement a written flare management plan. The owner or operator of a newly constructed or reconstructed flare must develop and implement the flare management plan by no later than the date that flare becomes an affected flare subject to this subpart. The owner or operator of a modified flare must develop and implement th e flare management plan by no later than 18 months after the flare becomes an affected flare subject to this subpart unless the owner or operator of the affected flare commits in writing to install a flare gas recovery system, in which case the owner or operator of a modified flare must develop and implement the flare management plan by no later than 2 years after the flare becomes an affected flare subject to this subpart . The plan must include: (1) A listing of all refinery process units and fuel gas systems connected to the flare for each affected flare and an assessment of whether discharges to affected flares from these process units and fuel gas systems can be minimized ; (2) Methods for monitoring flow rate to the flare, including a detailed description of the manufacturer's specifications, including but not limited to, make, model, type, range, precision, accuracy, calibration, maintenance, and quality assurance procedures for flare gas monitoring devices; (3) Procedures to minimize discharges to the flare gas system during the planned start-up and shutdown of the refinery process units that are connected to the affected flare; (4) Procedures to conduct a root cause analysis as soon as possible but no later than 45 days after any discharge to the flare in excess of 14,160 standard cubic meters ( m 3 ) (500,000 standard cubic feet (scf)) in any 24-hour period. The first root cause analysis and corrective action analysis for a modified flare must be conducted no later than th e first discharge triggering a root cause analysis that occurs after the flare has been an affected flare subject to this subpart for 18 months, unless the owner or operator of the affected flare commits in writing to install a flare gas recovery system, in which case the flow ra te root cause analysis for a modified flare must be conducted no later than the first discharge triggering a flow rate root cause analysis that occurs after the flare has been an affected flare subject to this subpart for 2 years; Deleted: 1 year

Deleted: diagram illustrating Deleted: connections

Deleted: of Deleted: process upset or malfunction that causes a Deleted: /day Deleted: scfd);(5) Procedures to conduct a corrective action analysis and implement corrective actions as soon as possible but no later than 45 days after a discharge exceeding the flow rate threshold in paragraph (a)(4) of this section to minimize the recurrence of similarly caused events based on the finding of the root cause analysis required under paragraph (a)(4) of this section ; and (6) Procedures to reduce flaring in cases of fuel gas imbalance (i.e., excess fuel gas for the refinery’s energy needs). (b) Each owner or operator that operates a fuel gas combustion device or sulfur recovery plant subject to this subpart shall conduct a root cause analysis and a corrective action analysis under each of the conditions specified in paragraphs (b)(1) through (3) of this section and implement corrective actions to minimize the recurrence of a similarly caused event. If a single continuous discharge causes emissions to exceed a level specified in paragraphs (b)(1) through (3) of this section for 2 or more consecutive 24-hour periods, a single root cause analysis may be conducted. For any root cause analysis and corrective action analysis performed, and for any corrective action taken, the owner or operator shall , as soon as possible but no later than 45 days after the discharge, record the identification of the affected facility, the date and duration of the discharge, a description of the root cause of the discharge as identified by the root cause analysis, results of the corrective action analysis, and the corrective action taken as a result of the root cause analysis , as specified in §60.108a(c)(6). (1) For a flare, conduct a root cause analysis and a corrective action analysis and take corrective action each time the SO 2 emissions exceed 227 kilograms (kg) (500 pounds (lb)) in any 24-hour period. The first root cause analysis and corrective action analysis for a modified flare must be conducted no later than the first discharge of SO 2 triggering a root caus e analysis that occurs after the flare has been an affected flare subject to this subpart for 18 months, unless the owner or operator of the affected flare commits in writing to install a flare gas recovery system, in which case the root cause analysis for a modified flare must be conducted no later than the first discharge of SO 2 triggering a root cause analysis that occurs after the flare has been an affected flare subject to this subpart for 2 years. (2) For any fuel gas combustion device other than a flare, conduct a root cause analysis and acorrective action analysis and take corrective action for each exceedance of an applicable shortterm emissions limit in §60.102a(g)(1) if the SO 2 discharge to the atmosphere is 227 kg (500 lb) greater than the amount that would have been emitted if the emissions limits had been met during the period of the exceedance. (3) For a sulfur recovery plant, conduct a root cause analysis and a corrective action analysis and take corrective action when the daily SO 2 emissions are more than 227 kg (500 lb) greater than the amount that would have been emitted if the SO 2 or reduced sulfur concentration was equal to the applicable emission limit in §60.102a(f)(1) or (2) for the entire 24-hour period. (c) When an owner or operator implements corrective action(s) as specified by paragraphs (a)(5) and (b) of this section, the owner or operator shall, no later than 45 days following the discharge, record a description of the action(s) and, if not already completed, a schedule for its (their) implementation, including proposed commencement and completion dates. If an owner or Deleted: reduce flaring in cases of fuel gas imbalance (i.e., excess fuel gas for Deleted: refinery's energy needs)

Deleted: Explanation of procedures to follow during times that the flare must exceed the limit in §60.102a(g)(3) (e.g., keep records of natural gas purchases to support assertion that the refinery is producing more fuel gas than needed to operate the processes). Deleted: any emission limit exceedance or process start-up, shutdown, upset, or malfunction that causes a discharge to Deleted: atmosphere Deleted: excess Deleted: 227 kilograms per day (kg/day) (500 lb per day (lb/day)) of SO 2 . Deleted: results Deleted: the Deleted: . The first root cause analysis for a modified flare must be conducted no later than the first discharge that occurs after the flare has been an affected flare subject to this subpart for 1 year.operator concludes that corrective action should not be conducted, the owner or operator shall record and explain the basis for that conclusion no later than 45 days following the discharge. (d) Each owner or operator of a delayed coking unit shall depressure to 5 lb per square inch gauge (psig) during reactor vessel depressuring and vent the exhaust gases to the fuel gas system for combustion in a fuel gas combustion device.

§ 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 th e 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 purp ose of obtaining supplem ental data because of continuous monitoring system breakdowns, repa irs, 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 §60.1 05a(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 X , SO 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 (E PM ) is computed for each run using Equation 4 of this section:

c sd s 

## R K Q c E = (Eq. 4 )

Where: E = Emission rate of PM, g/kg, lb per 1,000 lb (lb/1,000 lb) of coke burn-off;

c s = Concentration of total PM, grams per dry standard cubic meter (g/dscm), gr/dscf; Q sd = Volumetric flow rate of effluent gas, dry standard cubic meters per hour, dry standard cubic feet per hour;

R c = Coke burn-off rate, kilograms per hour (kg/hr), lb per hour (lb/hr) coke; and K = Conversion factor, 1.0 grams per gram (7,000 grains per lb). (iii) The coke burn-off rate (R c ) is computed for each run using Equation 5 of this section: 

# ( ) 

# ( ) ( )

oxy oxy r a r c 

## O Q K O CO CO Q K Q K CO CO Q K R % % % 2 % % % 3 2 2 3 2 2 1 

## + + +

− + + = (Eq. 5 )

Where:

R c = Coke burn-off rate, kg/hr (lb/hr); Q r = 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 standa rd cubic feet per minute (dscf/min); Q a = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from the unit's control room instrume ntation, dscm/min (dscf/min); Q oxy = Volumetric flow rate of O 2 enriched air to FCCU regenerator or fluid coking unit, as determined from the unit's control room instrumentation, dscm/min (dscf/min);

%CO 2 = 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);

%O 2 = O 2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis); Deleted: 3

Deleted: 3

Deleted: s Deleted: s Deleted: s

Deleted: s Deleted: s

Deleted: 4

Deleted: 4%O oxy = O 2 concentration in O 2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis);

K 1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-dsc-%) [0.0186 (lb-min)/(hrdscf-%)];

K 2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lb-min)/(hrdscf)]; and

K 3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-dscm-%) [0.00624 (lbmin)/(hr-dscf-%)]. (iv) During the performance test, the volumetri c flow rate of exhaust gas from catalyst regenerator (Q 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 r is calculated using average exhaust gas concentrations as measured by the monitors required in §60.105a(b)(2), if applicable, using Equation 6 of this section: 

## ( )

2 2 

### % % % 100 % 100 79 O CO CO Q Oxy Q Q oxy a

r



### − − − ×

− + ×

= (Eq. 6 )

Where: Q r = 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); Q a = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from the unit's control room instrume ntation, dscm/min (dscf/min); Q oxy = Volumetric flow rate of O 2 enriched air to FCCU regenerator or fluid coking unit, as determined from the unit's control room instrumentation, dscm/min (dscf/min);

%CO 2 = 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;

%O 2 = O 2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis); and

%O oxy = O 2 concentration in O 2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis). Deleted: 5

Deleted: 5(5) Method 6, 6A, or 6C of appendix A–4 to part 60 for moisture content and for the concentration of SO 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 X calculated as nitrogen dioxide (NO 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 X , SO 2 , and CO pollutant concentrations to 0 percent excess air or 0 percent O 2 using Equation 7 of this section: 

## ( ) ⎥ ⎦ ⎤ ⎢ ⎣ ⎡

− = 2 % 9

. 20 9

. 20 O C C c meas adj (Eq. 7 )

Where:

C adj = pollutant concentration adjusted to 0 percent excess air or O 2 , parts per million (ppm) or g/dscm;

C meas = pollutant concentration measured on a dry basis, ppm or g/dscm;

20.9 c = 20.9 percent O 2 –0.0 percent O 2 (defined O 2 correction basis), percent;

20.9 = O 2 concentration in air, percent; and

%O 2 = O 2 concentration measured on a dry basis, percent. (e) The owner or operator of a FCCU or FCU that is controlled by an electr ostatic 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. (3) Compute the site-specific limit using Equation 8 of this section:

⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

=

st st PMEmR burn coke lb lb x Opacity Limit Opacity 000 , 1 / 1 (Eq. 8) Deleted: 6

Deleted: 6Where: Opacity limit = Maximum permissible hourly average opacity, percent, or 10 percent, whichever is greater; Opacity st = Hourly average opacity measured during the source test runs, percent; and

PMEmR st = PM emission rate measured during the source test, lb/1,000 lb coke burn. (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 th e 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; Opacity st = Hourly average opacity measured during the source test runs, percent; and

PMEmR st = 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) an d that is subject to control device operating parameter limits in §60.102a(c) shall establish th e 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 2 concentrations from the parameter monitoring systems to hourly averages for each test run. (2) Determine the operating limit for temperature and O 2 concentrations as the average of the average temperature and O 2 concentration for the three test runs. (h) The owner or operator shall determine compliance with the SO 2 and H 2 S 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 2 S emissionslimits 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 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 2 S 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 sample s taken over a minimum of 3 hours. (ii) The owner or operator shall calculate the average H 2 S concentration after correcting for moisture and O 2 as the arithmetic average of the H 2 S concentration for each sample during the run (ppmv, dry basis, correct ed to 0 percent excess air). (iii) The owner or operator shall calculate the SO 2 equivalent for each run after correcting for moisture and O 2 as the arithmetic average of the SO 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 7 of this section to adjust pollutant concentrations to 0 percent O 2 or 0 percent excess air. (i) The owner or operator shall determine compliance with the SO 2 and NO 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 SO 2 concentration. The method ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses,” (incorporated by Deleted: 6reference—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 ru ns; 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 X calculated as NO 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 2 S 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 H 2 S concentration for affected plants using an H 2 S 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 2 S 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. § 60.105a Monitoring of emissions and operations for fluid catalytic cracking units (FCCU) and fluid coking units (FCU). (a) FCCU and FCU subject to PM emissions limit . Each owner or operator subject to the provisions of this subpart shall monitor each FCCU and FCU subject to the PM emissions limit in §60.102a(b)(1) according to the requirements in paragraph (b), (c), (d), or (e) of this section. (b) Control device operating parameters . Each owner or operator of a FCCU or FCU subject to the PM per coke burn-off emissions limit in §60.102a(b)(1) shall comply with the requirements in paragraphs (b)(1) and (2 ) of this section. (1) The owner or operator shall install, operat e, and maintain continuous parameter monitor systems (CPMS) to measure and record operating parameters for each control device according to the requirements in paragraph (b)(1)(i) through (iii) of this section. (i) For units controlled using an electrostatic pr ecipitator, the owner or operator shall use CPMS to measure and record the hourly average total power input and secondary voltage to the entire system. (ii) For units controlled using a wet scrubber, the owner or operator shall use CPMS to measure and record the hourly average pressure drop, liquid feed rate, and exhaust gas flow rate. As an alternative to a CPMS, the owner or operator must comply with the requirements in either paragraph (b)(1)(ii)(A) or (B) of this section. (A) As an alterative to pressure drop, the owner or operator of a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles must conduct a daily check of the air or water pressure to the spray nozzles and record the results of each check. (B) As an alternative to exhaust gas flow rate, the owner or operator shall comply with the approved alternative for monitoring exhaust gas flow rate in 40 CFR 63.1573(a) of the National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units. (iii) The owner or operator shall install, oper ate, and maintain each CPMS according to the manufacturer's specifications and requirements. (iv) The owner or operator shall determine and record the average coke burn-off rate and hours of operation for each FCCU or FCU using the procedures in §60.104a(d)(4)(iii). Deleted: through (3(v) If you use a control device other than an electrostatic precipitator, wet scrubber, fabric filter, or cyclone, you may request approval to monitor parameters other than those required in paragraph (b)(1) of this section by submitti ng an alternative monitoring plan to the Administrator. The request must include the info rmation in paragraphs (b)(1)(v)(A) through (E) of this section. (A) A description of each affected facility and the parameter(s) to be monitored to determine whether the affected facility will continuously comply with the emission limitations and an explanation of the criteria used to select the parameter(s). (B) A description of the methods and procedures that will be used to demonstrate that the parameter(s) can be used to determine whether the affected facility will continuously comply with the emission limitations and the schedule for this demonstration. The owner or operator must certify that an operating limit will be established for the monitored parameter(s) that represents the conditions in existence when the control device is being properly operated and maintained to meet the emission limitation. (C) The frequency and content of the recordkeeping, recording, and reporting, if monitoring and recording are not continuous. The owner or operator also must include the rationale for the proposed monitoring, recording, and reporting requirements. (D) Supporting calculations. (E) Averaging time for the alternative operating parameter. (2) For use in determining the coke burn-off rate for an FCCU or FCU, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring the concentrations of CO 2 , O 2 (dry basis), and if needed, CO in the exhaust gases prior to any control or energy recovery system that burns auxiliary fuels. (i) The owner or operator shall install, operate, and maintain each monitor according to Performance Specifications 3 and 4 of Appendix B to part 60. (ii) The owner or operator shall cond uct performance evaluations of each CO 2 , O 2 , and CO monitor according to the requirements in §60.13(c) and Performance Specifications 3 and 4 of Appendix B to part 60. The owner or operator shall use Method 3 of Appendix A–3 to part 60 and Method 10, 10A, or 10B of Appendix A–4 to part 60 for conducting the relative accuracy evaluations. (iii) The owner or operator shall comply with the quality assurance requirements of procedure 1 of appendix F to part 60, including quarterly accuracy determinations for CO 2 and CO monitors, annual accuracy determinations for O 2 monitors, and daily calibration drift tests. (c) Bag leak detection systems . Each owner or operator shall install, operate, and maintain a bag leak detection system for each baghouse or similar fabric filter control device that is used to comply with the PM per coke burn-off emissions limit in §60.102a(b)(1) for an FCCU or FCU according to paragraph (c)(1) of this section; prepare and operate by a site-specific monitoring Deleted: Specification Deleted: appendix

Deleted: Specification Deleted: appendix Deleted: appendixplan according to paragraph (c)(2) of this sect ion; take action according to paragraph (c)(3) of this section; and record information accord ing to paragraph (c)(4) of this section. (1) Each bag leak detection system must meet the specifications and requirements in paragraphs (c)(1)(i) through (viii) of this section. (i) The bag leak detection system must be cer tified by the manufacturer to be capable of detecting PM emissions at concentrations of 0. 00044 grains per actual cubic foot or less. (ii) The bag leak detection system sensor must provide output of relative PM loadings. The owner or operator shall continuously record the output from the bag leak detection system using electronic or other means (e.g., using a strip chart recorder or a data logger). (iii) The bag leak detection system must be equipped with an alarm system that will sound when the system detects an increase in relative particulate loading over the alarm set point established according to paragraph (c)(1)(iv) of this section, and the alarm must be located such that it can be heard by the appropri ate plant personnel. (iv) In the initial adjustment of the bag leak detection system, the owner or operator must establish, at a minimum, the baseline output by adjusting the sensitivity (range) and the averaging period of the device, the alarm set points, and the alarm delay time. (v) Following initial adjustment, the owner or operator shall not adjust the averaging period, alarm set point, or alarm delay time without approval from the Administrator or delegated authority except as provided in paragraph (c)(1)(vi) of this section. (vi) Once per quarter, the owner or operator may adjust the sensitivity of the bag leak detection system to account for seasonal effects, including temperature and humidity, according to the procedures identified in the site-specific mon itoring plan required by paragraph (c)(2) of this section. (vii) The owner or operator shall install the bag leak detection sensor downstream of the baghouse and upstream of any wet scrubber. (viii) Where multiple detectors are required, the system's instrumenta tion and alarm may be shared among detectors.(2) The owner or operator shall develop and submit to the Administrator for approval a sitespecific monitoring plan for each baghouse and bag leak detection system. The owner or operator shall operate and maintain each baghouse and bag leak detection system according to the site-specific monitoring plan at all times. Each monitoring plan must describe the items in paragraphs (c)(2)(i) through (vii) of this section. (i) Installation of the bag leak detection system; (ii) Initial and periodic adjustment of the bag le ak detection system, including how the alarm setpoint will be established;(iii) Operation of the bag leak detection system, including quality assurance procedures; (iv) How the bag leak detection system will be maintained, including a routine maintenance schedule and spare parts inventory list; (v) How the bag leak detection system output will be recorded and stored; (vi) Procedures as specified in paragraph (c)(3) of this section. In approving the site-specific monitoring plan, the Administrator or delegated authority may allow owners and operators more than 3 hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the monitoring plan this specific condition as one that could lead to an alarm, adequately explains why it is not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstrates that the requested time will ensure alleviation of this condition as expeditiously as practicable; and (vii) How the baghouse system will be operated and maintained, including monitoring of pressure drop across baghouse cells and frequency of visual inspections of the baghouse interior and baghouse components such as fans a nd dust removal and bag cleaning mechanisms. (3) For each bag leak detection system, the owner or operator shall initiate procedures to determine the cause of every alarm within 1 hour of the alarm. Except as provided in paragraph (c)(2)(vi) of this section, the owner or operator shall alleviate the cause of the alarm within 3 hours of the alarm by taking whatever action(s) are necessary. Actions may include, but are not limited to the following: (i) Inspecting the baghouse for air leaks, torn or broken bags or filter media, or any other condition that may cause an increase in particulate emissions; (ii) Sealing off defective bags or filter media; (iii) Replacing defective bags or filter media or otherwise repairing the control device; (iv) Sealing off a defective baghouse compartment; (v) Cleaning the bag leak detection system probe or otherwise repairing the bag leak detection system; or (vi) Shutting down the process producing the particulate emissions. (4) The owner or operator shall maintain records of the information specified in paragraphs (c)(4)(i) through (iii) of this secti on for each bag leak detection system. (i) Records of the bag leak detection system output; (ii) Records of bag leak detection system adjustments, including the date and time of the adjustment, the initial bag leak detection system settings, and the final bag leak detection system settings; and(iii) The date and time of all bag leak detection system alarms, the time that procedures to determine the cause of the alarm were initiated, the cause of the alarm, an explanation of the actions taken, the date and time the cause of the alarm was alleviated, and whether the alarm was alleviated within 3 hours of the alarm. (d) Continuous emissions mo nitoring systems (CEMS) . An owner or operator subject to the PM concentration emission limit (in gr/dscf) in §60. 102a(b)(1) for an FCCU or FCU shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration (0 percent excess air) of PM in the exhaust gases prior to release to the atmosphere. The monitor must include an O 2 monitor for correcting the data for excess air. (1) The owner or operator shall install, operate, and maintain each PM monitor according to Performance Specification 11 of appendix B to part 60. The span value of this PM monitor is 0.08 gr/dscf PM. (2) The owner or operator shall conduct performance evaluations of each PM monitor according to the requirements in §60.13(c) and Performance Specification 11 of appendix B to part 60. The owner or operator shall use EPA Methods 5 or 5I of appendix A–3 to part 60 or Method 17 of appendix A–6 to part 60 for conduct ing the relative accuracy evaluations. (3) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O 2 monitor must be selected between 10 and 25 percent, inclusive. (4) The owner or operator shall conduct performance evaluations of each O 2 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 of Procedure 2 of appendix B to part 60 for each PM CEMS and Procedure 1 of appendix F to part 60 for each O 2 monitor, including quarterly accuracy determinations for each PM monitor, annual accuracy determinations for each O 2 monitor, and daily calibration drift tests. (e) Alternative monitoring option for FCCU and FCU—COMS . Each owner or operator of an FCCU or FCU that uses cyclones to comply with the PM emission limit in §60.102a(b)(1) shall monitor the opacity of emissions according to the requirements in paragraphs (e)(1) through (3) of this section. (1) The owner or operator shall install, operate, and maintain an instrument for continuously monitoring and recording the opacity of emissions from the FCCU or the FCU exhaust vent. (2) The owner or operator shall install, operate, and maintain each COMS according to Performance Specification 1 of appendix B to part 60. The instrument shall be spanned at 20 to 60 percent opacity.(3) The owner or operator shall conduct performance evaluations of each COMS according to §60.13(c) and Performance Specification 1 of appendix B to part 60. (f) FCCU and FCU subject to NO X limit . Each owner or operator subject to the NO X emissions limit in §60.102a(b)(2) for an FCCU or FCU shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration by volume (dry basis, 0 percent excess air) of NO X emissions into the atmosphere. The monitor must include an O 2 monitor for correcting the data for excess air. (1) The owner or operator shall install, operate, and maintain each NO X monitor according to Performance Specification 2 of appendix B to part 60. The span value of this NO X monitor is 200 ppmv NO X . (2) The owner or operator shall conduct performance evaluations of each NO X 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 refere nce—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 O 2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O 2 monitor must be selected between 10 and 25 percent, inclusive. (4) The owner or operator shall conduct performance evaluations of each O 2 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 of Procedure 1 of appendix F to part 60 for each NO X and O 2 monitor, including quarterly accuracy determinations for NO X monitors, annual accuracy determinations for O 2 monitors, and daily calibration drift tests. (g) FCCU and FCU subject to SO 2 limit . The owner or operator subject to the SO 2 emissions limit in §60.102a(b)(3) for an FCCU or an FCU shal l install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration by volume (dry basis, corrected to 0 percent excess air) of SO 2 emissions into the atmosphere. The monitor shall include an O 2 monitor for correcting the data for excess air. (1) The owner or operator shall install, operate, and maintain each SO 2 monitor according to Performance Specification 2 of appendix B to part 60. The span value of this SO 2 monitor is 200 ppmv SO 2 . (2) The owner or operator shall conduct performance evaluations of each SO 2 monitor according to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. Theowner 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. (3) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O 2 monitor must be selected between 10 and 25 percent, inclusive. (4) The owner or operator shall conduct performance evaluations of each O 2 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 SO 2 and O 2 monitor, including quarterly accuracy determinations for SO 2 monitors, annual accura cy determinations for O 2 monitors, and daily calibration drift tests. (h) FCCU and fluid coking units subject to CO emissions limit . Except as specified in paragraph (h)(3) of this section, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration by volume (dry basis) of CO emissions into the atmosphere from each FC CU and FCU subject to the CO emissions limit in §60.102a(b)(4). (1) The owner or operator shall install, operate, and maintain each CO monitor according to Performance Specification 4 or 4A of appendix B to part 60. The span value for this instrument is 1,000 ppm CO. (2) The owner or operator shall conduct performance evaluations of each CO monitor according to the requirements in §60.13(c) and Performance Specification 4 or 4A of appendix B to part 60. The owner or operator shall use Methods 10, 10A, or 10B of appendix A–4 to part 60 for conducting the relative accuracy evaluations. (3) A CO CEMS need not be installed if the owner or operator demonstrates that all hourly average CO emissions are and will remain less than 50 ppmv (dry basis) corrected to 0 percent excess air. The Administrator may revoke this exemption from monitoring upon a determination that CO emissions on an hourly average basis have exceeded 50 ppmv (dry basis) corrected to 0 percent excess air, in which case a CO CEMS shall be installed within 180 days. (i) The demonstration shall consist of continuou sly monitoring CO emissions for 30 days using an instrument that meets the requirements of Pe rformance Specification 4 or 4A of appendix B to part 60. The span value shall be 100 ppm CO instead of 1,000 ppm, and the relative accuracy limit shall be 10 percent of the average CO emissions or 5 ppm CO, whichever is greater. For instruments that are identical to Method 10 of appendix A–4 to part 60 and employ the sample conditioning system of Method 10A of appendix A–4 to part 60, the alternative relative accuracytest procedure in section 10.1 of Performance Specification 2 of appendix B to part 60 may be used in place of the relative accuracy test. (ii) The owner or operator must submit the following information to the Administrator: (A) The measurement data specified in paragraph (h)(3)(i) of this section along with all other operating data known to affect CO emissions; and (B) Descriptions of the CPMS for exhaust gas temperature and O 2 monitor required in paragraph (h)(4) of this section and operating limits for those parameters to ensure combustion conditions remain similar to those that exist during the demonstration period. (iii) The effective date of the exemption from installation and operation of a CO CEMS is the date of submission of the information and data required in paragraph (h)(3)(ii) of this section. (4) The owner or operator of a FCCU or FCU that is exempted from the requirement to install and operate a CO CEMS in paragraph (h)(3) of this section shall install, operate, calibrate, and maintain CPMS to measure and record the operating parameters in paragraph (h)(4)(i) or (ii) of this section. The owner or operator shall install, operate, and maintain each CPMS according to the manufacturer's specifications. (i) For a FCCU or FCU with no post-combustion control device, the temperature and O 2 concentration of the exhaust gas stream exiting the unit. (ii) For a FCCU or FCU with a post-combustion control device, the temperature and O 2 concentration of the exhaust gas stream exiting the control device. (i) Excess emissions . For the purpose of reports required by §60.7(c), periods of excess emissions for a FCCU or FCU subject to the emissions limitations in §60.102a(b) are defined as specified in paragraphs (i)(1) through (6) of this section. Note: Determine all averages, except for opacity, 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) If a CPMS is used according to §60.105a(b)(1), all 3-hour periods during which the average PM control device operating characteristics, as measured by the continuous monitoring systems under §60.105a(b)(1), fall below the levels established during the performance test. (2) If a PM CEMS is used according to §60.105a(d), all 7-day periods during which the average PM emission rate, as measured by the continuous PM monitoring system under §60.105a(d) exceeds 0.040 gr/dscf corrected to 0 percent excess air for a modified or reconstructed FCCU, 0.020 gr/dscf corrected to 0 percent excess air for a newly constructed FCCU, or 0.040 gr/dscf for an affected fluid coking unit. (3) If a COMS is used according to §60.105a(e), all 3-hour periods during which the average opacity, as measured by the COMS under §60.105a( e), exceeds the site-spe cific limit established during the most recent performance test.(4) All rolling 7-day periods during which the average concentration of NO X as measured by the NO X CEMS under §60.105a(f) exceeds 80 ppmv for an affected FCCU or FCU. (5) All rolling 7-day periods during which the average concentration of SO 2 as measured by the SO 2 CEMS under §60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods during which the average concentration of SO 2 as measured by the SO 2 CEMS exceeds 25 ppmv. (6) All 1-hour periods during which the average CO concentration as measured by the CO continuous monitoring system under §1A60.105a(h ) exceeds 500 ppmv or, if applicable, all 1- hour periods during which the average temperature and O 2 concentration as measured by the continuous monitoring systems under §60.105a(h)(4) fall below the operating limits established during the performance test. § 60.106a Monitoring of emissions and operations for sulfur recovery plants. (a) The owner or operator of a sulfur recovery pl ant that is subject to the emissions limits in §60.102a(f)(1) or §60.102a(f)(2) shall: (1) For sulfur recovery plants subject to the SO 2 emission limit in §60.102a(f)(1)(i) or §60.102a(f)(2)(i), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration (dry basis, zero percent excess air) of any SO 2 emissions into the atmosphere. The monitor shall include an oxygen monitor for correcting the data for excess air. (i) The span values for this monitor are two times the applicable SO 2 emission limit and between 10 and 25 percent O 2 , inclusive. (ii) The owner or operator shall install, operate, and maintain each SO 2 CEMS according to Performance Specification 2 of appendix B to part 60. (iii) The owner or operator shall conduct performance evaluations of each SO 2 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 6 or 6C of appendix A–4 to part 60 and Method 3 or 3A of appendix A–2 of 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. (2) For sulfur recovery plants that are subject to the reduced sulfur compound and H 2 S emission limit in §60.102a(f)(1)(ii) or §60.102a(f)(2)(ii), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of reduced sulfur, H 2 S, and O 2 emissions into the atmosp here. The reduced sulfur emissions shall be calculated as SO 2 (dry basis, zero percent excess air). (i) The span values for this monitor are two times the applicable reduced sulfur emission limit, two times the H 2 S emission limit, and between 10 and 25 percent O 2 , inclusive. (ii) The owner or operator shall install, operate, and maintain each reduced sulfur CEMS according to Performance Specification 5 of appendix B to part 60. Deleted: Except as provided in p aragraph (i)(7) of this section, all(iii) The owner or operator shall conduct perform ance 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 refere nce—see §60.17) is an acceptable alternative to EPA Method 15A of appendix A–5 to part 60. (iv) The owner or operator shall install, operate, and maintain each H 2 S CEMS according to Performance Specification 7 of appendix B to part 60. (v) 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 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. (vi) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. (vii) The span value for the O 2 monitor must be selected betwee n 10 and 25 percent, inclusive. (viii) The owner or operator shall conduct performance evaluations for the O 2 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. (ix) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to part 60 for each monitor, including annual accuracy determinations for each O 2 monitor, and daily calibration drift determinations. (3) In place of the reduced sulfur monitor required in paragraph (a)(2) of this section, the owner or operator shall install, calibrate, operate, and maintain an instrument using an air or O 2 dilution and oxidation system to convert any reduced sulfur to SO 2 for continuously monitoring and recording the concentration (dry basis, 0 percent excess air) of the total resultant SO 2 . The monitor must include an O 2 monitor for correcting the data for excess O 2 . (i) The span value for this monitor is two times the applicable SO 2 emission limit. (ii) The owner or operator shall cond uct performance evaluations of each SO 2 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.(iii) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. (iv) The span value for the O 2 monitor must be selected between 10 and 25 percent, inclusive. (v) The owner or operator shall conduct performance evaluations for the O 2 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. (vi) The owner or operator shall comply with th e applicable quality assurance procedures of appendix F to part 60 for each monitor, includi ng quarterly accuracy determinations for each SO 2 monitor, annual accuracy determinations for each O 2 monitor, and daily calibration drift determinations. (b) Excess emissions . For the purpose of reports required by §60.7(c), periods of excess emissions for sulfur recovery plants subject to the emissions limitations in §60.102a(f) are defined as specified in paragraphs (b)(1) through (3) of this section. Note: Determine all averages as the arithmetic average of the applicable 1-hour averages, e.g., determine the rolling 12-hour average as the arithmetic average of 12 contiguous 1-hour averages. (1) All 12-hour periods during which the average concentration of SO 2 as measured by the SO 2 continuous monitoring system required under paragraph (a)(1) of this section exceeds the applicable emission limit (dry basis, zero percent excess air); or (2) All 12-hour periods during which the average concentration of reduced sulfur (as SO 2 ) as measured by the reduced sulfur continuous monitoring system required under paragraph (a)(2) of this section exceeds the applicable emission limit; or (3) All 12-hour periods during which the average concentration of H 2 S as measured by the H 2 S continuous monitoring system required under pa ragraph (a)(2) of this section exceeds the applicable emission limit (dry basis, 0 percent excess air). § 60.107a Monitoring of emissions and operations for fuel gas combustion devices. (a) Fuel gas combustion de vices 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 SO 2 emissions or paragraph (a)(2) of this section for H 2 S emissions. (1) The owner or operator of a fuel gas combustion device subject to the SO 2 emissions limits in §60.102a(g)(1)(i) shall install, operate, calibra te, and maintain an instrument for continuously monitoring and recording the concentration (dry basis, 0 percent excess air) of SO 2 emissionsinto the atmosphere. The monitor must include an O 2 monitor for correcting the data for excess air. (i) The owner or operator shall install, operate, and maintain each SO 2 monitor according to Performance Specification 2 of appendix B to part 60. The span value for the SO 2 monitor is 50 ppm SO 2 . (ii) The owner or operator shall conduct performance evaluations for the SO 2 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, wh ichever 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 O 2 monitor according to Performance Specification 3 of appendix B to part 60. The span value for the O 2 monitor must be selected between 10 and 25 percent, inclusive. (iv) The owner or operator shall conduct performance evaluations for the O 2 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 SO 2 monitors, annual accuracy determinations for O 2 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 SO 2 emissions into the atmosphere from each of the combustion devices. (2) The owner or operator of a fuel gas combustion device subject to the H 2 S 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 H 2 S in the fuel gases before being burned in any fuel gas combustion device. (i) The owner or operator shall install, operate, and maintain each H 2 S monitor according to Performance Specification 7 of appendix B to part 60. The span value for this instrument is 300 ppmv H 2 S. (ii) The owner or operator shall conduct performance evaluations for each H 2 S 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 Deleted: 320Method 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 alternat ive 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 H 2 S 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 H 2 S 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 str eams 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 containi ng-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 plan t, 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 H 2 S 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 H 2 S content) to be introduced into the fuel gas stream/system (t his 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 H 2 S. 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 H 2 S; and (v) A description of how the 2 weeks (or seven samples for infrequently operated fuel gas streams/systems) of monitoring result s compares to the typical range of H 2 S 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 H 2 S content in the fuel gas stream going to the loading rack flare). (2) The effective date of the exemption is the da te 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 H 2 S 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 ow ner 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 th e owner or operator chooses not to submit newinformation to support an exemption, the owner or operator must begin H 2 S 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 oper ation change. During daily stain tube sampling, a daily sample exceeding 162 ppmv is an exceedance of the 3-hour H 2 S concentration limit. The owner or operator must determine a rolling 365-day average using the stain sampling results; an average H 2 S concentration of 5 ppmv must be used for days 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 NO X emission limit in §60.102a(g)(2) and electing to comply with the applicable emission 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 NO X 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 O 2 monitor for correcting the data for excess air. (1) The owner or operator shall install, operate, and maintain each NO X monitor according to Performance Specification 2 of appendix B to part 60. The span value of this NO X monitor must be between 2 and 3 times the applicable emission limit, inclusive

. (2) The owner or operator shall conduct performance evaluations of each NO X 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 refere nce—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 O 2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O 2 monitor must be selected between 10 and 25 percent, inclusive. (4) The owner or operator shall conduct performance evaluations of each O 2 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 NO X and O 2 monitor, including quarterly accuracy determinations for NO X monitors, annual accuracy determinations for O 2 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 NO X emissions (i.e., low-NO X burners , ultra-low-NO X burners) may elect to comply with the Deleted: subject to NO X

Deleted: is 200 ppmv NO X

Deleted: lowDeleted: b urners (LNB) or ultra Deleted: (ULNB) is not subject to themonitoring 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 , establish a maximum excess oxygen concentration operating limit, and comply with the O 2 monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. (d) Process heaters complying with the NO X heating value-based limit. The owner or operator of a process heater subject to the NO X emissions limit in §60.102a(g)(2) and electing to comply with the applicable emissions limit in §60.102a(g)(2 )(i)(B), (g)(2)(ii)(B), or (g)(2)(iii)(B) shall install, operate, calibrate, and maintain an in strument for continuously monitoring and recording the concentration (dry basis, 0 percent excess air) of NO X 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 NO X emission limit in §60.102a(g)(2) and electing to comply with the heating value-based limit in §60.102a(g)(2)(iv)(B) shall also install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration (dry basis, 0 percent excess air) of NO X emissions into the atmosphere according to the monitoring requirements in paragraph (d)(1) of this section, an instrument for continuously monitoring and recording the flow rate of the fuel oil and fuel gas fed to the process heater according to the monitoring requirements in paragr aph (d)(5) and (6) of this section, and shall determine the heating value of the fuel oil and fuel gas streams no less frequently than once per day according to the monitoring requirements in paragraph (d)(7) of this section. (1) The owner or operator shall install, operate, and maintain each NO X monitor according to the requirements in paragraphs (c)(1) through (5) of this section. The monitor must include an O 2 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 he ater using the methods and equations in section 12.3.2 of 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 9 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). 

# ( ) ( ) 

# ∑ ∑

× × ×

= i i i i d 

## MHC X MEV X F 000 , 000 , 1

(Eq. 9)

Where: Deleted: . The Deleted: mustF d = F factor on dry basis at 0% excess air.

X i = mole or volume fraction of each component in the fuel gas.

MEV i = molar exhaust volume, dry standard cubic feet per mole (dscf/mol).

MHC i = 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. Method 18 of Appendix A–6 to part 60 shall be used for conducting the relative accuracy evaluations. The following methods are acceptable alternatives to EPA Method 18 of Appendix A–2 to part 60: (i) ASTM D1945–03, Standard Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference-see §60.17); (ii) ASTM D6420–99 (Reapproved 2004) Standard Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Ch romatography-Mass Spectrometry (incorporated by reference-see §60.17); (iii) ASTM D1946–90 (Reapproved 2006), Standard Method for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference-see §60.17); and (iv) Gas Processors Association Standard 2261–00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference-see §60.17). (5) The owner or operator shall conduct performance evaluations of each fuel gas flow monitor according to the requirements in §60.13(c) and Performance Specification 6 of Appendix B to part 60. Method 2, 2A, 2B, 2C, or 2D of Appendix A–2 to part 60 shall be used for conducting the relative accuracy evaluations. The following methods are acceptable alternatives to EPA Method 2, 2A, 2B, 2C, or 2D of Appendix A–2 to part 60: (i) ASME MFC–3M–1989 (Reaffirmed 1995), Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference-see §60.17); (ii) ASME MFC–4M–1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference-see §60.17); (iii) ASME–MFC–5M–1985, (Reaffirmed 1994), Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowme ters (incorporated by reference-see §60.17); (iv) ASME MFC–6M–1998, Measurement of Flui d Flow in Pipes Usin g Vortex Flowmeters (incorporated by reference-see §60.17);(v) ASME MFC–7M–1987 (Reaffirmed 1992), Meas urement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference-see §60.17); (vi) ASME MFC–9M–1988 (Reaffirmed 2001), Measurement of Liquid Flow in Closed Conduits by Weighing Method (incorporated by reference-see §60.17); (vii) American Gas Association Transmission Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters Second Revision, April 1996 (incorporated by reference-see §60.17); and (viii) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, First Edition, Chapter 22-Testing Protocol, Section 2-Differential Pressure Flow Measurement Devices, August 2005 (incorporated by reference-see §60.17). (6) The owner or operator shall conduct install, operate, and maintain each fuel oil flow monitor according to the manufacturer’s recommendations. (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 incl uded in paragraphs (d)(7)(i) through (v) 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). (i) ASTM D240–02, (Reapproved 2007), Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference-see §60.17). (ii) ASTM D1826–94 (Reapproved 2003), Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated by reference-see §60.17). (iii) ASTM D4809–06, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference-see §60.17). (iv) ASTM D4891–89 (Reapproved 2006), Standard Test Method for Heatin g Value of Gases in Natural Gas Range by Stoichiometric Combus tion (incorporated by reference-see §60.17). (v) Gas Processors Association Standard 2172–96, Calculation of Gross Heating Value, Relative Density and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis (incorporated by reference—see §60.17). (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 NO X emissions (i.e., low-NO X burners or ultra-low NO X 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, establish a maximum excess oxygen concentration operating limit, and comply with the O 2 monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance.( e ) Sulfur monitoring for affected flares . The owner or operator of an affected flare subject to §60.103a(b) shall determine reduced sulfur compound concentrations in accordance with paragraph (e)(1) of this section or total sulfur compound concentrations in accordance with either paragraph (e)(2) or (3) of this section. (1) The owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of reduced sulfur compounds in flare gas. The owner or operator of a modified flare must install this instrument no later than 18 months after the flare becomes an affected flare subject to this subpart unless the owner or operator of the affected flare commits in writing to install a flare gas recovery system, in which case the owner or operator of a modified flare must install this instrument no later than 2 years after the flare becomes an affected flare subject to this subpart

. ( i ) The owner or operator shall install, operate, and maintain each reduced sulfur compounds CEMS according to Performance Specification 5 of Appendix B to part 60. ( ii ) The owner or operator shall conduct perfor mance evaluations of each reduced sulfur compounds 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 Method 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. ( iii ) The owner or operator shall comply with the applicable quality assurance procedures in Appendix F to part 60 for each reduced sulfur monitor. (2) The owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of total sulfur compounds in flare gas. The owner or operator of a modified flare must in stall this instrument no later than 18 months after the flare becomes an affected flare subject to this subpart unless the owner or operator of the affected flare commits in writing to install a flare gas recovery system, in which case the owner or operator of a modified flare must install this instrument no later than 2 years after the flare becomes an affected fl are subject to this subpart. (i) The owner or operator shall install, operate, and maintain each total sulfur compounds CEMS according to Performance Specification 5 of Appendix B to part 60. (ii) The owner or operator shall conduct performa nce evaluations of each total sulfur compounds 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 Method 16 or 16A 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 16A of Appendix A–6 to part 60. (iii) The owner or operator shall comply with the applicable quality assurance procedures in Appendix F to part 60 for each reduced sulfur monitor. Deleted: d

Deleted: shall Deleted: by Deleted: 1 year

Deleted: 1 Deleted: appendix

Deleted: 2

Deleted: appendix Deleted: Methods Deleted: appendix Deleted: appendix

Deleted: 3 Deleted: appendix(3) The owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of H 2 S in flare gas according to the requirements in paragraphs (e)(3)(i) through (iii ) of this section and shall collect and analyze samples of flare gas and calculate total sulfur concentrations as specified in paragraphs (e)(3)(iv) through (ix) of this section. The owner or operator of a modified flare must install this H 2 S monitor no later than 18 months after the flare becomes an affected flare subject to this subpart unless the owner or operator of the affected flare commits in writing to install a flare gas recovery system, in which case the owner or operator of a modified flare must install this instrument no later than 2 years after the flare becomes an affected flare subject to this subpart. (i) The owner or operator shall install, operate, and maintain each H 2 S monitor according to Performance Specification 7 of Appendix B to part 60. The span value must be between 1 and 5 percent (by volume) inclusiv e. A single dual range H 2 S 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 cond uct performance evaluations of each H 2 S monitor according to the requirements in §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 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 H 2 S monitor. (iv) In the first 10 operating days after the flare may be required to perform a root cause analysis under §60.103a(b)(1), the owner or operator shall collect representative daily samples of the flare gas. The samples may be grab sa mples or integrated samples. The owner or operator shall take subsequent representative daily samples at least once per week or as required in paragraph (e)(3)(vii) of this section. (v) The owner or operator shall analyze each daily sample for total sulfur using Method 16A of Appendix A–6 to part 60, ASTM Method D4468–85 (Reapproved 2006), “Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry” (incorporated by reference—see §60.17), or ASTM Method D5504–01 (Reapproved 2006), “Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemilumine scence” (incorporated by reference—see §60.17). (vi) The owner or operator shall develop a 10-day average total sulfur-to-H 2 S ratio and 95 percent confidence interval as follows: (A) Calculate the ratio of the total sulfur concentration to the H 2 S concentration for each day during which samples are collected. (B) Determine the 10-day average total sulfur-to-H 2 S ratio as the arithmetic average of the daily ratios calculated in paragraph (e)(3)(vi)(A) of this section.(C) Determine the 95 percent confidence interval for the distribution of daily ratios based on the 10 individual daily ratios. (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 whic h 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-H 2 S ratio by the daily average H 2 S concentrations obtained using the monitor as required by paragraph (e)(3)(i) through (iii) of this section to estimate total sulfur concentrations. (ix) If the total sulfur-to-H 2 S ratio for a subsequent weekly sample is outside the 95 percent confidence interval for the most recent distributi on of daily ratios, the owner or operator shall develop a new 10-day average ratio and 95 percent confidence interval based on data for the outlying weekly sample plus data collect ed over the following 9 operating days. ( f

) Flow monitoring for flares . The owner or operator of an affected flare subject to §60. 103a(a)(4 ) shall install, operate, calibrate, and maintain CPMS to measure and record the flare gas flow rate. The owner or operator of a modified flare shall install this instrument by no later than 18 months after the flare becomes an affected flare subject to this subpart unless the owner or operator of the affected flare commits in writing to install a flare gas recovery system, in which case flow monitoring is not required until after the flare has been an affected flare subject to this subpart for 2 years

. (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. ( g ) 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 SO 2 as measured by the SO 2 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 SO 2 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 H 2 S as measured by the H 2 S continuous monitoring system required under paragraph (a)(2) of this section exceeds 162 ppmv, all days in which the concentration of H 2 S as measured by daily stain tube sampling Deleted: e Deleted: 102a(g)(3 Deleted: exhaust Deleted: 1 year

Deleted: frequired 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 H 2 S continuous monitoring system under paragraph (a)(2) of this section exceeds 60 ppmv. (3) All rolling 365-day periods during which the average concentration of NO X as measured by the NO X continuous monitoring system required under paragraph (c) or (d) of this section exceeds : (i) 40 ppmv or 0.035 lb/MMBtu for a newly constructed process heater or a modified or reconstructed natural draft process heater; (ii) 60 ppmv or 0.055 lb/MMBtu for a modified or reconstructed forced draft process heater; (iii) 150 ppmv or the daily average emissi on limit calculated using Equation 3 in §60.102a(g)(2)(iv)(B) for a co-fired process heater; and (iv) The site-specific limit determined by the Administrator under §60.102a(i). (4) All daily periods during which the concentration of NO X as measured by the NO X continuous monitoring system required under paragraph ( d ) of this section exceeds the applicable emissions limit in §60.102a(g)(2)(iv)

. § 60.108a Recordkeeping and reporting requirements. (a) Each owner or operator subject to the emissi ons limitations in §60.102a shall comply with the notification, recordkeeping, and reporting requi rements in §60.7 and other requirements as specified in this section. (b) Each owner or operator subject to an emissions limitation in §60.102a or work practice standard in §60.103a shall notify the Administrator of the specific monitoring provisions of §§60.105a, 60.106a, and 60.107a with which the owner or operator seeks to comply. The notification must include, if applicable, a written statement that the owner or operator of an affected flare is installing a flare gas recovery system or additional amine adsorption and stripping columns. Notification shall be submitted with the notification of initial startup required by §60.7(a)(3). (c) The owner or operator shall maintain the following records: (1) A copy of the flare management plan and each root cause analysis of a discharge; (2) Records of information to document conforma nce with bag leak detection system operation and maintenance requirements in §60.105a(c). (3) Records of bag leak detection system al arms and actions according to §60.105a(c). (4) For each FCCU and fluid coking unit subject to the monitoring requirements in §60.105a(b)(1), records of the average coke burn-off rate and hours of operation. Deleted: 24-hour Deleted: 40 ppmv.

Deleted: rolling 30-day Deleted: average flow rate to an affected flare Deleted: e Deleted: 250,000 scfd(5) For each fuel gas stream to which one of the exemptions listed in §60.107a(a)(3) applies, records of the specific exemption determined to apply for each fuel stream. If the owner or operator applies for the exemption described in §60.107a(a)(3)(iv), the owner or operator must keep a copy of the application as well as the letter from the Administrator granting approval of the application. (6) The owner or operator shall record and maintain records of discharges greater than 500 lb SO 2 in any 24-hour period from any affected flare, discharges greater than 500 lb SO 2 in excess of the allowable limits from a fuel gas combustion device other than a flare or sulfur recovery plant , and discharges to an affected flare in excess of 500,000 scf in any 24-hour period. The following information shall be recorded no later than 45 days following the end of a discharge exceeding the thresholds : (i) A description of the discharge. (ii) The date and time the discharge was first identified and the duration of the discharge. (iii) The measured or calculated cumulative quantity of gas discharged over the discharge duration. If the discharge duration exceeds 24 hours, record the discharge quantity for each 24- hour period. For a flare, record the measured or calculated cumulative quantity of gas discharged to the flare over the discharge duration. If the discharge duration exceeds 24 hours, record the quantity of gas discharged to the flare for each 24-hour period. Engineering calculations are allowed for fuel gas combustion devices other than flares. (iv) For each discharge greater than 500 lb SO 2 in any 24-hour period from a flare , the measured reduced sulfur concentration , measured total sulfur concentration, or both the measured H 2 S concentration and the estimated total sulfur concentration in the fuel gas at a representative location in the flare inlet. (v) For each discharge greater than 500 lb SO 2 in excess of the applicable short-term emissions limit in §60.102a(g)(1) from a fuel gas combustion device other than a flare, either the measured concentration of H 2 S in the fuel gas or the measured concentration of SO 2 in the stream discharged to the atmosphere . Process knowledge can be used to make these estimates for fuel gas combustion devices other than flares. (v i ) For each discharge greater than 500 lb SO 2 in excess of the allowable limits from a sulfur recovery plant, either the measured concentration of reduced sulfur or SO 2 discharged to the atmosphere. (vii) For each discharge greater than 500 lb SO 2 in any 24-hour period from any affected flare or discharge greater than 500 lb SO 2 in excess of the allowable li mits from a fuel gas combustion device other than a flare or sulfur recovery plant , the cumulative quantity of H 2 S and SO 2 released into the atmosphere. For releases controlled by flares, assume 99 percent conversion of reduced sulfur or total sulfur to SO 2 . For other fuel gas combustion devices, assume 99 percent conversion of H 2 S to SO 2 . (vi ii) The steps that the owner or operator took to limit the emissions during the discharge. Deleted: /day

Deleted: scfd. These records shall include

Deleted: For discharges greater than 500 lb/day SO 2 , the

Deleted: discharges Deleted: /day Deleted: or estimated Deleted: of Deleted: , TRS

Deleted: discharges Deleted: /day(ix ) Results of any root-cause analysis and corrective action analysis conducted as required in §60.103a(a)(4) and (5) and §60.103a(b ), including a statement noting whether the discharge resulted from the same root cause identified in a previous analysis, and either a description of the corrective action and a schedule for implementation or an explanation of why corrective action is not necessary as required in §60.103a(c ). (7) If the owner or operator complies with §60.107a(d)(3) for a flare, records of the H 2 S and total sulfur analyses of each grab or integrated sample, the calculated daily total sulfur-to-H 2 S ratios, the calculated 10-day average total sulfur-to-H 2 S ratios, and the 95 percent confidence intervals for each 10-day average total sulfur-to-H 2 S ratio. (d) Each owner or operator subject to this subpar t shall submit an excess emissions report for all periods of excess emissions according to the requirements of §60.7(c) except that the report shall contain the information specified in paragraphs (d)(1) through (7) of this section. (1) The date that the exceedance occurred; (2) An explanation of the exceedance; (3) Whether the exceedance was concurrent with a startup, shutdown, or malfunction of an affected facility or control system; and (4) A description of the action taken, if any. (5) The information described in paragraph ( c )(6) of this section for all discharges for which a root-cause analysis , corrective action analysis, and implementation of corrective action were required by §60.103a(a)(4) and (5), §60.103a(b ), and §60.103a(c ). (6) For any periods for which monitoring data are not available, any changes made in operation of the emission control system during the period of data unavailability which could affect the ability of the system to meet the applicable emission limit. Operations of the control system and affected facility during periods of data unavailability are to be compared with operation of the control system and affected facility before a nd following the period of data unavailability. (7) A written statement, signed by a respons ible official, certifying the accuracy and completeness of the information contained in the report. § 60.109a Delegation of authority. (a) This subpart can be implemented and enforced by the U.S. EPA or a delegated authority such as a State, local, or tribal agency. You should contact your U.S. EPA Regional Office to find out if this subpart is delegated to a State, local, or tribal agency within your State. (b) In delegating implementation and enforcement authority of this subpart to a State, local, or tribal agency, the approval authorities contained in paragraphs (b)(1) through ( 4 ) of this section are retained by the Administrator of the U.S. EPA and are not transferred to the State, local, or tribal agency. Deleted: A root-cause summary report that provides the Deleted: e Deleted: was

Deleted: 3(1) Approval of a major change to test methods under §60.8(b). A “major change to test method” is defined in 40 CFR 63.90. (2) Approval of a major change to monitoring under §60.13(i). A “major change to monitoring” is defined in 40 CFR 63.90. (3) Approval of a major change to recordkeeping/reporting under §60.7(b) through (f). A “major change to recordkeeping/reporting” is defined in 40 CFR 63.90. (4) Approval of a petition to establish a site-specific NO X emissions limit for a modified or reconstructed process heater under §60.102a(i). Tables to Subpart Ja of Part 60 Table 1 to Subpart Ja of Part 60--Molar Exhaust Volumes and Molar Heat Content of Fuel Gas Constituents

Constituent MEV a dscf/mol MHC b Btu/mol Methane (CH 4 ) 7.28 842 Ethane (C 2 H 6 ) 12.94 1,475 Hydrogen (H 2 ) 1.61 269 Ethene (C 2 H 4 ) 11.34 1,335 Propane (C 3 H 8 ) 18.61 2,100 Propene (C 3 H 6 ) 17.01 1,947 Butane (C 4 H 10 ) 24.28 2,717 Butene (C 4 H 8 ) 22.67 2,558 Inerts 0.85 0

a MEV = molar exhaust volume, dry standard cubic feet per mole (dscf/mol) b MHC = molar heat content, Btu per mole (Btu/mol)