May 15, 2014 Redline of 40 CFR part 60, subpart Ja, showing proposed 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 PERFORMANCE 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 § 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 process heat ers), flares and sulfur recovery plants. The sulfur recovery plant need not be physically located within the boundari es of a petroleum refinery to be an affected facility, provided it processes gases produced within a petroleum refinery. (b) Except for flares and delayed coking units, the provisions of this subpart apply only to affected facilities unde r paragraph (a) of this section which either commence construction, modification or recons truction after May 14, 2007 , or elect to comply with the provisions of this subpart in lieu of complying with the provisions in subpart J of this part . For flares, the provisions of this subpart appl y only to flares which commen ce construction, modification or reconstruction 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. For delayed coking units, the provisions of this subpart apply to delayed coking units that commence construction, reconstruc tion or modification on the earliest of the following dates: (1) May 14, 2007, for such activities that involve a “delayed coking unit” defined as follows: one or more refinery process units in which hi gh molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors; (2) December 22, 2008, for such activities that involve a “delayed coking unit” defined as follows: a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced ina series of closed, ba tch system reactors. A delayed coking unit consists of the coke drums and associated fractionator; (3) September 12, 2012, for such activities that in volve a “delayed coking unit” as defined in §60.101a. (c) For all affected facilities other than fl ares, the provisions in §60.14 regarding modification apply. As provided in §60.14(f), the special pr ovisions set forth under this subpart shall2 supersede the provisions in §60.14 with respect to flares. For the purposes of this subpart, a modification to a flare occurs as provided in paragraphs (c)(1) or (2 ) of this section. (1) Any new piping from a refinery process unit, including ancillary equi pment, 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). However, the connections described in paragraphs (c)(1)(i) through (vii) of this section are not c onsidered modifications of a flare. (i) Connections made to install monitoring systems to the flare. (ii) Connections made to install a flare gas rec overy system or connections made to upgrade or enhance components of a flar e gas recovery system ( e.g. , addition of compressors or recycle lines). (iii) Connections made to repla ce or upgrade existing pressure re lief or safety valves, provided the new pressure relief or safety valve has a se t 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 (redundant) equipment associated with the flare (such as a back-up compressor) that does not increase the capacity of the flare. (vi) Replacing piping or moving an existing connec tion from a refinery process unit to a new location in the same flare, provide d the new pipe diameter is less th an or equal to the diameter of the pipe/connection being replaced/moved. (vii) Connections that interc onnect 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 the relevant applicabili ty date specified in paragraph (b) of this section. § 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 supplied to a process heater generally by use of a heat exchanger to recover the sensible heat of exhaust gas from the process heater. Ancillary equipment means equipment used in conjunction wi th or that serve a refinery process unit. Ancillary equipment includes, but is not limited to, storage tanks, product loading3 operations, wastewater treatment systems, steam- or electricity-p roducing units (including coke gasification units), pressure relief valves, pumps , sampling vents and cont inuous analyzer vents. Cascaded flare system means a series of flares connected 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 discharge pressure exceeds a set point at which the flow to the primary flare would exceed the primary fl are's capacity, flow will be diverted to the second flare in the series. Similarly, flow would be diverted to a third (or fourth) flare if the pressure in the flare gas header system exceeds a threshold where the flow to the first two (or three) flares would exceed their capacities. Co-fired process heater means a process heater that employs burners that ar e 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 ar e not considered co-fired process heaters. Coke burn-off means the coke removed from the surf ace 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 maintenance changes that one takes consistent with good engineering practice to reduce or eliminate the like lihood of the recurrence of the primary cause and any other contributing cause(s) of an event identified by a root cause analysis as having resulted in a discharge of gases to from an affected flare facility in excess of specified thresholds. Corrective action analysis means a description of all reasonable interim and long-term measures, if any, that are available, and an explanation of why the selected correct ive action(s) is/are the best alternative(s), including, but not limited to, c onsiderations of cost ef fectiveness, technical feasibility, safety and secondary impacts. Delayed coking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum c oke is produced in a series of closed, batch system reactors. A delayed coking unit includes, but is not limite d to, all of the coke drums associated with a single fractionator; the fracti onator, including the bottoms receiver and the overhead condenser; the coke drum cutting water and quench system, including the jet pump and coker quench water tank; and the coke dr um blowdown recovery compressor system. Emergency flare means a flare that combusts gas exclusivel y 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. For purposes of this ru le, a flare cannot be categorized as an emergency flare unless it maintains a water seal.4 Flare means a combustion device that uses an uncontrolled volume of air to burn gases. The flare includes the foundation, flare tip, structural support, burner, ign iter, flare controls, including air injection or steam injection systems, flame arrestors and the flare gas header system. In the case of an interconnected flare gas header system, the flare includes each individual flare serviced by the interconnected flare gas header system and the interconnected flare gas header system. Flare gas header system means all piping and knockout pots, including those in a subheader system, used to collect and transport gas to a flar e either from a process un it or a pressure relief valve from the fuel gas system, regardless of wh ether 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 piping is to transp ort gas to a flare or knockout pot that is part of the flare. Flare gas recovery system means a system of one or more compressors, piping and the associated water seal, rupture disk or similar devi ce 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 a refinery process unit in wh ich high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuouslyproduced 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, spent 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 units share a common exhaust treatment (e.g., CO boiler or wet scrubber), the fluid catalytic cracking unit is a single affected facility. Fluid coking unit means a refinery process unit in wh ich high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuouslyproduced 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 re covery on the fluid coking burner exhaust vent. Forced draft process heater means a process heater in which the combustion air is supplied under positive pressure produced by a fan at any lo cation in the inlet air line prior to the point where the combustion air enters the process heat er 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 with5 a gas generated at a refinery. Fuel gas does not include gases generated by catalytic cracking unit catalyst regenerators, coke cal ciners (used to make premiu m grade coke) and fluid coking burners, but does include gases from flexic oking unit gasifiers and other gasifiers. Fuel gas does not include vapors that are collec ted and combusted in a thermal oxidizer or flare installed to control emissions from wastewat er treatment units other than those processing sour water, marine tank vessel loading operati ons or asphalt processing units ( i.e. , asphalt blowing stills). Fuel gas combustion device means any equipment, such as process heaters and boilers, used to combust fuel gas. For the purposes of this subpart, fuel gas combustion device does not include flares or facilities in which gases are com busted to produce sulfur or sulfuric acid. Fuel gas system means a system of compressors, pipi ng, knock-out pots, mix drums, and units used to remove sulfur contaminants from th e fuel gas (e.g., amine sc rubbers) 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 wh ich 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, includi ng induced draft systems. Non-emergency flare means any flare that is not an emerge ncy 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 redistillati on, cracking or reforming of unfin ished petroleum derivatives. A facility that produces only oil shale or tar sands-derived crude oil for further processing at a petroleum refinery using only solv ent extraction and/or distillati on 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 i ndirectly to process stream materials (liquids, gases, or solids) or to a heat transfer material for use in a process unit instead of steam.6 Process upset gas means any gas generated by a petroleum refinery process unit or by ancillary equipment as a result of start up, shutdown, upset or malfunction. Purge gas means gas introduced between a flare's wate r seal and a flare's tip to prevent oxygen infiltration (backflow) into the flare tip. For flares with no water seals, the function 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 thr ough a process of investigation to determine the primary cause, and any other contributing cause(s), of a discharge of gases in excess of specified thresholds. Secondary flare means a flare in a cascaded flare system that provides additional flare capacity and pressure relief to a flare gas system 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.

Sour watermeans water that contains sulfur compounds (usually H 2 S) at concentrations of 10 parts per million by weight or more. Sulfur pit means the storage vessel in which sulfur that is condensed after each Claus catalytic reactor is initially accumulated and stored. A sulfur pit does not include secondary sulfur storage vessels downstream of the initial Claus reactor sulfur pits. Sulfur recovery plant means all process units which recover sulfur from H 2 S and/or SO 2 from a common source of sour gas producedat a petroleum refinery. The sulfur recovery plant also includes sulfur pits used to st ore the recovered sulfur product, but it does not include secondary sulfur storage vessels or loadi ng facilities downstream of the su lfur 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 control systems or in cinerator, thermal oxidizer or similar combustion device. Multiple sulfur recoveryunits are a single affected facility only when the units share the same source of sour gas. Sulfur recovery plants that receive source gas from completely segregated sour gas treatment systems are separate affected facilities.7 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 flare h eader. For flares with no water seals, sweep gas also performs the function of preventing oxygen in filtration (backflow) into the flare tip. § 60.102a Emission s limitations. (a) Each owner or operator that is subject to th e requirements of this subpart shall comply with the emissions limitations in paragraphs (b) throu gh (i) 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 gram per kilogram per Megagram ( (g/kg /Mg)( ) ( 1 pound (lb) per 1,000 lb) coke burn-off or, if a PM continuous emission monitoring system (CEMS) is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air for each m odified 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 g/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; and8 (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; and (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 design production capacity greater than 20 long tons per day (LTD) , the owner or operator shall comply wi th the applicable emission limit in paragraphs (f)(1)(i) or (f)(1)(ii ) of this section. If the sulf ur recovery plant consists of multiple process trains or release points, the owner or operator sh all comply with the applicable emission limit for each process trai n or release point individually or comply with the applicable emission limit in paragraphs (f)(1)(i ) or (f)(1)(ii) of this section as a flow rate weighted average for a group of release points from the sulfur recovery plant provided that9 flow is monitored as specified in §60.106a(a)(7); if flow is not monitored as specified in §60.106a(a)(7), the owner or operator shall complywith the applicable emission limit in paragraphs (f)(1)(i) or (f)(1)( ii) of this section for each process train or release point individually. For a sulfur recovery plant with a design production capacity greater than 20 long LTD and a reduction control system no t followed by incineration, the owner or operator shall also comply with the H 2 S emission limit in paragraph (f)(1)(iii) of this section for each individual release point. : (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 (SO 2 ) in excess of the emission limit calculat ed using Equation 1 of this section. For Claus units that use only am bient air in the Claus burner or that elect not to monitor O 2 concentration of the air/oxygen mixture used in the Claus burner or for nonClaus sulfur recovery plants, this SO 2 emissions limit is 250 ppm by v olume (dry basis) of sulfur dioxide (SO 2 ) at zero percent excess air. If the sulfur recovery plant consists of multiple process trains or release point s the owner or operator shall co mply with the 250 ppmv limit for each process train or release point or comply witha flow rate weighted average of 250 ppmv for all release points from the sulfur recovery plant; or 

##   

#   6

. 25 53

. 11 038

. 0 2 1    

   2 2 LS %O %O k E (Eq. 1)

Where:

E LS = Emission limit for large su lfur recovery plant, ppmv (as SO 2 , dry basis at zero percent excess air);

k 1 = Constant factor for emission limit conversion: k 1 = 1 for converting to the SO 2 limit for a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration and k 1 = 1.2 for converting to the reduced sulfur compounds limit for a sulfur recovery plan t with a reduction control system not followed by incineration; and

%O 2 = O 2 concentration of the air/oxygen mixture supplied to the Claus burner, percent by volume (dry basis). If only ambient air is used for the Claus burner or if the owner or operator elects not to monitor O 2 concentration of the ai r/oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, use 20.9% for %O 2 . (ii) For a sulfur recovery plant with a reducti on control system not followed by incineration, the owner or operator shall not disc harge or cause the di scharge of any gases into the atmosphere containing reduced sulfur compounds in excess of the emission limit calculated using Equation 1 of this section. For Claus units th at use only ambient air in the Claus burner or for non-Claus sulfur recovery plants, this reduced sulfur compounds emission limit is 300 ppmvof reduced sulfur compounds and 10 ppmv of H 2 S, eachcalculated as ppmv SO 2 (dry basis) at 0-percent excess air

. ; or10 (iii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not di scharge or cause the discharge of any gases into the atmosphere containing hydrogen sulfide (H 2 S) in excess of 10 ppmv calculated as ppmv SO 2 (dry basis) at zero percent excess air. For systems using oxygen enrichment, the owner or operator shall calculate the applicable emission limit using Equation 1 of this section:

Where:

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

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

%O 2 = O 2 concentration to the SRP, percent by volume (dry basis). (2) For a sulfur recovery plant with a design production capacity of 20 LTD or less , the owner or operator shall comply with the applicable emission limit in paragraphs (f)(2)(i) or (f)(2)(ii) of this sectio n. If the sulfur recovery plant consis ts of multiple process trains or release points, the owner or operator may comp ly with the applicable emission limit for each process train or release point individuallyor comply with the applicable emission limit in paragraphs (f)(2)(i) or ( f)(2)(ii) of this section as a flow rate weighted average for a group of release points from the sulfur recove ry plant provided that flow is monitored as specified in §60.106a(a)(7); if flow is not monito red as specified in §60.106a(a)(7), the owner or operator shall comply with the applicable emission limit in paragraphs (f)(2)(i) or (f)(2)(ii) of this section for each process trai n or release point individually. For a sulfur recovery plant with a design production capacity of 20 LTD or less and a reduction control system not followed by incineration, the own er or operator shall also comply with the H 2 S emission limit in paragraph (f)(2)(iii) of this section for each individual release point. : (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 containing SO 2 in excess of the emission limit calculated using Equation 2 of this section. For Claus units th at use only ambient air in the Claus burner or that elect not to monitor O 2 concentration of the air/oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, this SO 2 emission limit is in excess of 2,500 ppmvby volume (dry basis) of SO 2 at zero percent excess air. If the sulfur recovery plant consists of multiple process trains or release po ints the owner or operator shall comply with the 2,500 ppmv limit for each process train or release poi nt or comply with a flow rate weighted average of 2,500 ppmv for all release point s from the sulfur recovery plant; or 

##   

#   256 3

. 115 38

. 0 2 1    

   2 2 SS %O %O k E (Eq. 2)

Where:11 E SS = Emission limit for small su lfur recovery plant, ppmv (as SO 2 , dry basis at zero percent excess air);

k 1 = Constant factor for emission limit conversion: k 1 = 1 for converting to the SO 2 limit for a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration and k 1 = 1.2 for converting to the reduced sulfur compounds limit for a sulfur recovery plan t with a reduction control system not followed by incineration; and

%O 2 = O 2 concentration of the air/oxygen mixture supplied to the Claus burner, percent by volume (dry basis). If only ambient air is us ed in the Claus burner or if the owner or operator elects not to monitor O 2 concentration of the air/oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, use 20.9% for %O 2 . (ii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not disc harge or cause the di scharge of any gases into the atmosphere containing reduced sulfur compounds in exces s of the emission limit calculated using Equation 2 of this section. For Claus units th at use only ambient air in the Claus burner or for non-Claus sulfur recovery plants, this reduced sulfur compounds emission limit is in excess of 3,000 ppm by v olume of reduced sulfur compounds and 100 ppm by volume of hydrogen sulfide (H 2 S), each calculated as ppmvSO 2 by volume (dry basis) at zero percent excess air ; or . (iii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not di scharge or cause the discharge of any gases into the atmosphere containing H 2 S in excess of 100 ppmv calculated as ppmv SO 2 (dry basis) at zero percent excess air. For systems using oxygen enrichment, the owner or operator shall calculate the applicable emission limit using Equation 2 of this section:

Where:

E SS = Emission rate of SO 2 for small sulfur recovery plant, ppmv. (3) The emission limits in paragraphs (f)(1) and (2) shall not apply during p P eriods of maintenance of the sulfur pit, during which the emission limits in paragraphs (f)(1) and (2) shall not apply, which shall not exceed 240 hours per year. The owner or operator must document the time periods during which the sulfur pit vents were not controlled and measures taken to minimize emissions during these periods. Examples of these measures include not adding fresh sulfur or shutting off vent fans. (g) Each owner or operator of an affected fuel gas combustion device shall comply with the emissions limits in paragraphs (g)(1) and (2) of this section.12 (1) Except as provided in (g)(1)(i ii) of this section, for each fu el gas combustion device, the owner or operator shall comply with either the emission limit in paragraph (g)(1)(i) of this section or the fuel gas concentration limit in paragraph (g)(1)(ii) of this section. For CO boilers or furnaces that are part of a fluid catalyti c cracking unit or fluid coking unit affected facility, the owner or operator shall comply with the fuel gas concentration limit in paragraph (g)(1)(ii) of this section for all fuel gas streams combusted in these units. (i) The owner or operator shall not discharge or cause the discharge of any gases into the atmosphere that contain SO 2 in excess of 20 ppmv (dry basis, corrected to 0-percent excess air) determined hourly on a 3-hour rolling average basis and SO 2 in excess of 8 ppmv (dry basis, corrected to 0-percent excess air), determined daily on a 365 successive 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 portabl e generator of fuel gas releas ed as a result of tank degassing and/or cleaning is exempt from the emissions lim its in paragraphs (g)(1)(i) and (ii) of this section. (2) For each process heater with a rated capacity of greater than 40 million British thermal units per hour (MMBtu/hr) on a higher he ating 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 w ith the limit in either paragraph (g)(2)(i)(A) or (B) of this section. The owner or operator may comply with either limit at any time, provided that the appropriate parameters for each alternative are monitored as specified in §60.107a; if fuel gas composition is not monitored as speci fied in §60.107a(d), the owner or operator must comply with the concentration limits inparagraph (g)(2)(i)(A) of this section. (A) 40 ppmv (dry basis, corrected to 0-percent excess air) determ ined daily on a 30-day rolling average basis; or (B) 0.040 pounds per million British thermal units (lb/MMBtu) higher heating value basis determined daily on a 30-day rolling average basis. (ii) For each forced draft process heater, complywith the limit in either paragraph (g)(2)(ii)(A) or (B) of this section. The owner or operator may comply with either limit at any time, provided that the appropriate parameters for each alternative are monitored as specified in §60.107a; if fuel gas composition is not monitored as speci fied 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-percent excess air) determ ined daily on a 30-day rolling average basis; or13 (B) 0.060 lb/MMBtu higher heati ng value basis determined dailyon 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-percent excess air) dete rmined 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 heati ng 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 dr aft process heater, comply with the limit in either paragraph (g)(2)(iv)(A) or (B) of this section. The owner or operato r must choose one of the emissions limits with which to comply at all times: (A) 150 ppmv (dry basis, corrected to 0-percent 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:

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, scf/day;14 Q oil = Daily average volumetric flow rate of fuel oil, scf/day;

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

HHV oil = Daily average higher heating value of fuel oil fired to the process heater, MMBtu/scf. (h) [Reserved] (i) For a process heater that meet s any of the criteria of paragra phs (i)(1)(i) through (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 facility. The request shall include information as described in paragraph (i)(2) of this section. The request sha ll be submitted and followed as described in paragraph (i )(3) of this section. (1) A process heater that meets one of the criteri a 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 heat er that lacks sufficient space to accommodate installation and proper operation of co mbustion modification-based technology ( e.g. , ultra-low NO Xburners); or (ii) A modified or reconstructed process heater that has downwardly firing induced draft burners; or (iii) A co-fired process heater; or (iv) A process heater operati ng at reduced firing conditions fo r 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 and approp riate 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 th is section. At a minimum, the request shall contain the information described in paragr aphs (i)(2)(i) through (iv) of this section. (i) The design and dimensions of the proce ss heater, evaluation of available combustion modification-based technology, description of fuel ga s and, if applicable, fu el oil characteristics, information regarding the combustion conditions (temperature, oxygen content, firing rates) and other information needed to demons trate that the process heater m eets one of the four classes of process heaters listed in para graph (i)(1) of this section. (ii) An explanation of how the data in para graph (i)(2)(i) demonstr ate that ultra-low NO X burners, flue gas recirculation, control of ex cess air or other combus tion modification-based technology (including combinations of these combustion modification-based technologies) cannot be used to meet the applicable emissions limit in paragraph (g)( 2) of this section.15 (iii) Results of a performance te st 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 followed as described in paragraphs (i)(3)(i) through (iii) of this section. (i) The owner or operator of a process heater that meets one of the criteria in paragraphs (i)(1)(i) through (iv) of this section ma y request approval from the Admi nistrator 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 request as 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 Planning and Stan dards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: Refi nery 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 request for a facility-specific NO Xemissions limit is described in paragraphs (i)(4)(i) through (iii) of this section. (i) Approval by the Administrato r of a facility-specific NO Xemissions limit request will be based on the completeness, accuracy and reasonable ness of the request. Factors that the EPA will consider in reviewing the reque st for approval include, but are not limited to, the following: (A) A demonstration that the process heater meet s one of the four cla sses 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 rate, heater box temperature and excess oxygen concentration) at which the NO Xemission level was established. (ii) If the request is approved by the Administrator, a facility-specific NO Xemissions limit will be established at the NO Xemission level demonstrated in the approved request.16 (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. § 60.103a Design, equipment, work pr actice or operational standards. (a) Except as provided in paragra ph (g) of this section, each ow ner or operator that operates a flare that is subject to this s ubpart shall develop and implement a written flare management plan no later than the date specified in paragraph (b) of this section. The flare management plan must include the information described in paragr aphs (a)(1) through (7 ) of this section. (1) A listing of all refinery process units, ancillary equipment, and fuel gas systems connected to the flare for each affected flare. (2) An assessment of whether di scharges to affected flares fr om these process units, ancillary equipment and fuel gas systems can be minimized. The flare minimization assessment must (at a minimum) consider the items in paragraphs (a)(2 )(i) through (iv) of this section. The assessment must provide clear rationale in terms of costs (capital and annual operati ng), natural gas offset credits (if applicable), techni cal feasibility, secondary envi ronmental impacts and safety considerations for the selected minimization alternat ive(s) or a statement, with justifications, that flow reduction could not be achieved. Based upon the assessment, each owner or operator of an affected flare shall identify the minimization alte rnatives that it has implemented by the due date of the flare management plan and shall include a schedule for the prompt implementation of any selected measures that cannot reasonab ly be completed 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 un it 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 containing the information in paragr aphs (a)(3)(i) through (vii) of this section. (i) A general description of the flare, including the informati on in paragraphs (a)(3)(i)(A) through (G) of this section. (A) Whether it is a ground flare or elevated (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).17 (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 emergenc y flare or a non-emergency flare. (G) Whether the flare is equipped wi th a flare gas recovery system. (ii) Description and simple process flow diag ram showing the interconnection of the following components of the flare: flare tip (date instal led, manufacturer, nomin al and effective tip diameter, tip drawing); knockout or surge drum (s) or pot(s) (including dimensions and design capacities); flare header(s) and subheader(s ); assist system; and ignition system. (iii) Flare design parameters, in cluding the maximum vent gas flow rate; minimum sweep gas flow rate; minimum purge gas flow rate (i f any); maximum supplemental gas flow rate; maximum pilot gas flow rate; and, if the flar e is steam-assisted, minimum total steam rate. (iv) Description and simple process flow diagram showing all gas lines (inc luding flare, purge (if applicable), sweep, supplemental an d pilot gas) that are associat ed with the flare. For purge, sweep, supplemental and pilot gas, identify the type of gas used. Designate which lines are exempt from sulfur, H 2 S or flow monitoring and why ( e.g. , natural gas, inherently low sulfur, pilot gas). Designate which lines are monitored and identify on the process flow diagram the location and type of each monitor. (v) For each flow rate, H 2 S, sulfur content, pressure or wate r seal monitor identified in paragraph (a)(3)(iv) of this secti on, provide a detailed description of the manufacturer's specifications, including, but not limited to, make, model, type, range, precision, accuracy, calibration, maintenance and quality assurance procedures. (vi) For emergency flares, secondary flares and fl ares equipped with a flare gas recovery system designed, sized and operated to capture all flow s except those 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 elected (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 mon itoring parameters used to qua ntify the amount of flare gas recovered.18 (C) For systems with staged compressors, th e 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 during compre ssor staging and a just ification 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 minimization 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 these gas flows remain reasonably constant ( i.e. , separate flow monitors for these streams are not required). Separa te baseline flow rates may be established for different operating conditi ons provided that the mana gement plan includes: (i) A primary baseline flow rate that will be us ed as the default baselin e for all conditions except those specifically delineated in the plan; (ii) A description of each special condition for which an alternate base line is established, including the rationale for each alternate baseline, the daily flow for each alternate baseline and the expected duration of the special c onditions for each alternate baseline; and (iii) Procedures to minimize discharges to th e affected flare during each special condition described in paragraph (a)(4)(ii) of this section, unless proced ures are already developed for these cases under paragraph (a)(5) through (7) of this section, as applicable. (5) Procedures to minimize or eliminate discharg es to the flare during the planned startup and shutdown of the refinery process units and ancillary equipment thatare connected to the affected flare, together with a schedule for the prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission of the flare management plan. (6) Procedures to reduce flaring incases of fuel gas imbalance ( i.e. , excess fuel gas for the refinery's energy needs), together with a sc hedule for the prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission of the flare management plan. (7) For flares equipped with flar e gas recovery systems, procedures to minimize the frequency and duration of outages of the flare gas recovery system and procedures to minimize the volume of gas flared during such outages , together with a schedule for th e prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission of the flare management plan. (b) Except as provided in paragr aph (g) of this section, eachowner or operator required to develop and implement a written flare management plan as described in paragraph (a) of this section must submit the plan to the Administrator as described in paragraphs (b)(1) through (3) of this section. (1) The owner or operator of a newly construc ted or reconstructed fl are must develop and implement the flare management plan by no later thanthe date that the flare becomes an affected19 facility subject to this subpart, except for the selected minimization alte rnatives in paragraph (a)(2) and/or the procedures in paragraphs (a )(5) though (a)(7) of this section that cannot reasonably be implemented by that date, whic h the owner or operator must implement in accordance with the schedule in the flare manageme nt plan. The owner or operator of a modified flare must develop and implement the flare management plan by no later than November 11, 2015 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) of this section. The plan shoul d be updated periodically to account for changes in the operation of the flare, such as new connecti ons to the flare or the installation of a flare gas recovery system, but the plan need be re-submitted to the Administrator only if the owner or operator adds an alternative baseline flow rate , revises an existing base line as described in paragraph (a)(4) of this section, in stalls a flare gas recovery system or is required to change flare designations and monitoring methods as describe d 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 Protectio n Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Driv e, Research Triangle Pa rk, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov

. (c) Except as provided in paragraphs (f) and (g) of this section, each owner or operator that operates a fuel gas combustion device , flare or sulfur recovery plant 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) thro ugh (3) of this section. (1) For a flare: (i) Any time the SO 2 emissions exceed 227 kilograms (kg) (500 lb) in any 24-hour period; or (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 baseli ne, determined in paragraph (a)(4 ) of this section, in any 24- hour period; or (iii) If the monitoring alternativ e in §60.107a(g) is elected, any period when the flare gas line pressure exceeds the water seal liquid depth, 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 exceed ance 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 emitted if the emi ssions limits had been met during one or more consecutive periods of excess emissions 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 woul d have been emitted if the SO 2 or reduced sulfur concentration20 was equal to the applicable emissions limit in §60.102a(f)(1) or (2) during one or more consecutive periods of excess emissions or any 24-hour period, whichever is shorter. (d) Except as provided in paragraphs (f) and (g) of this section, a r oot cause analysis and corrective action analysis must be completed as s oon as possible, but no later than 45 days after a discharge meeting one of the conditi ons specified in paragraphs (c)( 1) through (3) of this section. Special circumstances affecting the number of root cause anal yses and/or corrective action analyses are provided in paragraphs (d)(1) through (5) of this section. (1) If a single continuous discharge meets any of the conditions sp ecified in paragraphs (c)(1) through (3) of this sectio n for 2 or more consecutive 24-hour pe riods, a single root cause analysis and corrective action analysis may be conducted. (2) If a single discharge from a flare triggers a ro ot cause analysis based on more than one of the conditions specified in paragraphs (c)(1)(i) through (i ii) of this section, a single root cause analysis and corrective action analysis may be conducted. (3) If the discharge from a flare is the result of a planned startup or shutdown of a refinery process unit or ancillary equipm ent connected to the affected flare and the procedures in paragraph (a)(5) of this secti on were followed, a root cause analysis and corrective action analysis is not required ; however, the discharge mu st be recorded as described in §60.108a(c)(6) and reported as described in §60.108a(d)(5). (4) If both the primary and secondary flare in a ca scaded flare system meet any of the conditions specified in paragraphs (c)(1)(i) through (iii) of this section in the same 24-hour period, a single root cause analysis and corrective action analysis may be conducted. (5) Except as provided in paragraph (d)(4) of this section, if disc harges occur that meet any of the conditions specified in paragraphs (c)(1) through (3) of this sec tion for more than one affected facility in the same 24- hour period, initial root cause an alyses shall be conducted for each affected facility. If the initial root cause analyses indicate that the discharges have the same root cause(s), the initial 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 pl ant 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 applicable requirements in paragraphs (e)(1) through (3) of this section. (1) All corrective action(s) must be implemented within 45 days of the discharge for which the root cause and corrective action anal yses were required or as soon th ereafter as practicable. If an owner or operator concludes that corrective action should not be conducted, the owner or operator shall record and explain the basis for that conclusion no later than 45 days following the discharge as specified in §60.108a(c)(6)(ix).21 (2) For corrective acti ons that cannot be fully implemented within 45 days following the discharge for which the root cause and correctiv e action analyses were required, the owner or operator shall develop an implem entation schedule to complete the corrective action(s) as soon as practicable. (3) No later than 45 days following the discharg e for which a root cause and corrective action analyses were required, the owne r or operator shall record the co rrective action(s) completed to date, and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates as specified in§60.108a(c)(6)(x). (f) Modified flares shall comply with the requirements of para graphs (c) through (e) of this section by November 11, 2015 or at startup of the modified flare, whicheve r is later. Modified flares that were not affected faci lities subject to subpart J of this part prior to becoming affected facilities under §60.100a shal l comply with the requirements of paragraph (h) of this section and the requirements of §60.107a(a)(2) by November 11, 2015 or at startup of the modified flare, whichever is later. Modified flares that were aff ected facilities subject to subpart J of this part prior to becoming affected fac ilities under §60.100a shall comp ly with the requirements of paragraph (h) of this section and the require ments of §60.107a(a)(2) by November 13, 2012 or at startup of the modified flare, whichever is late r, except that modified flares that have accepted applicability of subpart J under a federal cons ent decree shall comply with the subpart J requirements as specified in the consent decree, but shall comply with the requirements of paragraph (h) of this section and the require ments of §60.107a(a)(2) by no later than November 11, 2015. (g) An affected flare subject to this subpart located in the Bay Area Air Quality Management District (BAAQMD) may elect to comply w ith 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 aff ected flare subject to this subpart located in the South Coast Air Quality Manage ment District (SC AQMD) may elect to comply with SCAQMD Rule 1118 as an alternative to complying with th e requirements of paragr aphs (a) through (e) of this section. The owner or operator of an affected flare must notify the Administrator that the flare is in compliance with BAAQMD Regula tion 12, Rule 11 and BAAQMD Regulation 12, Rule 12 or SCAQMD Rule 1118. The owner or operator of an affected flar e shall also submit the existing flare management plan to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Se ctor Policies and Progr ams Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electroni c copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov

. (h) Each owner or operator shall not burn in any 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 emergency malfunctions is exempt from this limit. (i) Each owner or operator of a delayed coking un it shall depressure each coke drum to 5 lb per square inch gauge (psig) or less prior to di scharging the coke drum steam exhaust to the22 atmosphere. Until the coke drum pressure reaches 5 psig, the coke drum steam exhaust must be managed in an enclosed blowdown system and th e uncondensed vapor must either be recovered ( e.g. , sent to the delayed coking unit fractionators) or vented to th e fuel gas system, 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 th e Administrator for a determinati on of equivalence for any means of emission limitation that achieve s a reduction in emissions of a specified pollutant at least equivalent to the reduction in emissions of that pollutant achieved by the controls required in this section. (2) Determination of equivalence to the desi gn, equipment, work practice or operational requirements of this section will be evaluated by the following guidelines: (i) Each owner or operator applying for a determin ation of equivalence sh all be responsible for collecting and verifying test data to demonstrat e the equivalence of the alternative means of emission limitation. (ii) For each affected facility for which a dete rmination of equivalence is requested, the emission reduction achieved by the design, equipment, work practice or operational requirements shall be demonstrated. (iii) For each affected facilityfor which a determination of equivalence is requested, the emission reduction achieved by the alternative 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 writing to work practice(s) that provide for emission reductions equal to or greater than the emissi on reductions achieved by the required work practice. (v) The Administrator will compare the demons trated emission reduction for the alternative means of emission limitation to the demonstrated emission reduction for the design, equipment, work practice or operational 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 necessary to ensure operation and maintenance to achieve the same emissions reduction as the design, equipment, work practice or operational requirements. (3) An owner or operator may offer a unique appr oach 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:23 (i) After a request for determination of equivale nce is received, the Administrator will publish a notice in the F EDERAL R EGISTER and provide the opportunity for public hearing if the Administrator judges that th e request may be approved. (ii) After notice and opportunity for public hearing, the Admi nistrator will determine the equivalence of a means of emission limitati on and will publish the determination in the F EDERAL REGISTER

. (iii) Any equivalent means of emission limitation s approved under this section shall constitute a required work practice, equipment, design or oper ational 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 alternat ive means of emission limitation that achieves a reduction in emissions achieved by the equipmen t, design and operational requirements of this section. The Administrator will make an equivalence determination according to the provisions of paragraphs (j)(2) thro ugh (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 and conduct a performance test for each flare to demonstrate initial compliance with the H 2 S concentration requirement in §60.103a(h) according to the requirements of §60.8. The notif ication requirements of §60.8(d) apply to the initial performance test and to subsequent performance tests re quired by paragraph (b) of this section (or as required by the Administrator), but does not apply to pe rformance tests conducted for the purpose of obtaining supplemental databecause of continuous monitoring system breakdowns, repairs, calibration chec ks 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 CO MS according to the requirements in §60.105a(e) shall conduct a PM performance test at least once every 12 months annually (i.e., once per calendar year, with an interval of at least 8 months but no more than 16 months between annual tests) 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 in this section, except as provided in §60.8(b). (d) The owner or operator shall determine compliance with the PM, NO X , SO 2 , and CO emissions limits in §60.102a(b) for FCCU and FCU using the following methods and procedures: (1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses.24 (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 scrubber subject to the emissions limit in §63.102a(b)(1). Use Method 5 or 5B of appendix A- 3 to part 60 for determining PM emissions and associated moisture content from a FCCU or FCU with a wet scrubber subject to the emissions limit in §63.102a(b)(1). (i) The PM performance test consists of 3 valid 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 usi ng Equation 5 of this section:

c sd s 

## KR

Q c E  (Eq. 5)

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

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

R c = Coke burn-off rate, kilograms per hour (kg/hr) [lb per hour (lb/hr)] coke; and K = Conversion factor, 1.0 grams pe r gram (7,000 grains per lb). (iii) The coke burn-off rate (R c ) is computed for each run using Equation 6 of this section: 

##   

#     oxy oxy 3 2 2 r 3 a 2 2 r 1 c %O Q K %O %CO %CO Q K Q K %CO %CO Q K R   

    2 (Eq. 6)

Where:

R c = Coke burn-off rate, kg/hr (lb/hr); Q r = Volumetric flow rate of exhaust gas from FCCU regenerator or fl uid coking burner before any emissions control or energy recovery syst em that burns auxiliar y fuel, dry standard cubic meters per minute (dscm/min) [dry st andard cubic feet per minute (dscf/min)];25 Q a= Volumetric flow rate of air to FCCU regene rator or fluid coking burner, as determined from the unit's control room instrume ntation, dscm/min (dscf/min); Q oxy= Volumetric flow rate of O 2 enriched air to FCCU 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 rege nerator or fluid coking burner exhaust, percent by volume (dry basis);

%CO = CO concentration in F CCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);

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

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

K 1 = Material balance and conversion factor, 0. 2982 (kg-min)/(hr-dscm-%) [0.0186 (lb-min)/(hrdscf-%)];

K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lb-min)/(hrdscf)]; and

K 3 = Material balance and conversion fact or, 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 flow rates, 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 app licable, using Equation 7 of this section: 

#  

2 2 oxy xy a r 

### %O %CO %CO Q %O Q Q

   

  

 100 100 79 (Eq. 7)

Where: Q r = Volumetric flow rate of exhaust gas from FCCU regenerator or fl uid coking burner before any emission control or energy recovery syst em that burns auxiliary fuel, dscm/min (dscf/min);26 Q a= Volumetric flow rate of air to FCCU regene rator or fluid coking burner, as determined from the unit's control room instrume ntation, dscm/min (dscf/min); Q oxy= Volumetric flow rate of O 2 enriched air to FCCU 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 re generator 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 (h)(3), assume %CO to be zero;

%O 2 = O 2 concentration in FCCU regenerator or fl uid 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). (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 alte rnative to EPA Method 6 or 6A of appendix A-4 to part 60. (6) Method 7, 7A, 7C, 7D, or 7E of appendix A- 4 to part 60 for moisture content and for the concentration of NO Xcalculated as nitrogen dioxide (NO 2 ); the duration of each test run must be no less than 4 hours. The method ANSI/ASM E 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 operator shall adjust PM, NO X , SO 2 and CO pollutant concentrations to 0- percent excess air or 0-percent O 2 using Equation 8 of this section: 

##        

  2 c meas adj %O C C 9

. 20 9

. 20 (Eq. 8)

Where:

C adj = pollutant concentration adjust ed 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;27 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 FCCU or FCU that uses cyclones to comply with the PM per coke burn-off emissions limit in §60.102a(b)(1) and elects to comply with the COMS alternative monitoring option in §60.105a(d) shall establish a site-specific opacity operating limit according to the procedures in paragraphs (f)(1) through (3) of this section. (1) Collect COMS data every 10 seconds during the entire period of the PM performance test and reduce the data to 6-minute averages. (2) Determine and record the hourly averag e opacity from all the 6-minute averages. (3) Compute the site-specific limit using Equation 9 of this section:

         

st st PMEmR Opacity mit Opacity Li burn coke lb 1,000 / lb 1 (Eq. 9)

Where: Opacity limit = Maximum permissible 3-hour averag e opacity, percent, or 10 percent, whichever is greater; Opacity st = Hourly average opacity measured during the source test, percent; and

PMEmR st = PM emission rate measured during th e source test, lb/1,000 lb 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.28 (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), and 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) , 60.102a(f)(1)(iii), 60.102a(f)(2)(ii) and § 60.102a(f)(2)(ii i ) 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 E xhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternativ e to EPA Method 6 or 6A of appendix A-4 to part 60. (5) Method 15 or 15A of appendix A-5 to part 60 or Method 16 of appendix A-6 to part 60 to determine the reduced su lfur compounds and H 2 S concentrations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (i ncorporated 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, correct ed to 0 percent excess air). (iii) The owner or operato r shall calculate the SO 2 equivalent for each r un 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 of this section to adjust pollutant concentrations to 0-percent O 2 or 0- percent excess air. (6) If oxygen or oxygen enriched air is used in the Claus burner and either Equation 1 or 2 of this subpart is used to determine the a pplicable emissions limit, determine the average O 2 concentration of the air/oxygen mixture supp lied to the Claus burner, in percent by volume (dry basis), for the performan ce test using all hourly average O 2 concentrations determined during the test runs using the procedures in §60.106a(a)(5) or (6).29 (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 ac cording 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 E xhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternativ e 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 for 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. (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 or operator shall establish the O 2 operating limit or O 2 operating curve based on the performance test resu lts 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 heater is firing at no less 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 fu el gas and fuel oil and conduct at least one of the test runs while the process heater is being supplied solely by fuel gas.30 (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 th e three test runs. If the NO X concentration for the performance test is less th an or equal to the num erical value of the applicable NO Xemissions limit (regardless of averaging time), then the test is considered to be a valid test. (C) Determine the average O 2 concentration for each te st 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 methods provided in paragraphs (i)(1), (2), (3) and (5) of this section at a representative condi tion for each operating range for which different O 2 operating limits will be established. Different ope rating 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 h eaters, 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 value is from fuel oil). Performance tests for different operating ranges may be conducted 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 th e three test runs. If the NO X concentration for the performance test is less th an or equal to the num erical value of the applicable NO Xemissions limit (regardless of averaging time), then the test is considered to be a valid test. (C) If an operating curve is developed for different 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 rates (and not by fuel mixtures), conduct at least one of the test runs for each test while the process heater is being supplied byboth fuel gas and fuel oil and conduct at least one of the test runs while the process heat er is being supplied solely by fuel gas. (D) Determine the average O 2 concentration for each te st 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 represen tative conditions for that given operating range. (F) Identify the firing rates for which the differe nt 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 established31 for turndown conditions must apply when the process heater is firing at 50 percent or less of the rated heat capacity. (G) Operating limits associated with each interv al will be valid for 2 years or until another operating limit is established for that interval 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 interval based on the mo st recent performance test conducted for that interval. (7) The owner or operator of a pr ocess heater complying with a NO Xlimit in terms of lb/MMBtu as provided in §60.102a(g)(2)(i)(B), (g)(2)(ii)(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 according to the methods provided in §60.107a(d)(5) , (d)(6), and (d)(4) or (d)(7), respectively. (8) The owner or operator shall us e 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 determ ine 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 follo wing test methods and procedures: (1) [Reserved] Method 1 of appendix A-1 to part 60 for sample and velocity traverses; (2) [Reserved] Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate; (3) [Reserved] 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 al ternative to EPA Method 3B of appendix A-2 to part 60; (4) EPA Method 11, 15 or 15A of Appendix A-5 to part 60 or EPA Method 16 of Appendix A-6 to part 60 for determining the H 2 S concentration for affected facilities using an H 2 S monitor as specified in §60.107a(a)(2). The method ANS I/ASME PTC 19.10-1981 (incorporated by reference—see §60.17) is an acceptable alternativ e to EPA Method 15A of Appendix A-5 to part 60. The owner or operator may demonstrate comp liance 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, the sampling time and sample volume must be at least 10 minutes and 0.010 dscm (0.35 dscf). Two samples of equal sampling times must be taken at about 1-hour intervals. The arithmetic average of these two samples constitutes a run. For most fuel gases, sampling times exceeding 20 minutes may result in depletion of the collection solution, altho ugh fuel gases containing low concentrations of H 2 S may necessitate sampling for longer periods of time.32 (ii) For Method 15 of appendix A-5 to part 60, at least three inject s 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 combusti on 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 emissions limit in §60.102a (b)(1) that uses a control device other than fabric filter or cyclone shall co mply with the requirements in paragraphs (b)(1) and (2) of this section. (1) The owner or operator shall install, operate and maintaincontinuous parameter monitor systems (CPMS) to measure and record operati ng parameters for each control device according to the applicable requirements in paragraphs (b)(1)(i) through (v ) 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 aver age total power input and secondary voltage current to the entire system. (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 to pressure drop, the owner or operator of a jet ejector type wet scrubber or other type of wet scrubber equipped with atomiz ing spray nozzles must conduct a daily check of the air or water pressure to the spray nozzles and record the results of each check. Faulty (e.g., leaking or plugged) air or water lines must be repaired within 12 hours of identification of an abnormal pressure reading. (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 National33 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, ope rate, and maintain each CPMS according to the manufacturer's specifications and requirements. (iv) The owner or operator shall determine and record the average coke burn-off rate and hours of operation for each FCCU or FCU using the procedures in §60.104a(d)(4)(iii). (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 monitoring 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 established 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 recordkeepi ng, recording, and reporting, if monitoring and recording are not continuous. The owner or opera tor also must include the rationale for the proposed monitoring, recording, and reporting requirements. (D) Supporting calculations. (E) Averaging time for the alternative operating parameter. (2) For use in determining the coke burn-off rate for an FCCU or FCU, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring the concentrations of CO 2 , O 2 (dry basis), and if needed, CO in the exhaust gases prior to any control or energy recovery system that burns auxiliary fuels. A CO monitor is not required for determining coke burn-off rate when no aux iliary fuel is burned and a continuous CO monitor is not required in accordance with §60.105a(h)(3). (i) The owner or operator shall in stall, operate and maintain eachCO 2 and O 2 monitor according to Performance Specifications 3 and 4 of Appendix B to part 60. (ii) The owner or operator shall cond uct performance evaluations of each CO 2 , O 2 and CO O 2 monitor according to the requirements in §60.13(c) and Performance Specifications 3 and 4 of34 Appendix B to part 60. The owner or operator sh all use EPA Method 3 of Appendix A-3 to part 60 and EPA Method 10, 10A or 10B of Appendi x A-4 to part 60 for conducting the relative accuracy evaluations. (iii) If a CO monitor is required, the owner or op erator shall install, operate, and maintain each CO monitor according to Performance Specification 4 or 4A of Appendix B to part 60. If this CO monitor also serves to demonstrat e compliance with the CO emissions limit in §60.102a(b)(4), the span value for this instrument is 1,000 ppmv; otherwise, the span value for this instrument should be set at approxi mately 2 times the typical CO concentration expected in the FCCU of FCU flue gas prior to any emission control or energy recovery system that burns auxiliary fuels. (iv) If a CO monitor is required, the ow ner or operator sha ll conduct performance evaluations of each CO monitor accord ing to the requirements in §60.13(c) and Performance Specification 4 of Appendix B to part 60. The owner or operator shall use Method 10, 10A, or 10B of Appendix A–3 to pa rt 60 for conducting the relative accuracy evaluations. (v) The owner or operator shall comply with the qu ality assurance requirements 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 recorder 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 alarm set point established according to paragraph (c)(1)(iv) of this section, a nd the alarm must be located such that it can be heard by the appropriate plant personnel.35 (iv) In the initial adjustment of the bag leak detection system, the owner or operator must establish, at a minimum, the baseline output by adjusting the 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 op erator shall not adjust the averaging period, alarm set point, or alarm delay 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 the procedures identified in the site -specific monitoring plan requir ed 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 and mainta in each baghouse and bag leak detection system according to the site-specific monitoring plan at all times. Eachmonitoring 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 approving the site-specific monitoring plan, the Administrator or delegated authority may allow owners and operators more than 3 hours to alleviate a specific condition 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; and36 (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 alarm within 1 hour of the alarm. Except as provided in paragraph (c)(2)(vi) of this section, the owner or operator shall alleviate the cause of the alarm within 3 hours of the alarm by taking 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; (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 the 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 detection 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 th e 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.37 (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 perfor mance 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 part60 shall be used for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (5) The owner or operator shall comply with the quality assurance requir ements 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 e ach 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 w ith 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 NOX 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.38 (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 evaluations . 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 part60 shall be used for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (5) The owner or operator shall comply with the quality assurance requir ements 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 ANS I / ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptabl e alternative to EPA Method 6 or 6A of appendix A-4 to part 60.39 (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 part60 shall be used for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 of appendix F to part 60 for each SO 2 and O 2 monitor, including quarterly accuracy determinations for SO 2 monitors, annual accuracy determinations for O 2 monitors, and daily calibration drift tests. (h) FCCU and fluid coking units subject to CO emissions limit . Except as specified in paragraph (h)(3) of this section, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and 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). (1) The owner or operator shall install, opera te, and maintain each CO monitor according to Performance Specification 4 or 4A of appendix B to part 60. The sp an value for this instrument is 1,000 ppmvCO. (2) The owner or operator shall conduct perfor mance 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 owner 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 ppmvCO instead of 1,000 ppmv , and the relative accuracy limit shall be 10 percent of the average CO emissions or 5 ppmvCO, whichever is greater. For instruments that are identical to Method 10 of appendix A-4 to part 60 and employ the sample conditioning system of Method 10A of appendix A- 4 to part 60, the alternative relative accuracy test procedure in section 10.1 of Performance Sp ecification 2 of appendix B to part 60 may be used in place of the relative accuracy test.40 (ii) The owner or operator must 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 operator shall install, operate, 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. (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) through (6) of this secti on. 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. If the alternative to pressure drop CP MS is used for the owner or operator of a jet ejector type wet scrubber or other type of wet scrubber e quipped with atomizing spray nozzles, each day in which abnormal pressure readings are not corrected within 12 hours of identification. (2) If a bag leak detection syst em is used according to §60.105a( c), each day in which the cause of an alarm is not alleviated within the time period sp ecified in §60.105a(c)(3). (3) 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.41 ( 3 4 ) 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 5 ) All rolling 7-day periods during wh ich 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 6 ) All rolling 7-day periods during wh ich the average concentration of SO 2 as measured by the SO 2 CEMS under §60.105a(g) exceed s 50 ppmv, and all rolling 365-day periods during which the average concentration of SO 2 as measured by the SO 2 CEMS exceeds 25 ppmv. ( 6 7 ) All 1-hour periods during wh ich the average CO concentration as measured by the CO continuous monitoring system under § 1A 60.105a(h) exceeds 500 ppmv or, if applicable, all 1- hour periods during which the average temperature and O 2 concentration as measured by the continuous monitoring systems under §60.105a(h)(4) fall below the operating limits established during the performance test. § 60.106a Monitoring of emissions and operations for sulfur recovery plants. (a) The owner or operator of a su lfur recovery plant that is subject to the emissions limits in §60.102a(f)(1) or §60. 102a(f)(2) shall: (1) For sulfur recovery plants subject to the SO 2 emission limit in §60.102a(f)(1)(i) or §60.102a(f)(2)(i), the owner or operator shall install, operate , calibrate, and maintain an instrument for continuously monitoring and 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. (i) The span value s for this the SO 2 monitor are is two times the applicable SO 2 emission limit and between 10 and 25 percent at the highest O 2 , inclusive concentration in the air/oxygen stream used in the Claus burner, if applicable

. (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 a ppendix A-4 to part 60 and Method 3 or 3A of appendix A-2 of part 60 for conducti ng 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 al ternative to EPA Method 6. (iv) The owner or operator shall inst all, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60.42 (v) The span value for the O 2 monitor must be selected between 10 and 25 percent, inclusive. (vi) The owner or operator shall co nduct performance eval uations for the O 2 monitor according to the requirements of §60.13(c) an d Performance Specification 3 of appendix B to part 60. The owner or operator shall use Me thods 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,” (incor porated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A–2 to part 60. (vii) The owner or operator sh all comply with the applicable quality assurance procedures of appendix F to part 60 for each monitor, including annual accuracy determinations for each O 2 monitor, and daily calibration drift determinations. (2) For sulfur recovery plants that are subject to the reduced sulfur compound and H 2 S compounds emission limit in §60.102a(f)(1)(ii) or §60.102a(f)(2)(ii), th e owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentrat ion of reduced sulfur , H 2 S, compounds and O 2 emissions into the atmosphere. The reduced sulfur compounds emissions shall be calculated as SO 2 (dry basis, zero percent excess air). (i) The span value s for this the reduced sulfur compounds monitor are is two times the applicable reduced sulfur compounds emission limit , two times the H 2 S emission limit, and between 10 and 25 percentas SO 2 at the highestO 2 , inclusive concentration in the air/oxygen stream used in the Claus burner, if applicable

. (ii) The owner or operator shall install, operate, and maintain each reduced sulfur compounds CEMS according to Performance Specifi cation 5 of appendix B to part 60. (iii) The owner or operator shall conduct perf ormance evaluations of each reduced sulfur compounds monitor according to the requirements in §60.13(c) and Performance Specification 5 of appendix B to part 60. The owner or operator shall use Methods 15 or 15A of appendix A-5 to part 60 for conducting the rela tive accuracy evaluations. Th e 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. (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 E xhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternativ e to EPA Method 15A of appendix A-5 to part 60.43 ( iv vi ) 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. ( vii v ) The span value for the O 2 monitor must be selected betw een 10 and 25 percent, inclusive. ( viii vi ) The owner or operator shall conduc t performance evaluations for the O 2 monitor according to the requirements of §60.13(c) and Performance Specification 3 of appendix B to part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part 60 for conducting the relative accuracy evaluations . The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by re ference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. ( ix vii ) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to part 60 for each monitor, including annual accuracy determinations for each O 2 monitor, and daily calibration drift determinations. (3) In place of the reduced sulfur compounds monitor required in paragraph (a)(2) of this section, the owner or operator shall mayinstall, calibrate, operate, and maintain an instrument using an air or O 2 dilution and oxidation system to convert any reduced sulfur to SO 2 for continuously monitoring and record ing the concentration (dry basi s, 0 percent ex cess 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 mon itor is two times the applicable SO 2 emission limit reduced sulfur compounds emission limit as SO 2 at the highest O 2 concentration in the air/oxygen stream used in the Claus burner, if applicable

. (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 ANS I/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §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 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 ANS I/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptabl e alternative to EPA Method 3B of appendix A-2 to part 60.44 (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. (4) For sulfur recovery plants that are subject to the H 2 S emission limit in §60.102a(f)(1)(iii) or §60.102a(f)(2)(ii i), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of H 2 S, and O 2 emissions into the atmosphere. The H 2 S emissions shall be calculated as SO 2 (dry basis, zero percent excess air). (i) The span value for this monitor is two times the applicable H 2 S emission limit. (ii) The owner or operator shall inst all, operate, and maintain each H 2 S CEMS according to Performance Specification 7 of appendix B to part 60. (iii) The owner or operator shall conduc t performance evalua tions for each H 2 S monitor according to the requirements of §60.13(c) an d Performance Specification 7 of appendix B to part 60. The owner or operator shall use Methods 11 or 15 of appendix A–5 to part 60 or Method 16 of appendix A–6 to part 60 for con ducting 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. (iv) 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. (v) The span value for the O 2 monitor must be selected between 10 and 25 percent, inclusive. (vi) The owner or operator shall co nduct performance eval uations for the O 2 monitor according to the requirements of §60.13(c) an d Performance Specification 3 of appendix B to part 60. The owner or operator shall use Me thods 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,” (incor porated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A–2 to part 60. (vii) The owner or operator sh all comply with the applicable quality assurance procedures of appendix F to part 60 for each monitor, including annual accuracy determinations for each O 2 monitor, and daily calibration drift determinations.. (5) For sulfur recovery plants that use oxyge n or oxygen enriched air in the Claus burner and that elects to monitor O 2 concentration of the air/oxygen mixture supplied to the Claus burner, the owner or operator shall install, op erate, calibrate, and maintain an instrument for continuously monitoring and recording the O 2 concentration of the air/oxygen mixture supplied to the Claus burner in order to determine the allowable emissions limit.45 (i) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. (ii) The span value for the O 2 monitor shall be 100 percent. (iii) The owner or operator shall co nduct performance eval uations for the O 2 monitor according to the requirements of §60.13(c) an d Performance Specification 3 of appendix B to part 60. The owner or operator shall use Me thods 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,” (incor porated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A–2 to part 60. (iv) The owner or operator sh all comply with the applicable quality assurance procedures of appendix F to part 60 for each monitor, including annual accuracy determinations for each O 2 monitor, and daily calibration drift determinations. (v) The owner or operator shall use the hourly average O 2 concentration from this monitor for use in Equation 1 or 2 of §60.102a(f), as applicable, for each hour and determine the allowable emission limit as the arithmetic ave rage of 12 contiguous 1-hour averages (i.e., the rolling 12-hour average). (6) As an alternative to the O 2 monitor required in paragraph (a)(5) of this section, the owner or operator may install, calibrate, op erate, and maintain a CPMS to measure and record the volumetric gas flow rate of ambien t air and oxygen-enriched gas supplied to the Claus burner and calculate the hourly average O 2 concentration of the air/oxygen mixture used in the Claus burner as speci fied in paragraphs (a)(6)(i) th rough (iv) of this section in order to determine the allowable emissions limit as specified in paragraphs (a)(6)(v) of this section. (i) The owner or operator shall install, calibra te, operate and maintain each flow monitor according to the manufacturer’s procedu res and specifications and the following requirements. (A) The owner or operator sha ll install locate the monitor in a position that provides a representative measurement of the total gas flow rate. (B) Use a flow sensor with a measurement sensit ivity of no more than 5 percent of the flow rate or 10 cubic feet per minute, whichever is greater. (C) Use a flow monitor that is maintainable online, is able to continuously correct for temperature, pressure and, for am bient air flow monitor, moisture content, and is able to record dry flow in standard conditions (a s defined in §60.2) over one-minute averages. (D) At least quarterly, perform a visual inspec tion of all components of the monitor for physical and operational integrity and all elec trical connections for oxidation and galvanic corrosion if the flow monitor is not equipped with a redundant flow sensor.46 (E) 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. (ii) The owner or operator shall use 20.9 percen t as the oxygen content of the ambient air. (iii) The owner or operator shall use product specifications (e.g., as reported in material safety data sheets) for percent oxygen for purchased oxygen. For oxygen produced onsite, the percent oxygen shall be determined by peri odic measurements or process knowledge. (iv) The owner or operator sha ll calculate the hourly average O 2 concentration of the air/oxygen mixture used in the Claus burn er using Equation 10 of this section:

       

   



oxy air oxy 2,oxy air 2 Q Q Q %O Q %O 9

. 20 (Eq. 10)

Where:

%O 2 = O 2 concentration of the air/oxygen mixture used in the Claus burner, percent by volume (dry basis);

20.9 = O 2 concentration in air, percent dry basis; Q air= Volumetric flow rate of ambient air used in the Claus burner, dscfm;

%O 2,oxy= O 2 concentration in the enriched ox ygen stream, percent dry basis; and Q oxy= Volumetric flow rate of enriched oxygen stream used in the Claus burner, dscfm. (v) The owner or operator shall use the hourly average O 2 concentration determined using Equation 8 of this section for use in Equation 1 or 2 of §60.102a(f), as applicable, for each hour and determine the allowable emission limit as the arithmetic aver age of 12 contiguous 1-hour averages (i.e., the rolling 12-hour average). (7) Owners or operators of a sulfur recoveryplant that elects to comply with the SO 2 emission limit in §60.102a(f)(1)(i) or §60.102a(f)(2 )(i) or the reduced sulfur compounds emission limit in §60.102a(f)(1)(ii ) or §60.102a(f)(2)(ii) as a flow rate weighted average for a group of release points from the sulfur recove ry plant rather than for each process train or release point individually shall install, calibra te, operate, and maintain a CPMS to measure and record the volumetric gas flow rate of each release point within the group of release points from the sulfur recovery plant as specified in paragraphs (a)(7)(i) through (iv) of this section.47 (i) The owner or operator shall install, calibra te, operate and maintain each flow monitor according to the manufacturer’s procedu res and specifications and the following requirements. (A) The owner or operator sha ll install locate the monitor in a position that provides a representative measurement of the total gas flow rate. (B) 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. (C) Use a flow monitor that is maintainable online, is able to continuously correct for temperature, pressure, and moisture content, a nd is able to record dry flow in standard conditions (as defined in §60.2) over one-minute averages. (D) At least quarterly, perform a visual inspec tion of all components of the monitor for physical and operational integrity and all elec trical connections for oxidation and galvanic corrosion if the flow monitor is not equipped with a redundant flow sensor. (E) 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. (ii) The owner or operator sh all correct the flow to 0 percen t excess air using Equation 11 of this section: 

##        

 

c 2 meas adj %O Q Q 9

. 20 9

. 20 (Eq. 11)

Where: Q adj = Volumetric flow rate adjusted to 0 perce nt excess air, dry standard cubic feet per minute (dscfm);

C meas = Volumetric flow rate measured by the flow meter corrected to dry standard conditions, dscfm;

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. (iii) The owner or operator shall ca lculate the flow weighted average SO 2 or reduced sulfur compounds concentration for each hour using Equation 12 of this section:48 

#    



 

 N

n adj,n N

n adj,n n

ave Q Q C C

1 1 (Eq. 12)

Where:

C ave = Flow weighted average concentration of the pollutant, ppmv (dry basis, zero percent excess air). The pollutant is either SO 2 [if complying with the SO 2 emission limit in §60.102a(f)(1)(i) or §60.102a(f)(2)(i)] or reduc ed sulfur compou nds [if complying with the reduced sulfur compounds emission limit in §60.102a(f)(1)(ii) or §60.102a(f)(2)(ii)]; N = Number of release points within the group of release points from the sulfur recovery plant for which emissions averaging is elected;

C n = Pollutant concentration in the n th release point within the group of release points from the sulfur recovery plant for which emission s averaging is elected, ppmv (dry basis, zero percent excess air); Q adj,n = Volumetric flow rate of the n th release point within the group of release points from the sulfur recovery plant for which emissi ons averaging is elected, dry standard cubic feet per minute (dscfm, adjusted to 0 percent excess air). (iv) For sulfur recovery plants that use oxyge n or oxygen enriched air in the Claus burner, the owner or operator shall use Equation 10 of this section and the hourly emission limits determined in paragraphs (a)(5)(v) or (a)(6) (v) of this section in-place of the pollutant concentration to determine the flow weighted average hourly emission limit for each hour. The allowable emission limit shall be calculated as the arithmetic average of 12 contiguous 1-hour averages (i.e., the rolling 12-hour average). (b) Excess emissions . For the purpose of reports requi red by §60.7(c), periods of excess emissions for sulfur recovery plants subject to the emissions limitations in §60.102a(f) are defined as specified in paragraphs (b)(1) through (3) of this section. N OTE : Determine all averages as the arithmetic average of the appli cable 1-hour averages, e.g ., determine the rolling 12-hour average 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 con centration of reduced sulfur compounds (as SO 2 ) as measured by the reduced sulfur compounds continuous monitoring system required under paragraph (a)(2 ) or (a)(3 ) of this section exceeds the applicable emission limit; or49 (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 4 ) of this section exceeds the applicable emission limit (dry basis, 0 percent excess air). § 60.107a Monitoring of emissions and operati ons 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 §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 sect ion. 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 w ith paragraph (a)(2) of this section. (1) The owner or operator of a fuel gas combus tion device that elects to comply with the SO 2 emissions limits in §60.102a(g)(1)(i) shall install, operate, calibrate and maintain an instrument for continuously monitoring and re cording the concentration (dry ba sis, 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 ppmvSO 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 ANS I/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §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 ppmv , whichever is greater, and the calibration drift limit shall be 5 percent of the established span value. (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 ANS I/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptabl e alternative to EPA Method 3B of appendix A-2 to part 60.50 (v) The owner or operator shall comply with th e applicable quality assurance procedures in appendix F to part 60, including quart erly accuracy determinations for SO 2 monitors, annual accuracy determinations for O 2 monitors, and daily calibration drift tests. (vi) Fuel gas combustion devices having a common source of fuel gas may be monitored at only one location (i.e., after one of th e combustion devices), if monito ring 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 combus tion device that 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 install, operate , calibrate and maintain an instrument for continuously monitoring and recording the concentration by volume (dry basis) of H 2 S in the fuel gases before being burned in any fuel gas combustion device or flare. (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 for this instrument is 300 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 E xhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternativ e 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 subject to §60. 103a(c) through (e) may use the instrument required in paragraph (e)(1) of this sec tion to demonstrate compliance with the H 2 S concentration requirement in §60.103a(h) if the owner or operator complies with the requirements of paragraph (e)(1)(i) through (iv) and if the instrumenthas a span (or dual span, if necessary) capable of accurately measuring co ncentrations between 20 and 300 ppmv. If the instrument required in paragraph (e)(1) of this section is used to demonstrate compliance with the H 2 S concentration requirement, th e concentration directly measured by the instrument must meet the numeric concentration in §60.103a(h). (vi) The owner or operator of modified flare that meets all three cr iteria in paragraphs (a)(2)(vi)(A) through (C) of this section shall comply with th e requirements of paragraphs (a)(2)(i) through (v) of this section no later than November 11, 2015. The owner or operator shall51 comply with the approved alternative monitori ng plan or plans pursuant to §60.13(i) until the flare is in compliance with requ irements of paragraphs (a)(2)(i ) through (v) of this section. (A) The flare was an affected f acility subject to subpart J of this part prior to becoming an affected facility under §60.100a. (B) The owner or operator had an approved alte rnative monitoring plan or plans pursuant to §60.13(i) for all fuel gases combusted in the flare. (C) The flare did not have in place on or before September 12, 2012 an instrument for continuously monitoring and recording the concentration by volume (dry basis) of H 2 S in the fuel gases that is capable of complying with the requirements of paragraphs (a)(2)(i) through (v) of this section. (3) The owner or operator of a fuel gas combustion device or flare is not re quired to comply with paragraph (a)(1) or (2) of this section fo r fuel gas streams that are exempt under §§60.102a(g)(1)(iii) or 60.103a(h) or, for fuel gas streams combusted in a process heater, other fuel gas combustion device or flare that are inhere ntly low in sulfur content. Fuel gas streams meeting one of the requirements in paragraphs (a )(3)(i) through (iv) of this section will be considered inherently lo w 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 cont aining-compounds at the product specification concentration. (iii) Fuel gas streams produced in process units that are intolerant to sulfur contamination, such as fuel gas streams produced in the hydrogen plant, catalytic reforming un it, isomerization unit, and HF alkylation process units. (iv) Other fuel gas streams that an owner or operator demonstrates are low-sulfur according to the procedures in 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 combus tion 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.52 (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 combus tion 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); (iii) An explanation of the condi tions that ensure low amounts of sulfur in the fuel gas stream (i.e., control equipment or produc t 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 ppmvH 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 Standard 2377-86, Testfor Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,” 1986 Revision (incorporated by reference—see §60.17), with ranges 0-10/0-100 ppm (N = 10/1) using tubes with a maximum span between 10 and 40 ppmv inclusive when 1 ≤ N ≤ 10, where N = number of pump strokes, to test the applicant fuel gas stream for H 2 S; and (v) A description of how the 2 weeks (or seven samples for infrequently operated fuel gas streams/systems) of monitoring 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 in paragraph (b)(3)(i), (b)(3)(ii), or (b)(3)(iii) of this section. (i) If the operation change results in a sulfur content that is still within the range of concentrations included in the original 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.53 (ii) If the operation change result s in a sulfur content that is outside the range of concentrations included in the original application, the owner or operator may submit new information following the procedures of paragr aph (b)(1) of this section with in 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 using length-of-stain tubes with a maximum span between 200 and 400 ppmv inclusive when 1 ≤ N ≤ 5, where N = number of pump strokes . The owner or operator must begin mon itoring according to the requirements in paragraphs (a)(1) or (a)(2) of this section as soon as practicable, but in no case later than 180 days after the operation change. During daily st ain tube sampling, a daily sample exceeding 162 ppmv is an exceedance of the 3-hour H 2 S concentration limit. The owner or operator of a fuel gas combustion device must also determine a rolling 365-day average using the stain sampling results; an average 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 NOX concentration-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 applicable emissions limit in §60.102a (g)(2)(i)(A), (g)(2)(ii)(A ), (g)(2)(iii)(A) or (g)(2)(iv)(A) shall instal l, operate, calibrate and maintainan instrument for continuously monitoring and recording the concentration (dry basis, 0-percent excess air) of NO Xemissions into the atmosphere according to the requireme nts 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 paragra ph (c)(6) of this secti on, the owner or oper ator shall install, operate and maintain each NO Xmonitor according to Performance Specification 2 of Appendix B to part 60. The span value of this NO Xmonitor must be between 2 and 3 times the applicable emissions limit, inclusive. (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 evaluations . 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 part60 shall be used for conducting the relative54 accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 of appendix F to part 60 for each NO 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 heating capacity of less than 100 MMBtu and is equipped with combustion modification-based technology to reduce NO X emissions ( i.e. , low-NO Xburners, ultra-low-NO Xburners) may elect to comply with the monitoring requirements in paragrap hs (c)(1) through (5) of this section or, alternatively, the owner or operator of such a process heater sh all conduct biennial performance tests according to the requirements in §60.104a(i), establish a maximum excess O 2 operating limit or operating curve according to the requirements in§60.104a(i)(6) and co mply 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 different operating ranges), the owner or operator of the pro cess heater must also monitor fuel gas flow rate, fuel oil flow rate (as applicable) and heating value co ntent according to the methods provided in paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7) of this section, respectively. (d) Process heaters complying with the NOX 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 applicable emissions lim it in §60.102a(g)(2)(i)(B) or (g)(2)(ii)(B) shall install, operate, calibrate and maintain an instrument for continuously monitoring and recording the concentration (dry basis, 0-percent excess air) of NO Xemissions into the atmosphere and shall determine the F factor of the fuel gas stream no less frequently than once per day according to the monitoring requirements in paragraphs (d )(1) through (4) of this section. The owner or operator of a co-fired process heater subject to the NO Xemissions limit in §60.102a(g)(2) and electing to comply with the heating value-ba sed limit in §60.102a(g)(2)(i ii)(B) or (g )(2)(iv)(B) shall install, operate, calibrate and maintain an instrument for continuously monitoring and recording the concentration (dry ba sis, 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 fo r continuously monitoring and recording the flow rate of the fuel gas and fuel oil fed to the process heater according to the monitoring requirements in paragraph (d)(5) and (6) of this section; for fuel gas streams, determine gas composition according to the requirements in paragraph (d)(4) of this section or the higher heating value according to the requirements in paragr aph (d)(7) of this section; and for fuel oil streams, determine the heating value according to the monitoring requirements in paragraph (d)(7) of this section. (1) Except as provided in paragra ph (d)(8) of this secti on, the owner or oper ator shall install, operate and maintain each NO Xmonitor according to the requirements in paragraphs (c)(1) through (5) of this se ction. The monitor must include an O 2 monitor for correcting the data for excess air.55 (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 heat er using the methods and equations in section 12.3.2 of EPA Method 19 of Appendix A-7 to part 60 to determine the F factor on a dry basis. If a single fuel gas system provides fuel gas to several process heaters, the F factor may be determined at a single location in the fuel gas syst em provided it is representative of the fuel gas fed to the affected process heater(s). (3) As an alternative to the requirements in paragraph (d)(2) of this section, the owner or operator of a gas-fired process heater shall install, operate and maintain a gas composition analyzer and determine the average F factor of the fuel gas using the factors in Table 1 of this subpart and Equation 10 13 of this section. If a single fuel ga s system provides fuel gas to several process heaters, the F factor may be determined at a single location in the fuel gas system provided it is representative of the fuel ga s fed to the affected process heater(s). 

##     

##  

  

 i i i i d MHC X MEV X F 000 , 000 , 1 (Eq. 10 13 )

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 perfor mance evaluations of each compositional monitor according to the requirements in Performance Sp ecification 9 of Appendix B to part 60. Any of the following methods shall be used for conducting the relative accuracy evaluations: (i) EPA Method 18 of Appendix A-6 to part 60; (ii) ASTM D1945-03 (Reapproved 2010)(inc orporated by reference-see §60.17); (iii) ASTM D1946-90 (Reapproved 2006)(inc orporated by reference-see §60.17); (iv) ASTM D6420-99 (Reapproved 2004)(inc orporated by reference-see §60.17); (v) GPA 2261-00 (incorporated by reference-see §60.17); or (vi) ASTM UOP539-97 (incorporated by reference-see §60.17).56 (5) The owner or operator shall inst all, operate and maintain fuel gas flow monitors according to the manufacturer's recommendations. For volumetri c flow meters, temperature and pressure monitors must be installed in conjunction with th e flow meter or in a representative location to correct the measured flow to standard conditions ( i.e. , 68 °F and 1 atmosphere). For mass flow meters, use gas compositions determined accordi ng to paragraph (d)(4) of this section to determine the average molecular weight of th e fuel gas and convert the mass flow to a volumetric flow at standard conditions ( i.e. , 68 °F and 1 atmosphere). The owner or operator shall conduct performance evaluations of each fuel gas flow monitor according to the requirements in §60.13 and Performance Specificati on 6 of Appendix B to part 60. Any of the following methods shall be used for conduc ting the relative accuracy evaluations: (i) EPA Method 2, 2A, 2B, 2C or 2D of Appendix A-2 to part 60; (ii) ASME MFC-3M-2004 (incorpo rated by reference-see §60.17); (iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008) (incorporated by re ference-see §60.17); (iv) ASME MFC-6M-1998 (Reaffirmed 2005) (incorporated by reference-see §60.17); (v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006) (incorporated by re ference-see §60.17); (vi) ASME MFC-11M-2006 (incorpor ated by reference-see §60.17); (vii) ASME MFC-14M-2003 (incorpor ated by reference-see §60.17); (viii) ASME MFC-18M-2001 (incor porated by reference-see §60.17); (ix) AGA Report No. 3, Part 1 (inc orporated by reference-see §60.17); (x) AGA Report No. 3, Part 2 (inc orporated by reference-see §60.17); (xi) AGA Report No. 11 (incorpo rated by reference-see §60.17); (xii) AGA Report No. 7 (incorporated by reference-see §60.17); and (xiii) API Manual of Petroleum Measurement Standards, Chapter 22, Section 2 (incorporated by reference-see §60.17). (6) The owner or operator shall in stall, operate and maintain eachfuel oil flow monitor according to the manufacturer's recommendations. The ow ner or operator shall conduct performance evaluations of each fuel oil flow monitor according to the requirements in §60.13 and Performance Specification 6 of Appendix B to part 60. Any of the following methods shall be used for conducting the relative accuracy evaluations: (i) Any one of the methods listed in paragraph (d)(5) of this section that are applicable to fuel oil ( i.e., “fluids”);57 (ii) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006) (incorporated by re ference-see §60.17); (iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006) (incorporated by re ference-see §60.17); (iv) ASME MFC-16-2007 (incorpora ted by reference-see §60.17); (v) ASME MFC-22-2007 (incorporate d by reference-see §60.17); or (vi) ISO 8316 (incorporate d by reference-see §60.17). (7) The owner or operator shall determine the highe r heating value of each fu el fed to the process heater using any of the applicab le methods included in paragra phs (d)(7)(i) through (ix) of this section. If a common fuel supply system provides fu el gas or fuel oil to several process heaters, the higher heating value of the fuel in each fuel supply system may be determined at a single location in the fuel supply system provided it is represen tative of the fuel fed to the affected process heater(s). The higher he ating value of each fuel fed to the process heater must be determined no less frequently than once per day ex cept as provided in paragr aph (d)(7)(x) of this section. (i) ASTM D240-02 (Reapproved 2007) (inc orporated by reference-see §60.17). (ii) ASTM D1826-94 (Reapproved 2003) (i ncorporated by reference-see §60.17). (iii) ASTM D1945-03 (Reapproved 2010) (i ncorporated by reference-see §60.17). (iv) ASTM D1946-90 (Reapproved 2006) (i ncorporated by reference-see §60.17). (v) ASTM D3588-98 (Reapproved 2003) (inc orporated by reference-see §60.17). (vi) ASTM D4809-06 (incorporat ed by reference-see §60.17). (vii) ASTM D4891-89 (Reapproved 2006) (i ncorporated by reference-see §60.17). (viii) GPA 2172-09 (incorporated by reference-see §60.17). (ix) Any of the methods specified in s ection 2.2.7 of Appendix D to part 75. (x) If the fuel oil supplied to the affected co-fir ed process heater originates from a single storage tank, the owner or operator may elect to use th e storage tank sampling method in section 2.2.4.2 of Appendix D to part 75 instead of daily sampli ng, except that the most recent value for heating content must be used. (8) The owner or operator of a pr ocess heater that has a rated heating capacity of less than 100 MMBtu and is equipped with combustion modification based t echnology to reduce NO X emissions ( i.e. , low-NO Xburners or ultra-low NO Xburners) may elect to comply with the monitoring requirements in paragr aphs (d)(1) through (7) of this section or, alternatively, the58 owner or operator of such a process heater sh all conduct biennial performance tests according to the requirements in §60.104a(i), establish a maximum excess O 2 operating limit or operating curve according to the requirements in§60.104a(i)(6) and co mply 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 different operating ranges), the owner or operator of the pro cess heater must also monitor fuel gas flow rate, fuel oil flow rate (as applicable) and heating value co ntent according to the methods provided in paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7) of this section, respectively. (e) Sulfur monitoring for assessi ng root cause analysis thre shold for affected flares . Except as described in paragraphs (e)(4) and (h) of this section, the owner or operator of an affected flare subject to §60.103a(c) through (e) shall determine the total reduced sulfur concentration for each gas line directed to the affected flare in accordance with either paragraph (e)(1), (e)(2) or (e)(3) of this section. Different options may be elected for different gas lines. If a monitoring system is in place that is capable of complying with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section, the owner or operator of a modified flare must comply with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section upon startup of the modified flare. If a monitoring system is not in place that is capable of complying with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section, the owner or operator of a modified flare must comply withthe requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section no la ter than November 11, 2015 or upon startup of the modified flare, whichever is later. (1) Total reduced sulfur monitoring requirements . The owner or operator shall install, operate, calibrate and maintain an instrument or instruments for continuously monitoring and recording the concentration of total reduced sulf ur in gas discharged to the flare. (i) The owner or operator shall install, operate and maintain each total reduced sulfur monitor according to Performance Specification 5 of Appe ndix B to part 60. The span value should be determined based on the maximum sulfur content of gas that can be discharged to the flare ( e.g. , roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 5,000 ppmv. A single dual range monitor may be us ed to comply with the requirements of this paragraph and paragraph (a)(2) of this section provided the applicable span specifications are met. (ii) The owner or operator shall conduct perfor mance evaluations of each total reduced sulfur monitor according to the requirements in §60. 13(c) and Performance Specification 5 of Appendix B to part 60. For flares that routinely have flow, the The owner or operator of each total reduced sulfur monitor shall use EPA Method 15A of Appendix A-5 to part 60 for conducting the relative accuracy evalua tions. The method ANSI/ASME PTC 19.10-1981 (incorporated by referen ce-see §60.17) is an acceptable al ternative to EPA Method 15A of Appendix A-5 to part 60. The a lternative relative accura cy procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for conducting the relative accuracy evaluations . For flares that do not receive routine flow, the alternative relative accuracy pr ocedures 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 accuracy59 evaluations , except that it is not necessary to include as much of the sampling probe or sampling line as practical. (iii) The owner or operator shall comply with th e applicable quality assurance procedures in 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 instrumentor instruments for continuously monito ring and recording the concentration of H 2 S in gas discharged to the flare accord ing to the requirements in paragraphs (e)(2)(i) through (iii) of this section and shall collect and analyze samples of the gas and calculate total sulfur co ncentrations as specified in paragrap hs (e)(2)(iv) thr ough (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 be determined based on the maximum sulfur content of gas that can be discharged to the flare ( e.g. , roughly 1.1 to 1.3 times the maximum anticipated sulfur co ncentration), 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 paragraph (a)(2) of this se ction provided the applicable span specifications are met. (ii) The owner or operator shall cond uct performance evaluations of each H 2 S monitor according to the requirements in §60.13(c) and Performanc e Specification 7 of Appendix B to part 60. For flares that routinely have flow, t T he owner or operator shall us e EPA Method 11, 15 or 15A of Appendix A-5 to part 60 for conducting th e relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 15A of Appendix A-5 to part 60. The alternative relative accuracy procedures described in secti on 16.0 of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for c onducting the relative accuracy evaluations . For flares that do not receive routine flow, 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 evaluations , except that it is not neces sary to include as much of the sampling probe or sampling line as practical. (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) In the first 10 operating days after the date the flare must begin to comply with §60.103a(c)(1), the owner or operator shall collec t representative daily samples of the gas discharged to the flare. The samples may be grab samples or integrated samples. The owner or operator shall take subsequent re presentative daily samples at least once per week or as required in paragraph (e)(2)(ix) of this section. (v) The owner or operator shall analyze each dail y sample for total sulf ur using either EPA Method 15A of Appendix A-5 to part 60, EPA Me thod 16A of Appendix A-6 to part 60, ASTM Method D4468-85 (Reapproved 2006) (incorporated by reference—see §60.17) or ASTM Method D5504-08 (incorporated by reference—see §60.17).60 (vi) The owner or operator shall deve lop 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 paragraph (e)(2)(vi)(A) of this section. (C) Determine the acceptable range for subse quent weekly samples based on the 95-percent confidence interval for the distribution of daily ratios based on the 10 individual daily ratios using Equation 11 14 of this section.

SDev Ratio AR Avg    262

. 2 (Eq. 11 14 )

Where: AR = Acceptable range of subsequent ratio 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 the 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 data ar e being collected to develop a 10-day average, the owner or operator shall estimate the total sulfur concentration using the measured total sulfur concentration measured for that day. (viii) For all days other than those during whic h data are being collected to develop a 10-day average, the owner or operator shall multiply the most recent 10-day average total sulfur-to-H 2 S ratio by the daily average H 2 S concentrations obtained using the monitor as required by paragraph (e)(2)(i) through (iii) of this sec tion 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 range based on data for the outlying weekly sample plus data collected over the following 9 operating days. (3) SO 2 monitoring requirements . The owner or operator shall install, operate, calibrate and maintain an instrument for continuously mon itoring and recording the concentration of SO 2 from a process heater or other fuel gas combustion de vice that is combusting gas representative of the fuel gas in the flare gas line acco rding to the requirements in paragraph (a)(1) of this section, determine the F factor of the fuel gas at least daily according to the requirements in paragraphs61 (d)(2) through (4) of this section, determine the hi gher heating value of the fuel gas at least daily according to the requirements in paragraph (d)(7) of this section and calc ulate the total sulfur content (as SO 2 ) in the fuel gas using Equation 12 15 of this section.

FG d SO FG HHV F C TS 2    (Eq. 12 15 )

Where:

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

C SO2 = Concentration of SO 2 in the exhaust gas, ppmv (drybasis 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 exempt from the requirements in paragraphs (e)(1) through (3) of this section. For each such flare, except as provided in paragraph (e)(4)(iv), engineering calculations shall be used to calculate the 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 su lfur content as described in paragraph (a)(3)(i) through (iv) of this section; and/or (B) Fuel gas streams that are inherently low in su lfur content for which the owner or operator has applied for an exemption from the H 2 S monitoring requirements as de scribed 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 para graph (g) of this section. (iii) Flares equipped withflare gas recovery systems designed, sized and operated to capture all flows except those resulting from startup, shutdo wn or malfunction, provided that for each such flare, the owner or operator complies with the m onitoring alternative in paragraph (g) of this section. (iv) Secondary flares that receiv e gas diverted from the primary fl are. In the event of a discharge from the secondary flare, the su lfur content measured by the sulf ur monitor on the primary flare should be used to calculate SO 2 emissions, regardless of wh ether or not the monitoring alternative in paragraph (g) of this section is selected for the secondary flare. (f) Flow monitoring for flares . Except as provided in paragraphs (f)(2) and (h ) of this section, the owner or operator of an affected flare subjec t to §60.103a(c) through (e) shall install, operate,62 calibrate and maintain, in accordance with the speci fications in paragraph (f )(1) of this section, a CPMS to measure and record the flow rate of gas discharged to the flare. If a flow monitor is not already in place, the owner or operator of a modified flare shall co mply with the requirements of this paragraph by no later than November 11, 2015 or upon startup of the modified flare, whichever is later. (1) The owner or operator shall install, calib rate, operate and mainta in each flow monitor according to the manufacturer's procedures and specifications and the following requirements. (i) Locate the monitor in a position that provides a representative measurement of the total gas flow rate. (ii) Use a flow sensor with a measurement sensitiv ity 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 ab le 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 compone nts of the monitor for physical and operational integr ity and all electrical connections for oxidation and galvanic corrosion if the flow monitor is not equipped with a redundant flow sensor. (v) Recalibrate the flow monitor in accordan ce with the manufacturer's procedures and specifications biennially (every two years) or at the frequenc y specified by the manufacturer. (2) Emergency flares, secondary flares and flar es equipped with flare gas recovery systems designed, sized and operated to capture all flow s except those resulting from startup, shutdown or malfunction are not required to install continuous flow monito rs; provided, however, that for any such flare, the owner or operator shall comp ly 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) th at can be classified as either an emergency flare, a secondary flare or a flare equipped with a flare gas recovery syst em designed, sized and operated to capture all flows except those result ing from startup, shutdown or malfunction may, as an alternative to the sulfur and flow monitori ng 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 th is section, a CPMS to measure and record the pressure in the flare gas header between the knock-out pot and wa ter seal and to measure and record the water seal liquid level. If the requi red monitoring systems are not al ready in place, the owner or operator of a modified flare shall comply with th e requirements of this paragraph by no later than November 11, 2015 or upon startup of the m odified flare, whichever is later.63 (1) Locate the pressure sensor(s) in a position that provides a re presentative measurement of the pressure and locate the liquid seal level monito r in a position that pr ovides a representative measurement of the water column height. (2) Minimize or eliminate pulsating pressure, vibr ation and internal and external corrosion. (3) Use a pressure sensor and level monitor wi th a minimum tolerance of 1.27 centimeters of water. (4) Using a manometer, check pressure sensor calibration quarterly. (5) Conduct calibration checks any time the pressure sensor exceeds the manufacturer's specified maximum operating pressure range orinstall a new pressure sensor. (6) In a cascaded flare system that employs multiple secondary flares, pressure and liquid level monitoring is required only on the firs t secondary flare in the system ( i.e. , the secondary flare with the lowest pressure release set point). (7) This alternative monitoring op tion may be elected only for flares with four or fewer pressure exceedances required to be reported under §60.108a(d )(5) (“reportable pressure exceedances”) in any 365 consecutive calendar days. Following the fi fth reportable pressure exceedance in a 365- day period, the owner or operator must comply w ith the sulfur and flowmonitoring requirements of paragraphs (e) and (f) of this section as soon as practical, but no later than 180 days after the fifth reportable pressure ex ceedance in a 365-day period. (h) Alternative monitoring for flares located in the BAAQMD or SCAQMD . An affected flare subject to this subpart located in the BAAQMD may elect to comply with the monitoring requirements in both BAAQMD Re gulation 12, Rule 11 and BAAQ MD Regulation 12, Rule 12 as an alternative to complying w ith the requirements of paragraphs (e) and (f) of this section. An affected flare subject to this subpart located in the SCAQMD may elect to comply with the monitoring requirements in SCAQMD Rule 1118 as an alternative to complying with the requirements of paragraphs (e ) and (f) of this section. (i) Excess emissions . For the purpose of reports required by §60.7(c), periods of excess emissions for fuel gas combustion devices subject to the emissions limitations in §60.102a(g) and flares subject to the concentration requirement in §60. 103a(h) are defined as specified in paragraphs (i)(1) through (5) of this sect ion. Determine a rolling 3-hour or a rolling daily average as the arithmetic average of the a pplicable 1-hour averages ( e.g. , a rolling 3-hour average is the arithmetic average of three contiguous 1-hour av erages). Determine a rolling 30-day or a rolling 365-day average as the arithmetic average of the applicable daily averages ( e.g. , a rolling 30-day average is the arithmetic average of 30 contiguous daily averages). (1) SO 2 or H 2 S limits for fuel gas combustion devices . (i) If the owner or operator of a fuel gas combustion device elects to comply with the SO 2 emission limits in §60.102a(g)(1)(i), each rolling 3-hour period during which the average concentration of SO 2 as measured by the SO 2 continuous monitoring system required under para graph (a)(1) of this section exceeds 20 ppmv,64 and each rolling 365-day period during wh ich 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 8 ppmv. (ii) If the owner or operator of a fuel gas combustion device elects to comply with the H 2 S concentration limits in §60.102a(g)(1)(ii), 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 sec tion exceeds 162 ppmv and each rolling 365-day period 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 paragr aph (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 peri od 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 requirement s of daily stain tube sampling in paragraph (b)(3)(iii) of this section, each day during which the daily concentration of H 2 S exceeds 162 ppmv. (3) Rolling 30-day average NOX limits for fuel gas combustion devices . Each rolling 30-day period during which the aver age concentration of NO Xas measured by the NO Xcontinuous monitoring system required under paragraph (c) or (d) of this section exceeds: (i) For a natural draft process heater, 40 ppmv and, if monitored according to §60.107a(d), 0.040 lb/MMBtu; (ii) For a forced draft process heater, 60 ppmvand, 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 limit determined by the Administrator under §60.102a(i). (4) Daily NOX limits for fuel gas combustion devices . Each day during which the concentration of NO Xas measured by the NO Xcontinuous monitoring system required under paragraph (d) of this section exceeds the dailyaverage emissions limit calculated using Equation 3 in §60.102a(g)(2)(iii)(B) or Equati on 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 system required under paragraph (c)(6) or65 (d)(8) of this section exceeds the O 2 operating limit or operating curve determined during the most recent biennial performance test. § 60.108a Recordkeeping and reporting requirements. (a) Each owner or operator subject to the emissi ons limitations in §60.102a shall comply with the notification, recordkeeping, and reporting 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 monitoring pr ovisions of §§60.105a, 60.106a and 60.107a with which the owner or operator intends 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 showi ng that the process heater meet s the definition of a co-fired process heater in §60.101a. Notifications requiredby this paragraph shall be submitted with the notification of in itial 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. (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 dete ction 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 exempti on 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) Records of discharges greater than 500 lb SO 2 in any 24-hour period from any affected flare, discharges greater than 500 lb SO 2 in excess of the allowable limits from a fuel gas combustion device or sulfur recovery plant and discharges to an affected flare in excess of 500,000 scf above baseline in any 24-hour period as required by §60.103a(c). If the monitoring alternative provided in §60.107a(g) is selected, the owner or operator sh all record any instance when the flare gas line pressure exceeds the water seal liquid depth, except for periods attributable to compressor staging that do not exceed the staging time speci fied in §60.103a(a)(3)(vii)(C). The following information shall be recorded no later than 45 days following the end of a discharge exceeding the thresholds: (i) A description of the discharge.66 (ii) The date and time the discharge was first identified and the durati on of the discharge. (iii) The measured or calculated cumulative quantity of gas discharged over the discharge duration. If the discharge duration exceeds 24 ho urs, record the discharge quantity for each 24- hour period. For a flare, record th e measured or calculated cumulative quantity of gas discharged to the flare over the discharge duration. If the discharge duration ex ceeds 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 flares, except for those complying with the alternative m onitoring requirements in §60.107a(g). (iv) For each discharge greater than 500 lb SO 2 in any 24-hour period from a flare, the measured total sulfur concentration or both the measured H 2 S concentration and the estimated total sulfur concentration in the fuel gas at a repr esentative location in the flare inlet. (v) For each discharge greater than 500 lb SO 2 in excess of the applicable short-term emissions limit in §60.102a(g)(1) from a fuel gas combustion de vice, either the measured concentration of H 2 S in the fuel gas or the measured concentration of SO 2 in the stream discharged to the atmosphere. Process knowledge can be used to make these estimates for fuel gas combustion devices, 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 allowable limits from a sulfur recovery plant, either the measured concentration of reduced sulfur or SO 2 discharged to the atmosphere. (vii) For each discharg e greater than 500 lb SO 2 in any 24-hour period fromany affected flare or discharge greater than 500 lb SO 2 in excess of the allowable 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, as sume 99-percent conversion of reduced sulfur or total sulfur to SO 2 . For 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. (ix) The root cause analysis and corrective action anal ysis conducted as re quired in §60.103a(d), including an identification of the affected faci lity, the date and duration of the discharge, a statement noting whether the discharge resulted from the same root cause(s) identified in a previous analysis and either a description of the recommende d corrective action(s) or an explanation of why corr ective action is not neces sary under §60.103a(e). (x) For any corrective ac tion analysis for which corrective ac tions 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 sc hedule for implementation, including proposed commencement and completion dates.67 (xi) For each discharge from any affected flare th at is the result of a pl anned startup or shutdown of a refinery process unit or an cillary equipment connected to the affected flare, a statement that a root cause analysis and corrective action anal ysis are not necessary because the owner or operator followed the flare management plan. (7) If the owner or operator elects to comply with §60.107a(e)(2) for a flare, records of the H 2 S and total sulfur analyses of each grab or integr ated sample, the calculated daily total sulfur-toH 2 S ratios, the calculated 10-day average total sulfur-to-H 2 S ratios and the 95-percent confidence intervals for each 10-day av erage 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 with a startup, shutdown, or malfunction of an affected facility or control system; and (4) A description of the action taken, if any. (5) The information described in paragraph (c)(6) of this section for all discharges listed in paragraph (c)(6) of this section. 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. Operations 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. (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.68 (b) In delegating implementation and enforcement authority of this subpart to a state, local or tribal agency, the approval auth orities contained in paragraphs (b)(1) through (4) of this section are retained by the Administrator of the U.S. EPA and are not transferred to the state, local or tribal agency. (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 un der §60.13(i). A “major change to monitoring” is defined in 40 CFR 63.90. (3) Approval of a major change to recordkeeping/reporting under §60.7(b) through (f). A “major change to recordkeeping/reportin g” is defined in 40 CFR 63.90. (4) Approval of an application for an alternative means of emission lim itation under §60.103a(j) of this subpart. Table 1 to Subpart Ja of Part 60—Molar Exhaust Volumes and Molar Heat Content of Fuel Gas Constituents

Constituent MEV a dscf/mol MHC b Btu/mol Methane (CH 4 ) 7.29 842 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

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

b MHC = molar heat content (h igher heating value basis), Bt u per gram-mole (Btu/g-mol).