## ELECTRONIC CODE OF FEDERAL REGULATIONS

e-CFR Data is curren t as of March 9, 2015

Title 40 → Chapter I → Subchapter C → Part 60 → Subpart Ja

Title 40: Protection of Environment PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES



## Subpart Ja—Standards of Performance for Petroleu m Refineries for Which Construction, Reconstruction, or Mo dification Commenced After May 14, 2007

Contents §60.100a Applicability, designation of affected facility, and reconstruction. §60.101a Definitions. §60.102a Emissions limitations. §60.103a Design, equipment, work practice or operational standards. §60.104a Performance tests. §60.105a Monitoring of emissions and operations for fluid catalytic cracking units (FCCU) and fluid coking units (FCU). §60.106a Monitoring of emissions and operations for sulfur recovery plants. §60.107a Monitoring of emissions and operations for fuel gas combustion devices and flares. §60.108a Recordkeeping and reporting requirements. §60.109a Delegation of authority. Table 1 to Subpart Ja of Part 60—Molar Exhaust Volumes and Molar Heat Content of Fuel Gas Constituents

S OURCE : 73 FR 35867, June 24, 2008, unless otherwise noted. Back to Top §60.100a Applicability, designation of affected facility, and reconstruction. (a) The provisions of this subpart apply to the following affected facilities in petroleum refineries: fluid catalytic cracking units (F CCU), fluid coking units (FCU), delayed coking units, fuel gas combustion devices (including process heaters), flares and sulfur recovery plants. The sulfur recovery plant need not be physically located within the boundaries of a petroleum refinery to be an affected facility, provided it processes gases produced within a petroleum refinery. (b) Except for flares and delayed coking units, the provisions of this subpart apply only to affected facilities under paragraph (a) of this section which commence construction, modification or reconstruction after May 14, 2007. For flares, the prov isions of this subpart apply only to flares which commence construction, modification or reconstruc tion 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, reconstruction or modification on the earliest of the following dates: Page 1 of 48 eCFR— Code of Federal Regulations

12/23/2015(1) May 14, 2007, for such activities that involv e a “delayed coking unit” defined as follows: one or more refinery process units in which high 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 wei ght petroleum derivatives are thermally cracked and petroleum coke is produced in a series of clos ed, batch system reactors. A delayed coking unit consists of the coke drum s and associated fractionator; (3) September 12, 2012, for such activities that involve a “delayed coking unit” as defined in §60.101a. (c) For all affected facilities other than flares , the provisions in §60.14 regarding modification apply. As provided in §60.14(f), the special provisi ons set forth under this subpart shall supersede the provisions in §60.14 with respect to flares. For t he 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 equipment, or a fuel gas system is physically connected to the flare ( e.g., for direct emergency relief or some form of continuous or intermittent venting). However, t he 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 re covery system or connections made to upgrade or enhance components of a flare gas recovery system ( e.g., addition of compressors or recycle lines). (iii) Connections made to replace or upgrade existing pr essure relief or safety valves, provided the new pressure relief or safety valve has a set point opening pressure no lower and an internal diameter no greater than the existing equipment being replaced or upgraded. (iv) Connections made for flare gas sulfur removal. (v) Connections made to install back-up (redundant) equi pment 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 c onnection from a refinery process unit to a new location in the same flare, provided the new pipe diameter is less than or equal to the diameter of the pipe/connection being replaced/moved. (vii) Connections that interconnect two or more flares. (2) A flare is physically altered to in crease the flow capacity of the flare. (d) For purposes of this subpart, under §60.15, the “fixed capital cost of the new components” includes the fixed capital cost of all depreciable components which are or will be replaced pursuant to all continuous programs of component replacement which are commenced within any 2-year period following the relevant applicability date specified in paragraph (b) of this section. [73 FR 35867, June 24, 2008, as amended at 77 FR 56464, Sep. 12, 2012] Back to Top §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. Page 2 of 48 eCFR— Code of Federal Regulations

12/23/2015Ancillary equipment means equipment used in conjunction with or that serve a refinery process unit. Ancillary equipment includes, but is not limited to, st orage tanks, product loading operations, wastewater treatment systems, steam- or electricity- producing units (including coke gasification units), pressure relief valves, pumps, samp ling vents and continuous 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 di scharges 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 flare's capac ity, 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 empl oys burners that are designed to be supplied by both gaseous and liquid fuels on a routine basis. Process heaters that have gas burners with emergency oil back-up burners are not considered co-fired process heaters.

Coke burn-off means the coke removed from the surface of the FCCU catalyst by combustion in the catalyst regenerator. The rate of coke burn-off is calculated by the formula specified in §60.104a.

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

Corrective action means the design, operation and maintenance changes that one takes consistent with good engineering practice to reduce or eliminate the likelihood 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 an affe cted flare 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 corrective action(s) is/are the best alternative(s), including, but not limited to, considerat ions of cost effectiveness, 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 coke is produced in a series of closed, batch system reactors. A delayed coking unit includes, but is not limited to, all of the coke drums associated with a single fractionator; the fractionator, including t he 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 drum blowdown recovery compressor system. Emergency flare means a flare that combusts gas exclusiv ely 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 rule, a flare cannot be categorized as an emergency flare unless it maintains a water seal.

Flare means a combustion device that uses an uncontrolled volume of air to burn gases. The flare includes the foundation, flare tip, structural support, bur ner, igniter, 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 flare either from a proce ss unit or a pressure relief valve from the fuel gas system, regardless of whether or not a flare gas recovery system draws gas from the flare gas header system. The flare gas header system includes piping inside the battery limit of a process unit if the purpose of the piping is to transport gas to a flare or knockout pot that is part of the flare. Page 3 of 48 eCFR— Code of Federal Regulations

12/23/2015Flare gas recovery systemmeans a system of one or more compressors, piping and the associated water seal, rupture disk or similar device used to divert gas from the flare and direct the gas to the fuel gas system or to a fuel gas combustion device. Flexicoking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuously produced and then gasified to produce a synthetic fuel gas. Fluid catalytic cracking unit means a refinery process unit in which petroleum derivatives are continuously charged and hydrocarbon molecules in the presence of a catalyst suspended in a fluidized bed are fractured into smaller molecules, or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, catalyst or contact material recovery equipment, and regenerator equipmentfor controlling air pollutant emissions and for heat recovery. When fluid catalyst cracking unit regenerator exhaust from two separate fluid catalytic cracking units share a common exhaust treatment (e.g., CO boiler or wet scrubber), the fluid catalytic cracking unit is a single affected facility. Fluid coking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuously produced in a fluidized bed system. The fluid coking unit includes the coking reactor, the coking burner, and equipment for controlling air pollutant emissi ons and for heat recovery on the fluid coking burner exhaust vent. Forced draft process heater means a process heater in whic h the combustion air is supplied under positive pressure produced by a fan at any location in the inlet air line prior to the point where the combustion air enters the process heater or air preheat. 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 petroleum refinery and which is combusted. Fuel gas includes natural gas when the natural gas is combined and combusted in any proportion with a gas generated at a refinery. Fuel gasdoes not include gases generated by catalytic cracking unit catalyst regenerators, coke calciners (used to make premium grade coke) and fluid coking burners, but does include gases from flexicoking unit gasifiers and other gasifiers. Fuel gas does not include vapors that are collected and combusted in a thermal oxidizer or flare installed to control emissions from wastewater treatment units other than those processing sour water, marine tank vessel loading operations 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 combusted 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 the fuel gas (e.g., amine scrubbers) that collects refinery fuel gas from one or more sources for treatment as nece ssary prior to combusting in process heaters or boilers. A fuel gas systemmay have an overpressure vent to a flare but the primary purpose for a fuel gas system is to provide fuel to the refinery. Natural draft process heater means any process heater in whic h the combustion air is supplied under ambient or negative pressure without the use of an inlet air (forced draft) fan. For the purposes of this subpart, a natural draft process heater is any process heater that is not a forced draft process heater, including induced draft systems. Non-emergency flare means any flare that is not an emergency flare as defined in this subpart. Oxidation control systemmeans 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 Page 4 of 48 eCFR— Code of Federal Regulations

12/23/2015reactor furnace or the first-stage catalytic reactor of the Claus sulfur recovery plant or converting the SO 2 to a sulfur product.

Petroleum means the crude oil removed from the earth and the oils derived from tar sands, shale, and coal. Petroleum refinery means any facility engaged in producing gasol ine, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of petroleum or through redistillation, cracking or reforming of unfin ished petroleum derivatives. A facility that produces only oil shale or tar sands-derived crude oil for fu rther processing at a petroleum refinery using only solvent extraction and/or distillation to recover diluent is not a petroleum refinery. Primary flare means the first flare in a cascaded flare system.

Process heater means an enclosed combustion device used to transfer heat indirectly to process stream materials (liquids, gases, or solids) or to a heat transfer material for use in a process unit instead of steam. Process upset gasmeans any gas generated by a petroleum refinery process unit or by ancillary equipment as a result of startup, shutdown, upset or malfunction. Purge gasmeans gas introduced between a flare's water seal and a flare's tip to prevent oxygen infiltration (backflow) into the flare tip. For flares with no water seals, the function of purge gas is performed by sweep gas ( i.e., flares without water seals do not use purge gas ). Reduced sulfur compoundsmeans hydrogen sulfide (H 2 S), carbonyl sulfide, and carbon disulfide. Reduction control systemmeans 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 the Claus sulfur recovery plant or converting the H 2 S to a sulfur product. Refinery process unit means any segment of the petroleum re finery in which a specific processing operation is conducted. Root cause analysismeans an assessment conducted through 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. 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 produc ed at a petroleum refinery. The sulfur recovery plant also includes sulfur pits used to store the recovered sulfur product, but it does not include secondary sulfur storage vessels or loading facilities downstream of the sulfur pits. For example, a Claus sulfur recovery plant includes: Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits and, if present, oxidation or reduction control systems or incinerator, thermal oxidizer or similar combustion device. Multiple sulfur recovery units are a single affected facility only when the units share the same source of sour gas. Sulfur recovery plantsthat receive source gas from completely segregated sour gas treatment systems are separate affected facilities. Page 5 of 48 eCFR— Code of Federal Regulations

12/23/2015Sweep 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 header. For flares with no water seals, sweep gas also performs the function of preventing oxygen infiltration (backflow) into the flare tip. [73 FR 35867, June 24, 2008, as amended at 77 FR 56464, Sep. 12, 2012; 78 FR 76756, Dec. 19, 2013] Back to Top §60.102a Emissions limitations. (a) Each owner or operator that is subject to the requirements of this subpart shall comply with the emissions limitations in paragraphs (b) through (i) of this section on and after the date on which the initial performance test, required by §60.8, is completed, but not later than 60 days after achieving the maximum production rate at which the affected facility will be operated or 180 days after initial startup, whichever comes first. (b) An owner or operator subject to the provisions of this subpart shall not discharge or cause the discharge into the atmosphere from any FCCU or FCU: (1) Particulate matter (PM) in excess of the limits in paragraphs (b)(1)(i), (ii), or (iii) of this section. (i) 1.0 kilogram per Megagram (kg/Mg)(1 pound (lb) per 1,000 lb) coke burn-off or, if a PM continuous emission monitoring system (CEMS) is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess ai r for each modified or reconstructed FCCU. (ii) 0.5 gram per kilogram (g/kg) coke burn-off (0 .5 lb PM/1,000 lb coke burn-off) or, if a PM CEMS is used, 0.020 gr/dscf corrected to 0 percent excess air for each newly constructed FCCU. (iii) 1.0 kg/Mg (1 lb/1,000 lb) coke burn-off; or if a PM CEMS is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air for each affected FCU. (2) Nitrogen oxides (NO X ) in excess of 80 parts per million by volume (ppmv), dry basis corrected to 0 percent excess air, on a 7-day rolling average basis. (3) Sulfur dioxide (SO 2 ) in excess of 50 ppmv dry basis corrected to 0 percent excess air, on a 7-day rolling average basis and 25 ppmv, dry basis corrected to 0 percent excess air, on a 365-day rolling average basis. (4) Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected to 0 percent excess air, on an hourly average basis. (c) The owner or operator of a FCCU or FCU thatuses a continuous parameter monitoring system (CPMS) according to §60.105a(b)(1) shall complywith the applicable control device parameter operating limit in paragraph (c)(1) or (2) of this section. (1) If the FCCU or FCU is controlled using an electrostatic precipitator: (i) The 3-hour rolling average total power and secondary current to the entire system must not fall below the level established during the most recent performance test; and (ii) The daily average exhaust coke burn-off rate must not exceed the level established during the most recent performance test. (2) If the FCCU or FCU is controlled using a wet scrubber: (i) The 3-hour rolling average pressure drop must not fall below the level established during the most recent performance test; and Page 6 of 48 eCFR— Code of Federal Regulations

12/23/2015(ii) The 3-hour rolling average liquid-to-gas ratio must not fall below the level established during the most recent performance test. (d) If an FCCU or FCU uses a continuous opacity monitoring system (COMS) according to the alternative monitoring option in §60.105a(e), the 3- hour rolling average opacity of emissions from the FCCU or FCU as measured by the COMS must not exceed the site-specific opacity limit established during the most recent performance test. (e) The owner or operator of a FCCU or FCU thatis exempted from the requirement for a CO continuous emissions monitoring system under §60.105a(h)(3) shall comply with the parameter operating limits in paragraph (e)(1) or (2) of this section. (1) For a FCCU or FCU with no post-combustion control device: (i) The hourly average temperature of the exhaust gases exiting the FCCU or FCU must not fall below the level established during the most recent performance test. (ii) The hourly average oxygen (O 2 ) concentration of the exhaust gases exiting the FCCU or FCU must not fall below the level established during the most recent performance test. (2) For a FCCU or FCU with a post-combustion control device: (i) The hourly average temperature of the exhaust gas vent stream exiting the control device must not fall below the level established during the most recent performance test. (ii) The hourly average O 2 concentration of the exhaust gas vent stream exiting the control device must not fall below the level established during the most recent performance test. (f) Except as provided in paragraph (f)(3), each owner or operator of an affected sulfur recovery plant shall comply with the applic able emission limits in paragraphs (f)(1) or (2) of this section. (1) For a sulfur recovery plant with a capacity greater than 20 long tons per day (LTD): (i) For a sulfur recovery plant with an oxidati on control system or a reduction control system followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere in excess of 250 ppm by volume (dry basis) of sulfur dioxide (SO 2 ) at zero percent excess air. If the sulfur recovery plant consis ts of multiple process trains or release points the owner or operator shall comply with the 250 ppmv li mit for each process train or release point or comply with a flow rate weighted average of 250 ppmv for all release points from the sulfur recovery plant; or (ii) For a sulfur recovery plant with a reducti on control system not followed by incineration, the owner or operator shall not discharge or cause t he discharge of any gases into the atmosphere in excess of 300 ppmv of reduced su lfur compounds and 10 ppmv of H 2 S, each calculated as ppmv SO 2 (dry basis) at 0-percent excess air; or (iii) For systems using oxygen enrichment, the owner or operator shall calculate the applicable emission limit using Equation 1 of this section:

View or download PDF

Where:

E LS = Emission rate of SO 2 for large sulfur recovery plant, ppmv; Page 7 of 48 eCFR— Code of Federal Regulations

12/23/2015k 1 = Constant factor for emission limit conversion: k 1 = 1 for converting to SO 2 limit and k 1 = 1.2 for converting to the reduced sulfur compounds limit; and

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

View or download PDF

Where:

E SS = Emission rate of SO 2 for small sulfur recovery plant, ppmv. (3) Periods of maintenance of the sulfur pit, during which the emission limits in paragraphs (f)(1) and (2) shall not apply, shall not exceed 240 hours per year. The owner or operator must document the time periods during which the sulfur pit vents were not controlled and measures taken to minimize emissions during these periods. Examples of t hese 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. (1) Except as provided in (g)(1)(iii) of this sect ion, for each fuel gas combustion device, the owner or operator shall comply with either the emission limitin paragraph (g)(1)(i) of this section or the fuel gas concentration limit in paragraph (g)(1)(ii) of this section. (i) The owner or operator shall not discharge or cause the discharge of any gases into the atmosphere that contain SO 2 in excess of 20 ppmv (dry basis, corrected to 0-percent excess air) determined hourly on a 3-hour rolling average basis and SO 2 in excess of 8 ppmv (dry basis, corrected to 0-percent excess air), determined daily on a 365 su ccessive 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 hourly on a 3-hour rolling average basis and H 2 S in excess of 60 ppmv determined daily on a 365 succe ssive calendar day rolling average basis. (iii) The combustion in a portable generator of fuel gas released as a result of tank degassing and/or cleaning is exempt from the emissions limits in 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 heating value basis, the owner or operator shall not discharge to the Page 8 of 48 eCFR— Code of Federal Regulations

12/23/2015atmosphere any emissions of NO Xin excess of the applicable limits in paragraphs (g)(2)(i) through (iv) of this section. (i) For each natural draft process heater, comply with the limit in either paragraph (g)(2)(i)(A) or (B) of this section. The owner or operator may complywith either limit at any time, provided that the appropriate parameters for each alternative are moni tored as specified in §60.107a; if fuel gas composition is not monitored as specified in §60.107a(d), the owner or operator must comply with the concentration limits in paragraph (g)(2)(i)(A) of this section. (A) 40 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30-day 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, comply with the limit in either paragraph (g)(2)(ii)(A) or (B) of this section. The owner or operator may complywith either limit at any time, provided that the appropriate parameters for each alternative are moni tored as specified in §60.107a; if fuel gas composition is not monitored as specified in §60.107a(d), the owner or operator must comply with the concentration limits in paragraph (g)(2)(ii)(A) of this section. (A) 60 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30-day rolling average basis; or (B) 0.060 lb/MMBtu higher heating value basis determined daily on a 30-day rolling average basis. (iii) For each co-fired natural draft process heater, comply with the limit in either paragraph (g)(2) (iii)(A) or (B) of this section. The owner or operator must choose one of the emissions limits with which to comply at all times: (A) 150 ppmv (dry basis, corrected to 0-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 3 of this section:

View or download PDF

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 flowrate of fuel oil, scf/day;

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

HHV oil = Daily average higher heating value of fuel oil fired to the process heater, MMBtu/scf. (iv) For each co-fired forced draft process heater, comply with the limit in either paragraph (g)(2) (iv)(A) or (B) of this section. The owner or operator must choose one of the emissions limits with which to comply at all times: (A) 150 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30 successive operating day rolling average basis; or Page 9 of 48 eCFR— Code of Federal Regulations

12/23/2015(B) The daily average emissions limit calcul ated using Equation 4 of this section:

View or download PDF

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;

Q oil = Daily average volumetric flowrate of fuel oil, scf/day;

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

HHV oil = Daily average higher heating value of fuel oil fired to the process heater, MMBtu/scf. (h) [Reserved] (i) For a process heater that meets any of the criteria of paragraphs (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 r equest shall be submitted and followed as described in paragraph (i)(3) of this section. (1) A process heater that meets one of the criteria in paragraphs (i)(1)(i) through (iv) of this section may apply for a site-specific NO Xemissions limit: (i) A modified or reconstructed process heater that lacks sufficient space to accommodate installation and proper operation of combustion modification-based technology (e.g., ultra-low NO X burners); 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 operating at reduced firi ng conditions for an extended period of time ( i.e., operating in turndown mode). The site-specific NO Xemissions limit will onl y apply for those operating conditions. (2) The request shall include sufficient and appropriate data, as determined by the Administrator, to allow the Administrator to confirm that the process heater is unable to comply with the applicable NO Xemissions limit in paragraph (g)(2) of this sect ion. At a minimum, the request shall contain the information described in paragraphs (i)(2)(i) through (iv) of this section. (i) The design and dimensions of the process heater, evaluation of available combustion modification-based technology, description of fuel gas and, if applicable, fuel oil characteristics, information regarding the combustion conditions (temperature, oxygen content, firing rates) and other information needed to demonstrate that the process heat er meets one of the four classes of process heaters listed in paragraph (i)(1) of this section. (ii) An explanation of how the data in paragraph (i)(2)(i) demonstrate that ultra-low NO Xburners, flue gas recirculation, control of excess air or other combustion modification-based technology (including combinations of thes e combustion modification-based technologies) cannot be used to meet the applicable emissions limit in paragraph (g)(2) of this section. Page 10 of 48 eCFR— Code of Federal Regulations

12/23/2015(iii) Results of a performance test conducted under representative conditions using the applicable methods specified in §60.104a(i) to demonstrate t he performance of the technology the owner or operator will use to minimize NO Xemissions. (iv) The means by which the owner or operator w ill document continuous compliance with the sitespecific 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 may request approval from the Administrator within 180 days after initial startup of the process heater for a NO Xemissions limit which shall apply specifically to that affected facility. (ii) The request must be submitted to the Admini strator 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 Standards , Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov. (4) The approval process for a request for a facility-specific NO Xemissions limit is described in paragraphs (i)(4)(i) through (iii) of this section. (i) Approval by the Administrator of a facility-specific NO Xemissions limit request will be based on the completeness, accuracy and reasonableness of the request. Factors that the EPA will consider in reviewing the request for approval include, but are not limited to, the following: (A) A demonstration that the process heater meets one of the four classes of process heaters outlined in paragraphs (i)(1) of this section; (B) A description of the low-NO Xburner designs and other combustion modifications considered for reducing NO Xemissions; (C) The combustion modification option selected; and (D) The operating conditions (firing 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. (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. [73 FR 35867, June 24, 2008, as amended at 77 FR 56466, Sep. 12, 2012] Back to Top §60.103a Design, equipment, work practice or operational standards. (a) Except as provided in paragraph (g) of this section, each owner or operator that operates a flare that is subject to this subpart shall dev elop 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 paragraphs (a)(1) through (7) of this section. Page 11 of 48 eCFR— Code of Federal Regulations

12/23/2015(1) A listing of all refinery process units, ancil lary equipment, and fuel gas systems connected to the flare for each affected flare. (2) An assessment of whether discharges to affe cted flares from these process units, ancillary equipment and fuel gas systems c an be minimized. The flare minimi zation 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 operating), natural gas offset credits (if applicable), technical feasibility, secondary environmental impacts and safety considerations for the selected minimization alternative(s) or a statement, wi th justifications, that flow reduction could not be achieved. Based upon the assessment, each owner or operator of an affected flare shall identify the minimization alternatives that it has implem ented by the due date of the flare management plan and shall include a schedule for the prompt implement ation of any selected measures that cannot reasonably be completed as of that date. (i) Elimination of process gas discharge to t he flare through process operating changes or gas recovery at the source. (ii) Reduction of the volume of process gas to the flare through process operating changes. (iii) Installation of a flare gas recovery system or, for facilities that are fuel gas rich, a flare gas recovery system and a co-generation unit or combined heat and power unit. (iv) Minimization of sweep gas flow rates and, for flares with water seals, purge gas flow rates. (3) A description of each affected flare containing the information in paragraphs (a)(3)(i) through (vii) of this section. (i) A general description of the flare, including the information 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). (D) Whether the flare is part of a cascaded flare system (and if so, whether the flare is primary or secondary). (E) Whether the flare serves as a backup to another flare. (F) Whether the flare is an emergency flare or a non-emergency flare. (G) Whether the flare is equipped with a flare gas recovery system. (ii) Description and simple process flow diagram showing the interconnection of the following components of the flare: flare tip (date installed, manufacturer, nominal 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); assistsystem; and ignition system. (iii) Flare design parameters, including the maximum vent gas flow rate; minimum sweep gas flow rate; minimum purge gas flow rate (if any); maximum supplemental gas flow rate; maximum pilot gas flow rate; and, if the flare is steam-assisted, minimum total steam rate. (iv) Description and simple process flow diagram showing all gas lines (including flare, purge (if applicable), sweep, supplemental and pilot gas) that ar e associated 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 Page 12 of 48 eCFR— Code of Federal Regulations

12/23/2015which 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 water seal monitor identified in paragraph (a)(3)(iv) of this section, provide a detailed descrip tion of the manufacturer's specifications, including, but not limited to, make, model, type, range, precis ion, 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 flows exc ept 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 sy stem, including number of compressors and capacity of each compressor. (B) A description of the monitoring parameters us ed to quantify the amount of flare gas recovered. (C) For systems with staged compressors, t he 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 compressor staging and a justification for why the maximum time period cannot be further reduced. (4) An evaluation of the baseline flow to the flare. The baseline flow to the flare must be determined after implementing the 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). Separate baseli ne flow rates may be established for different operating conditions provided that the management plan includes: (i) A primary baseline flow rate that will be used as the default baseline for all conditions except those specifically delineated in the plan; (ii) A description of each special condition for whic h an alternate baseline is established, including the rationale for each alternate baseline, the dailyflow for each alternate baseline and the expected duration of the special conditions for each alternate baseline; and (iii) Procedures to minimize discharges to the affected flare during each special condition described in paragraph (a)(4)(ii) of this section, unless procedures are already developed for these cases under paragraph (a)(5) through (7) of this section, as applicable. (5) Procedures to minimize or eliminate discharges to the flare during the planned startup and shutdown of the refinery process uni ts and ancillary equipment that are connected to the affected flare, together with a schedule for the prompt implemen tation of any procedures that cannot reasonably be implemented as of the date of the s ubmission of the flare management plan. (6) Procedures to reduce flaring in cases of fuel gas imbalance ( i.e., excess fuel gas for the refinery's energy needs), together with a schedule fo r the prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission of the flare management plan. Page 13 of 48 eCFR— Code of Federal Regulations

12/23/2015(7) For flares equipped with flare 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 the 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 paragraph (g) of this section, each owner 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 flare must develop and implement the flare management plan by no later than the date that the flare becomes an affected facility subject to this subpart, except for the selected minimization alternatives 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, which the owner or operator must implement in accordance with the schedule in the flare management plan. The owner or operator of a modified flare must develop and implement the flare management plan by no later than 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 should be updated periodically to account for changes in the operation of the flare, such as new connections to the flare or the installation of a flare gas recovery system, but the plan need be re-submitted to the Admi nistrator only if the owner or operator adds an alternative baseline flow rate, revises an existi ng baseline as described in paragraph (a)(4) of this section, installs a flare gas recovery system or is required to change flare designations and monitoring methods as described in §60.107a(g). The owner or operator must comply with the updated plan as submitted. (3) All versions of the plan submitted to the Admi nistrator shall also be submitted to the following address: U.S. Environmental Protection Agency, O ffice 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 Drive, Research Triangle Park, 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 sulf ur 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) through (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 excess of 14,160 standard cubic meters (m 3 ) (500,000 standard cubic feet (scf)) above the baseline, determined in paragraph (a)(4) of this section, in any 24-hour period; or (iii) If the monitoring alternative in §60.107a(g) is elected, any period when the flare gas line pressure exceeds the water seal liquid depth, exc ept for periods attributable to compressor staging that do not exceed the staging time specified in paragraph (a)(3)(vii)(C) of this section. (2) For a fuel gas combustion device, each ex ceedance 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 em issions limits had been met during one or more consecutive periods of excess emissions or any 24-hour per iod, 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 would have been emitted if the SO 2 or reduced sulfur concentration was equal to Page 14 of 48 eCFR— Code of Federal Regulations

12/23/2015the 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 root cause analysis and corrective action analysis must be completed as soon as possible, but no later than 45 days after a discharge meeting one of the conditions specified in paragraphs (c)(1) through (3) of this section. Special circumstances affecting the number of r oot cause analyses 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 specified in paragraphs (c)(1) through (3) of this section for 2 or more consec utive 24-hour periods, a single root cause analysis and corrective action analysis may be conducted. (2) If a single discharge from a flare triggers a root cause analysis based on more than one of the conditions specified in paragraphs (c)(1)(i) through (iii ) of this section, a single root cause analysis and corrective 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 equipment connected to the affected flare and the procedures in paragraph (a)(5) of this section were followed, a root cause analys is and corrective action analysis is not required; however, the discharge must be recorded as descri bed in §60.108a(c)(6) and reported as described in §60.108a(d)(5). (4) If both the primary and secondary flare in a cascaded flare system meet any of the conditions specified in paragraphs (c)(1)(i) through (iii) of this section in the same 24-hour period, a single root cause analysis and corrective ac tion analysis may be conducted. (5) Except as provided in paragraph (d)(4) of this section, if discharges occur that meet any of the conditions specified in paragraphs (c)(1) through (3) of this section for more than one affected facility in the same 24-hour period, initial root cause analyses shall be conducted for each affected facility. If the initial root 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 th is section, each owner or operator of a fuel gas combustion device, flare or sulfur recovery plant subject to this subpart shall implement the corrective action(s) identified in the corrective action analysis conducted pursuant to paragraph (d) of this section in accordance with the 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 analyses were required or as soon thereafter as practicable. If an owner or operator concludes that corrective action shoul d not be conducted, the owner or operator shall record and explain the basis for that conclusi on no later than 45 days following the discharge as specified in §60.108a(c)(6)(ix). (2) For corrective actions that cannot be fully implemented within 45 days following the discharge for which the root cause and corrective action analys es were required, the owner or operator shall develop an implementation schedule to complete the corrective action(s) as soon as practicable. (3) No later than 45 days following the discharge for which a root cause and corrective action analyses were required, the owner or operator shall record the corrective 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 requir ements of paragraphs (c) through (e) of this section by November 11, 2015 or at startup of the modified fl are, whichever is later. Modified flares that were not affected facilities subject to subpart J of this part prior to becoming affected facilities under Page 15 of 48 eCFR— Code of Federal Regulations

12/23/2015§60.100a shall 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 affected facilities subject to subpart J of this part prior to becoming affected facilities under §60.100a shall comply with the requirements of paragraph (h) of this section and the requirements of §60.107a(a)(2) by November 13, 2012 or at startup of the modified flare, whichever is later, except that modified flares that have ac cepted applicability of subpart J under a federal consent 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 requirements 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 wi th both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an alternative to complying with the requirements of paragraphs (a) through (e) of this section. An affected flare subject to this subpart located in the South Coast Air Quality Management District (SCAQMD) may elect to complywith SCAQMD Rule 1118 as an alternative to complying with the requirements of paragraphs (a) through (e) of this section. The owner or operator of an affected flare must notify the Administrator that the flare is in compliance with BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 or SCAQMD Rule 1118. The owner or operator of an affected flare shall also submit the existing flare management plan to the following address: U.S. Environmental Protection Agency, O ffice 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 Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov. (h) Each owner or operator shall not burn in anyaffected 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 t he 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 unit shall depressure each coke drum to 5 lb per square inch gauge (psig) or less prior to discharging the coke drum steam exhaust to the atmosphere. Until the coke drum pressure reaches 5 psig, the coke drum steam exhaust must be managed in an enclosed blowdown system and the uncondensed vapor mu st either be recovered (e.g., sent to the delayed coking unit fractionators) or vented to the f uel 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 the Administrator for a determination of equivalence for any means of emission limitation that achieves a reduction in emissions of a specifi ed 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 determi nation of equivalence shall be responsible for collecting and verifying test data to demonstrate t he equivalence of the alternative means of emission limitation. (ii) For each affected facility for which a deter mination of equivalence is requested, the emission reduction achieved by the design, equipment, work practice or operational requirements shall be demonstrated. (iii) For each affected facility for which a determination of equivalence is requested, the emission reduction achieved by the alternative means of emission limitation shall be demonstrated. (iv) Each owner or operator applying for a det ermination 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 emission reductions achi eved by the required work practice. Page 16 of 48 eCFR— Code of Federal Regulations

12/23/2015(v) The Administrator will compare the demonstrat ed 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 approval 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 approach to demonstrate the equivalence of any equivalent means of emission limitation. (4) Approval of the application for equivalence to the design, equipment, work practice or operational requirements of this section wi ll be evaluated by the following guidelines: (i) After a request for determination of equivalence is received, the Administrator will publish a notice in the F EDERAL R EGISTERand provide the opportunity for public hearing if the Administrator judges that the request may be approved. (ii) After notice and opportunity for public hearing, the Administrator will determine the equivalence of a means of emission limitation and will publish the determination in the F EDERAL R EGISTER

. (iii) Any equivalent means of emission limitations approved under this section shall constitute a required work practice, equipment, design or operat ional standard within the meaning of section 111 (h)(1) of the CAA. (5) Manufacturers of equipment used to control emissions may apply to the Administrator for determination of equivalence for any alternative means of emission limitation that achieves a reduction in emissions achieved by the equipment, design and operational requirements of this section. The Administrator will make an equivalence determination according to the provisions of paragraphs (j)(2) through (4) of this section. [77 FR 56467, Sep. 12, 2012] Back to Top §60.104a Performance tests. (a) The owner or operator shall conduct a performance test for each FCCU, FCU, sulfur recovery plant, flare and fuel gas combustion device to dem onstrate initial compliance with each applicable emissions limit in §60.102a according to the requirements of §60.8. The notification requirements of §60.8(d) apply to the initial performance test and to subsequent performance tests required by paragraph (b) of this section (or as required by the Administrator), but does not apply to performance tests conducted for the purpose of obtaining supplemental data because of continuous monitoring system breakdowns, repairs, calibrati on checks and zero and span adjustments. (b) The owner or operator of a FCCU or FCU t hat elects to monitor control device operating parameters according to the requirements in §60.105a( b), to use bag leak detectors according to the requirements in §60.105a(c), or to use COMS acco rding to the requirements in §60.105a(e) shall conduct a PM performance test at least once every 12 months and furnish the Administrator a written report of the results of each test. (c) In conducting the performance tests required by this subpart (or as requested by the Administrator), the owner or operator shall use the test methods in 40 CFR part 60, Appendices A-1 through A-8 or other methods as specified in this section, except as provided in §60.8(b). (d) The owner or operator shall determine compliance with the PM, NO X , SO 2 , and CO emissions limits in §60.102a(b) for FCCU and FCU using the following methods and procedures: Page 17 of 48 eCFR— Code of Federal Regulations

12/23/2015(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses. (2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate. (3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (i ncorporated 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 wi th a wet scrubber subject to the emissions limit in §63.102a(b)(1). (i) The PM performance test consists of 3 valid test runs; the duration of each test run must be no less than 60 minutes. (ii) The emissions rate of PM (E PM ) is computed for each run using Equation 5 of this section:

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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 st andard cubic feet per hour);

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

View or download PDF

Where:

R c= Coke burn-off rate, kg/hr (lb/hr);

Q r

= Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emissions control or energy recove ry system that burns au xiliary fuel, dry standard cubic meters per minute (dscm/min) [dry standard cubic feet per minute (dscf/min)];

Q a = Volumetric flow rate of air to FC CU regenerator or fluid coking burner, as determined from the unit's control room instrumentation, dscm/min (dscf/min);

Q oxy= Volumetric flow rate of O 2 enriched air to FCCU regenerator 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 regenerator or fluid coking burner ex haust, percent by volume (dry basis); Page 18 of 48 eCFR— Code of Federal Regulations

12/23/2015%CO = CO concentration in FCCU regenerator or fluid co king burner exhaust, percent by volume (dry basis);

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

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

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

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

K 3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-dscm- %) [0.00624 (lb-min)/(hr-dscf-%)]. (iv) During the performance test, the volumetric flow rate of exhaust gas from catalyst regenerator (Q r ) before any emission control or energy recovery sys tem that burns auxiliary fuel is measured using Method 2 of appendix A-1 to part 60. (v) For subsequent calculations of coke burn-off ra tes or exhaust gas flow rates, the volumetric flow rate of Q r is calculated using average exhaust gas conc entrations as measured by the monitors required in §60.105a(b)(2), if applicable, using Equation 7 of this section:

View or download PDF

Where:

Q r

= Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emission control or energy recovery system that burns auxiliaryfuel, dscm/min (dscf/min);

Q a = Volumetric flow rate of air to FC CU regenerator or fluid coking burner, as determined from the unit's control room instrumentation, dscm/min (dscf/min);

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

%CO 2 = Carbon dioxide concentration in FCCU regenerator or fluid coking burner ex haust, percent by volume (dry basis); %CO = CO concentration FCCU regenerator or fluid coki ng 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 fluid coking burner exhaust, percent by volume (dry basis); and

%O oxy= O 2 concentration in O 2 enriched air stream inlet to the FCCU re generator or fluid co king 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,” (i ncorporated by reference—see §60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60. (6) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the concentration of NO Xcalculated as nitrogen dioxide (NO 2 ); the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60. Page 19 of 48 eCFR— Code of Federal Regulations

12/23/2015(7) Method 10, 10A, or 10B of appendix A-4 to part 60 for moisture content and for the concentration of CO. The sampling time for each run must be 60 minutes. (8) The owner or operator shall adjust PM, NO X , SO 2 and CO pollutant concentrations to 0-percent excess air or 0-percent O 2 using Equation 8 of this section:

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Where:

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

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

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

20.9 = O 2 concentration in air, percent; and

%O 2 = O 2 concentration measured on a dry basis, percent. (e) The owner or operator of a FCCU or FCU that is controlled by an electrostatic precipitator or wet scrubber and that is subject to control device operating parameter limits in §60.102a(c) shall establish the limits based on the performance test results according to the following procedures: (1) Reduce the parameter monitoring data to hourly averages for each test run; (2) Determine the hourly average operating limit for each required parameter as the average of the three test runs. (f) The owner or operator of an FCCU or FCU that uses cyclones to comply with the PM limit in §60.102a(b)(1) and elects to comply with the COMS alternative monitoring option in §60.105a(d) shall establish a site-specific opacity operating limit a ccording to the procedures in paragraphs (f)(1) through (3) of this section. (1) Collect COMS data every 10 seconds during the entire period of the PM performance test and reduce the data to 6-minute averages. (2) Determine and record the hourly average opacity from all the 6-minute averages. (3) Compute the site-specific limit using Equation 9 of this section:

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Where: Opacity limit = Maximum permissible 3-hour average opacity, pe rcent, or 10 percent, whichever is greater; Opacity st= Hourly average opacity measured du ring 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) and that is subject to control device operating parameter limits in §60.102a(c) shall establish the li mits based on the performance test results using the procedures in paragraphs (g)(1) and (2) of this section. Page 20 of 48 eCFR— Code of Federal Regulations

12/23/2015(1) Reduce the temperature and O 2 concentrations from the parameter monitoring systems to hourly averages for each test run. (2) Determine the operating limit for temperature and O 2 concentrations as the average of the average temperature and O 2 concentration for the three test runs. (h) The owner or operator shall determine compliance with the SO 2 and H 2 S emissions limits for sulfur recovery plants in §§60.102a(f)(1)(i), 60.102a(f)(1)(iii), 60.102a(f)(1)(iii), 60.102a(f)(2)(i), and 60.102a(f)(2)(iii) and the reduced sulfur compounds and H 2 S emissions limits for sulfur recovery plants in §60.102a(f)(1)(ii) and §60.102a(f)(2)(ii) using the following methods and procedures: (1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses. (2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate. (3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (i ncorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO 2 concentration. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60. (5) Method 15 or 15A of appendix A-5 to part 60 or Method 16 of appendix A-6 to part 60 to determine the reduced sulfur compounds and H 2 S concentrations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (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 samples taken over a minimum of 3 hours. (ii) The owner or operator shall calculate the average H 2 S concentration after correcting for moisture and O 2 as the arithmetic average of the H 2 S concentration for each sample during the run (ppmv, dry basis, corrected to 0 percent excess air). (iii) The owner or operator shall calculate the SO 2 equivalent for each run after correcting for moisture and O 2 as the arithmetic average of the SO 2 equivalent of reduced sulfur compounds for each sample during the run (ppmv, dry basis, corrected to 0 percent excess air). (iv) The owner or operator shall use Equation 8 of th is section to adjust pollutant concentrations to 0-percent O 2 or 0- percent excess air. (i) The owner or operator shall determine compliance with the SO 2 and NO Xemissions limits in §60.102a(g) for a fuel gas combustion device according to the following test methods and procedures: (1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses; (2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate; (3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (i ncorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60; (4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO 2 concentration. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60. Page 21 of 48 eCFR— Code of Federal Regulations

12/23/2015(i) The performance test consists of 3 valid test runs; the duration of each test run must be no less than 1 hour. (ii) If a single fuel gas combustion device having a common source of fuel gas is monitored as allowed under §60.107a(a)(1)(v), only one performance test is required. That is, performance tests are not required when a new affected fuel gas combus tion device is added to a common source of fuel gas that previously demonstrated compliance. (5) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the concentration of NO 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 results 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 fuel gas and fuel oil and conduct at least one of the test runs while the process heater is being supplied solely by fuel gas. (B) Each test will consist of three test runs. Calculate the NO Xconcentration for the performance test as the average of the NO Xconcentrations from each of the three test runs. If the NO X concentration for the performance test is less than or equal to the numerical 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 test run of a valid test. (D) Calculate the O 2 operating limit as the average O 2 concentration of the three test runs from a valid test. (ii) If an O 2 operating curve will be used: (A) Conduct a performance test following the methods provided in paragraphs (i)(1), (2), (3) and (5) of this section at a representative condition for each operating range for which different O 2 operating limits will be established. Different operating conditions may be defined as different firing rates (e.g., above 50 percent of rated heat capacity and at or below 50 percent of rated heat capacity) and/or, for co-fired process heaters, different fuel mixt ures (e.g., primarily gas fired, primarily oil fired, and equally co-fired, i.e., approximately 50 percent of the inputheating value is from fuel gas and approximately 50 percent of the inputheating 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 the three test runs. If the NO X concentration for the performance test is less than or equal to the numerical 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 Page 22 of 48 eCFR— Code of Federal Regulations

12/23/2015heat capacity). If O 2 operating limits are developed for co-f ired 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 by both fuel gas and f uel oil and conduct at least one of the test runs while the process heater is being supplied solely by fuel gas. (D) Determine the average O 2 concentration for each test run of a valid test. (E) Calculate the O 2 operating limit for each operating range as the average O 2 concentration of the three test runs from a valid test conducted at the representative conditions for that given operating range. (F) Identify the firing rates for which the differentoperating limits apply. If only two operating limits are established based on firing rates, the O 2 operating limits established when the process heater is firing at no less than 70 percent of the rated heat capacity must apply when the process heater is firing above 50 percent of the rated heat capacity and the O 2 operating limits established for turndown conditions must apply when the process heater is firing at 50 percent or less of the rated heat capacity. (G) Operating limits associated with each interval 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 operat ors must use the operating limits determined for a given interval based on the most recent performance test conducted for that interval. (7) The owner or operator of a process heater complying with a NO Xlimit in terms of lb/MMBtu as provided in §60.102a(g)(2)(i)(B), (g)(2)(ii)(B), (g)(2)(i ii)(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 cont ent 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 use Equation 8 of this section to adjust pollutant concentrations to 0-percent O 2 or 0- percent excess air. (j) The owner or operator shall deter mine compliance with the applicable H 2 S emissions limit in §60.102a(g)(1) for a fuel gas combustion device or the concentration requirement in §60.103a(h) for a flare according to the following test methods and procedures: (1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses; (2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate; (3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (i ncorporated by reference—see §60.17) is an acceptable alternative 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 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 owner or operator may demonstrate compliance based on the mixture used in the fuel gas combustion device or flare or for each individual fuel gas stream used in the fuel gas combustion device or flare. (i) For Method 11 of appendix A-5 to part 60, 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, Page 23 of 48 eCFR— Code of Federal Regulations

12/23/2015although fuel gases containing low concentrations of H 2 S may necessitate sampling for longer periods of time. (ii) For Method 15 of appendix A-5 to part 60, at least three injects over a 1-hour period constitutes a run. (iii) For Method 15A of appendix A-5 to part 60, a 1-hour sample constitutes a run. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60. (iv) If monitoring is conducted at a single point in a common source of fuel gas as allowed under §60.107a(a)(2)(iv), only one performance test is required. That is, performance tests are not required when a new affected fuel gas combustion device or fl are is added to a common source of fuel gas that previously demonstrated compliance. [73 FR 35867, June 24, 2008, as amended at 77 FR 56470, Sep. 12, 2012] Back to Top §60.105a Monitoring of emissions and operations for fluid catalytic cracking units (FCCU) and fluid coking units (FCU). (a) FCCU and FCU subject toPM emissions limit. Each owner or operator subject to the provisions of this subpart shall monitor each FC CU and FCU subject to the PM emissions limit in §60.102a(b)(1) according to the requirements in paragraph (b), (c), (d), or (e) of this section. (b) Control device operating parameters. Each owner or operator of a FCCU or FCU subject to the PM per coke burn-off emissions limit in §60.102a(b)(1) that uses a control device other than fabric filter or cyclone shall comply with the requirements in paragraphs (b)(1) and (2) of this section. (1) The owner or operator shall install, operate and maintain continuous parameter monitor systems (CPMS) to measure and record operating par ameters 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 precip itator, the owner or operator shall use CPMS to measure and record the hourly average total power input and secondary voltage to the entire system. (ii) For units controlled using a wet scrubber, t he owner or operator shall use CPMS to measure and record the hourly average pressure drop, liquid feed rate, and exhaust gas flow rate. As an alternative to a CPMS, the owner or operator must comply with the requirements in either paragraph (b)(1)(ii)(A) or (B) of this section. (A) As an alternative to pressure drop, the owner or operator of a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles must conduct a daily check of the air or water pressure to the spray nozzles and record the results of each check. (B) As an alternative to exhaust gas flow rate, the owner or operator shall comply with the approved alternative for monitoring exhaust gas flow rate in 40 CFR 63.1573(a) of the National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units. (iii) The owner or operator shall install, operate, and maintain each CPMS according to the manufacturer's specifications and requirements. (iv) The owner or operator shall determine and re cord the average coke burn-off rate and hours of operation for each FCCU or FCU using the procedures in §60.104a(d)(4)(iii). Page 24 of 48 eCFR— Code of Federal Regulations

12/23/2015(v) If you use a control device other than an electrosta tic precipitator, wet scrubber, fabric filter, or cyclone, you may request approval to monitor parameters other than those required in paragraph (b) (1) of this section by submitting an alternative monitoring plan to the Administrator. The request must include the information 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 co mply with the emission li mitations and an explanation of the criteria used to select the parameter(s). (B) A description of the methods and procedures that will be used to demonstrate that the parameter(s) can be used to determine whether the affe cted facility will continuously comply with the emission limitations and the schedule for this demonstration. The owner or operator must certify that an operating limit will be established for the monitor ed parameter(s) that represents the conditions in existence when the control device is being proper ly operated and maintained to meet the emission limitation. (C) The frequency and content of the recordkeeping, recording, and reporting, if monitoring and recording are not continuous. The owner or operator also must include the rationale for the proposed monitoring, recording, and reporting requirements. (D) Supporting calculations. (E) Averaging time for the alternative operating parameter. (2) For use in determining the coke burn-off rate for an FCCU or FCU, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring the concentrations of CO 2 , O 2 (dry basis), and if needed, CO in the exhaust gases prior to any control or energy recovery system that burns auxiliary fuels. (i) The owner or operator shall install, operate and maintain each monitor according to Performance Specifications 3 and 4 of Appendix B to part 60. (ii) The owner or operator shall conduc t performance evaluations of each CO 2 , O 2 and CO monitor according to the requirements in §60.13(c) and Performance Specifications 3 and 4 of Appendix B to part 60. The owner or operator shall use EPA Method 3 of Appendix A-3 to part 60 and EPA Method 10, 10A or 10B of Appendix A-4 to part 60 for conducting the relative accuracy evaluations. (iii) The owner or operator shall comply with the quality assurance requirements of procedure 1 of appendix F to part 60, including quarterly accuracy determinations for CO 2 and CO monitors, annual accuracy determinations for O 2 monitors, and daily calibration drift tests. (c) Bag leak detection systems. Each owner or operator shall install, operate, and maintain a bag leak detection system for each baghouse or similar fabric filter control device that is used to comply with the PM per coke burn-off emissions limit in §60.102a(b)(1) for an FCCU or FCU according to paragraph (c)(1) of this section; prepare and operate by a site-specific monitoring plan according to paragraph (c)(2) of this section; take action according to paragraph (c)(3) of this section; and record information according 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 certifi ed 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 pr ovide output of relative PM loadings. The owner or operator shall continuously record the output from the bag leak detection system using electronic or other means (e.g., using a strip chart recorder or a data logger). Page 25 of 48 eCFR— Code of Federal Regulations

12/23/2015(iii) The bag leak detection system must be equipped with an alarm system that will sound when the system detects an increase in relative particulate loading over the alarm set point established according to paragraph (c)(1)(iv) of this section, and the alarm must be located such that it can be heard by the appropriate plant personnel. (iv) In the initial adjustment of the bag leak detection system, the owner or operator must establish, at a minimum, the baseline output by adjusting the sensitivity (range) and the averaging period of the device, the alarm set points, and the alarm delay time. (v) Following initial adjustment, the owner or oper ator shall not adjust the averaging period, alarm set point, or alarm delay time without approval from the Administrator or delegated authority except as provided in paragraph (c)(1)(vi) of this section. (vi) Once per quarter, the owner or operator may adjust the sensitivity of the bag leak detection system to account for seasonal effects, including temperature and humidity, according to the procedures identified in the site-specific monitori ng plan required by paragraph (c)(2) of this section. (vii) The owner or operator shall install the bag leak detection sensor downstream of the baghouse and upstream of any wet scrubber. (viii) Where multiple detectors are required, the system's instrumentation and alarm may be shared among detectors. (2) The owner or operator shall develop and submitto the Administrator for approval a sitespecific monitoring plan for each baghouse and bag leak detection system. The owner or operator shall operate and maintain each baghouse and bag l eak detection system according to the sitespecific monitoring plan at all times. Each monito ring plan must describe the items in paragraphs (c)(2) (i) through (vii) of this section. (i) Installation of the bag leak detection system;(ii) Initial and periodic adjustment of the bag 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 au thority may allow owners and operators more than 3 hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the monitoring plan this specific condition as one that c ould lead to an alarm, adequately explains why it is not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstrates that the requested time will ensure alleviation of th is condition as expeditiously as practicable; and (vii) How the baghouse system will be operated and ma intained, 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 detection system, the owner or operator shall initiate procedures to determine the cause of every alarm within 1 hour of the alarm. Except as provided in paragraph (c)(2) (vi) of this section, the owner or operator shall alleviate the cause of the alarm within 3 hours of the alarm by taking whatever action(s) are necessary . Actions may include, but are not limited to the following: Page 26 of 48 eCFR— Code of Federal Regulations

12/23/2015(i) Inspecting the baghouse for air leaks, torn or broken bags or filter media, or any other condition that may cause an increase in particulate emissions; (ii) Sealing off defective bags or filter media; (iii) Replacing defective bags or filter media or otherwise repairing the control device; (iv) Sealing off a defective baghouse compartment; (v) Cleaning the bag leak detection system probe or otherwise repairing the bag leak detection system; or (vi) Shutting down the process producing the particulate emissions. (4) The owner or operator shall maintain records of the information specified in paragraphs (c)(4) (i) through (iii) of this secti on for each bag leak detection system. (i) Records of the bag leak detection system output; (ii) Records of bag leak detection system adj ustments, including the date and time of the adjustment, the initial bag leak detection system settings, and the final bag leak detection system settings; and (iii) The date and time of all bag leak detection system alarms, the time that procedures to determine the cause of the alarm were initiated, t he cause of the alarm, an explanation of the actions taken, the date and time the cause of the alarm was alleviated, and whether the alarm was alleviated within 3 hours of the alarm. (d) Continuous emissions monitoring systems (CEMS). An owner or operator subject to the PM concentration emission limit (in gr/d scf) in §60.102a(b)(1) for an FCCU or FCU shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration (0 percent excess air) of PM in the exhaust gases prio r to release to the atmosphere. The monitor must include an O 2 monitor for correcting the data for excess air. (1) The owner or operator shall install, operate, and maintain each PM monitor according to Performance Specification 11 of appendix B to part 60. The span value of this PM monitor is 0.08 gr/dscf PM. (2) The owner or operator shall conduct performanc e 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 conducting the relative accuracy evaluations. (3) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O 2 monitor must be selected between 10 and 25 percent, inclusive. (4) The owner or operator shall conduct performance evaluations of each O 2 monitor according to the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used fo r conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (5) The owner or operator shall comply with the quality assurance requirements of Procedure 2 of appendix B to part 60 for each PM CEMS and Procedure 1 of appendix F to part 60 for each O 2 monitor, including quarterly accuracy determi nations for each PM monitor, annual accuracy determinations for each O 2 monitor, and daily calibration drift tests. Page 27 of 48 eCFR— Code of Federal Regulations

12/23/2015(e) Alternative monitoring option for FCCU and FCU—COMS. Each owner or operator of an FCCU or FCU that uses cyclones to comply with the PM emission limit in §60.102a(b)(1) shall monitor the opacity of emissions according to the requirem ents in paragraphs (e)(1) through (3) of this section. (1) The owner or operator shall install, operate, and maintain an instrument for continuously monitoring and recording the opacity of emissions from the FCCU or the FCU exhaust vent. (2) The owner or operator shall install, operate, and maintain each COMS according to Performance Specification 1 of appendix B to part 60. The instrument shall be spanned at 20 to 60 percent opacity. (3) The owner or operator shall conduct performanc e evaluations of each COMS according to §60.13(c) and Performance Specification 1 of appendix B to part 60. (f) FCCU and FCU subject to NO X limit. Each owner or operator subject to the NO Xemissions limit in §60.102a(b)(2) for an FCCU or FCU shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration by volume (dry basis, 0 percent excess air) of NO Xemissions into the atmosphere. The monitor must include an O 2 monitor for correcting the data for excess air. (1) The owner or operator shall install, operate, and maintain each NO 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 conduct 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 Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60. (3) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O 2 monitor must be selected between 10 and 25 percent, inclusive. (4) The owner or operator shall conduct performance evaluations of each O 2 monitor according to the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used fo r conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (5) The owner or operator shall comply with the quality assurance requirements of Procedure 1 of appendix F to part 60 for each NO 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 shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concent ration by volume (dry basis, corrected to 0 percent excess air) of SO 2 emissions into the atmosphere. The monitor shall include an O 2 monitor for correcting the data for excess air. (1) The owner or operator shall install, operate, and maintain each SO 2 monitor according to Performance Specification 2 of appendix B to part 60. The span value of this SO 2 monitor is 200 ppmv SO 2

. (2) The owner or operator shall conduct performance evaluations of each SO 2 monitor according to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The owner Page 28 of 48 eCFR— Code of Federal Regulations

12/23/2015or operator shall use Methods 6, 6A, or 6C of appendix A-4 to part 60 for conducting the relative accuracy evaluations. The method ANSI / ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60. (3) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O 2 monitor must be selected between 10 and 25 percent, inclusive. (4) The owner or operator shall conduct performance evaluations of each O 2 monitor according to the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used fo r 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 recording the concent ration by volume (dry basis) of CO emissions into the atmosphere from each FCCU and FCU subject to the CO emissions limit in §60.102a(b)(4). (1) The owner or operator shall install, operat e, and maintain each CO monitor according to Performance Specification 4 or 4A of appendix B to part 60. The span value for this instrument is 1,000 ppm CO. (2) The owner or operator shall conduct performanc e evaluations of each CO monitor according to the requirements in §60.13(c) and Performance Specification 4 or 4A of appendix B to part 60. The owner or operator shall use Methods 10, 10A, or 10B of appendix A-4 to part 60 for conducting the relative accuracy evaluations. (3) A CO CEMS need not be installed if the owner or operator demonstrates that all hourly average CO emissions are and will remain less than 50 ppmv (dry basis) corrected to 0 percent excess air. The Administrator may revoke this exemption from monitoring upon a determination that CO emissions on an hourly average basis have exceeded 50 ppmv (dry basis) corrected to 0 percent excess air, in which case a CO CE MS shall be installed within 180 days. (i) The demonstration shall consist of continuously monitoring CO emissions for 30 days using an instrument that meets the requirements of Perform ance Specification 4 or 4A of appendix B to part 60. The span value shall be 100 ppm CO instead of 1,000 pp m, and the relative accuracy limit shall be 10 percent of the average CO emissions or 5 ppm CO, whichever is greater. For instruments that are identical to Method 10 of appendix A-4 to part 60 and employ the sample conditioning system of Method 10A of appendix A-4 to part 60, the alternative relative accuracy test procedure in section 10.1 of Performance Specification 2 of appendix B to part 60 may be used in place of the relative accuracy test. (ii) The owner or operator must submit the following information to the Administrator: (A) The measurement data specified in paragraph (h)(3)(i) of this section along with all other operating data known to affect CO emissions; and (B) Descriptions of the CPMS for exhaust gas temperature and O 2 monitor required in paragraph (h)(4) of this section and operating limits for thos e parameters to ensure combustion conditions remain similar to those that exist during the demonstration period. Page 29 of 48 eCFR— Code of Federal Regulations

12/23/2015(iii) The effective date of the exemption from installation and operation of a CO CEMS is the date of submission of the information and data required in paragraph (h)(3)(ii) of this section. (4) The owner or operator of a FCCU or FCU that is exempted from the requirement to install and operate a CO CEMS in paragraph (h)(3) of this section shall install, operate, calibrate, and maintain CPMS to measure and record the operating parameters in paragraph (h)(4)(i) or (ii) of this section. The owner or operator shall install, operate, and maintain each CPMS according to the manufacturer's specifications. (i) For a FCCU or FCU with no post-combustion control device, the temperature and O 2 concentration of the exhaust gas stream exiting the unit. (ii) For a FCCU or FCU with a post-combustion control device, the temperature and O 2 concentration of the exhaust gas stream exiting the control device. (i) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess emissions for a FCCU or FCU subject to the em issions limitations in §60.102a(b) are defined as specified in paragraphs (i)(1) through (6) of this section. Note: Determine all averages, except for opacity, as the arithmetic average of the applicabl e 1-hour averages, e.g., determine the rolling 3-hour average as the arithmetic average of three contiguous 1-hour averages. (1) If a CPMS is used according to §60.105a(b)(1 ), all 3-hour periods during which the average PM control device operating characteristics, as measured by the continuous monitoring systems under §60.105a(b)(1), fall below the levels established during the performance test. (2) If a PM CEMS is used according to §60.105a(d), all 7-day periods during which the average PM emission rate, as measured by the continuous PM monitoring system under §60.105a(d) exceeds 0.040 gr/dscf corrected to 0 percent excess air fo r a modified or reconstructed FCCU, 0.020 gr/dscf corrected to 0 percent excess air for a newly cons tructed FCCU, or 0.040 gr/dscf for an affected fluid coking unit. (3) If a COMS is used according to §60.105a(e) , all 3-hour periods during which the average opacity, as measured by the COMS under §60.105a(e) , exceeds the site-specific limit established during the most recent performance test. (4) All rolling 7-day periods during which the average concentration of NO Xas measured by the NO XCEMS under §60.105a(f) exceeds 80 ppmv for an affected FCCU or FCU. (5) All rolling 7-day periods during which the average concentration of SO 2 as measured by the SO 2 CEMS under §60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods during which the average concentration of SO 2 as measured by the SO 2 CEMS exceeds 25 ppmv. (6) All 1-hour periods during which the average CO concentration as measured by the CO continuous monitoring system under §1A60.105a(h) exceeds 500 ppmv or, if applicable, all 1-hour periods during which the average temperature and O 2 concentration as measured by the continuous monitoring systems under §60.105a(h)(4) fall below the operating limits established during the performance test. [73 FR 35867, June 24, 2008, as amended at 77 FR 56473, Sep. 12, 2012] Back to Top §60.106a Monitoring of emissions and operations for sulfur recovery plants. (a) The owner or operator of a sulfur recovery plant that is subject to the emissions limits in §60.102a(f)(1) or §60.102a(f)(2) shall: Page 30 of 48 eCFR— Code of Federal Regulations

12/23/2015(1) For sulfur recovery plants subject to the SO 2 emission limit in §60.102a(f)(1)(i) or §60.102a(f) (2)(i), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration (dry basis, zero percent excess air) of any SO 2 emissions into the atmosphere. The monitor shall include an oxygen monitor for correcting the data for excess air. (i) The span values for this monitor are two times the applicable SO 2 emission limit and between 10 and 25 percent O 2 , inclusive. (ii) The owner or operator shall install, operate, and maintain each SO 2 CEMS according to Performance Specification 2 of appendix B to part 60. (iii) The owner or operator shall conduct performance evaluations of each SO 2 monitor according to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or operator shall use Methods 6 or 6C of appendix A-4 to part 60 and Method 3 or 3A of appendix A-2 of part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 6. (2) For sulfur recovery plants that are subject to the reduced sulfur compound and H 2 S emission limit in §60.102a(f)(1)(ii) or §60.102a(f)(2)(ii), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of reduced sulfur, H 2 S, and O 2 emissions into the atmosphere. The reduced sulfur emissions shall be calculated as SO 2 (dry basis, zero percent excess air). (i) The span values for this monitor are two time s the applicable reduced sulfur emission limit, two times the H 2 S emission limit, and between 10 and 25 percent O 2 , inclusive. (ii) The owner or operator shall install, operate, and maintain each reduced sulfur CEMS according to Performance Specification 5 of appendix B to part 60. (iii) The owner or operator shall conduct performance evaluations of each reduced sulfur monitor according to the requirements in §60.13(c) and Performance Specification 5 of appendix B to part 60. The owner or operator shall use Methods 15 or 15A of appendix A-5 to part 60 for conducting the relative accuracy 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 install, operate, and maintain each H 2 S CEMS according to Performance Specification 7 of appendix B to part 60. (v) The owner or operator shall conduct performance evaluations of each reduced sulfur monitor according to the requirements in §60.13(c) and Performance Specification 5 of appendix B to part 60. The owner or operator shall use Methods 11, 15, or 15A of appendix A-5 to part 60 or Method 16 of appendix A-6 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60. (vi) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. (vii) The span value for the O 2 monitor must be selected between 10 and 25 percent, inclusive. (viii) The owner or operator shall condu ct 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 Page 31 of 48 eCFR— Code of Federal Regulations

12/23/2015Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (ix) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to part 60 for each monitor, includi ng annual accuracy determinations for each O 2 monitor, and daily calibration drift determinations. (3) In place of the reduced sulfur monitor required in paragraph (a)(2) of this section, the owner or operator shall install, calibrate, operate, and maintain an instrument using an air or O 2 dilution and oxidation system to convert any reduced sulfur to SO 2 for continuously monitoring and recording the concentration (dry basis, 0 percent excess air) of the total resultant SO 2 . The monitor must include an O 2 monitor for correcting the data for excess O 2

. (i) The span value for this monitor is two times the applicable SO 2 emission limit. (ii) The owner or operator shall conduc t performance evaluations of each SO 2 monitor according to the requirements in §60.13(c) and Performance Specification 5 of appendix B to part 60. The owner or operator shall use Methods 15 or 15A of appendix A-5 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60. (iii) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. (iv) The span value for the O 2 monitor must be selected between 10 and 25 percent, inclusive. (v) The owner or operator shall conduct performance evaluations for the O 2 monitor according to the requirements of §60.13(c) and Performance Specification 3 of appendix B to part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (vi) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to part 60 for each monitor, including quarterly accuracy determinations for each SO 2 monitor, annual accuracy determinations for each O 2 monitor, and daily calibration drift determinations. (b) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess emissions for sulfur recovery plants subject to the emissions limitations in §60.102a(f) are defined as specified in paragraphs (b)(1) through (3) of this section.

N OTE : Determine all averages as the arithmetic average of the applicable 1-hour averages, e.g., determine the rolling 12-hour aver age as the arithmeticaverage of 12 cont iguous 1-hou r averages. (1) All 12-hour periods during which the average concentration of SO 2 as measured by the SO 2 continuous monitoring system requi red under paragraph (a)(1) of this section exceeds the applicable emission limit (dry basis, zero percent excess air); or (2) All 12-hour periods during which the aver age concentration of reduced sulfur (as SO 2 ) as measured by the reduced sulfur continuous monito ring system required under paragraph (a)(2) of this section exceeds the applicable emission limit; or (3) All 12-hour periods during which the average concentration of H 2 S as measured by the H 2 S continuous monitoring system requi red under paragraph (a)(2) of this section exceeds the applicable emission limit (dry basis, 0 percent excess air). Page 32 of 48 eCFR— Code of Federal Regulations

12/23/2015Back to Top §60.107a Monitoring of emissions and operations for fuel gas combustion devices and flares. (a) Fuel gas combustion devices subject toSO 2 or H 2 S limit and flares subject toH 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 section. 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 that is subject to the H 2 S concentration requirement in §60.103a(h) shall comply with paragraph (a)(2) of this section. (1) The owner or operator of a fuel gas combusti on 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 recording the concentration (dry basis, 0-percent excess air) of SO 2 emissions into the atmosphere. The monitor must include an O 2 monitor for correcting the data for excess air. (i) The owner or operator shall install, operate, and maintain each SO 2 monitor according to Performance Specification 2 of appendix B to part 60. The span value for the SO 2 monitor is 50 ppm SO 2

. (ii) The owner or operator shall conduct performance evaluations for the SO 2 monitor according to the requirements of §60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60. Samples taken by Method 6 of appendix A-4 to part 60 shall be taken at a flow rate of approximately 2 liters/min for at leas t 30 minutes. The relative accuracy limit shall be 20 percent or 4 ppm, whichever is greater, and the ca libration drift limit shall be 5 percent of the established span value. (iii) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. The span value for the O 2 monitor must be selected between 10 and 25 percent, inclusive. (iv) The owner or operator shall 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 reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (v) The owner or operator shall comply with the applicable quality assurance procedures in appendix F to part 60, including quarterly accuracy determinations for SO 2 monitors, annual accuracy determinations for O 2 monitors, and daily calibration drift tests. (vi) Fuel gas combustion devices having a common source of fuel gas may be monitored at only one location (i.e., after one of the combustion devices), if monitoring at this location accurately represents the SO 2 emissions into the atmosphere from each of the combustion devices. (2) The owner or operator of a fuel gas combusti on device that elects to comply with the H 2 S concentration limits in §60.102a(g)(1)(ii) or a flare that is subject to the H 2 S concentration requirement in §60.103a(h) shall install, operate, calibrate and maintain an instrument for continuously monitoring and 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. Page 33 of 48 eCFR— Code of Federal Regulations

12/23/2015(i) The owner or operator shall install, operate and maintain each H 2 S monitor according to Performance Specification 7 of Appendix B to part 60. The span value for this instrument is 300 ppmv H 2 S. (ii) The owner or operator shall conduc t 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 conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60. (iii) The owner or operator shall comply with the applicable quality assurance procedures in appendix F to part 60 for each H 2 S monitor. (iv) Fuel gas combustion devices or flares having a common source of fuel gas may be monitored at only one location, if monitoring at this loca tion accurately represent s 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 section 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 instrument has a span (or dual span, if necessary) capable of accurately measuring concentrations 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, the concentration directly measured by the instrumentmust meet the numeric concentration in §60.103a (h). (vi) The owner or operator of modified flare that meets all three criteria in paragraphs (a)(2)(vi)(A) through (C) of this section shall comply with the requirements of paragraphs (a)(2)(i) through (v) of this section no later than November 11, 2015. The owner or operator shall comply with the approved alternative monitoring plan or plans pursuant to §60.13(i) until the flare is in compliance with requirements of paragraphs (a)(2)(i) through (v) of this section. (A) The flare was an affected facility subject to subpart J of this part prior to becoming an affected facility under §60.100a. (B) The owner or operator had an approved alternative 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 required to comply with paragraph (a)(1) or (2) of this section for fuel gas streams that are exempt under §§60.102a(g)(1)(iii) or 60.103a(h) or, for fuel gas streams combusted in a process heater, other fuel gas combustion device or flare that are inherently low in sulf ur content. Fuel gas streams meeting one of the requirements in paragraphs (a)(3)(i) through (iv) of th is section will be considered inherently low in sulfur content. (i) Pilot gas for heaters and flares. (ii) Fuel gas streams that meet a commercial-grade product specification for sulfur content of 30 ppmv or less. In the case of a liquefied petroleum gas (LPG) product specification in the pressurized liquid state, the gas phase sulfur content should be evaluated assuming complete vaporization of the LPG and sulfur containing-compounds at the product specification concentration. Page 34 of 48 eCFR— Code of Federal Regulations

12/23/2015(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 unit, isomerization unit, and HF alkylation process units. (iv) Other fuel gas streams that an owner or operator demonstrates are low-sulfur according to the procedures in paragraph (b) of this section. (4) If the composition of an exempt fuel gas stream changes, the owner or operator must follow the procedures in paragraph (b)(3) of this section. (b) Exemption from H 2 S monitoring requirements for low-sulfur fuel gas streams. The owner or operator of a fuel gas combustion device 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 paragraphs (a)(1) and (2) of this section until there are changes in operating conditions or stream composition. (1) The owner or operator shall submit to the Ad ministrator a written application for an exemption from monitoring. The application must contain the following information: (i) A description of the fuel gas stream/system to be considered, including submission of a portion of the appropriate piping diagrams indicating the boundaries of the fuel gas stream/system and the affected fuel gas combustion device(s) or flare(s) to be considered; (ii) A statement that there are no crossover or entry points for sour gas (high H 2 S content) to be introduced into the fuel gas stream/system (t his should be shown in the piping diagrams); (iii) An explanation of the conditions that ensure low amounts of sulfur in the fuel gas stream (i.e., control equipment or product s pecifications) at all times; (iv) The supporting test results from samp ling the requested fuel gas stream/system demonstrating that the sulfur content is less than 5 ppm H 2 S. Sampling data must include, at minimum, 2 weeks of daily monitoring (14 grab samples) for frequently operated fuel gas streams/systems; for infrequently operated fuel gas streams/systems, seven grab samples must be collected unless other additional information would support reduced sampling. The owner or operator shall use detector tubes (“length-of-stain tube” type measurement) following the “Gas Processors Association Standard 2377-86, Test for Hydrogen Sulf ide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,” 1986 Revision (incorporated by reference—see §60.17), with ranges 0-10/0-100 ppm (N = 10/1) to test the applicant fuel gas stream for H 2 S; and (v) A description of how the 2 weeks (or seven samples for infrequently operated fuel gas streams/systems) of monitoring results compares to the typical range of H 2 S concentration (fuel quality) expected for the fuel gas stream/system goi ng to the affected fuel gas combustion device or flare (e.g., the 2 weeks of daily detector tube re sults 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 follow the proc edures in paragraph (b)(3)(i), (b)(3)(ii), or (b)(3)(iii) of this section. (i) If the operation change results in a sulfur content that is still within the range of concentrations included in the original application, t he 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. Page 35 of 48 eCFR— Code of Federal Regulations

12/23/2015(ii) If the operation change results 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 paragraph (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 results in a sulfur content that is outside the range of concentrations included in the original application and the owner or oper ator chooses not to submit new information to support an exemption, the owner or operator must begin H 2 S monitoring using daily stain sampling to demonstrate compliance. The owner or operator mustbegin monitoring according to the requirements in paragraphs (a)(1) or (a)(2) of this section as soon as practicable, but in no case later than 180 days after the operation change. During daily stain tube sampling, a daily sample exceeding 162 ppmv is an exceedance of the 3-hour H 2 S concentration limit. The owner or operator of a fuel gas combustion device must also determine a ro lling 365-day average using the stain sampling results; an average H 2 S concentration of 5 ppmv must be used for days wi thin 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 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 according to the requirements in paragraphs (c)(1) through (5) of this section, except as provided in paragraph (c)(6) of this section. The monitor must include an O 2 monitor for correcting the data for excess air. (1) Except as provided in paragraph (c)(6) of this section, the owner or operator 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 conduct 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 Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60. (3) The owner or operator shall install, operate, and maintain each O 2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O 2 monitor must be selected between 10 and 25 percent, inclusive. (4) The owner or operator shall conduct performance evaluations of each O 2 monitor according to the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used fo r conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. (5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 of appendix F to part 60 for each NO 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 process heater that has a rated heating capacity of less than 100 MMBtu and is equipped with combustion modification-based technology to reduce NO Xemissions ( i.e., low-NO Xburners, ultra-low-NO Xburners) may elect to comply with the monitoring requirements in paragraphs (c)(1) through (5) of this section or, alternatively, the owner or operator of such a process heater shall conduct biennial performance tests accord ing 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 comply with the O 2 monitoring requirements in paragraphs (c)(3) through (5) of this section to Page 36 of 48 eCFR— Code of Federal Regulations

12/23/2015demonstrate 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 process heater must also monitor fuel gas flow rate, fuel oil flow rate (a s applicable) and heating value content 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 limit 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 valuebased limit in §60.102a(g)(2)(iii)(B) or (g)(2)(iv)(B) shall install, operate, calibrate and maintain an instrument for continuously monitoring and recordi ng the concentration (dry basis, 0-percent excess air) of NO Xemissions into the atmosphere according to the monitoring requirements in paragraph (d) (1) of this section; install, operate, calibrate and maintain an instrument for continuously 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 paragraph (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 paragraph (d)(8) of this section, the owner or operator shall install, operate and maintain each NO Xmonitor according to the requirements in paragraphs (c)(1) through (5) of this section. The monitor must include an O 2 monitor for correcting the data for excess air. (2) Except as provided in paragraph (d)(3) of this section, the owner or operator shall sample and analyze each fuel stream fed to the process heater using the methods and equations in section 12.3.2 of EPA Method 19 of Appendix A-7 to part 60 to determine the F factor on a dry basis. If a single fuel gas system 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 repres entative 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, ope rate 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 of this section. If a single fuel gas system provides fuel gas to several process heaters, the F factor may be determined at a single location in the fuel gas system provided it is representative of the fuel gas fed to the affected process heater(s).

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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. Page 37 of 48 eCFR— Code of Federal Regulations

12/23/2015(4) The owner or operator shall conduct performanc e evaluations of each compositional monitor according to the requirements in Performance Spec ification 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)(incorporated by reference-see §60.17); (iii) ASTM D1946-90 (Reapproved 2006)(incorporated by reference-see §60.17); (iv) ASTM D6420-99 (Reapproved 2004)(incorporated 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). (5) The owner or operator shall install, operate and maintain fuel gas flow monitors according to the manufacturer's recommendations. For volumetric flow meters, temperature and pressure monitors must be installed in conjunction wi th the 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 according to paragraph (d)(4) of this section to determine the average molecular weight of the fuel gas and convert the mass flow to a volumetric flow at standard conditions ( i.e., 68 °F and 1 atmosphere). The owner or operator shall conduct performance evaluations of each fuel gas flow monitor according to the require ments 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) EPA Method 2, 2A, 2B, 2C or 2D of Appendix A-2 to part 60; (ii) ASME MFC-3M-2004 (incorporated by reference-see §60.17); (iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008) (incorporated by reference-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 reference-see §60.17); (vi) ASME MFC-11M-2006 (incorporated by reference-see §60.17); (vii) ASME MFC-14M-2003 (incorporated by reference-see §60.17); (viii) ASME MFC-18M-2001 (incorporated by reference-see §60.17); (ix) AGA Report No. 3, Part 1 (incorporated by reference-see §60.17); (x) AGA Report No. 3, Part 2 (incorporated by reference-see §60.17); (xi) AGA Report No. 11 (incorporated by reference-see §60.17); (xii) AGA Report No. 7 (incorporated by reference-see §60.17); and (xiii) API Manual of Petroleum Measurement St andards, Chapter 22, Section 2 (incorporated by reference-see §60.17). (6) The owner or operator shall install, operate and maintain each fuel oil flow monitor according to the manufacturer's recommendations. The owner 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: Page 38 of 48 eCFR— Code of Federal Regulations

12/23/2015(i) Any one of the methods listed in paragraph (d)(5) of this section that are applicable to fuel oil ( i.e., “fluids”); (ii) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006) (incorporated by reference-see §60.17); (iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006) (incorporated by reference-see §60.17); (iv) ASME MFC-16-2007 (incorporated by reference-see §60.17); (v) ASME MFC-22-2007 (incorporated by reference-see §60.17); or (vi) ISO 8316 (incorporated by reference-see §60.17). (7) The owner or operator shall determine the higher heating value of each fuel fed to the process heater using any of the applicable methods included in paragraphs (d)(7)(i) through (ix) of this section. If a common fuel supply system provides fuel gas or fuel oil to several process heaters, the higher heating value of the fuel in each fuel supply system may be determined at a single location in the fuel supply system provided it is representative of the fuel fed to the affected process heater(s). The higher heating value of each fuel fed to the process heater must be determined no less frequently than once per day except as provided in paragraph (d)(7)(x) of this section. (i) ASTM D240-02 (Reapproved 2007) (incorporated by reference-see §60.17). (ii) ASTM D1826-94 (Reapproved 2003) (incorporated by reference-see §60.17). (iii) ASTM D1945-03 (Reapproved 2010) (inc orporated by reference-see §60.17). (iv) ASTM D1946-90 (Reapproved 2006) (incorporated by reference-see §60.17). (v) ASTM D3588-98 (Reapproved 2003) (i ncorporated by reference-see §60.17). (vi) ASTM D4809-06 (incorporated by reference-see §60.17). (vii) ASTM D4891-89 (Reapproved 2006) (inc orporated by reference-see §60.17). (viii) GPA 2172-09 (incorporated by reference-see §60.17). (ix) Any of the methods specified in section 2.2.7 of Appendix D to part 75. (x) If the fuel oil supplied to the affected co-fired process heater originates from a single storage tank, the owner or operator may elect to use the storage tank sampling method in section 2.2.4.2 of Appendix D to part 75 instead of daily sampling, exceptthat the most recent value for heating content must be used. (8) The owner or operator of a process heater that has a rated heating capacity of less than 100 MMBtu and is equipped with combustion modi fication based technology to reduce NO Xemissions ( i.e., low-NO Xburners or ultra-low NO Xburners) may elect to comply with the monitoring requirements in paragraphs (d)(1) through (7) of this section or, alternatively, the owner or operator of such a process heater shall conduct biennial performance tests accord ing 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 comply with the O 2 monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O 2 operating curve is used ( i.e., if different O 2 operating limits are established for different operating ranges), the owner or operator of the process heater must also monitor fuel gas flow rate, fuel oil flow rate (a s applicable) and heating value content 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 assessing root caus e analysis threshold 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 Page 39 of 48 eCFR— Code of Federal Regulations

12/23/2015line 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 comply ing 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 no later 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 for continuously monitoring and recording the concentration of total reduced sulfur 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 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 concentration), but may be no less than 5,000 ppmv. A single dual range monitor may be used to co mply 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 perform ance 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 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 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 section 16.0 of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for conducting the re lative accuracy evaluations. For flares that do not receive routine flow, the alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for conducting the relative accuracy evaluations, 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 the 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 instrument for continuously monitoring and recording the concentration of H 2 S in gas discharged to the flare according to the requirements in paragraphs (e)(2)(i) through (iii) of this section and shall collect and analyze samples of the gas and calc ulate total sulfur concentrations as specified in paragraphs (e)(2)(iv) through (ix) of this section. (i) The owner or operator shall install, operate and maintain each H 2 S monitor according to Performance Specification 7 of Appendix B to part 60. The span value should be determined based on the maximum sulfur content of gas that can be di scharged to the flare (e.g., roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 5,000 ppmv. A single dual range H 2 S monitor may be used to comply with the requirements of this paragraph and paragraph (a) (2) of this section provided the applicable span specifications are met. (ii) The owner or operator shall conduc t performance evaluations of each H 2 S monitor according to the requirements in §60.13(c) and Performance Specification 7 of Appendix B to part 60. For flares that routinely have flow, the owner or operator shall use EPA Method 11, 15 or 15A of Appendix A-5 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference—see §60.17) is an acc eptable alternative to EPA Method 15A of Appendix A-5 to part 60. The alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for conducting the relative Page 40 of 48 eCFR— Code of Federal Regulations

12/23/2015accuracy evaluations. For flares that do not receiv e routine flow, the alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for conducting the relative accuracy evaluations, 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 the applicable quality assurance procedures in Appendix F to part 60 for each H 2 S monitor. (iv) In the first 10 operating days after the date the flare must begin to comply with §60.103a(c)(1), the owner or operator shall collect 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 representative daily samples at l east once per week or as required in paragraph (e)(2)(ix) of this section. (v) The owner or operator shall analyze each daily sample for total sulfur using either EPA Method 15A of Appendix A-5 to part 60, EPA Method 16A of Appendix A-6 to part 60, ASTM Method D4468- 85 (Reapproved 2006) (incorporated by reference—see §60.17) or ASTM Method D5504-08 (incorporated by reference—see §60.17). (vi) The owner or operator shall develop a 10-day average total sulfur-to-H 2 S ratio and 95-percent confidence interval as follows: (A) Calculate the ratio of the total sulfur concentration to the H 2 S concentration for each day during which samples are collected. (B) Determine the 10-day average total sulfur-to-H 2 S ratio as the arithmetic average of the daily ratios calculated in paragraph (e)(2)(vi)(A) of this section. (C) Determine the acceptable range for subsequent weekly samples based on the 95-percent confidence interval for the distribution of daily ra tios based on the 10 individual daily ratios using Equation 11 of this section.

View or download PDF

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 to tal 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 sulf ur concentration using the measured total sulfur concentration measured for that day. (viii) For all days other than those during which 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 section to estimate total sulfur concentrations. (ix) If the total sulfur-to-H 2 S ratio for a subsequent weekly sample is outside the acceptable range for the most recent distribution of daily ratios , the owner or operator shall develop a new 10-day Page 41 of 48 eCFR— Code of Federal Regulations

12/23/2015average 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 monitoring and recording the concentration of SO 2 from a process heater or other fuel gas combustion device that is combusting gas representative of the fuel gas in the flare gas line according to the requireme nts in paragraph (a)(1) of this section, determine the F factor of the fuel gas at least daily according to the requirements in paragraphs (d)(2) through (4) of this section, determine the higher heating value of the fuel gas at least daily according to the requirements in paragraph (d)(7) of this section and calculate the total sulfur content (as SO 2 ) in the fuel gas using Equation 12 of this section.

View or download PDF

Where:

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

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

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

HHV FG = Higher heating value of the fuel gas, MMBtu/scf. (4) Exemptions from sulfur monitoring requirements. Flares identified in paragraphs (e)(4)(i) through (iv) of this section are exempt from the requirements in paragraphs (e)(1) through (3) of this section. For each such flare, except as provi ded in paragraph (e)(4)(iv), engineering calculations shall be used to calculate the SO 2 emissions in the event of a discharge that may trigger a root cause analysis under §60.103a(c)(1). (i) Flares that can only receive: (A) Fuel gas streams that are inherently low in sulfur content as described in paragraph (a)(3)(i) through (iv) of this section; and/or (B) Fuel gas streams that are inherently low in sulfur content for which the owner or operator has applied for an exemption from the H 2 S monitoring requirements as described in paragraph (b) of this section. (ii) Emergency flares, provided that for each such flare, the owner or operator complies with the monitoring alternative in paragraph (g) of this section. (iii) Flares equipped with flare gas recovery sys tems designed, sized and operated to capture all flows except those resulting from startup, shutdown or malfunction, provided that for each such flare, the owner or operator complies with the monitoring alternative in paragraph (g) of this section. (iv) Secondary flares that receive gas diverted from the primary flare. In the event of a discharge from the secondary flare, the sulfur content measur ed by the sulfur monitor on the primary flare should be used to calculate SO 2 emissions, regardless of whether or not the monitoring alternative in paragraph (g) of this section is selected for the secondary flare. (f) Flow monitoring for flares. Except as provided in paragraphs (f)(2) and (h) of this section, the owner or operator of an affected flare subject to §60.103a(c) through (e) shall install, operate, calibrate and maintain, in accordance with the specifications in paragraph (f)(1) of this section, a CPMS to measure and record the 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 s hall comply with the requirements of this paragraph by no later than November 11, 2015 or upon startup of the modified flare, whichever is later. Page 42 of 48 eCFR— Code of Federal Regulations

12/23/2015(1) The owner or operator shall install, calibrate, operate and maintain 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 able to record flow in standar d conditions (as defined in §60.2) over one-minute averages. (iv) At least quarterly, perform a visual inspection of all components of the monitor for physical and operational integrity 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 accordance with the manufacturer's procedures and specifications biennially (every two years) or at the frequency specified by the manufacturer. (2) Emergency flares, secondary flares and flares equipped with flare gas recovery systems designed, sized and operated to capture all flows exc ept those resulting from startup, shutdown or malfunction are not required to install continuous flowmonitors; provided, however, that for any such flare, the owner or operator shall comply with the monitoring alternative in paragraph (g) of this section. (g) Alternative monitoring for certai n flares equipped with water seals. The owner or operator of an affected flare subject to §60.103a(c) through (e) thatcan be classified as eit her an emergency flare, a secondary flare or a flare equipped with a flare gas recovery system designed, sized and operated to capture all flows except those resulting from startup, shutdown or malfunction may, as an alternative to the sulfur and flow monitoring requirements of paragr aphs (e) and (f) of this section, install, operate, calibrate and maintain, in accordance with the requirements in paragraphs (g)(1) through (7) of this section, a CPMS to measure and record the pressure in the flare gas header between the knock-out pot and water seal and to measure and record the water seal liquid level. If the required monitoring systems are not already in place, the owner or operator of a modified flare shall comply with the requirements of this paragraph by no later than November 11, 2015 or upon startup of the modified flare, whichever is later. (1) Locate the pressure sensor(s) in a position that provides a representative measurement of the pressure and locate the liquid seal level monitor in a position that provides a representative measurement of the water column height. (2) Minimize or eliminate pulsating pressure, vibration and internal and external corrosion. (3) Use a pressure sensor and level monitor with a minimum tolerance of 1.27 centimeters of water. (4) Using a manometer, check pres sure sensor calibration quarterly. (5) Conduct calibration checks any time the pressure sensor exceeds the manufacturer's specified maximum operating pressure range or install 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 first secondary flare in the system ( i.e., the secondary flare with the lowest pressure release set point). (7) This alternative monitoring option may be elected only for flares with four or fewer pressure exceedances required to be reported under §60.108a(d)(5) (“reportable pressure exceedances”) in Page 43 of 48 eCFR— Code of Federal Regulations

12/23/2015any 365 consecutive calendar days. Following the fifth reportable pressure exceedance in a 365-day period, the owner or operator must comply with the sulfur and flow monitoring requirements of paragraphs (e) and (f) of this section as soon as practical, but no later than 180 days after the fifth reportable pressure exceedance in a 365-day period. (h) Alternative monitoring for flares located in the BAAQMD or SCAQMD. An affected flare subject to this subpart located in the BAAQMD may elect to comply with the monitoring requirements in both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an alternative to complying with the requirements of paragraphs (e) and (f) of this section. An affected flare subject to 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 subjec t 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 section. Determine a rolling 3-hour or a rolling daily average as the arithmetic average of the applicable 1-hour averages (e.g., a rol ling 3-hour average is the arithmetic average of three contiguous 1-hour averages). Determine a rol ling 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 2or 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 paragraph (a)(1) of this section exceeds 20 ppmv, and each rolling 365-day period 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 8 ppmv. (ii) If the owner or operator of a fuel gas co mbustion device elects to comply with the H 2 S concentration limits in §60.102a(g)(1)(ii), each ro lling 3-hour period during which the average concentration of H 2 S as measured by the H 2 S continuous monitoring system required under paragraph (a)(2) of this section exceeds 162 ppmv 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 co mbustion device becomes subject to the requirements 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 and each rolling 365-day period during which the average concentration of H 2 S exceeds 60 ppmv. (2) H 2 S concentration limits for flares. (i) Each rolling 3-hour period during which the average concentration of H 2 S as measured by the H 2 S continuous monitoring system required under paragraph (a)(2) of this section exceeds 162 ppmv. (ii) If the owner or operator of a flare becomes subject to the requirements of daily stain tube sampling in paragraph (b)(3)(iii) of 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 average 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 ppmv and, if monitored according to §60.107a(d), 0.060 lb/MMBtu; and Page 44 of 48 eCFR— Code of Federal Regulations

12/23/2015(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 daily average emissions limit calculated using Equation 3 in §60.102a(g)(2)(iii)(B) or Equation 4 in §60.102a(g)(2)(iv)(B). (5) Daily O 2 limits for fuel gas combustion devices. Each day during which the concentration of O 2 as measured by the O 2 continuous monitoring system required under paragraph (c)(6) of this section exceeds the O 2 operating limit or operating curve determined during the most recent biennial performance test. [73 FR 35867, June 24, 2008, as amended at 77 FR 56473, Sep. 12, 2012] Back to Top §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 requirement s 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 prov isions 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 showing that the process heater meets the defin ition of a co-fired process heater in §60.101a. Notifications required by this paragraph shall be subm itted with the notification of initial startup required by §60.7(a)(3). (c) The owner or operator shall maintain the following records: (1) A copy of the flare management plan. (2) Records of information to document confor mance with bag leak detection system operation and maintenance requirements in §60.105a(c). (3) Records of bag leak detection system alarms and actions according to §60.105a(c). (4) For each FCCU and fluid coking unit subject 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 appl y for each fuel stream. If the owner or operator applies for the exemption described in §60.107a(a)(3)(iv) , the owner or operator must keep a copy of the application as well as the letter from the Administrator granting approval of the application. (6) 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 shall 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 specified 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: Page 45 of 48 eCFR— Code of Federal Regulations

12/23/2015(i) A description of the discharge. (ii) The date and time the discharge was first identified and the duration of the discharge. (iii) The measured or calculated cumulative quantity of gas discharged over the discharge duration. If the discharge duration exceeds 24 hours, record the discharge quantity for each 24-hour period. For a flare, record the measured or calculated cumulative quantity of gas discharged to the flare over the discharge duration. If the discharge duration exceeds 24 hours, record the quantity of gas discharged to the flare for each 24-hour period. E ngineering calculations are allowed for fuel gas combustion devices, but are not allowed for flares, except for those complying with the alternative monitoring 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 representative location in the flare inlet. (v) For each discharge greater than 500 lb SO 2 in excess of the applicable short-term emissions limit in §60.102a(g)(1) from a fuel gas combustion device, 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 esti mates 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 allow able limits from a sulfur recovery plant, either the measured concentration of reduced sulfur or SO 2 discharged to the atmosphere. (vii) For each discharge greater than 500 lb SO 2 in any 24-hour period from any affected flare or discharge greater than 500 lb SO 2 in excess of the allowable limits from a fuel gas combustion device or sulfur recovery plant, the cumulative quantity of H 2 S and SO 2 released into the atmosphere. For releases controlled by flares, assume 99-percent c onversion 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 tookto limit the emissions during the discharge. (ix) The root cause analysis and corrective acti on analysis conducted as required in §60.103a(d), including an identification of the affected facility, 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 recommended corrective action(s) or an explanation of why corrective action is not necessary under §60.103a(e). (x) For any corrective action analysis for which corrective actions are required in §60.103a(e), a description of the corrective action(s) completed within the first 45 days following the discharge and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates. (xi) For each discharge from any affected flare thatis the result of a planned startup or shutdown of a refinery process unit or ancillary equipment connect ed to the affected flare, a statement that a root cause analysis and corrective acti on analysis are not necessary bec ause 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 integrated sample, the calculated daily total sulfur-to-H 2 S ratios, the calculated 10-day average total sulfur-to-H 2 S ratios and the 95-percent confidence intervals for each 10-day average total sulfur-to-H 2 S ratio. Page 46 of 48 eCFR— Code of Federal Regulations

12/23/2015(d) Each owner or operator subject to this subpart shall submit an excess emissions report for all periods of excess emissions acco rding to the requirements of §60.7( c) except that the report shall contain the information specified in paragraphs (d)(1) through (7) of this section. (1) The date that the exceedance occurred; (2) An explanation of the exceedance; (3) Whether the exceedance was concurrent with a startup, shutdown, or malfunction of an affected facility or control system; and (4) A description of the action taken, if any. (5) The information described in paragraph (c)(6) of this section for all discharges listed in paragraph (c)(6) of this section. For a flare comp lying 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 the applicable emission limit. Operati ons of the control system and affected facility during periods of data unavailability are to be co mpared with operation of the control system and affected facility before and following the period of data unavailability. (7) A written statement, signed by a responsible official, certifying the accuracy and completeness of the information contained in the report. [73 FR 35867, June 24, 2008, as amended at 77 FR 56479, Sep. 12, 2012] Back to Top §60.109a Delegation of authority. (a) This subpart can be implemented and enforced by the U.S. EPA or a delegated authority such as a State, local, or tribal agency. You should contact your U.S. EPA Regional Office to find out if this subpart is delegated to a State, local, or tribal agency within your State. (b) In delegating implementation and enforcement authority of this subpart to a state, local or tribal agency, the approval authorities contained in paragraphs (b)(1) through (4) of this section are retained by the Administrator of the U.S. EPA and are not tr ansferred to the state, local or tribal agency. (1) Approval of a major change to test methods under §60.8(b). A “major change to test method” is defined in 40 CFR 63.90. (2) Approval of a major change to monitoring under §60.13(i). A “major change to monitoring” is defined in 40 CFR 63.90. (3) Approval of a major change to recordkeeping/ reporting under §60.7(b) through (f). A “major change to recordkeeping/reporting” is defined in 40 CFR 63.90. (4) Approval of an application for an alternative means of emission limitation under §60.103a(j) of this subpart. [73 FR 35867, June 24, 2008, as amended at 77 FR 56480, Sep. 12, 2012] Back to Top Page 47 of 48 eCFR— Code of Federal Regulations

12/23/2015For questions or comments regarding e-CFR editorial content, features, or design, email ecfr@nara.gov

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. 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

a MEV = 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 (higher heating value basis), Btu per gram-mole (Btu/g-mol). [77 FR 56480, Sep. 12, 2012] Back to Top Page 48 of 48 eCFR— Code of Federal Regulations

12/23/2015