May 15, 2012 Redline of 40 CFR part 60, subpart Ja, showing final amendments Insertions are shown in bold blue text Deletions are shown in red strikeout text

1 Title 40: Protection of Environment

PART 60—STANDARDS OF PERFORMANC E FOR NEW STATIONARY SOURCES Subpart Ja—Standards of Performance for Petrol eum Refineries for Which Construction, Reconstruction, or Modificati on 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 th e following affected facilities in petroleum refineries: fluid catalytic crack ing units (FCCU), fluid coking un its (FCU), delayed coking units, fuel gas combustion devices , ( including flares and process heaters ) , flares and sulfur recovery plants. The sulfur recovery plant need not be physically located with in the boundaries of a petroleum refinery to be an affected facil ity, provided it processes gases produced within a petroleum refinery. (b) Except for flares, the provisi ons of this subpart apply only to affected facilities under paragraph (a) of this section which commence c onstruction, modification, or reconstruction after May 14, 2007. For flares, the provisions of this subpart apply only to flares which commence construction, modification, or r econstruction, after June 24, 2008. For the purposes of this subpart, a modification to a flare commences when a project that includes any of the activities in paragraphs (c)(1) or (2) of this section is commenced. (c) For all affected facilities other than flares, the provisions in §60.14 regarding modification apply. As provided in §60.14(f), the special provisions set forth under this subpart shall supersede the provision s in §60.14 with respect to flares. For the purposes of this subpart, under §60.14, a modification to a flare occurs as provided in paragraphs (c)(1) or (2) of this section. if: (1) Any new piping from a refinery process unit , including ancillary equipment, or a fuel gas system is physically connected to the flare ( e.g. , for direct emergency relief or some form of continuous or intermittent venting) ; or . However, the connections described in paragraphs (c)(1)(i) through (vi) of this section a re not considered modifications of a flare. (i) Connections made to install mo nitoring systems to the flare. (ii) Connections made to install a flare gas recovery system or connections made to upgrade or enhance components of a flare gas recovery system ( e.g. , addition of compressors or recycle lines).2 (iii) Connections made to replace or upgrade existing pressure relief or safety valves, provided the new pressure relief or safety valv e has a set point opening pressure no lower and an internal diameter no greater than the existing equipment being replaced or upgraded. (iv) Connections made for flare gas sulfur removal. (v) Connections made to install back-up (re dundant) equipment associated with the flare (such as a back-up compressor) that does not increase the capaci ty of the flare. (vi) Replacing piping or moving an existing connection from a refinery process unit to a new location in the same flare, provided the ne w pipe diameter is less than or equal to the diameter of the pipe/conn ection being replaced/moved. (vii) Connections that interco nnect two or more flares. (2) A flare is physically altered to in crease the flow capac ity 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 wh ich are or will be replaced pursuant to all continuous programs of com ponent replacement which are commenced within any 2-year period following May 14, 2007. For purpos es of this paragraph, “commenced” means that an owner or operator has undertaken a c ontinuous program of component replacement or that an owner or operator has entered into a contractual oblig ation to undertake and complete, within a reasonable time, a continuous program of component replacement.

Effective Date Note: At 73 FR 55752, Sept

. 26, 2008, §60.100a(c ) was stayed until Dec

. 25, 2008. § 60.101a Definitions. Terms used in this subpart are defined in the Clean Air Act (CAA) , in §60.2, and in this section. Air preheat means a device used to heat the air supp lied to a process heater generally by use of a heat exchanger to recover the latent heatof exhaust gas from the process heater. Ancillary equipment means equipment used in conjuncti on with or that serve a refinery process unit. Ancillary equipment includes, but is not limited to, storage tanks, product loading operations, wastewater treatment system s, steam- or electricity-producing units (including coke gasification units), pressure relief valves, pumps, sampling vents and continuous analyzer vents. Cascaded flare system means a series of flares connect ed to one flare gas header system arranged with increasing pressure set points so that discharges will be initially directed to the first flare in the series ( i.e. , the primary flare). If the di scharge pressure exceeds a set point at which the flow to the primary flare would exceed the primary flare’s capacity, flow will be diverted to the second flare in the series . Similarly, flow would be diverted to a third3 (or fourth) flare if the pre ssure in the flare gas header sy stem exceeds a threshold where the flow to the first two (or three) flares would exceed their capacities. Co-fired process heatermeans a process heater that employs burners that are designed to be supplied by both gaseous and liquid fuels on a routine basis. Process heaters that have gas burners with emergency oil back-up burners a re not considered co-fired process heaters. Coke burn-off means the coke removed from the surface of the FCCU catalyst by combustion in the catalyst regenerator. The rate of coke burn-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 ma intenance changes that one takes consistent with good engineering practice to reduce or eliminate th e likelihood of the recurrence of the primary cause and any other cont ributing cause(s) of an event identified by a root cause analysis as having resulted in a discharge of gases to an affected flare in excess of specified thresholds. Corrective action analysis means a description of all rea sonable interim and long-term measures, if any, that are available, and an explanation of why the selected corrective action(s) is/are the best altern ative(s), including, but not limi ted to, considerations of cost effectiveness, technical feasibil ity, safety and secondary impacts. Delayed coking unit means a one or more refinery process unit s in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit includes, but is not limited to, all of the coke drums associated with a single fraction ator; the fractionator, including the bottoms receiver and the overhead condenser; the coke drum cutting water and quench system, including the jet pump and coker quench wat er tank; process piping and associated equipment such as pumps, valves and connector s; and the coke drum blowdown recovery compressor system. Emergency flare means a flare that combusts gas exclusively released as a result of malfunctions (and not startup, shutdown, routine operations or any other cause) on four or fewer occasions in a rolling 365-day period. Fo r purposes of this rule, a flare cannot be categorized as an emergency flare unless it maintains a water seal.

Flare means an open - flame fuel gas combustion device that uses an uncontrolled volume of air to used for burn ing off unwanted gas es or flammable gas and liquids . The flare includes the foundation, flare tip, struct ural support, burner, igniter, flare controls , including air injection or steam injection systems, flame arrestors , knockout pots, piping and the flare gas header system s

. In the case of an interconnect ed flare gas header system, the flare includes each individual flare serviced by the interconnected flare gas header system and th e interconnected flare gas header system.4 Flare gas header system means all piping and knockout po ts, including those in a subheader system, used to collect and transport gas to a flare either from a pr ocess unit or a pressure relief valve from the fuel gas system, regardless of whether or not a flare gas recovery system draws gas from the flare gas header system . The flare gas header system includes piping inside the battery limit of a process unit if the purpose of the pi ping is to transport gas to a flare or knockout pot that is part of the flare. Flare gas recovery system means a system of one or mo re compressors, piping and the 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. Flexicoking unit means one or more a refinery process unit s in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke 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 hydrocar bon 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 regene rated by burning off coke and other deposits. The unit includes the riser, reactor, regenerator, air blowers, spen t catalyst or contact materi al stripper, catalyst or contact material recovery equipment, and rege nerator equipment for c ontrolling air pollutant emissions and for heat recovery. When fluid catalyst cracking unit regenerator exhaust from two separate fluid catalytic cracking unit s 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 one or more a refinery process unit s in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke 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 an y location in the inlet air line prior to the point where the combustion air enters the proc ess heater or air preheat. For the purposes of this subpart, a process heater that uses fans at both the inlet air side and the exhaust air side ( i.e. , balanced draft system) is considered to be a forced draft process heater

. Fuel gas means any gas which is generated at a pe troleum refinery and which is combusted. Fuel gas includes natural gas when the natural gas is combined and 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 premium 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 in a thermal oxidizer or flare installed to control emissions from comply with the wastewater treatment units other than those processing sour water provisions in §60.692 , 40 CFR 61.343 through 61.348, 40 CFR5 63.647, or the marine tank vessel loading operations or asphalt processing units ( i.e. , asphalt blowing stills) provisions in 40 CFR 63.562 or 40 CFR 63.651

. Fuel gas combustion device means any equipment, such as process heaters , and boilers, and flares, used to combust fuel gas . For the purposes of this subpart , fuel gas combustion device does not include flares or exceptfacilities 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 fo r 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 which the combustion air is supplied under ambient or negative 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, including induced draft systems. Non-emergency flare means any flare that is not an em ergency flare as defined in this subpart. Oxidation control system means an emission control system wh ich 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 r eactor 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, lubri cants, asphalt (bitumen) or othe r products through distillation of petroleum or through redistillation, cracking , or reforming of unfinis hed petroleum derivatives. A facility that produces only oil shale or ta r sands-derived crude oil for further processing at a petroleum refinery using only solvent extrac tion and/or distillation to recover diluent is not a petroleum refinery

. Primary flare means the first flare in a cascaded flare system.

Process heater means an enclosed combustion device used to transfer heat indi rectly 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 or by ancillary equipment as a result of startup, shutdown, upset or malfunction. Purge gas means gas introduced between a flare’s water seal and a flare’s tip to prevent oxygen infiltration (backflow) into the flare tip. For flares with no water seals, the function6 of purge gas is performed by sweep gas ( i.e. , flares without water seals do not use purge gas ). Reduced sulfur compounds means hydrogen sulfide (H 2 S), carbonyl sulfide, and carbon disulfide. Reduction control system means an emission control system wh ich 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 th e 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. Root cause analysis means an assessment conducted thro ugh a process of investigation to determine the primary cause, and any other co ntributing cause(s), of a discharge of gases in excess of specified thresholds. Secondary flare means a flare in a casc aded flare system that provides additional flare capacity and pressure relief to a flare gas sy stem when the flare gas flow exceeds the capacity of the primary flare. For purposes of this subpart, a secondary flare is characterized by infrequent use and must maintain a water seal. Sulfur pit means the storage vessel in which sulfur th at 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 process units which recover sulfur from H 2 S HS 2 and/or SO 2 from a common source of sour gas produced at a petroleum refinery. The sulfur recovery plant also includes sulfur pits used to store the recovered sulfur product, but it does not include secondary sulfur storage vessels or loading facilities downstream of the sulfur pits. For example, a Claus sulfur recovery plant includes: Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits, and, if present, oxidation or reduction co ntrol systems, or incinerator, thermal oxidizer, or similar combustion device. Multiple sulfur recovery units 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 segregat ed sour gas treatment systems are separate affected facilities. Sweep gas means the gas introduced in a flare gas header system to maintain a constant flow of gas to prevent oxygen buildup in the fl are header. For flares with no water seals, sweep gas also performs the function of preventi ng oxygen infiltration (backflow) into the flare tip.

Effective Date Note: At 73 FR 55752, Sept

. 26, 2008, in §60.101a, the definition of “flare” was stayed until Dec

. 25, 2008. § 60.102a Emission s limitations.7 (a) Each owner or operator that is subject to th e requirements of this subpart shall comply with the emissions limitations in paragraphs (b) through ( i h ) of this section on and after the date on which the initial performance te st, required by §60.8, is completed, but not later than 60 days after achieving the maximum production rate at whic h the affected facility will be operated, or 180 days after initial start up, 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 (l b) 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 perc ent 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 corr ected 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 co mply with the applicable control device parameter operating limit in paragra ph (c)(1) or (2) of this section. (1) If the FCCU or FCU is controlled using an electrostatic precipitator: (i) The 3-hour rolling average to tal 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 leve l established during the most recent performance test. (2) If the FCCU or FCU is c ontrolled using a wet scrubber: (i) The 3-hour rolling average pressure drop must not fall below the leve l established during the most recent performance test; and8 (ii) The 3-hour rolling average li quid-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 opacitymonitoring 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 CO MS 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 that is exempted from the requirement for a CO continuous emissions monitoring system under §6 0.105a(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 exhaus t gases exiting the FCCUor FCU must not fall below the level established during the most recent performance test. (ii) The hourly average oxygen (O 2 ) concentration of the exhaus t gases exiting the FCCU or FCU must not fall below the level establishe d 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 ga s vent stream exiting the control device must not fall below the level establis hed during the most recent performance test. (f) Except as provided in paragraph (f)(3), each owner or operator of an affected sulfur recovery plant shall comply with the applicable emission lim its 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 oxidati on 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 release points the owner or operator sh all comply with th e 250 ppmv limit for each process train or release point or comply with a flow rate wei ghted average of 250 ppmv for all release points from the sulfur recovery plant; or (ii) For sulfur recovery plan t 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 ppm v by volume of reduced sulfur compounds and 10 ppm v by volume of H 2 S hydrogen sulfide (HS 2 ) , each calculated as ppm v SO 2 by volume (dry basis) at 0- zero percent excess air; or9 (iii) For systems using oxygen enrichment, the ow ner or operator shall cal culate 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 wi th a capacity of 20 LTD or less: (i) For a sulfur recovery plant with an oxidati on 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 pp mv 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 plan t 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 3,000 ppm by volume of reduced su lfur 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 ow ner or operator shall cal culate the applicable emission limit using Equation 2 of this section:

Where:

E SS = Emission rate of SO 2 for small sulfur recovery plant, ppmv. (3) Periods of maintenance of the sulfur pit, during whic h 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.10 (g) Each owner or operator of an affected fuel gas combustion device shall comply with the emission limits in paragraphs (g)(1) and through( 2 3 ) of this section. (1) Except as provided in (g)(1)(iii) of this section, f F or each fuel gas co mbustion 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 (drybasis, 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 calendar 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 hourlyon 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. (iii) The combustion in a portable generator of fuel gas released as a result of tank degassing and/or cleaning is exempt from the emissions limits in pa ragraphs (g)(1)(i) and (ii). (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 Xin excess of the applicable limits in paragraphs (g)(2)(i) through (iv) of this section. (i) For each natural draft process heater, comply with the limit in either paragraph (g)(2)(i)(A) or (B) of this sect ion. The owner or operator may comply with either limit at any time, provided that the appropriate parame ters for each alternative are monitored as specified in §60.107a; if fuel gas composition is not monitored as specified in §60.107a(d), the owner or operator must comply with the concentration limits in paragraph (g)(2)(i)(A) of this section. (A) 40 ppmv (dry basis, corrected to 0

- percent excess air) determined daily on a 30-day 24

- hour rolling average basis ; or (B) 0.040 pounds per million British thermal uni ts (lb/MMBtu) higher heating value basis determined daily on a 30-day rolling average basis

. (ii) For each forced draft process heater, co mply with the limit in either paragraph (g)(2)(ii)(A) or (B) of this section. The own er or operator may comply with either limit at any time, provided that the appropriate parame ters for each alternative are monitored as specified in §60.107a; if fuel gas composition is not monitored as specified in §60.107a(d), the owner or operator must comply with the concentration limits in paragraph (g)(2)(ii)(A) of this section. (A) 60 ppmv (dry basis, corrected to 0-percen t excess air) determined daily on a 30-day rolling average basis; or11 (B) 0.060 lb/MMBtu higher heating value basi s determined daily on a 30-day rolling average basis. (iii) For each co-fired natural draft process heater, comply with the limit in either paragraph (g)(2)(iii)(A) or (B) of this section. The owner or operator must choose one of the emissions limits with which to comply at all times: (A) 150 ppmv (dry basis, corrected to 0-perce nt excess air) determined daily on a 30 successive operating day rolling average basis; or (B) The daily average emissions limit calcul ated using Equation 3 of this section:

oil oil gas gas oil oil gas gas NOx 

## HHV Q HHV Q HHV Q HHV Q ER  

 35

. 0 06

. 0 (Eq. 3)

Where:

ER NOx = Daily allowable average emission rate of NO X , lb/MMBtu (higher heating value basis); Q gas = Daily average volumetric flow rate of fuel gas, standard cubic feet per day (scf/day); Q oil = Daily average volumetric flow rate of fuel oil, scf/day;

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. (iv) For each co-fired forced draft process heater, comply with the limit in either paragraph (g)(2)(iv)(A) or (B) of this section. The owner or operator must choose one of the emissions limits with which to comply at all times: (A) 150 ppmv (dry basis, corrected to 0-perce nt excess air) determined daily on a 30 successive operating day rolling average basis; or (B) The daily average emissions limit calcul ated using Equation 4 of this section:

oil oil gas gas oil oil gas gas NOx 

## HHV Q HHV Q HHV Q HHV Q ER  

 40

. 0 11

. 0 (Eq. 4)

Where:12 ER NOx = Daily allowable average emission rate of NO X , lb/MMBtu (higher heating value basis); Q gas = Daily average volumetric flowrate of fuel gas, scf/day; Q oil = Daily average volumetric flow rate of fuel oil, scf/day;

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. (3 ) Except as provided in paragraphs (h ) and (i ) of this section, the ow ner or operator of an affected flare shall not allow flow to each aff ected flare during normal operations of more than 7,080 standard cubic meters per day (m 3 /day ) (250,000 s tandard cubic feet per day (scfd) ) on a 30

- day rolling average

. The owner or operator of a newly cons tructed or reconstructed flare shall comply with the emission limit in this paragraph by no later than the date that flare becomes an affected flare subjec t to this subpart

. The owner or operator of a modi fied flare shall comply with the emission limit in this paragraph by no later th an 1 year after that flare becomes an affected flare subject to this subpart. (h) [Reserved] The combustion in a flare of proce ss upset gases or fuel gas that is released to the flare as a result of relief valve leakage or other emergency malfuncti ons is exempt from paragraph (g ) of this section. (i) In periods of fuel gas imbalance that ar e described in the flare management plan required in section 60.103a(a), complia nce 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. For a process heater that meets any of the criteria of paragraphs (i)(1)(i) thro ugh (iv) of this section, an owner or operator may request approval from the Administrator for a NO Xemissions limit which shall apply specifically to that affected fa cility. The request shall include information as described in paragraph (i)(2) of this section. The request shall be submitted and fo llowed as described in paragraph (i)(3) of this section. (1) A process heater that meets one of the criteria in paragraphs (i)(1)(i) through (iv) of this section may apply for a site-specific NO Xemissions limit: (i) A modified or reconstructed process heater that lacks sufficient space to accommodate installation and proper operation of com bustion modification-based technology ( e.g. , ultralow NO Xburners); or (ii) A modified or reconstructed process heater that has downwardly firing induced draft burners; or (iii) A co-fired process heater; or13 (iv) A process heater operating atreduced firing conditions for an extended period of time ( i.e. , operating in turndown mode). The site-specific NO Xemissions limit will only apply for those operating conditions. (2) The request shall include sufficient a nd 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 Xemissions limit in paragraph (g)(2) of this section. At a minimum, the request shall contain the info rmation described in paragraphs (i)(2)(i) through (iv) of this section. (i) The design and dimensions of the process heater, evaluation of available combustion modification-based technology, description of fuel gas and, if applicable, fuel oil characteristics, information regarding the combustion conditions (temperature, oxygen content, firing rates) and other information ne eded to demonstrate that the process heater meets one of the four classes of process heater s listed in paragraph (i)(1) of this section. (ii) An explanation of how the data in pa ragraph (i)(2)(i) demonstrate that ultra-low NO X burners, flue gas recirculation, control of ex cess air or other combustion modificationbased technology (including combinations of these combustion modification-based technologies) cannot be used to meet the appl icable emissions limit in paragraph (g)(2) of this section. (iii) Results of a performa nce 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 Xemissions. (iv) The means by which the owner or operato r will document continuous compliance with the site-specific emissions limit. (3) The request shall be submitted and follo wed as described in paragraphs (i)(3)(i) through (iii) of this section. (i) The owner or operator of a process heater th at meets one of the criteria in paragraphs (i)(1)(i) through (iv) of this section may re quest approval from the Administrator within 180 days after initial startup of the process heater for a NO Xemissions limit which shall apply specifically to that affected facility. (ii) The request must be submitted to the Administrator for approval. The owner or operator must comply with the requestas submitted until it is approved. (iii) The request shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Air Quality Plan ning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143- 01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park , NC 27711. Electronic copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov. (4) The approval process for a req uest for a facility-specific NO Xemissions limit is described in paragraphs (i)(4)(i) through (iii) of this section.14 (i) Approval by the Administra tor of a facility-specific NO Xemissions limit request will be based on the completeness, accuracy and reaso nableness of the request. Factors that the EPA will consider in reviewing the request for approval include, but are not limited to, the following: (A) A demonstration that the process heater meet s one of the four classes of process heaters outlined in paragraphs (i )(1) of this section; (B) A description of the low-NO Xburner designs and other combustion modifications considered for reducing NO Xemissions; (C) The combustion modification option selected; and (D) The operating conditions (firing ra te, heater box temperature and excess oxygen concentration) at which the NO Xemission level was established. (ii) If the request is approved by th e Administrator, a facility-specific NO Xemissions limit will be established at the NO Xemission level demonstrated in the approved request. (iii) If the Administrator finds any deficiencies in the request, the request must be revised to address the deficiencies and be re-submitted for approval.

Effective Date Note: At 73 FR 55752, Sept

. 26, 2008, §60.102a(g ) was stayed until Dec

. 25, 2008. § 60.103a Work practice standards. (a) Except as provided in paragraph (g) of this section, e E ach 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 constructe d or reconstructed fl are must develop and implement the flare management plan byno later than the date specified in paragraph (b) of this section that flare becomes an affected flare subject to this subpart

. The owner or operator of a modified flare must develop and implement the flare management plan by no later than 1 year after the flare becomes an affected flare subject to this subpart

. The flare management plan must include the information described in paragraphs (a)(1) through (7) of this section. : (1) A listing of diagram illustrating all refinery process units, ancillary equipment, and fuel gas systems connect ed ions to the flare for each affected flare. ; (2) An assessment of whether discharges to af fected flares from these process units, ancillary equipment and fuel gas systems ca n be minimized. The flare minimization assessment must (at a minimum) co nsider the items in paragraphs (a)(2)(i) through (iv) of this section. The assessment must provide cl ear rationale in terms of costs (capital and annual operating), natural gas offset credits (i f applicable), technical feasibility, secondary environmental impacts and safety consid erations for the selected minimization alternative(s) or a statement, with justificatio ns, that flow reduction could not be achieved. Based upon the assessment, each owner or operato r of an affected flar e shall identify the minimization alternatives that it has implemented by the due date of the flare management15 plan and shall include a schedule for the promptimplementation of any selected measures that cannot reasonably be co mpleted as of that date. (i) Elimination of process gas discharge to th e flare through process operating changes or gas recovery at the source. (ii) Reduction of the volume of process gas to the flare through process operating changes. (iii) Installation of a flare gas recovery system or, for facilities that are fuel gas rich, a flare gas recovery system and a co-generation unit or combined heat and power unit. (iv) Minimization of sweep gas flow rates and, for flares with water seals, purge gas flow rates. (3) A description of each affected flare contai ning the information in paragraphs (a)(3)(i) through (vii) of this section. (i) A general description of the flare, includi ng the information in paragraphs (a)(3)(i)(A) through (G) of this section. (A) Whether it is a ground flare orelevated (including height). (B) The type of assist system ( e.g. , air, steam, pressure, non-assisted). (C) Whether it is simple or complex flare tip ( e.g. , staged, sequential). (D) Whether the flare is part of a cascaded flare system (and if so, whether the flare is primary or secondary). (E) Whether the flare serves as a backup to another flare. (F) Whether the flare is an emergency flare or a non-emergency flare. (G) Whether the flare is equipped with a flare gas recovery system (ii) Description and simple process flow diagram showing the interconnection of the following components of the flare: flare ti p (date installed, manufacturer, nominal and effective tip diameter, tip drawing); knocko ut or surge drum(s) or pot(s) (including dimensions and design capaci ties); flare header(s) and s ubheader(s); assist system; and ignition system. (iii) Flare design parameters, including the maximum vent gas flow rate; minimum sweep gas flow rate; minimum purge gas flow rate (if any); maximum supplemental gas flow rate; maximum pilot gas flow rate; an d, if the flare is steam-assis ted, minimum total steam rate. (iv) Description and simple process flow diagr am showing all gas lines (including flare, purge (if applicable), sweep, supplemental and p ilot gas) that are associated with the flare. For purge, sweep, supplemental and pilot gas, id entify the type of gas used. Designate which lines are exempt from sulfur, H 2 S or flow monitoring and why ( e.g. , natural gas,16 inherently low sulfur, pilot gas). Designate wh ich lines are monitored and identify on the process flow diagram the locationand type of each monitor. (v) For each flow rate, H 2 S, sulfur content, pressure or wa ter seal monitor identified in paragraph (a)(3)(iv) of this section, provide Methods for monitoring flow rate to the fla re, including a detailed description of the manu facturer’s specif ications, including , but not limited to, make, model, type, range, precision, accura cy, calibration, maintenance, and quality assurance procedures

. for flare gas monitoring devices; (vi) For emergency flares, secondary flares and flares equipped with a flare gas recovery system designed, sized and operated to capt ure all flows except th ose resulting from startup, shutdown or malfunction: (A) Description of the water seal, including the operating range for the liquid level. (B) Designation of the monitoring option elec ted (flow and sulfur monitoring or pressure and water seal liquid level monitoring). (vii) For flares equipped with a flare gas recovery system: (A) A description of the flare gas recovery system, including number of compressors and capacity of each compressor. (B) A description of the monitoring parameters used to quantify the amount of flare gas recovered. (C) For systems with staged compressors, the maximum time period required to begin gas recovery with the secondary compressor(s), the monitoring parameters and procedures used to minimize the duration of releases dur ing compressor staging and a justification for why the maximum time period cannot be further reduced. (4) An evaluation of the baseline flow to the flare. The baseline flow to the flare must be determined after implementing the minimizati on assessment in paragraph (a)(2) of this section. Baseline flows do not include pilot gas flow or purge gas flow ( i.e. , gas introduced after the flare’s water seal) provided th ese gas flows remain reasonably constant ( i.e. , separate flow monitors for these streams a re not required). Separate baseline flow rates may be established for different operating cond itions provided that the management plan includes: (i) A primary baseline flow rate that will be us ed as the default baseline for all conditions except those specifically delineated in the plan; (ii) A description of each special condition fo r which an alternate baseline is established, including the rationale for each alternate baselin e, the daily flow for each alternate baseline and the expected duration of the special co nditions for each alternate baseline; and17 (iii) Procedures to minimize discharges to th e affected flare during each special condition described in paragraph (a)(4)(ii) of this sect ion, unless procedures are already developed for these cases under paragraph (a)(5) throug h (7) of this section, as applicable. ( 5 3 ) Procedures to minimize or eliminate discharges to the flare gas system during the planned start

- up and shutdown of the re finery process units and ancillary equipment that are connected to the affected flare , together with a schedule for the prompt implementation of any procedures that cannot reasonably be implemente d as of the date of the submission of the flare management plan. ; (4 ) Procedures to conduct a root cause analysis of any process upset or malfunction that causes a discharge to the flare in excess of 14,160 m 3 /day (500,000 scfd); ( 6 5 ) Procedures to reduce flaring incases of fuel gas imbalance ( i.e. , excess fuel gas for the refinery’s energy needs) , together with a schedule for the prompt implementation of any procedures that cannot reasonably be implemente d as of the date of the submission of the flare management plan. ; and (6 ) Explanation of procedures to follow during ti mes 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). (7) For flares equipped with flare gas recovery systems, procedures to mi nimize the frequency and duration of outages of the flare gas recovery system and procedu res to minimize the volume of gas flared during such outages, together with a schedul e for the prompt implementation of any procedures that cannot reasonably be implemente d as of the date of the submission of the flare management plan. (b) Except as provided in paragraph (g) of this section, each owner or operator required to develop and implement a written flare manageme nt plan as described in paragraph (a) of this section must submit the plan to the Ad ministrator as described in paragraphs (b)(1) through (4) of this section. (1) The owner or operator of a newly construc ted or reconstructed flare must develop and implement the flare management plan by no la ter than the date that the flare becomes an affected facility subject to this subpart, excep t for the selected minimization alternatives in paragraph (a)(2) and/or the procedures in par agraphs (a)(5) though (a)(7) of this section that cannot reasonably be implemented by th at date, which the owner or operator must implement in accordance with the schedule in the flare management plan. The owner or operator of a modified flare must develop and implement the flare management plan by no later than [the date 3 years from the date of publication of these amendments in the Federal Register ] or upon startup of the modified flare, whichever is later. (2) The owner or operator must comply with the plan as submitted by the date specified in paragraph (b)(1). The plan should be updated periodically to account for changes in the operation of the flare, such as new connections to the flare or the installation of a flare gas recovery system, but the plan need be re-submi tted to the Administrator only if the owner or operator adds an alternative baseline flow ra te, revises an existing baseline as described18 in paragraph (a)(4) of this section, installs a flare gas recovery system or is required to change flare designations and monitoring methods as described in §60.107a(g). The owner or operator must comply with the updated plan as submitted. (3) All versions of the plan submitted to the Administrator shall also be submitted to the following address: U.S. Environmental Protec tion Agency, Office of Air Quality Planning and Standards, Sector Policies and Program s Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Al exander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov. ( c b ) Except as provided in paragraphs (f) and (g) of this section, e E ach owner or operator that operates a fuel gas combustion device , flare or sulfur recovery plan t subject to this subpart shall conduct a root cause analysis and a corrective action analysis for each of the conditions specified in paragraphs (c)(1) through (3) of this section. of any emission limit exceedance or process start

- up, shutdown, upset, or malfun ction (1) For a flare: (i) Any time the SO 2 emissions exceed that causes a discharge to the atmosphere in excess of 227 kilograms per day (kg /day ) (500 lb per day (lb/day) ) in any 24-hour period; or of SO 2 . (ii) Any discharge to the flare in ex cess of 14,160 standard cubic meters (m 3 ) (500,000 standard cubic feet (scf)) above the baseline, de termined in paragraph (a)(4) of this section, in any 24-hour period; or (iii) If the monitoring altern ative in §60.107a(g) is elected, an y period when the flare gas line pressure exceeds the water seal liquid de pth, except for periods attributable to compressor staging that do not exceed the stag ing time specified in paragraph (a)(3)(vii)(C) of this section. (2) For a fuel gas combustion device, each exce edance of an applicable short-term 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 emitte d if the emissions limits had been met during one or more consecutive periods of excess em issions or any 24-hour period, whichever is shorter. (3) For a sulfur recovery plant, each time the SO 2 emissions are more than 227 kg (500 lb) greater than the amount that wo uld have been emitted if the SO 2 or reduced sulfur concentration was equal to the applicable em issions limit in §60.102a(f) (1) or (2) during one or more consecutive periods of excess emissi ons or any 24-hour period, whichever is shorter. For any root cause analysis performed, the owner or operator shall record the identification of the af

fected facility, the date and duration of the discharge, the results of the root cause analysis, and the action taken as a result of the root cause analysis

. (d) Except as provided in paragraphs (f) and (g) of this section, a root cause anal ysis and corrective action analysis must be completed as soon as possible, but no later than 45 days after a discharge meeting one of19 the conditions specified in paragraphs (c)(1) through (3) of this section. Special circumstances affecting the number of rootcause analyses and/or corrective action analyses are provided in paragraphs (d)(1) through (5) of this section. (1) If a single continuous discharge meets an y of the conditions specified in paragraphs (c)(1) through (3) of this section for 2 or mo re consecutive 24-hour periods, a single root cause analysis and corrective acti on analysis may be conducted. (2) If a single discharge from a flare triggers a root cause an alysis based on more than one of the conditions specified in paragraphs (c)(1)(i) through (iii) of this section, a single root cause analysis and corrective acti on analysis may be conducted. (3) If the discharge from a flar e is the result of a planned star tup or shutdown of a refinery process unit or ancillary equipment connected to the affected flare and the procedures in paragraph (a)(5) of this section were followed, a root cause analysis and corrective action analysis is not required; however, the disc harge must be recorded as described in §60.108a(c)(6) and reported as de scribed in §60.108a(d)(5). (4) If both the primary and secondary flare in a cascaded flare system meet any of the conditions specified in paragraphs (c)(1)(i) thro ugh (iii) of this section in the same 24-hour period, a single root cause analysis and co rrective action analysis may be conducted. (5) Except as provided in paragraph (d)(4) of this section, if discharges occur that meet any of the conditions specified in paragraphs (c)(1) through (3) of this section for more than one affected facility in the same 24-hour period, initial root cause analyses shall be conducted for each affected facility. If the initial root ca use analyses indicate th at the discharges have the same root cause(s), the init ial root cause analyses can be recorded as a single root cause analysis and a single corrective action analysis may be conducted. (e) Except as provided in paragraphs (f) and (g) of this section, each owner or operator of a fuel gas combustion device, flare or sulfur recovery plant subject to this subpart shall implement the corrective action(s ) identified in the corrective action analysis conducted pursuant to paragraph (d) of this section in accordance with the appl icable requirements in paragraphs (e)(1) through (3) of this section. (1) All corrective action(s) must be implemente d within 45 days of the discharge for which the root cause and corrective action analys es were required or as soon thereafter as practicable. If an owner or operator concl udes that corrective action should not be conducted, the owner or operator shall record a nd explain the basis for that conclusion no later than 45 days following the disc harge as specified in §60.108a(c)(6)(ix). (2) For corrective actions that cannot be fu lly implemented within 45 days following the discharge for which the root cause and correcti ve action analyses were required, the owner or operator shall develop an implementation sc hedule to complete the corrective action(s) as soon as practicable. (3) No later than 45 days following the discharge for which a root cause and corrective action analyses were required, the owner or op erator shall record th e corrective action(s)20 completed to date, and, for action(s) not alrea dy completed, a schedule for implementation, including proposed commencement and completi on dates as specified in §60.108a(c)(6)(x). (f) Modified flares shall comply with the requirem ents of paragraphs (c) through (e) of this section by [the date 3 years from the date of publication of these amendments in the Federal Register ] or at startup of the modifi ed flare, whichever is later. The fir st root cause analysis for a modified flare must be conducted no later than the first disc harge that occurs after the flare has been an affected flare subject to this subpart for 1 year. (g) An affected flare subject to this subpart located in the Bay Area Air Quality Management District (BAAQMD) may elect to comply with both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an alternative to complying with the requirements of paragraphs (a) through (e) of this section. An affected flare subject to this subpart located in the South Coast Air Qual ity Management Distri ct (SCAQMD) may elect to comply with SCAQMD Rule 1118 as an alt ernative to complying with the requirements of paragraphs (a) through (e) of this section. The owner or operator of an affected flare must notify the Administrator that the flare is in compli ance with BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 or SCAQMD Rule 1118. The owner or operator of an affected flare shall also submitthe existing flare management plan to the following address: U.S. Environmental Protec tion Agency, Office of Air Quality Planning and Standards, Sector Policies and Program s Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Al exander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov. (h) Each owner or operator shall not burn in an y affected flare any fuel gas that contains H 2 S in excess of 162 ppmv determined hourly on a 3-hour rolling average basis. 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 emerge ncy malfunctions is exempt from this limit. ( i c ) Each owner or operator of a delayed coking unit shall depressure each coke drum to 5 lb per square inch gauge (psig) or less prior to discharging the coke drum steam exhaust to the atmosphere. during reactor vessel depressuring Until the coke drum pressure reaches 5 psig, the coke drum steam an d vent the exhaust gases must be managed in an enclosed blowdown system and the uncondensed vapor must either be recovered ( e.g. , sent to the delayed coking unit fractionators) or vented to the fuel gas system , for combustion in a fuel gas combustion device or a flare

. (j) Alternative means of emission limitation . (1) Each owner or operator subject to the provisions of this section may apply to the Administrator for a determination of equivalence for any means of emission limitation that achieves a reduction in emissions of a specified pollutant at least equivalent to th e reduction in emissions of that pollutant achieved by the controls required in this section. (2) Determination of equivalence to the design , equipment, work practice or operational requirements of this section will be evaluated by the following guidelines:21 (i) Each owner or operator applying for a de termination of equivalen ce shall be responsible for collecting and verifying test data to de monstrate the equivalence of the alternative means of emission limitation. (ii) For each affected facility for which a determination of equivalence is requested, the emission reduction achieved by the design, equipment, work prac tice or operational requirements shall be demonstrated. (iii) For each affected facility for which a determination of equivalence is requested, the emission reduction achieved by the alternat ive means of emission limitation shall be demonstrated. (iv) Each owner or operator applying for a de termination of equivalence to a work practice standard shall commit in writin g to work practice(s) that pr ovide for emission reductions equal to or greater than the emission reducti ons achieved by the required work practice. (v) The Administrator will compare the de monstrated emission reduction for the alternative means of emission limitation to the demonstrated emission reduction for the design, equipment, work practice or operati onal requirements and, if applicable, will consider the commitment in paragraph (j)(2)(iv) of this section. (vi) The Administrator may condition the appr oval of the alternative means of emission limitation on requirements that may be necessa ry to ensure operation and maintenance to achieve the same emissions reduction as th e design, equipment, work practice or operational requirements. (3) An owner or operator may offer a unique approach to demonstrate the equivalence of any equivalent means of emission limitation. (4) Approval of the application for equivalence to the design, equipment, work practice or operational requirements of this section will be evaluated by the following guidelines: (i) After a request for determination of e quivalence is received, the Administrator will publish a notice in the Federal Register and provide the opportunity for public hearing if the Administrator judges that the request may be approved. (ii) After notice and opportunity for public hearing, the Administrator will determine the equivalence of a means of em ission limitation and will publis h the determination in the Federal Register

. (iii) Any equivalent means of emission lim itations approved under this section shall constitute a required work prac tice, equipment, design or op erational standard within the meaning of section 111(h)(1) of the CAA. (5) Manufacturers of equipment used to contro l emissions may apply to the Administrator for determination of equivalence for any alt ernative means of emission limitation that achieves a reduction in emis sions achieved by the equipm ent, design and operational22 requirements of this section. The Administrator will make an equivalence determination according to the provisions of paragraphs (j)(2) through (4) of this section. § 60.104a Performance tests. (a) The owner or operator shall c onduct a performance test for each FCCU, FCU, sulfur recovery plant, flare and fuel gas combustion device to dem onstrate initial compliance with each applicable emissions limit in §60.102a according to the requirements of §60.8. The notification requirements of §60.8(d) apply to the initial performance test and to subsequent performance tests required by paragraph (b) of this section (or as required by the Administrator), but does not apply to performance tests conducted for the purpo se of obtaining supplemental data because of continuous monitoring system breakdowns, repair s, calibration checks, and zero and span adjustments. (b) The owner or operator of a FCCU or FCU th at elects to monitor control device operating parameters according to the requirements in §60.105a (b), to use bag leak detectors according to the requirements in §60.105a(c), or to use COMS according to the requirements in §60.105a(e) shall conduct a PM performance te st at least once every 12 months and furnish the Administrator a written report of the results of each test. (c) In conducting the performan ce tests required by this subp art (or as requested by the Administrator), the owner or ope rator shall use the test methods in 40 CFR part 60, Appendices A–1 through A–8 or other methods as specified inthis section, except as provided in §60.8(b). (d) The owner or operator shall de termine 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 fo r 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 scr ubber 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 mois ture content from a FCCU or FCU with a wet scrubber subject to the emi ssions limit in §63.102a(b)(1). (i) The PM performance test consists of 3 valid te st 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 5 3 of this section:23 c sd s 

## R K Q c E  (Eq. 5 3 )

Where: E = Emission rate of PM, g/kg , lbs per 1,000 lbs (lb/1,000 lb s ) 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 s per hour (lb s /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 6 4 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. 6 4 )

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 recove ry system that burns auxiliary fuel, dry standard cubic meters per minute (dscm/min) , [ dry standard 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 instrumentation, dscm/min (dscf/min); Q oxy= Volumetric flow rate of O 2 enriched air to FCCU regene rator or fluid coking unit, as determined from the unit’s control room instrumentation, dscm/min (dscf/min);

%CO 2 = Carbon dioxide (CO 2 ) concentration in FCCU regene rator or fluid coking burner exhaust, percent by volume (dry basis); %CO = CO concentration in FCCU regenerato r 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);24 %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 fa ctor, 0.2982 (kg-min)/(hr-dsc-%) [0.0186 (lbmin)/(hr-dscf-%)];

K2 = Material balance and conversion fa ctor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lbmin)/(hr-dscf)]; and

K 3 = Material balance and conversion fa ctor, 0.0994 (kg-min)/(hr-dscm-%) [0.00624 (lbmin)/(hr-dscf-%)]. (iv) During the performance test, the volumetric flow rate of exhaust gas from catalyst regenerator (Q r ) before any emission control or energy rec overy 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 flowrates, the volumetric flow rate of Q r is calculated using average exhaust ga s concentrations as measured by the monitors required in §60.105a(b)(2), if applicable, using Equation 7 5 of this section: 

##  

2 2 

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

r



###    

  

 (Eq. 7 5 )

Where: Q r = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emission control or energy rec overy system that burns auxiliary fuel, dscm/min (dscf/min); Q a= Volumetric flow rate of air to F CCU regenerator or fluid coking burner, as determined from the unit’s control room instrumentation, dscm/min (dscf/min); Q oxy= Volumetric flow rate of O 2 enriched air to FCCU regene rator 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).25 (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 altern ative 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 fo r moisture content and for the concentration of NO Xcalculated as nitr ogen dioxide (NO 2 ); the duration of eachtest run must be no less than 4 hours. The method ANSI/A SME 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 tim e for each run must be 60 minutes. (8) The owner or operato r shall adjust PM, NO X , SO 2 , and CO pollutant concentrations to 0

- percent excess air or 0

- percent O 2 using Equation 8 6 of this section: 

##        

  2 % 9

. 20 9

. 20 O C C c meas adj (Eq. 8 6 )

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 electrostatic precipitator or wet scrubber and that is subject to control de vice operating parameter lim its in §60.102a(c) shall establish the limits based on the performance test results according to the following procedures: (1) Reduce the parameter monitoring data to hourly averages for each test run; (2) Determine the hourly average operating limit for each required parameter as the average of the three test runs. (f) The owner or operator of an FC CU 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.26 (1) Collect COMS data every 10 seconds during the entire period of the PM performance test and reduce the data to 6-minute averages. (2) Determine and record the hourly averag e opacity from all the 6-minute averages. (3) Compute the site-specific limit using Equation 9 7 of this section:

       



st st PMEmR

x Opacity Limit Opacity burn coke lb /1,000 lb 1 (Eq. 9 7 )

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

PMEmR st= PM emission rate measured during the source test, lb/1,000 lb s 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) a nd 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 emissions limits for sulfur recovery plants in §60.102a(f )(1)(ii) and §60.102a(f)(2)(ii) using the following methods and procedures: (1) Method 1 of appendix A–1 to part 60 for sample and velocity traverses. (2) Method 2 of appendix A–1 to part 60 fo r 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 60.27 (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,” (inc orporated 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 sh all 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, correctedto 0 percent excess air). (iii) The owner or operato r 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 8 6 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 Xemissions limits in §60.102a(g) for a fuel gas combustion device acco rding 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 fo r 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. (i) The performance test consists of 3 valid test runs; the duration of each test run must be no less than 1 hour. (ii) If a single fuel gas combustion device havi ng 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 fu el gas combustion device is added to a common source of fuel gas that previ ously demonstrated compliance. (5) Method 7, 7A, 7C, 7D, or 7E of appendix A–4 to part 60 fo r moisture content and for the concentration of NO Xcalculated 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 60.28 (6) For process heaters with a rated heat capacity between 40 and 100 MMBtu/hr that elect to demonstrate continuous compliance with a maximum excess oxygen limit as provided in §60.107a(c)(6) or (d)(8), the owner oroperator shall establish the O 2 operating limit or O 2 operating curve based on the performance testresults according to the requirements in paragraph (i)(6)(i) or (ii) of this section, respectively. (i) If a single O 2 operating limit will be used: (A) Conduct the performance test following the methods provided in paragraphs (i)(1), (2), (3) and (5) of this section when the process he ater is firing at no le ss than 70 percent of the rated heat capacity. For co-fired process heaters , conduct at least one of the test runs while the process heater is being supplied by both fuel gas and fuel oil and conduct at least one of the test runs while the process heater is being supplied solely by fuel gas. (B) Each test will consist of three test runs. Calculate the NO Xconcentration for the performance test as the average of the NO Xconcentrations from each of the three test runs. If the NO Xconcentration for the performance test is less than or equal to the numerical value of the applicable NO Xemissions limit (regardless of ave raging time), then the test is considered to be a valid test. (C) Determine the average O 2 concentration for each test run of a valid test. (D) Calculate the O 2 operating limit as the average O 2 concentration of the three test runs from a valid test. (ii) If an O 2 operating curve will be used: (A) Conduct a performance test following the me thods provided in paragraphs (i)(1), (2), (3) and (5) of this section at a representativ e condition for each operating range for which different O 2 operating limits will be established. Different operating conditions may be defined as different firing rates ( e.g. , above 50 percent of rated heat capacity and at or below 50 percent of rated heat capacity) and/or , for co-fired process heaters, different fuel mixtures ( e.g. , primarily gas fired, primarily oil fired, and equally co-fired, i.e. , approximately 50 percent of the input heating value is from fuel gas and approximately 50 percent of the input heating val ue is from fuel oil). Perf ormance tests for different operating ranges may be co nducted at different times. (B) Each test will consist of three test runs. Calculate the NO Xconcentration for the performance test as the average of the NO Xconcentrations from each of the three test runs. If the NO Xconcentration for the performance test is less than or equal to the numerical value of the applicable NO Xemissions limit (regardless of av eraging time), then the test is considered to be a valid test. (C) If an operating curve is developed for diff erent firing rates, conduct at least one test when the process heater is firing at no less than 70 percent of the rated heat capacity and at least one test under turndown conditions ( i.e. , when the process heater is firing at 50 percent or less of the rated heat capacity). If O 2 operating limits are developed for co-fired process heaters based only on overall firing ra tes (and not by fuel mixtures), conduct at29 least one of the test runs for each test while th e process heater is bein g supplied by both fuel gas and fuel oil and conduct at least one of the test runs while the process heater is being supplied solely by fuel gas. (D) Determine the average O 2 concentration for each test run of a valid test. (E) Calculate the O 2 operating limit for each operating range as the average O 2 concentration of the three test runs from a valid test conducted at the representative conditions for that given operating range. (F) Identify the firing rates for which the different operating limits apply. If only two operating limits are established based on firing rates, the O 2 operating limits established when the process heater is firing at no less than 70 percent of the rated heat capacity must apply when the process heater is firing above 50 percent of the rated heat capacity and the O 2 operating limits established for turndown conditions must apply when the process heater is firing at 50 percent or le ss of the rated heat capacity. (G) Operating limits associated with each inte rval will be valid for 2 years or until another operating limit is established for that int erval based on a more recent performance test specific for that interval, whichever occurs first. Owners and operators must use the operating limits determined for a given inter val based on the most recent performance test conducted for that interval. (7) The owner or operator of a process heater complying with a NO Xlimit in terms of lb/MMBtu as provided in §60.102a(g )(2)(i)(B), (g)(2)(i i)(B), (g)(2)(iii)(B) or (g)(2)(iv)(B) or a process heater with a rated heat capacity between 40 and 100 MMBtu/hr that elects to demonstrate continuous compliance with a maximum excess O 2 limit, as provided in §60.107a(c)(6) or (d)(8), shall determine heat input to the process heater in MMBtu/hr during each performance test run by measuring fuel gas flow rate, fuel oil flow rate (as applicable) and heating value content accord ing to the methods provided in §60.107a(d)(5), (d)(6), and (d)(4) or (d)(7), respectively. (8) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations to 0-percent O 2 or 0-percent excess air. (j) The owner or operator shall determine compliance with the applicable H 2 S emissions limit in §60.102a(g) (1) for a fuel gas combustion device or the concentration requirement in §60.103a(h) for a flare 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 fo r 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;30 (4) EPA Method 11, 15 , or 15A of A appendix A–5 to part 60 or EPA Method 16 of A 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 A 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 flare or for each individual fuel gas stream used in the fuel gas combustion device or flare

. (i) For Method 11 of appendix A–5 to part 60, th e 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 thes e 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 lo w 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 al ternative 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 or flare is added to a common source of fuel gas that previouslydemonstrated compliance. § 60.105a Monitoring of emissions and opera tions 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 F CCU and FCU subject to the PM emissions limit in §60.102a(b)(1) according to the requi rements 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 em issions limit in §60.102a(b)(1) that uses a control device other than fabric filter or cyclone shall comply with the require ments in paragraphs (b)(1) and through( 2 3 ) of this section. (1) The owner or operator shall install, operate, and maintain continuous parameter monitor systems (CPMS) to measure and record operating parameters for each control device according to the applicable requirements in para graph (b)(1)(i) through ( v iii ) of this section. (i) For units controlled using an electrostatic precipitator, the ow ner or operator shall use CPMS to measure and record the hourly average total power i nput and secondary volta ge to the entire system.31 (ii) For units controlled using a wet scrubber, th e owner or operator sha ll use CPMS to measure and record the hourly average pre ssure drop, liquid feed rate, and exhaust gas flow rate. As an alternative to a CPMS, the owne r or operator must comply with the requirements in either paragraph (b)(1)(ii)(A) or (B) of this section. (A) As an alternative alterative to pressure drop, the owner or ope rator of a jet ej ector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles must conduct a daily check of the air or water pr essure to the spray nozzles and re cord the results of each check. (B) As an alternative to exhaus t 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, operate, and maintain each CPMS according to the manufacturer’s specifica tions 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 usi ng the procedures in §60.104a(d)(4)(iii). (v) If you use a control device other than an electr ostatic precipitator, wet scrubber, fabric filter, or cyclone, you may request approval to mon itor parameters other than those required in paragraph (b)(1) of this section by submitti ng an alternative mon itoring plan to the Administrator. The request must include the in formation 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 dete rmine whether the affected faci lity will continuously comply with the emission limitations and the schedule fo r this demonstration. The owner or operator must certify that an operating limit will be es tablished for the monitored parameter(s) that represents the conditions in ex istence when the control device is being properly operated and maintained to meet the emission limitation. (C) The frequency and content of the recordk eeping, recording, and repor ting, 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 the32 concentrations of CO 2 , O 2 (dry basis), and if needed, CO in th e exhaust gases prior to any control or energy recovery system th at burns auxiliary fuels. (i) The owner or operato r shall install, operate , and maintain each monitor according to Performance Specification s 3 and 4 of A 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 Specification s 3 and 4 of A appendix B to part 60. The owner or operator shall use EPA Method 3 of A appendix A–3 to part 60 and EPA 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 th e quality assurance requir ements of procedure 1 of appendix F to part 60, including qu arterly 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 in stall, 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 emissi ons 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 plan 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 ce rtified 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 continuous ly record the output from the ba g leak detection system using electronic or other means ( e.g. , using a strip chart record er or a data logger). (iii) The bag leak detection system must be equi pped with an alarm system that will sound when the system detects an increase in relative partic ulate loading over the al arm 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 appropriate plant personnel. (iv) In the initial adjustment of the bag leak detection syst em, the owner or operator must establish, at a minimum, the baseline output by adjusting the sensit ivity (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 dela y time without approval from th e Administrator or delegated authority except as provided in para graph (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, includ ing temperature and humidity, according to the33 procedures identified in the site-specific monito ring 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, th e system’s instrumentation and alarm may be shared among detectors. (2) The owner or operator shall develop and submit to the Admi nistrator for approval a sitespecific monitoring plan for each baghouse and bag leak detection system. The owner or operator shall operate an d 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 ba g leak detection system; (ii) Initial and periodic adjustment of the bag leak detection system, including how the alarm setpoint will be established; (iii) Operation of the bag leak detection sy stem, 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 a pproving the site-specific monitoring plan, the Administrator or delegated authority may allow owners and operators more than 3 hours to alleviate a specific condition th at 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 al leviate this condition with in 3 hours of the time the alarm occurs, and demonstrates that the requested time will ensure alleviati on 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 and dust removal and bag cleaning mechanisms. (3) For each bag leak detecti on system, the owner or operator shall initiate procedures to determine the cause of every alar m within 1 hour of the alarm. Except as provided in paragraph (c)(2)(vi) of this section, the owner or operato r shall alleviate the cause of the alarm within 3 hours of the alarm by taking whatev er action(s) are necessary. Ac tions 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 incr ease in particulate emissions;34 (ii) Sealing off defective bags or filter media; (iii) Replacing defective bags or filter medi a or otherwise repairing the control device; (iv) Sealing off a defective baghouse compartment; (v) Cleaning the bag leak detecti on system probe or otherwise re pairing the bag leak detection system; or (vi) Shutting down the process producing the particulate emissions. (4) The owner or operator shall maintain record s of the information specified in paragraphs (c)(4)(i) through (iii) of this secti on for each bag leak detection system. (i) Records of th e bag leak detection system output; (ii) Records of bag leak dete ction system adjustments, incl uding the date and time of the adjustment, the initial bag leak de tection system settings, and the final bag leak detection system settings; and (iii) The date and time of all bag leak detecti on 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 monitoring 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 monitori ng 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, opera te, 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 performa nce 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 conducti ng the relative accuracy evaluations. (3) The owner or operator shall inst all, 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 conduc t performance evaluations of each O 2 monitor according to the requirements in §60.13(c) and Performanc e 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/AS ME PTC 19.10–1981, “Flue and Exhaust Gas35 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 co mply with the quality assuran ce 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 op tion 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 inparagraphs (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 opaci ty of emissions from the FCCU or the FCU exhaust vent. (2) The owner or operator shall install, ope rate, 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 perfor mance evaluations of each COMS according to §60.13(c) and Performance Specificati on 1 of appendix B to part 60. (f) FCCU and FCU subject to NO X limit . Each owner or operator subject to the NO Xemissions limit in §60.102a(b)(2) for an FCCU or FCU shall in stall, operate, calibrate, and maintain an instrument for continuously monitoring and record ing the concentration by volume (dry basis, 0 percent excess air) of NO Xemissions into the atmosphere. The monitor must include an O 2 monitor for correcting th e data for excess air. (1) The owner or operator shall inst all, operate, and maintain each NO Xmonitor according to Performance Specification 2 of appendix B to part 60. The span value of this NO Xmonitor is 200 ppmv NO X . (2) The owner or operator shall conduc t performance evaluations of each NO Xmonitor according to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or operator shall use Me thods 7, 7A, 7C, 7D, or 7E of appendix A–4 to part 60 for conducting the relative accuracy evaluati ons. The method ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses,” (incorporated by re ference—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 inst all, 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 conduc t performance evaluations of each O 2 monitor according to the requirements in §60.13(c) and Performanc e 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/AS ME PTC 19.10–1981, “Flue and Exhaust Gas36 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 co mply with the quality assuran ce requirements of Procedure 1 of appendix F to part 60 for each NO Xand O 2 monitor, including quarterly accuracy determinations for NO Xmonitors, 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 sha ll install, operate, calibrate, and maintain an instrument for continuously monitoring and record ing the concentration by volume (dry basis, corrected to 0 per cent 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 inst all, 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 conduc t 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, 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—s ee §60.17) is an acceptabl e alternative to EPA Method 6 or 6A of appendix A–4 to part 60. (3) The owner or operator shall inst all, 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 performan ce evaluations of each O 2 monitor according to the requirements in §60.13(c) and Performanc e 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/AS ME 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 co mply with the quality assuran ce 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 accuracy determinations for O 2 monitors, and daily calibration drift tests. (h) FCCU and fluid coking units su bject to CO emissions limit . Except as specifi ed in paragraph (h)(3) of this section, th e owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recordi ng the concentration by volume (dry basis) of CO emissions into the atmosphere from each F CCU and FCU subject to the CO emissions limit in §60.102a(b)(4).37 (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 performa nce evaluations of each CO monitor according to the requirements in §60.13(c) and Performance Sp ecification 4 or 4A of appendix B to part 60. The owner or operator shall us e 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 ow ner or operator demonstr ates that all hourly average CO emissions are and will remain less th an 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 CE MS shall be installed within 180 days. (i) The demonstration shall cons ist of continuously 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 in stead of 1,000 ppm, and the relative accuracy limit shall be 10 percent of the average CO emi ssions 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 10Aof appendix A–4 to part 60, th e alternative relative accuracy test procedure in section 10.1 of Performance Speci fication 2 of appendix B to part 60 may be used in place of the relative accuracy test. (ii) The owner or operator mu st submit the following information to the Administrator: (A) The measurement data specified in paragra ph (h)(3)(i) of this sec tion along with all other operating data known to a ffect CO emissions; and (B) Descriptions of the CPMS fo r exhaust gas temperature and O 2 monitor required in paragraph (h)(4) of this section and operating limits for those paramete rs to ensure co mbustion conditions remain similar to those that exis t 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 re quired 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 paragr aph (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 operato r shall install, oper ate, and maintain each CPMS according to the manufacturer’s specifications. (i) For a FCCU or FCU with no post-combus tion 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-combus tion control device, the temperature and O 2 concentration of the exhaust gas stream exiting the control device.38 (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 lim itations in §60.102a(b) are defined as specified in paragraphs (i)(1) thro ugh (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 charac teristics, 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 con tinuous PM monitoring system under §60.105a(d) exceeds 0.040 gr/dscf corrected to 0 percent exce ss air for a modified or reconstructed FCCU, 0.020 gr/dscf corrected to 0 percent excess air fo r 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-specific limit established during the most recent performance test. (4) All rolling 7-day peri ods during which the average concentration of NO Xas measured by the NO XCEMS under §60.105a(f) exceeds 80 ppmv for an affected FCCU or FCU. (5) Except as provided in paragraph (i)(7 ) of this section, a A ll 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 duri ng 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 averag e CO concentration as measured by the CO continuous monitoring system under §60.105a(h) exceed s 500 ppmv or, if applicable, all 1-hour periods during which the av erage temperature and O 2 concentration as measured by the continuous monitoring systems under §60.105a(h)(4) fa ll 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 su lfur recovery plant that is subject to the emissions limits in §60.102a(f)(1) or §60.10 2a(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 ope rator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and record ing the concentration (d ry basis, zero percent excess air) of any SO 2 emissions into the atmosphere. Th e monitor shall include an oxygen monitor for correcting th e data for excess air.39 (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 in stall, operate, and maintain each SO 2 CEMS according to Performance Specification 2 of appendix B to part 60. (iii) The owner or operator shall con duct 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 fo r conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, “Flue and E xhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 6. (2) For sulfur recovery plants that are s ubject 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 oper ator 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 atmosphere. 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 tim es 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, ope rate, and maintain each reduced sulfur CEMS according to Performance Specification 5 of appendix B to part 60. (iii) The owner or operator shall conduct performance evaluations of each reduced sulfur monitor according to the requirements in §60.13(c) and Performance Specification 5 of appendix B to part 60. The owner or operator shall use Methods 15 or 15A of appendix A–5 to part 60 for conducting the relative accuracy evaluati ons. The method ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses,” (incorporated by re ference—see §60.17) is an acceptable alternative to EPA Method 15A of appendix A–5 to part 60. (iv) The owner or operator shall in stall, 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 performa nce 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 c onducting the relative accura cy 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 in stall, 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 between10 and 25 percent, inclusive.40 (viii) The owner or operator shall co nduct performance evaluations for the O 2 monitor according to the requirements of §60.13(c) and Performanc e 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—s ee §60.17) is an acceptabl e alternative to EPA Method 3B of appendix A–2 to part 60. (ix) The owner or operator shall comply with th e 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 conve rt any reduced sulfur to SO 2 for continuously monitoring and recording the concentration (d ry 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 monito r 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 Me thods 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—s ee §60.17) is an acceptabl e alternative to EPA Method 15A of appendix A–5 to part 60. (iii) The owner or operator shall in stall, 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 between10 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 Sp ecification 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—s ee §60.17) is an acceptabl e 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, including 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 re quired by §60.7(c), periods of excess emissions for sulfur recovery plants subject to the emissi ons limitations in §60.102a(f) are defined as specified in paragraphs (b)(1) through (3) of this section.41 Note: Determine all averages as the arithmetic average of the applicable 1-hour averages, e.g. , determine the rolling 12-hour av erage as the arithmetic aver age 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 ba sis, zero percent excess air); or (2) All 12-hour period s during which the average concentr ation of reduced sulfur (as SO 2 ) as measured by the reduced sulfur continuous monito ring system required unde r paragraph (a)(2) of this section exceeds the app licable 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 paragraph (a)(2) of this section exceeds the applicable emission limit (dry basis, 0 percent excess air). § 60.107a Monitoring of emissions and opera tions for fuel gas combustion devices and flares

. (a) Fuel gas combustion devices subject to SO 2 or H 2 S limit and flares subject to H 2 S concentration requirements . The owner or operator of a fuel gas combustion device that is subject to the requirements in §60.102a(g) (1) and elects to comply with the SO 2 emission limits in §60.102a(g)(1)(i) shall comply with the requirements in paragraph (a)(1) of this section for SO 2 emissions or . The owner or operator of a fuel gas combustion device that is subject to §60.102a(g)(1) and elects to comply with the H 2 S concentration limits in §60.102a(g)(1)(ii) or a flare th at is subject to the H 2 S concentration requirement in §60.103a(h) shall comply with paragraph (a)(2) of this section for H 2 S emissions

. (1) The owner or operator of a fuel gas combustion device that elects to comply with subject to the SO 2 emissions limits in §60.102a(g)(1)(i) shall inst all, operate, calibrate, and maintain an instrument for continuously monitoring and r ecording the concentration (dry basis, 0

- percent excess air) of SO 2 emissions into the atmosphere. The monitor must include an O 2 monitor for correcting the data for excess air. (i) The owner or operator shall inst all, 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 cond uct performance evaluations for the SO 2 monitor according to the requirements of §60.13(c) and Performanc e 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—s ee §60.17) is an acceptabl e alternative to EPA Method 6 or 6A of appendix A–4 to part 60. Samp les 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, whiche ver is greater, and the calibration drift limit shall be 5 percent of the established span value.42 (iii) The owner or operator shall in stall, 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 con duct performance evaluations for the O 2 monitor according to the requirements of §60.13(c) and Performanc e 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—s ee §60.17) is an acceptabl e 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 quarter ly accuracy determinations for SO 2 monitors, annual accuracy determinations for O 2 monitors, and daily ca libration 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 combusti on 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 that elects to comply with subject to the H 2 S concentration lim its in §60.102a(g)(1)(ii) or a flare that is subject to the H 2 S concentration requirement in §60.103a(h) shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recordi ng the concentration by volume (dry basis) of H 2 S in the fuel gases before being burned in any fuel gas combustion device or flare

. (i) The owner or operato r shall install, operate , and maintain each H 2 S monitor according to Performance Specification 7 of A appendix B to part 60. The span value for this instrument is 300 320 ppmv H 2 S. (ii) The owner or operator shall cond uct 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 Method 16 of appendix A–6 to part 60 for c onducting the relative accura cy 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 th e applicable quality assurance procedures in appendix F to part 60 for each H 2 S monitor. (iv) Fuel gas combustion devices or flares having a common source of fuel gas may be monitored at only one location, if monitoring at this location accurately represents the concentration of H 2 S in the fuel gas being burned in the respective fuel gas combustion devices or flares

. (v) The owner or operator of a flare s ubject to §60.103a(c) through (e) may use the instrument required in paragraph (e)(1) of this section to demonstrate compliance with the H 2 S concentration requirement in §60.103a(h) if th e owner or operator complies with the43 requirements of paragraph (e)(1)(i) through (iv) and if the instrument has a span (or dual span, if necessary) capable of accurately measuring concentrations between 20 and 300 ppmv. If the instrument required in paragra ph (e)(1) is used to demonstrate compliance with the H 2 S concentration requirement, the con centration directly measured by the instrument must meet the num eric concentration in §60.103a(h). (3) The owner or operator of a fuel gas combustion device or flare is not required to comply with paragraph (a)(1) or (2) of this section for fuel gas streams that are exempt under §§60.102a(g)(1)(iii) or 60.103a(h) or, for §60.102a(h ) and fuel gas streams combusted in a process heater , or other fuel gas combustion device or flare that are inherently low in sulfur content. Fuel gas streams meeting one of the requ irements 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 meeta commercial-grade product specifi cation for sulfur content of 30 ppmv or less. In the case of a liquefied pe troleum gas (LPG) product specification in the pressurized liquid state, the ga s phase sulfur content should be evaluated assuming complete vaporization of the LPG and sulfur contai ning-compounds at the product specification concentration. (iii) Fuel gas streams produced in process units th at are intolerant to su lfur contamination, such as fuel gas streams produced in the hydrogen plant, catalytic reforming un it, isomerization unit, and HF alkylation process units. (iv) Other fuel gas streams that an owner or ope rator demonstrates are low-sulfur according to the procedures in paragra ph (b) of this section. (4) If the composition of an exempt fuel gas stream changes, the owner or operator must follow the procedures in paragra ph (b)(3) of this section. (b) Exemption from H 2 S monitoring requirements for lo w-sulfur fuel gas streams . The owner or operator of a fuel gas combustion device or flare 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 paragrap hs (a)(1) and (2) of this sec tion until there are changes in operating conditions or stream composition. (1) The owner or operator shal l 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/syste m to be considered, including submission of a portion of the appropriate piping diagrams indicating the boundaries of the fuel gas stream/system, and the affected fuel gas combustion device(s) or flare(s) to be considered; (ii) A statement that there are no cross over or entry points fo r sour gas (high H 2 S content) to be introduced into the fuel gas stream/system (this should be shown in the piping diagrams);44 (iii) An explanation of the condi tions 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 samp ling 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 m easurement) following the “Gas Processors Association Standa rd 2377–86, Test for Hydrogen Su lfide 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 te st 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 results compares to the typical range of H 2 S concentration (fuel quality) expected for the fuel gas stream/system go ing to the affected fuel gas combustion device or flare ( e.g. , the 2 weeks of daily detector tube results for a frequently operated loading rack included the entire range of products loaded out , and, therefore, should be representative of typical operating conditions affecting H 2 S content in the fuel gas stream going to the loading rack flare). (2) The effective date of the exemption is the date of submission of the information required in paragraph (b)(1) of this section. (3) No further action is required unless refinery operating conditions change in such a way that affects the exempt fuel gas stream/system ( e.g. , the stream composition changes). If such a change occurs, the owner or operator shall fo llow the procedures inparagraph (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 appli cation, 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 result s in a sulfur content that is outside the range of concentrations included in the original app lication, the owner or operato r may submit new information following the procedures of paragr aph (b)(1) of this se ction within 60 days (or within 30 days after the seventh grab sample is tested for infrequently operated process units). (iii) If the operation change result s in a sulfur content that is out side the range of concentrations included in the original app lication, and the owner or operator chooses not to submit new information 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 sectio n as soon as practicable but in no case later than 180 days after the operation change. During daily stain tube sampling, a daily sample exceeding 162 ppmv is an exceedance of the 3-hour H 2 S concentration limit. The45 owner or operator of a fuel gas combustion device must also 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 within the rolling 365-day period prior to the operation change. (c) Process heaters complying with the subject to NOX concentration-based limit . The owner or operator of a process heater subject to the NO Xemission s limit in §60.102a(g)(2) and electing to comply with the applicable em issions limit in §60.102a(g) (2)(i)(A), (g)(2)(ii )(A), (g)(2)(iii)(A) or (g)(2)(iv)(A) shall install, operate, calib rate, and maintain an instrument for continuously monitoring and recording the c oncentration (dry basis, 0

- percent excess air) of NO Xemissions 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 th e data for excess air. (1) Except as provided in paragraph (c)(6) of this section, t T he owner or operator shall install, operate, and maintain each NO Xmonitor according to Performance Specification 2 of A appendix B to part 60. The span value of this NO Xmonitor must be between 2 and 3 times the applicable emissions limit, inclusive is 200 ppmv NO X . (2) The owner or operator shall conduc t performance evaluations of each NO Xmonitor according to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or operator shall use Me thods 7, 7A, 7C, 7D, or 7E of appendix A–4 to part 60 for conducting the relative accuracy evaluati ons. The method ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses,” (incorporated by re ference—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 inst all, 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 performan ce evaluations of each O 2 monitor according to the requirements in §60.13(c) and Performanc e 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/AS ME 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 co mply with the quality assuran ce requirements in Procedure 1 of appendix F to part 60 for each NO Xand O 2 monitor, including quarterly accuracy determinations for NO Xmonitors, annual accuracy determinations for O 2 monitors, and daily calibration drift tests. (6) The owner or operator of a pr ocess heater that has a rated h eating capacity of less than 100 MMBtu and is equipped with combustion modification-based technology to reduce NO X emissions ( i.e. , low-NO Xburners , (LNB ) or ultra low-NO Xburners (ULNB ) may elect to comply with is not subject to the monitoring requirements in para graphs (c)(1) through (5) of this section

. or, alternatively, t T he owner or operator of such a process heater shall mustconduct biennial performance tests according to the requiremen ts in §60.104a(i), establish a46 maximum excess O 2 operating limit or operating curv e according to the requirements in §60.104a(i)(6) and comply with the O 2 monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O 2 operating curve is used ( i.e. , if different O 2 operating limits are established for di fferent operating ranges), the owner or operator of the process heater must also monitor fuel gas flow rate, fuel oil flow rate (as applicable) and heating value content accord ing to the methods provided in paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7 ) of this section, respectively. (d) Process heaters complying with the NO X heating value-based or mass-based limit . The owner or operator of a process heater subject to the NO Xemissions limit in §60.102a(g)(2) and electing to comply with the applicab le emissions limit in §60.102a(g)(2)(i)(B) or (g)(2)(ii)(B) shall install, operate, calibrate a nd maintain an instrument for continuously monitoring and recording the concentration (dry basis, 0-percent excess air) of NO X emissions into the atmosphere and shall determin e the F factor of the fuel gas stream no less frequently than once per day according to the monitoring require ments in paragraphs (d)(1) through (4) of this section. The owner or operator of a co-fired process heater subject to the NO Xemissions limit in §60.102a(g )(2) and electing to comply with the heating valuebased limit in §60.102a(g)(2 )(iii)(B) or (g)(2)(iv )(B) shall install, operate, calibrate and maintain an instrument for continuously mo nitoring and recording the concentration (dry basis, 0-percent excess air) of NO Xemissions into the atmosphere according to the monitoring requirements in paragraph (d)(1) of this section; install, operate, calibrate and maintain an instrument for continuously monito ring and recording the flow rate of the fuel gas and fuel oil fed to the process heater a ccording to the monitoring requirements in paragraph (d)(5) and (6) of this section; fo r fuel gas streams, determine gas composition according to the requirements in paragraph (d )(4) of this section or the higher heating value according to the requirements in paragra ph (d)(7) of this section; and for fuel oil streams, determine the heating value accord ing to the monitoring requirements in paragraph (d)(7) of this section. (1) Except as provided in paragraph (d)(8) of this section, the owner or operator shall install, operate and maintain each NO Xmonitor according to the requirements in paragraphs (c)(1) through (5) of this s ection. 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 heater using the methods and equations in section 12.3.2 of EPA Method 19 of Appendix A-7 to part 60 to determine the F factor on a dry basis. If a single fuel gas system provide s fuel gas to several process heaters, the F factor may be dete rmined at a single location in the fuel gas system provided it is representative of the fuel gas fe d to the affected process heater(s). (3) As an alternative to the requirements in pa ragraph (d)(2) of this section, the owner or operator of a gas-fired process he ater shall install, operate a nd maintain a gas composition analyzer and determine the average F factor of the fuel gas using the factors in Table 1 of this subpart and Equation 10 of this section. If a single fuel gas syst em provides fuel gas to several process heaters, the F factor may be det ermined at a single location in the fuel gas system provided it is representative of the fu el gas fed to the affected process heater(s).47 

#     

#  

  

 i i i i d 

## MHC X MEV X F 000 , 000 , 1 (Eq. 10)

Where:

F d = F factor on dry basis at 0-percent excess air, dscf/MMBtu.

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 perf ormance evaluations of each compositional monitor according to the requirements in P erformance Specification 9 of Appendix B to part 60. Any of the following methods shall be used for conducting the relative accuracy evaluations: (i) EPA Method 18 of Appendix A–6 to part 60; (ii) ASTM D1945–03, Standard Method for Analysis of Natural Gas by Gas Chromatography (incorporate d 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); (iv) ASTM D6420–99 (Reapproved 2004), Standard Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography-Mass Spectrometry (incorporated by reference—see §60.17); (v) Gas Processors Association Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (2000) (incorporated by reference—see §60.17); or (vi) ASTM UOP539-97, Refinery Gas Analysis by Gas Chromatography (incorporated by reference—see §60.17). (5) The owner or operator shall install, opera te and maintain fuel gas flow monitors according to the manufacturer’s recomme ndations. For volumetric flow meters, temperature and pressure monitors must be inst alled in conjunction with the flow meter or in a representative location to correct the measured flow to standard conditions ( i.e. , 68° Fahrenheit and 1 atmosphere). For mass flow meters, use gas compositions determined according to paragraph (d)(4) of this section to determine the average molecular weight of the fuel gas and convert the mass flow to a volumetric flow at standard conditions ( i.e. , 68° Fahrenheit and 1 atmosphere). The own er or operator shall conduct performance48 evaluations of each fuel gas flow monito r according to the requirements in §60.13 and Performance Specification 6 of Appendix B to part 60. Any of the following methods shall be used for conducting the rel ative accuracy evaluations: (i) EPA Method 2, 2A, 2B, 2C or 2D of Appendix A–2 to part 60; (ii) ASME MFC-3M-2004, Measurement of Fluid Fl ow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference—see §60.17); (iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008) , Measurement of Gas Flow by Turbine Meters (incorporated by reference—see §60.17); (iv) ASME MFC-6M-1998 (Reaffirmed 2005), Mea surement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference—see §60.17); (v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference—see §60.17); (vi) ASME MFC-11M-2006, Measurement of Fl uid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference—see §60.17); (vii) ASME MFC-14M-2003, Measurement of Fl uid Flow Using Small Bore Precision Orifice Meters (incorporated by reference—see §60.17); (viii) ASME MFC-18M-2001, Measurement of Fluid Flow Using Variable Area Meters (incorporated by reference—see §60.17); (ix) American Gas Association (AGA) Report No. 3: Orifice Metering for Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines (1990) (incorporated by reference—see §60.17); (x) AGA Report No. 3: Orifice Metering for Natural Gas and Other Related Hydrocarbon Fluids, Part 2: Specification and Installa tion Requirements (2000) (incorporated by reference—see §60.17); (xi) AGA Report No. 11: Measurement of Natural Gas by Coriolis Meter (2003) (incorporated by reference—see §60.17); (xii) American Gas Association Transmis sion Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters (Rev ised February 2006) (incorporated by reference—see §60.17); and (xiii) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 22-Testing Protocol, Se ction 2-Differential Pressure Flow Measurement Devices, First Edition, August 2005 (incorporated by reference—see §60.17). (6) The owner or operator shall install, operate and maintain each fuel oil flow monitor according to the manufacturer’s recommendati ons. The owner or operator shall conduct49 performance evaluations of each fuel oil flowmonitor according to the requirements in §60.13 and Performance Specification 6 of Appe ndix B to part 60. Any of the following methods shall be used for conducting the relative accuracy evaluations: (i) Any one of the methods listed in paragraph (d )(5) of this section that are applicable to fuel oil ( i.e. , “fluids”); (ii) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006) , Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flow meters (incorporated by reference—see §60.17); (iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement of Liquid Flow in Closed Conduits by Weighing Method (incorporated by reference—see §60.17); (iv) ASME MFC-16-2007, Measurement of Li quid Flow in Closed Conduits with Electromagnetic Flowmeters (inc orporated by reference—see §60.17); (v) ASME MFC-22-2007, Measurement of Liquid by Turbine Flowmeters (incorporated by reference—see §60.17); or (vi) ISO 8316: Measurement of Liquid Flow in Closed Conduits—Method by Collection of the Liquid in a Volumetric Tank (1987–10-01)—F irst Edition (incorporated by reference— see §60.17). (7) The owner or operator shall determine the higher heating value of each fuel fed to the process heater using any of the applicable methods included in paragraphs (d)(7)(i) through (ix) of this section. If a common fuel supply system provides fuel gas or fuel oil to several process heaters, the higher heating value of the fuel in each fuel supply system may be determined at a single loca tion in the fuel supply system provided it is representative of the fuel fed to the affected pr ocess heater(s). The higher heating value of each fuel fed to the process heater must be determined no le ss frequently than once per day except as provided in paragraph (d)(7)( x) of this section. (i) ASTM D240-02 (Reapproved 2007), Standard Te st Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorime ter (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 Cont inuous Recording Calorimeter (incorporated by reference—see §60.17). (iii) ASTM D1945-03, Standard Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference—see §60.17). (iv) ASTM D1946-90 (Reapproved 2006), Standard Method for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference—see §60.17).50 (v) ASTM D3588-98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Dens ity of Gaseous Fuels (incorporated by reference—see §60.17). (vi) ASTM D4809-06, Standard Test Metho d for Heat of Com bustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference—see §60.17). (vii) ASTM D4891-89 (Reapproved 2006), Standa rd Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometr ic Combustion (incorporated by reference— see §60.17). (viii) Gas Processors Association Standard 2172-09, Calculation of Gross Heating Value, Relative Density, Compressibility and Th eoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transf er (2009) (incorporated by reference—see §60.17). (ix) Any of the methods specified in section 2.2.7 of Appendix D to part 75. (x) If the fuel oil supplied to the affected co-fired process he ater originates from a single storage tank, the owner or operator may elect to use the storage tank sampling method in section 2.2.4.2 of Appendix D to part 75 instea d of daily sampling, except that the most recent value for heating content must be used. (8) The owner or operator of a process heater th at has a rated heating capacity of less than 100 MMBtu and is equipped with combustion modification based technology to reduce NO Xemissions ( i.e. , low-NO Xburners or ultra-low NO Xburners) may elect to comply with the monitoring requirements in paragraphs (d)(1) through (7) of this section or, alternatively, the owner or operator of such a process heater shall conduct biennial performance tests according to the requi rements in §60.104a(i), establish a maximum excess O 2 operating limit or operating curv e according to the requirements in §60.104a(i)(6) and comply with the O 2 monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O 2 operating curve is used ( i.e. , if different O 2 operating limits are established for di fferent operating ranges), the owner or operator of the process heater must also monitor fuel gas flow rate, fuel oil flow rate (as applicable) and heating value content accord ing to the methods provided in paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7 ) of this section, respectively. ( e d ) Sulfur monitoring for assessing root cause analysis threshold for affected flares

. Except as described in paragraphs (e)(4) and (h) of this section, t T he owner or operator of an affected flare subject to §60.103a( b c ) through (e) shall determine the total reduced sulfur concentration for each gas line directed to the affected fl are in accordance with either paragraph (e)(1), (e)(2) or (e)(3) of this se ction. Different option s may be elected for different gas lines. install, operate, calibrate , and maintain an instrument for continuously monitoring and recording th e concentration of reduced sulfur in flare gas. If a monitoring system is in place that is capable of comp lying with the requiremen ts related to either paragraph (e)(1), (e)(2) or (e)(3) of this sect ion, the owner or operator of a modified flare51 must comply with the requirements related to ei ther paragraph (e)(1), (e)(2) or (e)(3) of this section upon startup of the modified flare. If a monitoring system is not in place that is capable of complying with the requirements re lated to either paragraph (e)(1), (e)(2) or (e)(3) of this section, t T he owner or operator of a modified flare must comply with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section shall install this instrument by no later than [the date 3 years from the date of publication of these amendments in the Federal Register ] or upon startup of the modified flare, whichever is later 1 year af ter the flare becomes an affected flare subject to this subpart

. (1) Total reduced sulfur monitoring requirements . The owner or operator shall install, operate, calibrate and maintain an instrumentfor continuously monitoring and recording the concentration of total reduced sulfur in gas discharged to the flare. ( i 1 ) The owner or operator shall install, operate , and maintain each total reduced sulfur monitor CEMS according to Performance Specification 5 of A appendix B to part 60. The span value should be determined based on the m aximum sulfur content of gas that can be discharged to the flare ( e.g. , roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 5,000 ppmv. A single dual range monitor may be used to comply with the requirements of this paragraph and paragraph (a)(2) of this section provided the applicable span specifications are met. ( ii 2 ) The owner or operator shall conduc t performance evaluations of each total reduced sulfur monitor according to the requirements in §60.13(c) and Performance Specification 5 of A appendix B to part 60. For flares that routinely have flow, t T he owner or operator of each total reduced sulfur monitor shall use EPA Method s 15 or 15A of A appendix A–5 to part 60 for conducting the relative accuracy eval uations. 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 A appendix A–5 to part 60. The alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for conducting the relative accuracy evaluations. For flares that do not receive ro utine flow, the alternative relative accuracy procedures described in section 16.0 of Perfor mance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for conduc ting the relative accuracy evaluations, except that it is not necessary to include as much of the sampling probe or sampling line as practical. ( iii 3 ) The owner or operator shall comply with the applicable quality assurance procedures in A appendix F to part 60 for each total reduced sulfur monitor. (2) H 2 S monitoring requirements . The owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of H 2 S in gas discharged to the flare according to the requirements in paragraphs (e)(2)(i) through (iii) of this section and shall collectand analyze samples of the gas and calculate total sulfur concentrations as sp ecified in paragraphs (e)(2)(iv) through (ix) of this section. (i) The owner or operator shall inst all, operate and maintain each H 2 S monitor according to Performance Specification 7 of Appendix B to part 60. The span value should be52 determined based on the maximum sulfur content of gas that can be discharged to the flare ( e.g. , roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 5,000 ppmv. A single dual range H 2 S monitor may be used to comply with the requirements of this paragraph and paragr aph (a)(2) of this section provided the applicable span specifications are met. (ii) The owner or operator shall conduc t 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. For flares that routinely have fl ow, the owner or operator shall use EPA Method 11, 15 or 15A of Appendix A–5 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, “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 alternative relativ e accuracy procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for conducting the relative accuracy evalua tions. For flares that do not receive routine flow, the alternative relative ac curacy procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 (cyl inder gas audits) may be used for conducting the relative accuracy evaluations, except that it is not necessary to include as much of the sampling probe or samplin g line as practical. (iii) The owner or operator sh all 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 date the flare must begin to comply with §60.103a(c)(1) of this subpart, the owner or op erator shall collect representative daily samples of the gas discharged to the flare. Th e samples may be grab samples or integrated samples. The owner or operator shall take subs equent representative daily samples at least once per week or as required in par agraph (e)(2)(ix) of this section. (v) The owner or operator shall analyze each da ily sample for total sulfur using either EPA Method 15A of Appendix A-5 to part 60, EPA Method 16A of Appendix A-6 to part 60, ASTM Method D4468-85 (Reapproved 2006) “Standa rd Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rate ometric Colorimetry” (incorporated by reference—see §60.17) or ASTM Method D5504-08 “Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence” (incorporated by reference—see §60.17). (vi) The owner or operator shall de velop a 10-day average total sulfur-to-H 2 S ratio and 95- percent confidence interval as follows: (A) Calculate the ratio of the tota l 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 paragr aph (e)(2)(vi)(A) of this section.53 (C) Determine the acceptable range for subseque nt weekly samples based on the 95-percent confidence interval for the dist ribution of daily ratios base d on the 10 individual daily ratios using Equation 11 of this section.



### SDev Ratio AR Avg 

###    262

. 2 (Eq. 11)

Where: AR = Acceptable range of subsequentratio determinations, unitless.

Ratio Avg= 10-day average total sulfur-to-H 2 S concentration ratio, unitless. 2.262 = t-distribution statistic for 95-percent 2-sided confidence interval for 10 samples (9 degrees of freedom).

SDev = Standard deviation of th e 10 daily average total sulfur-to-H 2 S concentration ratios used to develop the 10- day average total sulfur-to-H 2 S concentration ratio, unitless. (vii) For each day during the period when da ta are being collected to develop a 10-day average, the owner or operator shall estimate the total sulf ur concentration using the measured total sulfur concentr ation measured for that day. (viii) For all days other than those during wh ich data are being collected to develop a 10- day average, the owner or operator shall mult iply 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)(2)(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 acceptable range for the most recent distribution of daily ratios, the owner or operator shall develop a new 10-day average ratio and acceptable rang e based on data for the outlying weekly sample plus data collected over the following 9 operating days. (3) SO 2 monitoring requirements . The owner or operator shall in stall, operate, calibrate and maintain an instrument for continuously mo nitoring and recording the concentration of SO 2 from a process heater or ot her fuel gas combustion device that is combusting gas representative of the fuel gas in the flare gas line according to the requirements in paragraph (a)(1) of this section, determine th e F factor of the fuel gas at least daily according to the requirements in paragraphs (d )(2) through (4) of this section, determine the higher heating value of the fuel gas at least daily according to the requirements in paragraph (d)(7) of this section and ca lculate the total sulfur content (as SO 2 ) in the fuel gas using Equation 12 of this section.

FG d SO FG 

### HHV F C TS    2 (Eq. 12)

Where:54 TS FG = Total sulfur concentration, as SO 2 , in the fuel gas, ppmv.

C SO2 = Concentration of SO 2 in the exhaust gas, ppmv (dry basis at 0-percent excess air).

F d = F factor gas on dry basis at 0-percent excess air, dscf/MMBtu.

HHV FG = Higher heating value of the fuel gas, MMBtu/scf. (4) Exemptions from sulfur monitoring requirements . Flares identified in paragraphs (e)(4)(i) through (iv) of this section are exem pt from the requirements in paragraphs (e)(1) through (3) of this section. For each such fl are, except as provided in paragraph (e)(4)(iv), engineering calculations shall be used to calculate the SO 2 emissions in the event of a discharge that may trigger a root cause analysis under §60.103a(c)(1). (i) Flares that can only receive: (A) Fuel gas streams that are inherently low in sulfur content as described in paragraph (a)(3)(i) through (iv) of this section; and/or (B) Fuel gas streams that are inherently lo w in sulfur content for which the owner or operator has applied for an exemption from the H 2 S monitoring require ments as described in paragraph (b) of this section. (ii) Emergency flares, provided that for each such flare, the owner or operator complies with the monitoring alternative in paragraph (g) of this section. (iii) Flares equipped with flare gas recovery systems designed, sized and operated to capture all flows except those resulting from startup, shut down or malfunction, provided that for each such flare, the owner or operator complies with the monitoring alternative in paragraph (g) of this section. (iv) Secondary flares that receive gas diverted from the primary flare. In the event of a discharge from the secondary flare, the sulfurcontent measured by the sulfur monitor on the primary flare should be used to calculate SO 2 emissions, regardless of whether or not the monitoring alternative in paragraph (g) of this section is selected for the secondary flare. ( f

e ) Flow monitoring for flares

. Except as provided in paragra phs (f)(2) and (h) of this section, t T he owner or operator of an affected flare subject to §60.103a(c) through (e) §60.102a(g)(3) shall install, operate, calibrate , and maintain , in accordance with the specifications in paragraph (f)(1) of this section, a CPMS to measure and record the exhaust gas flow rate of gas discharged to the flare

. If a flow monitor is not already in place, t T he owner or operator of a modified flare shall comply with the requirements of this paragraph install this instrument by no later than [the date 3 years from the date of publication of these amendments in the Federal Register ] or upon startup of the modified flare, whichever is later 1 year after the flare becomes an a ffected flare subject to this subpart

.55 (1) The CPMS mu st be able to correct for the temperatur e and pressure of the system and output flow in standard conditions as defined in §60.2. ( 1 2 ) The owner or operator shall install, calibrate, operate , and maintain each flow monitor CPMS according to the manufacturer’s procedures and specifications and the following requirements. (i) Locate the monitor in a position that pr ovides a representative me asurement of the total gas flow rate. (ii) Use a flow sensor with a measurement sens itivity of no more than 5 percent of the flow rate or 10 cubic feet per minute, whichever is greater. (iii) Use a flow monitor that is maintainable online, is able to continuously correct for temperature and pressure and is able to record flow in standard conditions (as defined in §60.2) over one-minute averages. (iv) At least quarterly, perform a visual inspection of all co mponents of the monitor for physical and operational integrity and all elec trical connections for oxidation and galvanic corrosion if the flow monitor is not e quipped with a redundant flow sensor. (v) Recalibrate the flow monitor in accord ance with the manufacturer's procedures and specifications biennially (ev ery two years) or at the frequency specified by the manufacturer. (2) Emergency flares, secondary flares and fla res equipped with flare gas recovery systems designed, sized and operated to capture all flows except those resulting from startup, shutdown or malfunction are not required to install continuous flow monitors; provided, however, that for any such flare, the owner or operator shall comply with the monitoring alternative in paragraph (g) of this section. (g) Alternative monitoring for certain flares equipped with water seals . The owner or operator of an affected flare subject to §60.103a(c) through (e) that can be classified as either an emergency flare, a secondary flare or a flare equipped with a flare gas recovery system designed, sized and operated to capt ure all flows except th ose resulting from startup, shutdown or malfunction may, as an al ternative to the sulfur and flow monitoring requirements of paragraphs (e) and (f) of this section, install, operate, calibrate and maintain, in accordance with the requirements in paragraphs (g)(1) through (7) of this section, a CPMS to measure and record the p ressure in the flare gas header between the knock-out pot and water seal a nd to measure and record the wat er seal liquid level. If the required monitoring systems are not already in place, the owner or operator of a modified flare shall comply with the requirements of th is paragraph by no later than [the date 3 years from the date of publicatio n of these amendments in the Federal Register ] or upon startup of the modified fl are, whichever is later.56 (1) Locate the pressure sensor(s) in a positi on that provides a representative measurement of the pressure and locate the liquid seal le vel monitor in a position that provides a representative measurement of the water column height. (2) Minimize or eliminate pulsating pressu re, vibration and internal and external corrosion. (3) Use a pressure sensor and level monitor with a minimum tolerance of 1.27 centimeters of water. (4) Using a manometer, check pres sure sensor calibration quarterly. (5) Conduct calibration checks any time the pressure sensor exceed s the manufacturer's specified maximum operating pressure ra nge or install a new pressure sensor. (6) In a cascaded flare system that employs multiple seconda ry flares, pressure and liquid level monitoring is required only on th e first secondary flare in the system ( i.e. , the secondary flare with the lowest pressure release set point). (7) This alternative monitoring option may be elected only for flares with four or fewer pressure exceedances required to be repor ted under §60.108a(d)(5) (“reportable pressure exceedances”) in any 365 consecutive calendar d ays. Following the fifth reportable pressure exceedance in a 365-day period, the owner or op erator must comply with the sulfur and flow monitoring requirements of paragraphs (e) and (f) of this section as soon as practical, but no later than 180 days after the fifth reportable pressure exceedance in a 365-day period. (h) Alternative monitoring for flares located in the BAAQMD or SCAQMD . An affected flare subject to this subpart locate d in the BAAQMD may elect to comply with the monitoring requirements in both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an alternative to complying with the requirements of paragraphs (e) and (f) of this section. An affected flare subject to th is subpart located in th e SCAQMD may elect to comply with the monitoring requirements in SCAQMD Rule 1118 as an alternative to complying with the requirements of par agraphs (e) and (f) of this section. ( i f ) Excess emissions . For the purpose of reports re quired by §60.7(c), periods of excess emissions for fuel gas combustion devices subj ect to the emissions limitations in §60.102a(g) and flares subject to the con centration requirement in §60.103a(h) are defined as specified in paragraphs ( i f )(1) through ( 5 4 ) of this section.

Note: Determine al l averages as the arithmetic average of the applicable 1

- hour averages, e.g. , determine the a rolling 3-hour or a rolling daily average as the arithmetic average of the applicable three contiguous 1-hour averages ( e.g. , a rolling 3-hour average is the arithmetic average of three contiguous 1-hour averages) . Determine a rolling 30-day or a rolling 365- day average as the arithmetic average of the applicable daily averages ( e.g. , a rolling 30- day average is the arithmetic aver age of 30 contiguous daily averages)

.57 (1) SO 2 or H 2 S limits for fuel gas combustion devices . (i) If the owner or operator of a fuel gas combustion device elec ts to comply with the SO 2 emission limits in §60.102a(g)(1)(i), each All rolling 3-hour period s during which the average concentration of SO 2 as measured by the SO 2 continuous monitoring system required under paragraph (a)(1) of th is section exceeds 20 ppmv, and each all rolling 365-day period s during which the average concentration of SO 2 as measured by the SO 2 continuous monitoring system require d under paragraph (a)(1) of this section exceeds 8 ppmv

. ; or ( ii 2 ) If the owner or operator of a fuel gas com bustion device elects to comply with the H 2 S concentration limits in §60.102a(g)(1)(ii), each All rolling 3-hour period s 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 required under paragraph (b)(3)(iii) of this section exceeds 162 ppmv, and each all rolling 365-day period s 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. (iii) If the owner or operator of a fuel gas combustion device becomes subject to the requirements of daily stain tube sampling in par agraph (b)(3)(iii) of this section, each day during which the daily concentration of H 2 S exceeds 162 ppmv and each rolling 365-day period during which the average concentration of H 2 S exceeds 60 ppmv. (2) H 2 S concentration limits for flares . (i) Each rolling 3-hour period 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. (ii) If the owner or operator of a flare becomes subject to the requirements of daily stain tube sampling in paragraph (b)(3)(iii) of th is section, each day during which the daily concentration of H 2 S exceeds 162 ppmv. (3) Rolling 30-day average NO X limits for fuel gas combustion devices . Each All rolling 30- day 24

- hour period s during which the average concentration of NO Xas measured by the NO X continuous monitoring system required under paragraph (c) or (d) of this section exceeds : (i) For a natural draft process heater, 40 ppmvand, if monitored according to §60.107a(d), 0.040 lb/MMBtu; (ii) For a forced draft process heater, 60 ppmv and, if monitored according to §60.107a(d), 0.060 lb/MMBtu; and (iii) For a co-fired process heater electing to comply with the NO Xlimit in §60.102a(g)(2)(iii)(A) or (g)(2)(iv)(A), 150 ppmv

. (iv) The site-specific li mit determined by the Administrator under §60.102a(i). (4) All rolling 30

- day periods during which the av erage flow rate to an aff ected flare as measured by the monitoring system required under para graph (e) of this section exceeds 250,000 scfd. Daily NO X limits for fuel gas combustion devices . Each day during which the58 concentration of NO Xas measured by the NO Xcontinuous monitoring system required under paragraph (d) of this section exceeds th e daily average emissions limit calculated using Equation 3 in §60.102a( g)(2)(iii)(B) or Equation 4 in §60.102a(g)(2)(iv)(B). (5) Daily O 2 limits for fuel gas combustion devices . Each day during which the concentration of O 2 as measured by the O 2 continuous monitoring sy stem required under paragraph (c)(6) of this section exceeds the O 2 operating limit or operatin g curve determined during the most recent bienni al performance test.

Effective Date Note: At 73 FR 55752, Sept. 26, 2008, §60.107a (d) and (e) were stayed until Dec

. 25, 2008. § 60.108a Recordkeeping and reporting requirements. (a) Each owner or operator subject to the emi ssions limitations in §60.102a shall comply with the notification, recordkeeping, and reporting requirements in §60.7 and other requirements as specified in this section. (b) Each owner or operator subject to an emissions limitation in §60.102a shall notify the Administrator of the specific monitori ng provisions of §§60.105a, 60.106a, and 60.107a with which the owner or operator seeks to comply. Each owner or operator of a co-fired process heater subject to an emissions limitation in §60.102a(g)(2)(iii) or (iv) shall submit to the Administrator documentation showing that the process heater meets the definition of a cofired process heater in §60.101a. Notification s required by this paragraph 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 conformance with bag leak detection system operation and maintenance requirements in §60.105a(c). (3) Records of bag leak detection system alarms and actions according to §60.105a(c). (4) For each FCCU and fluid coking unit s ubject to the monitoring requirements in §60.105a(b)(1), records of the average coke burn-off rate and hours of operation. (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 exemp tion 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 shal l record and maintain r R ecords of discharges greater than 500 lb /daySO 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 or sulfur recovery plant and discharges to an affected flare in excess of 500,000 scf d

above baseline in any 24-hour period59 as required by §60.103a(c)

. If the monitoring alternative provided in §60.107a(g) is selected, the owner or operator shall record an y instance when the fla re gas line pressure exceeds the water seal liquid depth, except for periods attributable to compressor staging that do not exceed the staging ti me specified in §60.103a(a)(3)(vii)(C). The se following information records shall be recorded no later than 45 days following the end of a discharge exceeding the thresholds include : (i) A description of the discharge. (ii) For d ischarges greater than 500 lb/day SO 2 , t T he 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 hour s, record the discharge quantity for each 24- hour period. For a flare, record the measured or ca lculated 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 , but are not allowed for other thanflares , except for those complying with the alternative monitoring requirements in §60.107a(g)

. (iv) For each discharge s greater than 500 lb /daySO 2 in any 24-hour period from a flare , the measured total sulfur or estimated concentration or both the measured of H 2 S concentration and the estimated total sulfur concentration in the fuel gas at a repres entative location in the flare inlet , TRS and SO 2 of the stream discharged

. Process knowledge can be used to make these estimates for fuel gas combustion devices other than flares. (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 ga s combustion device, 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 knowledg e can be used to make these estimates for fuel gas combustion devices, but cannot be used to make these estimates for flares, except as provided in §60.107a(e)(4). (vi) For each discharge greater than 500 lb SO 2 in excess of the allo wable limits from a sulfur recovery plant, either the measured concentration of reduced sulfur or SO 2 discharged to the atmosphere. (v ii ) For each discharge s greater than 500 lb /daySO 2 in any 24-hour period from any affected flare or discharge greater than 500 lb SO 2 in excess of the allowabl e limits from a fuel gas combustion device 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 . (viii) The steps that the owner or operator took to limit the emissions during the discharge.60 ( v i x ) The Results of anyroot

- cause analysis and corrective action analysis conducted as required in §60.103a(a)(4 ) and §60.103a( d b ) , including an identification of the affected facility, the date and duration of the discharg e, a statement noting whether the discharge resulted from the same root cause(s) identi fied in a previous analysis and either a description of the recommended corrective action (s) or an explanation of why corrective action is not necessary under §60.103a(e)

. (x) For any corrective action analysis fo r which corrective actions are required in §60.103a(e), a description of the corrective action (s) completed within the first 45 days following the discharge and, for action(s ) not already completed, a schedule for implementation, including proposed commencement and completion dates. (xi) For each discharge from any affected flar e that is the result of a planned startup or shutdown of a refinery process unit or ancillary equipment connected to the affected flare, a statement that a root cause analysis and corrective action analysis are not necessary because the owner or operator foll owed the flare management plan. (7) If the owner or operator el ects to comply with §60.107a(e)(2 ) 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 interval s for each 10-day average total sulfur-to-H 2 S ratio. (d) Each owner or operator subjec t to this subpart shall submit an excess emissions report for all periods of excess emissions according to the requir ements of §60.7(c) except that the report shall contain the information specified in paragr aphs (d)(1) through (7) of this section. (1) The date that th e exceedance occurred; (2) An explanation of the exceedance; (3) Whether the exceedance was concurrent w ith a startup, shutdown, or malfunction of an affected facility or control system; and (4) A description of th e action taken, if any. (5) A root

- cause summary report that provides t T he information described in paragraph ( c e )(6) of this section for all discharges listed in paragraph (c)(6) of this section for which a root

- cause analysis was required by §60.103a(a)(4 ) and §60.103a(b)

. For a flare complying with the monitoring alternative under §60.107a(g), following the fifth discharge required to be recorded under paragraph (c)(6) of this section and reported under this paragraph, the owner or operator shall include notification that monitoring systems will be installed according to §60.107a(e) and (f) within 180 days following the fifth discharge. (6) For any periods for which monitoring data ar e 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 th e applicable emission limit. Operat ions of the control system and affected facility during periods of data unavailab ility are to be compared with operation of the control system and affected facility before and following the period of data unavailability.61 (7) A written statement, signed by a responsib le official, certifying the accuracy and completeness of the informati on 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 ag ency. 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 s S tate, local, or tribal agency, the approval authorities contained in paragraphs (b)(1) through ( 4 3 ) of this section are retained by the Administrator of the U.S. EPA and are not transferred to the s S tate, local, or tribal agency. (1) Approval of a major change to test methods under §60.8(b). A “m ajor 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 unde r §60.7(b) through (f). A “major change to recordkeeping/reportin g” is defined in 40 CFR 63.90. (4) Approval of an application for an alt ernative means of emission limitation under §60.103a(j) of this subpart. Tables to Subpart Ja of Part 60 Table 1 to Subpart Ja of Part 60--Molar Exhaus t Volumes and Molar Heat Content of Fuel Gas Constituents

Constituent MEV a dscf/mol MHC b Btu/mol Methane (CH 4 ) 7.29 842 Ethane (C 2 H 6 ) 12.96 1,475 Hydrogen (H 2 ) 1.61 269 Ethene (C 2 H 4 ) 11.34 1,335 Propane (C 3 H 8 ) 18.62 2,100 Propene (C 3 H 6 ) 17.02 1,947 Butane (C 4 H 10 ) 24.30 2,717 Butene (C 4 H 8 ) 22.69 2,558 Inerts 0.85 0

a MEV = molar exhaust volume, dry standard cubic feet per gram-mole (dscf/g-mol) at standard conditions of 68° Farhenheit and 1 atmosphere

b MHC = molar heat content (higher heating value basis), Btu per gram-mole (Btu/g-mol)