ELECTRONIC CODE OF FEDERAL REGULATIONS

e-CFR Data is current 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 Petroleum Refineries for Which 

Construction, Reconstruction, or Modification 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

SOURCE: 73 FR 35867, June 24, 2008, unless otherwise noted. 

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§60.100a Applicability, designation of affected facility, and reconstruction.

(a) The provisions of this subpart apply to the following affected facilities in petroleum refineries: 

fluid catalytic cracking units (FCCU), fluid coking units (FCU), delayed coking units, fuel gas 

combustion devices (including 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 provisions of this subpart apply only to flares which 

commence construction, modification or reconstruction after June 24, 2008. For the purposes of this 

subpart, a modification to a flare commences when a project that includes any of the activities in 

paragraphs (c)(1) or (2) of this section is commenced. For delayed coking units, the provisions of this 

subpart apply to delayed coking units that commence construction, reconstruction or modification on 

the earliest of the following dates:

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(1) May 14, 2007, for such activities that involve 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 weight petroleum derivatives are thermally cracked and 

petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit 

consists of the coke drums 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 provisions set forth under this subpart shall supersede the 

provisions in §60.14 with respect to flares. For the purposes of this subpart, a modification to a flare 

occurs as provided in paragraphs (c)(1) or (2) of this section.

(1) Any new piping from a refinery process unit, 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, the connections described in paragraphs (c)(1)(i) through 

(vii) of this section are not considered modifications of a flare.

(i) Connections made to install monitoring systems to the flare.

(ii) Connections made to install a flare gas recovery system 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 pressure relief or safety valves, provided the 

new pressure relief or safety valve has a set point opening pressure no lower and an internal diameter 

no greater than the existing equipment being replaced or upgraded.

(iv) Connections made for flare gas sulfur removal.

(v) Connections made to install back-up (redundant) equipment associated with the flare (such as 

a back-up compressor) that does not increase the capacity of the flare.

(vi) Replacing piping or moving an existing connection from a refinery process unit to a new 

location in the same flare, provided the new pipe diameter is less than or equal to the diameter of the 

pipe/connection being replaced/moved.

(vii) Connections that interconnect two or more flares.

(2) A flare is physically altered to increase the flow capacity of the flare.

(d) For purposes of this subpart, under §60.15, the “fixed capital cost of the new components” 

includes the fixed capital cost of all depreciable components which are or will be replaced 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]

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§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.

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Ancillary equipment means equipment used in conjunction with or that serve a refinery process 

unit. Ancillary equipment includes, but is not limited to, storage tanks, product loading operations, 

wastewater treatment systems, steam- or electricity-producing units (including coke gasification units), 

pressure relief valves, pumps, sampling vents and continuous analyzer vents.

Cascaded flare system means a series of flares connected to one flare gas header system 

arranged with increasing pressure set points so that discharges will be initially directed to the first flare 

in the series (i.e., the primary flare). If the discharge pressure exceeds a set point at which the flow to 

the primary flare would exceed the primary flare's capacity, flow will be diverted to the second flare in 

the series. Similarly, flow would be diverted to a third (or fourth) flare if the pressure in the flare gas 

header system exceeds a threshold where the flow to the first two (or three) flares would exceed their 

capacities.

Co-fired process heater means a process heater that employs burners that 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 affected 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, considerations 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 the bottoms receiver and the overhead condenser; the 

coke drum cutting water and quench system, including the jet pump and coker quench water tank; and 

the coke drum blowdown recovery compressor system.

Emergency flare means a flare that combusts gas exclusively released as a result of malfunctions 

(and not startup, shutdown, routine operations or any other cause) on four or fewer occasions in a 

rolling 365-day period. 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, burner, 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 process 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.

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Flare gas recovery system means 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 equipment for controlling air pollutant emissions and for 

heat recovery. When fluid catalyst cracking unit regenerator exhaust from two separate fluid catalytic 

cracking units share a common exhaust treatment (e.g., CO boiler or wet scrubber), the fluid catalytic 

cracking unit is a single affected facility.

Fluid coking unit means a refinery process unit in which high molecular weight petroleum 

derivatives are thermally cracked and petroleum coke is continuously produced in a fluidized bed 

system. The fluid coking unit includes the coking reactor, the coking burner, and equipment for 

controlling air pollutant emissions and for heat recovery on the fluid coking burner exhaust vent.

Forced draft process heater means a process heater in which the combustion air is supplied 

under positive pressure produced by a fan at 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 gas does not include gases generated by catalytic cracking unit 

catalyst regenerators, coke calciners (used to make premium grade coke) and fluid coking burners, 

but does include gases from flexicoking unit gasifiers and other gasifiers. Fuel gas does not include 

vapors that are collected and combusted in a thermal oxidizer or flare installed to control emissions 

from 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, piping, knock-out pots, mix drums, and units 

used to remove sulfur contaminants from the fuel gas (e.g., amine scrubbers) that collects refinery fuel 

gas from one or more sources for treatment as necessary prior to combusting in process heaters or 

boilers. A fuel gas system may have an overpressure vent to a flare but the primary purpose for a fuel 

gas system is to provide fuel to the refinery.

Natural draft process heater means any process heater in which the combustion air is supplied 

under ambient or negative pressure without the use of an inlet air (forced draft) fan. For the purposes 

of this subpart, a natural draft process heater is any process heater that is not a forced draft process 

heater, including induced draft systems.

Non-emergency flare means any flare that is not an emergency flare as defined in this subpart.

Oxidation control system means an emission control system which reduces emissions from sulfur 

recovery plants by converting these emissions to sulfur dioxide (SO2) and recycling the SO2 to the 

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reactor furnace or the first-stage catalytic reactor of the Claus sulfur recovery plant or converting the 

SO2 to a sulfur product.

Petroleum means the crude oil removed from the earth and the oils derived from tar sands, shale, 

and coal.

Petroleum refinery means any facility engaged in producing gasoline, kerosene, distillate fuel oils, 

residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of petroleum or 

through redistillation, cracking or reforming of unfinished petroleum derivatives. A facility that produces 

only oil shale or tar sands-derived crude oil for further processing at a petroleum refinery using only 

solvent extraction and/or distillation to recover diluent is not a petroleum refinery.

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 gas means any gas generated by a petroleum refinery process unit or by ancillary 

equipment as a result of startup, shutdown, upset or malfunction.

Purge gas means gas introduced between a flare's water seal and a flare's tip to prevent oxygen 

infiltration (backflow) into the flare tip. For flares with no water seals, the function of purge gas is 

performed by sweep gas (i.e., flares without water seals do not use purge gas).

Reduced sulfur compounds means hydrogen sulfide (H2S), carbonyl sulfide, and carbon disulfide.

Reduction control system means an emission control system which reduces emissions from sulfur 

recovery plants by converting these emissions to H2S and either recycling the H2S to the reactor 

furnace or the first-stage catalytic reactor of the Claus sulfur recovery plant or converting the H2S to a 

sulfur product.

Refinery process unit means any segment of the petroleum refinery in which a specific processing 

operation is conducted.

Root cause analysis means an assessment conducted 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 H2S and/or SO2 from a 

common source of sour gas produced at a petroleum refinery. The sulfur recovery plant also includes 

sulfur pits used to store the recovered sulfur product, but it does not include secondary sulfur storage 

vessels or loading facilities downstream of the sulfur pits. For example, a Claus sulfur recovery plant 

includes: Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits and, if present, oxidation 

or reduction 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 plants that receive source gas from completely segregated sour gas treatment 

systems are separate affected facilities.

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Sweep gas means the gas introduced in a flare gas header system to maintain a constant flow of 

gas to prevent oxygen buildup in the flare 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]

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§60.102a Emissions limitations.

(a) Each owner or operator that is subject to the requirements of this subpart shall comply with the 

emissions limitations in paragraphs (b) through (i) of this section on and after the date on which the 

initial performance test, required by §60.8, is completed, but not later than 60 days after achieving the 

maximum production rate at which the affected facility will be operated or 180 days after initial startup, 

whichever comes first.

(b) An owner or operator subject to the provisions of this subpart shall not discharge or cause the 

discharge into the atmosphere from any FCCU or FCU:

(1) Particulate matter (PM) in excess of the limits in paragraphs (b)(1)(i), (ii), or (iii) of this section.

(i) 1.0 kilogram per Megagram (kg/Mg)(1 pound (lb) per 1,000 lb) coke burn-off or, if a PM 

continuous emission monitoring system (CEMS) is used, 0.040 grain per dry standard cubic feet 

(gr/dscf) corrected to 0 percent excess air for each modified or reconstructed FCCU.

(ii) 0.5 gram per kilogram (g/kg) coke burn-off (0.5 lb PM/1,000 lb coke burn-off) or, if a PM CEMS 

is used, 0.020 gr/dscf corrected to 0 percent excess air for each newly constructed FCCU.

(iii) 1.0 kg/Mg (1 lb/1,000 lb) coke burn-off; or if a PM CEMS is used, 0.040 grain per dry standard 

cubic feet (gr/dscf) corrected to 0 percent excess air for each affected FCU.

(2) Nitrogen oxides (NOX) 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 (SO2) in excess of 50 ppmv dry basis corrected to 0 percent excess air, on a 

7-day rolling average basis and 25 ppmv, dry basis corrected to 0 percent excess air, on a 365-day 

rolling average basis.

(4) Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected to 0 percent excess air, on 

an hourly average basis.

(c) The owner or operator of a FCCU or FCU that uses a continuous parameter monitoring system 

(CPMS) according to §60.105a(b)(1) shall comply with the applicable control device parameter 

operating limit in paragraph (c)(1) or (2) of this section.

(1) If the FCCU or FCU is controlled using an electrostatic precipitator:

(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

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(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 that is exempted from the requirement for a CO 

continuous emissions monitoring system under §60.105a(h)(3) shall comply with the parameter 

operating limits in paragraph (e)(1) or (2) of this section.

(1) For a FCCU or FCU with no post-combustion control device:

(i) The hourly average temperature of the exhaust gases exiting the FCCU or FCU must not fall 

below the level established during the most recent performance test.

(ii) The hourly average oxygen (O2) 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 O2 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 applicable 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 oxidation control system or a reduction control system 

followed by incineration, the owner or operator shall not discharge or cause the discharge of any 

gases into the atmosphere in excess of 250 ppm by volume (dry basis) of sulfur dioxide (SO2) 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 250 ppmv limit for each process train or release point or 

comply with a flow rate weighted average of 250 ppmv for all release points from the sulfur recovery 

plant; or

(ii) For a sulfur recovery plant with a reduction control system not followed by incineration, the 

owner or operator shall not discharge or cause the discharge of any gases into the atmosphere in 

excess of 300 ppmv of reduced sulfur compounds and 10 ppmv of H2S, each calculated as ppmv SO2

(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:

ELS = Emission rate of SO2 for large sulfur recovery plant, ppmv;

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k1 = Constant factor for emission limit conversion: k1 = 1 for converting to SO2 limit and k1 = 1.2 for converting to 

the reduced sulfur compounds limit; and

%O2 = O2 concentration to the SRP, percent by volume (dry basis).

(2) For a sulfur recovery plant with a capacity of 20 LTD or less:

(i) For a sulfur recovery plant with an oxidation control system or a reduction control system 

followed by incineration, the owner or operator shall not discharge or cause the discharge of any 

gases into the atmosphere in excess of 2,500 ppm by volume (dry basis) of SO2 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 the discharge of any gases into the atmosphere in 

excess of 3,000 ppm by volume of reduced sulfur compounds and 100 ppm by volume of hydrogen 

sulfide (H2S), each calculated as ppm SO2 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:

ESS = Emission rate of SO2 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 these measures include not adding fresh sulfur or 

shutting off vent fans.

(g) Each owner or operator of an affected fuel gas combustion device shall comply with the 

emissions limits in paragraphs (g)(1) and (2) of this section.

(1) Except as provided in (g)(1)(iii) of this section, for each fuel gas combustion device, the owner 

or operator shall comply with either the emission limit in paragraph (g)(1)(i) of this section or the fuel 

gas concentration limit in paragraph (g)(1)(ii) of this section.

(i) The owner or operator shall not discharge or cause the discharge of any gases into the 

atmosphere that contain SO2 in excess of 20 ppmv (dry basis, corrected to 0-percent excess air) 

determined hourly on a 3-hour rolling average basis and SO2 in excess of 8 ppmv (dry basis, corrected 

to 0-percent excess air), determined daily on a 365 successive calendar day rolling average basis; or

(ii) The owner or operator shall not burn in any fuel gas combustion device any fuel gas that 

contains H2S in excess of 162 ppmv determined hourly on a 3-hour rolling average basis and H2S in 

excess of 60 ppmv determined daily on a 365 successive calendar day rolling average basis.

(iii) The combustion in a portable generator of fuel gas released as a result of tank degassing 

and/or cleaning is exempt from the emissions limits in 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 

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atmosphere any emissions of NOX in 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 comply with either limit at any time, provided that the 

appropriate parameters for each alternative are monitored as specified in §60.107a; if fuel gas 

composition is not monitored as 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 comply with either limit at any time, provided that the 

appropriate parameters for each alternative are monitored as specified in §60.107a; if fuel gas 

composition is not monitored as 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 calculated using Equation 3 of this section:

View or download PDF

Where:

ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu (higher heating value basis);

Qgas = Daily average volumetric flow rate of fuel gas, standard cubic feet per day (scf/day);

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

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

HHVoil = 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

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(B) The daily average emissions limit calculated using Equation 4 of this section:

View or download PDF

Where:

ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu (higher heating value basis);

Qgas = Daily average volumetric flow rate of fuel gas, scf/day;

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

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

HHVoil = 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 NOX emissions limit 

which shall apply specifically to that affected facility. The request shall include information as 

described in paragraph (i)(2) of this section. The request 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 NOX emissions 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 NOX

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 firing conditions for an extended period of time (i.e.,

operating in turndown mode). The site-specific NOX emissions limit will only 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 

NOX emissions limit in paragraph (g)(2) of this section. 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 heater 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 NOX burners, 

flue gas recirculation, control of excess air or other combustion modification-based technology 

(including combinations of these combustion modification-based technologies) cannot be used to meet 

the applicable emissions limit in paragraph (g)(2) of this section.

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(iii) Results of a performance test conducted under representative conditions using the applicable 

methods specified in §60.104a(i) to demonstrate the performance of the technology the owner or 

operator will use to minimize NOX emissions.

(iv) The means by which the owner or operator will 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 NOX emissions limit which shall apply specifically to that affected 

facility.

(ii) The request must be submitted to the Administrator for approval. The owner or operator must 

comply with the request as submitted until it is approved.

(iii) The request shall also be submitted to the following address: U.S. Environmental Protection 

Agency, Office of Air Quality Planning and 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 NOX emissions limit is described in 

paragraphs (i)(4)(i) through (iii) of this section.

(i) Approval by the Administrator of a facility-specific NOX emissions 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-NOX burner designs and other combustion modifications considered 

for reducing NOX emissions;

(C) The combustion modification option selected; and

(D) The operating conditions (firing rate, heater box temperature and excess oxygen 

concentration) at which the NOX emission level was established.

(ii) If the request is approved by the Administrator, a facility-specific NOX emissions limit will be 

established at the NOX emission 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 develop and implement a written flare management plan no 

later than the date specified in paragraph (b) of this section. The flare management plan must include 

the information described in paragraphs (a)(1) through (7) of this section.

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(1) A listing of all refinery process units, ancillary equipment, and fuel gas systems connected to 

the flare for each affected flare.

(2) An assessment of whether discharges to affected flares from these process units, ancillary 

equipment and fuel gas systems can be minimized. The flare minimization assessment must (at a 

minimum) consider the items in paragraphs (a)(2)(i) through (iv) of this section. The assessment must 

provide clear rationale in terms of costs (capital and annual operating), natural gas offset credits (if 

applicable), technical feasibility, secondary environmental impacts and safety considerations for the 

selected minimization alternative(s) or a statement, with justifications, that flow reduction could not be 

achieved. Based upon the assessment, each owner or operator of an affected flare shall identify the 

minimization alternatives that it has implemented by the due date of the flare management plan and 

shall include a schedule for the prompt implementation of any selected measures that cannot 

reasonably be completed as of that date.

(i) Elimination of process gas discharge to the 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); assist system; and ignition system.

(iii) Flare design parameters, including the maximum vent gas flow rate; minimum sweep gas flow 

rate; minimum purge gas flow rate (if any); maximum supplemental gas flow rate; maximum pilot gas 

flow rate; 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 are associated with the flare. For purge, sweep, 

supplemental and pilot gas, identify the type of gas used. Designate which lines are exempt from 

sulfur, H2S or flow monitoring and why (e.g., natural gas, inherently low sulfur, pilot gas). Designate 

eCFR —Code of Federal Regulations Page 12 of 48

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which lines are monitored and identify on the process flow diagram the location and type of each 

monitor.

(v) For each flow rate, H2S, sulfur content, pressure or water seal monitor identified in paragraph 

(a)(3)(iv) of this section, provide a detailed description of the manufacturer's specifications, including, 

but not limited to, make, model, type, range, precision, accuracy, calibration, maintenance and quality 

assurance procedures.

(vi) For emergency flares, secondary flares and flares equipped with a flare gas recovery system 

designed, sized and operated to capture all flows except those resulting from startup, shutdown or 

malfunction:

(A) Description of the water seal, including the operating range for the liquid level.

(B) Designation of the monitoring option elected (flow and sulfur monitoring or pressure and water 

seal liquid level monitoring).

(vii) For flares equipped with a flare gas recovery system:

(A) A description of the flare gas recovery system, including number of compressors and capacity 

of each compressor.

(B) A description of the monitoring parameters used to quantify the amount of flare gas recovered.

(C) For systems with staged compressors, the maximum time period required to begin gas 

recovery with the secondary compressor(s), the monitoring parameters and procedures used to 

minimize the duration of releases 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 baseline 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 which an alternate baseline is established, including 

the rationale for each alternate baseline, the daily flow 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 units and ancillary equipment that are connected to the affected flare, 

together with a schedule for the prompt implementation of any procedures that cannot reasonably be 

implemented as of the date of the submission 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 for the prompt implementation of any procedures 

that cannot reasonably be implemented as of the date of the submission of the flare management 

plan.

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(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 constructed 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 Administrator only if the owner or operator adds an 

alternative baseline flow rate, revises an existing 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 Administrator 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.

(c) Except as provided in paragraphs (f) and (g) of this section, each owner or operator that 

operates a fuel gas combustion device, flare or sulfur recovery plant subject to this subpart shall 

conduct a root cause analysis and a corrective action analysis for each of the conditions specified in 

paragraphs (c)(1) through (3) of this section.

(1) For a flare:

(i) Any time the SO2 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 (m3

) (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, except 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 exceedance of an applicable short-term emissions 

limit in §60.102a(g)(1) if the SO2 discharge to the atmosphere is 227 kg (500 lb) greater than the 

amount that would have been emitted if the emissions limits had been met during one or more 

consecutive periods of excess emissions or any 24-hour period, whichever is shorter.

(3) For a sulfur recovery plant, each time the SO2 emissions are more than 227 kg (500 lb) greater 

than the amount that would have been emitted if the SO2 or reduced sulfur concentration was equal to 

eCFR —Code of Federal Regulations Page 14 of 48

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the applicable emissions limit in §60.102a(f)(1) or (2) during one or more consecutive periods of 

excess emissions or any 24-hour period, whichever is shorter.

(d) Except as provided in paragraphs (f) and (g) of this section, a 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 root 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 consecutive 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 analysis and corrective action analysis is not required; 

however, the discharge must be recorded as described in §60.108a(c)(6) and reported as described in 

§60.108a(d)(5).

(4) If both the primary and secondary flare in a 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 action analysis may be conducted.

(5) Except as provided in paragraph (d)(4) of this section, if discharges occur that meet any of the 

conditions specified in paragraphs (c)(1) through (3) of this section for more than one affected facility 

in the same 24-hour period, initial root cause analyses shall be conducted for each affected facility. If 

the initial root cause analyses indicate that the discharges have the same root cause(s), the initial root 

cause analyses can be recorded as a single root cause analysis and a single corrective action 

analysis may be conducted.

(e) Except as provided in paragraphs (f) and (g) of this section, each owner or operator of a fuel 

gas combustion device, flare or sulfur recovery 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 should not be conducted, the owner or operator shall 

record and explain the basis for that conclusion no later than 45 days following the discharge as 

specified in §60.108a(c)(6)(ix).

(2) For corrective actions that cannot be fully implemented within 45 days following the discharge 

for which the root cause and corrective action analyses 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 requirements of paragraphs (c) through (e) of this section 

by November 11, 2015 or at startup of the modified flare, whichever is later. Modified flares that were 

not affected facilities subject to subpart J of this part prior to becoming affected facilities under 

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§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 accepted 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 with both BAAQMD Regulation 12, Rule 11 and BAAQMD 

Regulation 12, Rule 12 as an alternative to complying with the requirements of paragraphs (a) through 

(e) of this section. An affected flare subject to this subpart located in the South Coast Air Quality 

Management District (SCAQMD) may elect to comply with 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, 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.

(h) Each owner or operator shall not burn in any affected flare any fuel gas that contains H2S in 

excess of 162 ppmv determined hourly on a 3-hour rolling average basis. The combustion in a flare of 

process upset gases or fuel gas that is released to the flare as a result of relief valve leakage or other 

emergency malfunctions is exempt from this limit.

(i) Each owner or operator of a delayed coking 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 must either be recovered (e.g., sent to the 

delayed coking unit fractionators) or vented to the fuel gas system, a fuel gas combustion device or a 

flare.

(j) Alternative means of emission limitation. (1) Each owner or operator subject to the provisions of 

this section may apply to the Administrator for a determination of equivalence for any means of 

emission limitation that achieves a reduction in emissions of a specified pollutant at least equivalent to 

the reduction in emissions of that pollutant achieved by the controls required in this section.

(2) Determination of equivalence to the design, equipment, work practice or operational 

requirements of this section will be evaluated by the following guidelines:

(i) Each owner or operator applying for a determination of equivalence shall be responsible for 

collecting and verifying test data to demonstrate the equivalence of the alternative means of emission 

limitation.

(ii) For each affected facility for which a determination of equivalence is requested, the emission 

reduction achieved by the design, equipment, work 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 determination 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 achieved by the required work practice.

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(v) The Administrator will compare the demonstrated 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 will be evaluated by the following guidelines:

(i) After a request for determination of equivalence is received, the Administrator will publish a 

notice in the FEDERAL REGISTER and provide the opportunity for public hearing if the Administrator 

judges that the request may be approved.

(ii) After notice and opportunity for public hearing, the Administrator will determine the equivalence 

of a means of emission limitation and will publish the determination in the FEDERAL REGISTER.

(iii) Any equivalent means of emission limitations approved under this section shall constitute a 

required work practice, equipment, design or operational 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 demonstrate 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, calibration checks and zero and span adjustments.

(b) The owner or operator of a FCCU or FCU that elects to monitor control device operating 

parameters according to the requirements in §60.105a(b), to use bag leak detectors according to the 

requirements in §60.105a(c), or to use COMS according to the requirements in §60.105a(e) shall 

conduct a PM performance 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, NOX, SO2, and CO emissions 

limits in §60.102a(b) for FCCU and FCU using the following methods and procedures:

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(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses.

(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate.

(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 

19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an 

acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

(4) Method 5, 5B, or 5F of appendix A-3 to part 60 for determining PM emissions and associated 

moisture content from a FCCU or FCU without a wet scrubber subject to the emissions limit in 

§63.102a(b)(1). Use Method 5 or 5B of appendix A-3 to part 60 for determining PM emissions and 

associated moisture content from a FCCU or FCU with a wet scrubber subject to the emissions limit in 

§63.102a(b)(1).

(i) The PM performance test consists of 3 valid test runs; the duration of each test run must be no 

less than 60 minutes.

(ii) The emissions rate of PM (EPM) is computed for each run using Equation 5 of this section:

View or download PDF

Where:

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

cs = Concentration of total PM, grams per dry standard cubic meter (g/dscm) (gr/dscf);

Qsd = Volumetric flow rate of effluent gas, dry standard cubic meters per hour (dry standard cubic feet per hour);

Rc = 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 (Rc) is computed for each run using Equation 6 of this section:

View or download PDF

Where:

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

Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emissions 

control or energy recovery system that burns auxiliary fuel, dry standard cubic meters per minute 

(dscm/min) [dry standard cubic feet per minute (dscf/min)];

Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from the unit's control 

room instrumentation, dscm/min (dscf/min);

Qoxy = Volumetric flow rate of O2 enriched air to FCCU regenerator or fluid coking unit, as determined from the 

unit's control room instrumentation, dscm/min (dscf/min);

%CO2 = Carbon dioxide (CO2) concentration in FCCU regenerator or fluid coking burner exhaust, percent by 

volume (dry basis);

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

%O2 = O2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);

%Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent 

by volume (dry basis);

K1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)];

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

K3 = 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 

(Qr) before any emission control or energy recovery system that burns auxiliary fuel is measured using 

Method 2 of appendix A-1 to part 60.

(v) For subsequent calculations of coke burn-off rates or exhaust gas flow rates, the volumetric 

flow rate of Qr is calculated using average exhaust gas concentrations as measured by the monitors 

required in §60.105a(b)(2), if applicable, using Equation 7 of this section:

View or download PDF

Where:

Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emission 

control or energy recovery system that burns auxiliary fuel, dscm/min (dscf/min);

Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from the unit's control 

room instrumentation, dscm/min (dscf/min);

Qoxy = Volumetric flow rate of O2 enriched air to FCCU regenerator or fluid coking unit, as determined from the 

unit's control room instrumentation, dscm/min (dscf/min);

%CO2 = Carbon dioxide concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume 

(dry basis);

%CO = CO concentration FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis). 

When no auxiliary fuel is burned and a continuous CO monitor is not required in accordance with 

§60.105a(h)(3), assume %CO to be zero;

%O2 = O2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis); and

%Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent 

by volume (dry basis).

(5) Method 6, 6A, or 6C of appendix A-4 to part 60 for moisture content and for the concentration 

of SO2; the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 

19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an 

acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60.

(6) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the 

concentration of NOX calculated as nitrogen dioxide (NO2); 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.

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(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, NOX, SO2 and CO pollutant concentrations to 

0-percent excess air or 0-percent O2 using Equation 8 of this section:

View or download PDF

Where:

Cadj = pollutant concentration adjusted to 0-percent excess air or O2, parts per million (ppm) or g/dscm;

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

20.9c = 20.9 percent O2−0.0 percent O2 (defined O2 correction basis), percent;

20.9 = O2 concentration in air, percent; and

%O2 = O2 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 according to the procedures in paragraphs (f)(1) 

through (3) of this section.

(1) Collect COMS data every 10 seconds during the entire period of the PM performance test and 

reduce the data to 6-minute averages.

(2) Determine and record the hourly average opacity from all the 6-minute averages.

(3) Compute the site-specific limit using Equation 9 of this section:

View or download PDF

Where:

Opacity limit = Maximum permissible 3-hour average opacity, percent, or 10 percent, whichever is greater;

Opacityst = Hourly average opacity measured during the source test, percent; and

PMEmRst = PM emission rate measured during the 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 limits based on the performance test results using 

the procedures in paragraphs (g)(1) and (2) of this section.

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(1) Reduce the temperature and O2 concentrations from the parameter monitoring systems to 

hourly averages for each test run.

(2) Determine the operating limit for temperature and O2 concentrations as the average of the 

average temperature and O2 concentration for the three test runs.

(h) The owner or operator shall determine compliance with the SO2 and H2S 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 H2S 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,” (incorporated by reference—see §60.17) is an 

acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

(4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO2 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 H2S concentrations. The method ANSI/ASME PTC 

19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an 

acceptable alternative to EPA Method 15A of appendix A-5 to part 60.

(i) Each run consists of 16 samples taken over a minimum of 3 hours.

(ii) The owner or operator shall calculate the average H2S concentration after correcting for 

moisture and O2 as the arithmetic average of the H2S concentration for each sample during the run 

(ppmv, dry basis, corrected to 0 percent excess air).

(iii) The owner or operator shall calculate the SO2 equivalent for each run after correcting for 

moisture and O2 as the arithmetic average of the SO2 equivalent of reduced sulfur compounds for 

each sample during the run (ppmv, dry basis, corrected to 0 percent excess air).

(iv) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations to 

0-percent O2 or 0- percent excess air.

(i) The owner or operator shall determine compliance with the SO2 and NOX emissions limits in 

§60.102a(g) for a fuel gas combustion device according to the following test methods and procedures:

(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses;

(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate;

(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 

19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an 

acceptable alternative to EPA Method 3B of appendix A-2 to part 60;

(4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO2 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.

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(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 combustion device is added to a common source of fuel 

gas that previously demonstrated compliance.

(5) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the 

concentration of NOX calculated as NO2; 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 O2 operating limit or O2 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 O2 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 NOX concentration for the performance 

test as the average of the NOX concentrations from each of the three test runs. If the NOX

concentration for the performance test is less than or equal to the numerical value of the applicable 

NOX emissions limit (regardless of averaging time), then the test is considered to be a valid test.

(C) Determine the average O2 concentration for each test run of a valid test.

(D) Calculate the O2 operating limit as the average O2 concentration of the three test runs from a 

valid test.

(ii) If an O2 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 O2

operating limits will be established. Different operating conditions may be defined as different firing 

rates (e.g., above 50 percent of rated heat capacity and at or below 50 percent of rated heat capacity) 

and/or, for co-fired process heaters, different fuel mixtures (e.g., primarily gas fired, primarily oil fired, 

and equally co-fired, i.e., approximately 50 percent of the input heating value is from fuel gas and 

approximately 50 percent of the input heating 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 NOX concentration for the performance 

test as the average of the NOX concentrations from each of the three test runs. If the NOX

concentration for the performance test is less than or equal to the numerical value of the applicable 

NOX emissions 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 

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heat capacity). If O2 operating limits are developed for co-fired process heaters based only on overall 

firing rates (and not by fuel mixtures), conduct at least one of the test runs for each test while the 

process heater is being supplied by both fuel gas and fuel oil and conduct at least one of the test runs 

while the process heater is being supplied solely by fuel gas.

(D) Determine the average O2 concentration for each test run of a valid test.

(E) Calculate the O2 operating limit for each operating range as the average O2 concentration of 

the three test runs from a valid test conducted at the representative conditions for that given operating 

range.

(F) Identify the firing rates for which the different operating limits apply. If only two operating limits 

are established based on firing rates, the O2 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 O2 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 operators 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 NOX limit in terms of lb/MMBtu as 

provided in §60.102a(g)(2)(i)(B), (g)(2)(ii)(B), (g)(2)(iii)(B) or (g)(2)(iv)(B) or a process heater with a 

rated heat capacity between 40 and 100 MMBtu/hr that elects to demonstrate continuous compliance 

with a maximum excess O2 limit, as provided in §60.107a(c)(6) or (d)(8), shall determine heat input to 

the process heater in MMBtu/hr during each performance test run by measuring fuel gas flow rate, fuel 

oil flow rate (as applicable) and heating value content according to the methods provided in §60.107a

(d)(5), (d)(6), and (d)(4) or (d)(7), respectively.

(8) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations to 

0-percent O2 or 0- percent excess air.

(j) The owner or operator shall determine compliance with the applicable H2S 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,” (incorporated 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 H2S concentration for affected facilities using an H2S 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, 

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although fuel gases containing low concentrations of H2S 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 flare 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 to PM emissions limit. Each owner or operator subject to the 

provisions of this subpart shall monitor each FCCU and FCU subject to the PM emissions limit in 

§60.102a(b)(1) according to the requirements in paragraph (b), (c), (d), or (e) of this section.

(b) Control device operating parameters. Each owner or operator of a FCCU or FCU subject to the 

PM per coke burn-off emissions limit in §60.102a(b)(1) 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 parameters for each control device according to the 

applicable requirements in paragraphs (b)(1)(i) through (v) of this section.

(i) For units controlled using an electrostatic precipitator, the owner or operator shall use CPMS to 

measure and record the hourly average total power input and secondary voltage to the entire system.

(ii) For units controlled using a wet scrubber, the owner or operator shall use CPMS to measure 

and record the hourly average pressure drop, liquid feed rate, and exhaust gas flow rate. As an 

alternative to a CPMS, the owner or operator must comply with the requirements in either paragraph 

(b)(1)(ii)(A) or (B) of this section.

(A) As an 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 record the average coke burn-off rate and hours of 

operation for each FCCU or FCU using the procedures in §60.104a(d)(4)(iii).

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(v) If you use a control device other than an electrostatic precipitator, wet scrubber, fabric filter, or 

cyclone, you may request approval to monitor parameters other than those required in paragraph (b)

(1) of this section by 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 comply with the emission limitations and an explanation 

of the criteria used to select the parameter(s).

(B) A description of the methods and procedures that will be used to demonstrate that the 

parameter(s) can be used to determine whether the affected facility will continuously comply with the 

emission limitations and the schedule for this demonstration. The owner or operator must certify that 

an operating limit will be established for the monitored parameter(s) that represents the conditions in 

existence when the control device is being properly operated and maintained to meet the emission 

limitation.

(C) The frequency and content of the recordkeeping, recording, and reporting, if monitoring and 

recording are not continuous. The owner or operator also must include the rationale for the proposed 

monitoring, recording, and reporting requirements.

(D) Supporting calculations.

(E) Averaging time for the alternative operating parameter.

(2) For use in determining the coke burn-off rate for an FCCU or FCU, the owner or operator shall 

install, operate, calibrate, and maintain an instrument for continuously monitoring the concentrations of 

CO2, O2 (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 conduct performance evaluations of each CO2, O2 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 CO2 and CO monitors, annual 

accuracy determinations for O2 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 certified by the manufacturer to be capable of detecting 

PM emissions at concentrations of 0.00044 grains per actual cubic foot or less.

(ii) The bag leak detection system sensor must provide output of relative PM loadings. The owner 

or operator shall continuously record the output from the bag leak detection system using electronic or 

other means (e.g., using a strip chart recorder or a data logger).

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(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 operator shall not adjust the averaging period, alarm 

set point, or alarm delay time without approval from the Administrator or delegated authority except as 

provided in paragraph (c)(1)(vi) of this section.

(vi) Once per quarter, the owner or operator may adjust the sensitivity of the bag leak detection 

system to account for seasonal effects, including temperature and humidity, according to the 

procedures identified in the site-specific monitoring 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 submit to the Administrator for approval a sitespecific monitoring plan for each baghouse and bag leak detection system. The owner or operator 

shall operate and maintain each baghouse and bag leak detection system according to the sitespecific monitoring plan at all times. Each monitoring plan must describe the items in paragraphs (c)(2)

(i) through (vii) of this section.

(i) Installation of the bag leak detection system;

(ii) Initial and periodic adjustment of the bag leak detection system, including how the alarm setpoint will be established;

(iii) Operation of the bag leak detection system, including quality assurance procedures;

(iv) How the bag leak detection system will be maintained, including a routine maintenance 

schedule and spare parts inventory list;

(v) How the bag leak detection system output will be recorded and stored;

(vi) Procedures as specified in paragraph (c)(3) of this section. In approving the site-specific 

monitoring plan, the Administrator or delegated authority may allow owners and operators more than 3 

hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the 

monitoring plan this specific condition as one that could lead to an alarm, adequately explains why it is 

not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstrates 

that the requested time will ensure alleviation of this condition as expeditiously as practicable; and

(vii) How the baghouse system will be operated and maintained, including monitoring of pressure 

drop across baghouse cells and frequency of visual inspections of the baghouse interior and 

baghouse components such as fans 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:

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(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 section for each bag leak detection system.

(i) Records of the bag leak detection system output;

(ii) Records of bag leak detection system adjustments, including the date and time of the 

adjustment, the initial bag leak detection system settings, and the final bag leak detection system 

settings; and

(iii) The date and time of all bag leak detection system alarms, the time that procedures to 

determine the cause of the alarm were initiated, the cause of the alarm, an explanation of the actions 

taken, the date and time the cause of the alarm was alleviated, and whether the alarm was alleviated 

within 3 hours of the alarm.

(d) Continuous emissions monitoring systems (CEMS). An owner or operator subject to the PM 

concentration emission limit (in gr/dscf) in §60.102a(b)(1) for an FCCU or FCU shall install, operate, 

calibrate, and maintain an instrument for continuously monitoring and recording the concentration (0 

percent excess air) of PM in the exhaust gases prior to release to the atmosphere. The monitor must 

include an O2 monitor for correcting the data for excess air.

(1) The owner or operator shall install, operate, and maintain each PM monitor according to 

Performance Specification 11 of appendix B to part 60. The span value of this PM monitor is 0.08 

gr/dscf PM.

(2) The owner or operator shall conduct performance evaluations of each PM monitor according 

to the requirements in §60.13(c) and Performance Specification 11 of appendix B to part 60. The 

owner or operator shall use EPA Methods 5 or 5I of appendix A-3 to part 60 or Method 17 of appendix 

A-6 to part 60 for conducting the relative accuracy evaluations.

(3) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be 

selected between 10 and 25 percent, inclusive.

(4) The owner or operator shall conduct performance evaluations of each O2 monitor according to 

the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 

3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative accuracy evaluations. 

The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

(5) The owner or operator shall comply with the quality assurance requirements of Procedure 2 of 

appendix B to part 60 for each PM CEMS and Procedure 1 of appendix F to part 60 for each O2

monitor, including quarterly accuracy determinations for each PM monitor, annual accuracy 

determinations for each O2 monitor, and daily calibration drift tests.

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(e) Alternative monitoring option for FCCU and FCU—COMS. Each owner or operator of an 

FCCU or FCU that uses cyclones to comply with the PM emission limit in §60.102a(b)(1) shall monitor 

the opacity of emissions according to the requirements in paragraphs (e)(1) through (3) of this section.

(1) The owner or operator shall install, operate, and maintain an instrument for continuously 

monitoring and recording the opacity of emissions from the FCCU or the FCU exhaust vent.

(2) The owner or operator shall install, operate, and maintain each COMS according to 

Performance Specification 1 of appendix B to part 60. The instrument shall be spanned at 20 to 60 

percent opacity.

(3) The owner or operator shall conduct performance evaluations of each COMS according to 

§60.13(c) and Performance Specification 1 of appendix B to part 60.

(f) FCCU and FCU subject to NOX limit. Each owner or operator subject to the NOX emissions limit 

in §60.102a(b)(2) for an FCCU or FCU shall install, operate, calibrate, and maintain an instrument for 

continuously monitoring and recording the concentration by volume (dry basis, 0 percent excess air) of 

NOX emissions into the atmosphere. The monitor must include an O2 monitor for correcting the data 

for excess air.

(1) The owner or operator shall install, operate, and maintain each NOX monitor according to 

Performance Specification 2 of appendix B to part 60. The span value of this NOX monitor is 200 ppmv 

NOX.

(2) The owner or operator shall conduct performance evaluations of each NOX monitor according 

to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The owner 

or operator shall use Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas 

Analyses,” (incorporated by 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 O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be 

selected between 10 and 25 percent, inclusive.

(4) The owner or operator shall conduct performance evaluations of each O2 monitor according to 

the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 

3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative accuracy evaluations. 

The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

(5) The owner or operator shall comply with the quality assurance requirements of Procedure 1 of 

appendix F to part 60 for each NOX and O2 monitor, including quarterly accuracy determinations for 

NOX monitors, annual accuracy determinations for O2 monitors, and daily calibration drift tests.

(g) FCCU and FCU subject to SO2 limit. The owner or operator subject to the SO2 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 concentration by volume (dry basis, corrected to 0 

percent excess air) of SO2 emissions into the atmosphere. The monitor shall include an O2 monitor for 

correcting the data for excess air.

(1) The owner or operator shall install, operate, and maintain each SO2 monitor according to 

Performance Specification 2 of appendix B to part 60. The span value of this SO2 monitor is 200 ppmv 

SO2.

(2) The owner or operator shall conduct performance evaluations of each SO2 monitor according 

to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The owner 

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or operator shall use Methods 6, 6A, or 6C of appendix A-4 to part 60 for conducting the relative 

accuracy evaluations. The method ANSI / ASME PTC 19.10-1981, “Flue and Exhaust Gas 

Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 6 or 

6A of appendix A-4 to part 60.

(3) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be 

selected between 10 and 25 percent, inclusive.

(4) The owner or operator shall conduct performance evaluations of each O2 monitor according to 

the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 

3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative accuracy evaluations. 

The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

(5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 of 

appendix F to part 60 for each SO2 and O2 monitor, including quarterly accuracy determinations for 

SO2 monitors, annual accuracy determinations for O2 monitors, and daily calibration drift tests.

(h) FCCU and fluid coking units subject to CO emissions limit. Except as specified in paragraph 

(h)(3) of this section, the owner or operator shall install, operate, calibrate, and maintain an instrument 

for continuously monitoring and recording the concentration by volume (dry basis) of CO emissions 

into the atmosphere from each FCCU and FCU subject to the CO emissions limit in §60.102a(b)(4).

(1) The owner or operator shall install, operate, and maintain each CO monitor according to 

Performance Specification 4 or 4A of appendix B to part 60. The span value for this instrument is 

1,000 ppm CO.

(2) The owner or operator shall conduct performance evaluations of each CO monitor according 

to the requirements in §60.13(c) and Performance Specification 4 or 4A of appendix B to part 60. The 

owner or operator shall use Methods 10, 10A, or 10B of appendix A-4 to part 60 for conducting the 

relative accuracy evaluations.

(3) A CO CEMS need not be installed if the owner or operator demonstrates that all hourly 

average CO emissions are and will remain less than 50 ppmv (dry basis) corrected to 0 percent 

excess air. The Administrator may revoke this exemption from monitoring upon a determination that 

CO emissions on an hourly average basis have exceeded 50 ppmv (dry basis) corrected to 0 percent 

excess air, in which case a CO CEMS shall be installed within 180 days.

(i) The demonstration shall consist of continuously monitoring CO emissions for 30 days using an 

instrument that meets the requirements of Performance Specification 4 or 4A of appendix B to part 60. 

The span value shall be 100 ppm CO instead of 1,000 ppm, and the relative accuracy limit shall be 10 

percent of the average CO emissions or 5 ppm CO, whichever is greater. For instruments that are 

identical to Method 10 of appendix A-4 to part 60 and employ the sample conditioning system of 

Method 10A of appendix A-4 to part 60, the alternative relative 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 O2 monitor required in paragraph 

(h)(4) of this section and operating limits for those parameters to ensure combustion conditions remain 

similar to those that exist during the demonstration period.

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(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 O2

concentration of the exhaust gas stream exiting the unit.

(ii) For a FCCU or FCU with a post-combustion control device, the temperature and O2

concentration of the exhaust gas stream exiting the control device.

(i) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess 

emissions for a FCCU or FCU subject to the emissions limitations in §60.102a(b) are defined as 

specified in paragraphs (i)(1) through (6) of this section. Note: Determine all averages, except for 

opacity, as the arithmetic average of the applicable 1-hour averages, e.g., determine the rolling 3-hour 

average as the arithmetic average of three contiguous 1-hour averages.

(1) If a CPMS is used according to §60.105a(b)(1), all 3-hour periods during which the average 

PM control device operating characteristics, as measured by the continuous monitoring systems under 

§60.105a(b)(1), fall below the levels established during the performance test.

(2) If a PM CEMS is used according to §60.105a(d), all 7-day periods during which the average 

PM emission rate, as measured by the continuous PM monitoring system under §60.105a(d) exceeds 

0.040 gr/dscf corrected to 0 percent excess air for a modified or reconstructed FCCU, 0.020 gr/dscf 

corrected to 0 percent excess air for a newly constructed FCCU, or 0.040 gr/dscf for an affected fluid 

coking unit.

(3) If a COMS is used according to §60.105a(e), all 3-hour periods during which the average 

opacity, as measured by the COMS under §60.105a(e), exceeds the site-specific limit established 

during the most recent performance test.

(4) All rolling 7-day periods during which the average concentration of NOX as measured by the 

NOX CEMS under §60.105a(f) exceeds 80 ppmv for an affected FCCU or FCU.

(5) All rolling 7-day periods during which the average concentration of SO2 as measured by the 

SO2 CEMS under §60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods during which the 

average concentration of SO2 as measured by the SO2 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 O2 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]

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§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:

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(1) For sulfur recovery plants subject to the SO2 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 

SO2 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 SO2 emission limit and between 

10 and 25 percent O2, inclusive.

(ii) The owner or operator shall install, operate, and maintain each SO2 CEMS according to 

Performance Specification 2 of appendix B to part 60.

(iii) The owner or operator shall conduct performance evaluations of each SO2 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 H2S 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, 

H2S, and O2 emissions into the atmosphere. The reduced sulfur emissions shall be calculated as SO2

(dry basis, zero percent excess air).

(i) The span values for this monitor are two times the applicable reduced sulfur emission limit, two 

times the H2S emission limit, and between 10 and 25 percent O2, 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 H2S 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 O2 monitor according to 

Performance Specification 3 of appendix B to part 60.

(vii) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive.

(viii) The owner or operator shall conduct performance evaluations for the O2 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 

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Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 3B of 

appendix A-2 to part 60.

(ix) The owner or operator shall comply with the applicable quality assurance procedures of 

appendix F to part 60 for each monitor, including annual accuracy determinations for each O2 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 O2 dilution and 

oxidation system to convert any reduced sulfur to SO2 for continuously monitoring and recording the 

concentration (dry basis, 0 percent excess air) of the total resultant SO2. The monitor must include an 

O2 monitor for correcting the data for excess O2.

(i) The span value for this monitor is two times the applicable SO2 emission limit.

(ii) The owner or operator shall conduct performance evaluations of each SO2 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 O2 monitor according to 

Performance Specification 3 of appendix B to part 60.

(iv) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive.

(v) The owner or operator shall conduct performance evaluations for the O2 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 SO2

monitor, annual accuracy determinations for each O2 monitor, and daily calibration drift 

determinations.

(b) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess 

emissions for sulfur recovery plants subject to the emissions limitations in §60.102a(f) are defined as 

specified in paragraphs (b)(1) through (3) of this section.

NOTE: Determine all averages as the arithmetic average of the applicable 1-hour averages, e.g., determine 

the rolling 12-hour average as the arithmetic average of 12 contiguous 1-hour averages.

(1) All 12-hour periods during which the average concentration of SO2 as measured by the SO2

continuous monitoring system required under paragraph (a)(1) of this section exceeds the applicable 

emission limit (dry basis, zero percent excess air); or

(2) All 12-hour periods during which the average concentration of reduced sulfur (as SO2) as 

measured by the reduced sulfur continuous monitoring system required under paragraph (a)(2) of this 

section exceeds the applicable emission limit; or

(3) All 12-hour periods during which the average concentration of H2S as measured by the H2S 

continuous monitoring system required under paragraph (a)(2) of this section exceeds the applicable 

emission limit (dry basis, 0 percent excess air).

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§60.107a Monitoring of emissions and operations for fuel gas combustion devices and flares.

(a) Fuel gas combustion devices subject to SO2 or H2S limit and flares subject to H2S 

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 SO2 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 H2S concentration limits in 

§60.102a(g)(1)(ii) or a flare that is subject to the H2S concentration requirement in §60.103a(h) shall 

comply with paragraph (a)(2) of this section.

(1) The owner or operator of a fuel gas combustion device that elects to comply with the SO2

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 SO2

emissions into the atmosphere. The monitor must include an O2 monitor for correcting the data for 

excess air.

(i) The owner or operator shall install, operate, and maintain each SO2 monitor according to 

Performance Specification 2 of appendix B to part 60. The span value for the SO2 monitor is 50 ppm 

SO2.

(ii) The owner or operator shall conduct performance evaluations for the SO2 monitor according to 

the requirements of §60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or 

operator shall use Methods 6, 6A, or 6C of appendix A-4 to part 60 for conducting the relative 

accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas 

Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 6 or 

6A of appendix A-4 to part 60. Samples taken by Method 6 of appendix A-4 to part 60 shall be taken at 

a flow rate of approximately 2 liters/min for at least 30 minutes. The relative accuracy limit shall be 20 

percent or 4 ppm, whichever is greater, and the calibration drift limit shall be 5 percent of the 

established span value.

(iii) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value for the O2 monitor must be 

selected between 10 and 25 percent, inclusive.

(iv) The owner or operator shall conduct performance evaluations for the O2 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 SO2 monitors, annual accuracy 

determinations for O2 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 SO2 emissions into the atmosphere from each of the combustion devices.

(2) The owner or operator of a fuel gas combustion device that elects to comply with the H2S 

concentration limits in §60.102a(g)(1)(ii) or a flare that is subject to the H2S 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 H2S in the fuel gases before being burned in 

any fuel gas combustion device or flare.

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(i) The owner or operator shall install, operate and maintain each H2S monitor according to 

Performance Specification 7 of Appendix B to part 60. The span value for this instrument is 300 ppmv 

H2S.

(ii) The owner or operator shall conduct performance evaluations for each H2S 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 H2S monitor.

(iv) Fuel gas combustion devices or flares having a common source of fuel gas may be monitored 

at only one location, if monitoring at this location accurately represents the concentration of H2S 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 H2S 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 H2S concentration requirement, the 

concentration directly measured by the instrument must meet the numeric concentration in §60.103a

(h).

(vi) The owner or operator of modified flare that meets all three 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 H2S 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 sulfur content. Fuel gas streams meeting one of the 

requirements in paragraphs (a)(3)(i) through (iv) of this section will be considered inherently low in 

sulfur content.

(i) Pilot gas for heaters and flares.

(ii) Fuel gas streams that meet a commercial-grade product specification for sulfur content of 30 

ppmv or less. In the case of a liquefied petroleum gas (LPG) product specification in the pressurized 

liquid state, the gas phase sulfur content should be evaluated assuming complete vaporization of the 

LPG and sulfur containing-compounds at the product specification concentration.

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(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 H2S 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 H2S monitoring 

requirements in paragraph (a)(2) of this section for a fuel gas stream that is inherently low in sulfur 

content. A fuel gas stream that is demonstrated to be low-sulfur is exempt from the monitoring 

requirements of paragraphs (a)(1) and (2) of this section until there are changes in operating 

conditions or stream composition.

(1) The owner or operator shall submit to the Administrator a written application for an exemption 

from monitoring. The application must contain the following information:

(i) A description of the fuel gas stream/system to be considered, including submission of a portion 

of the appropriate piping diagrams indicating the boundaries of the fuel gas stream/system and the 

affected fuel gas combustion device(s) or flare(s) to be considered; 

(ii) A statement that there are no crossover or entry points for sour gas (high H2S content) to be 

introduced into the fuel gas stream/system (this should be shown in the piping diagrams);

(iii) An explanation of the conditions that ensure low amounts of sulfur in the fuel gas stream (i.e., 

control equipment or product specifications) at all times;

(iv) The supporting test results from sampling the requested fuel gas stream/system 

demonstrating that the sulfur content is less than 5 ppm H2S. Sampling data must include, at 

minimum, 2 weeks of daily monitoring (14 grab samples) for frequently operated fuel gas 

streams/systems; for infrequently operated fuel gas streams/systems, seven grab samples must be 

collected unless other additional information would support reduced sampling. The owner or operator 

shall use detector tubes (“length-of-stain tube” type measurement) following the “Gas Processors 

Association Standard 2377-86, Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using 

Length of Stain Tubes,” 1986 Revision (incorporated by reference—see §60.17), with ranges 

0-10/0-100 ppm (N = 10/1) to test the applicant fuel gas stream for H2S; 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 H2S concentration (fuel 

quality) expected for the fuel gas stream/system going to the affected fuel gas combustion device or 

flare (e.g., the 2 weeks of daily detector tube results for a frequently operated loading rack included 

the entire range of products loaded out and, therefore, should be representative of typical operating 

conditions affecting H2S 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 procedures in paragraph (b)(3)(i), (b)(3)(ii), or (b)(3)(iii) of 

this section.

(i) If the operation change results in a sulfur content that is still within the range of concentrations 

included in the original application, the owner or operator shall conduct an H2S test on a grab sample 

and record the results as proof that the concentration is still within the range.

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(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 within 60 days (or within 30 days after the seventh grab 

sample is tested for infrequently operated process units).

(iii) If the operation change results in a sulfur content that is outside the range of concentrations 

included in the original application and the owner or operator chooses not to submit new information to 

support an exemption, the owner or operator must begin H2S monitoring using daily stain sampling to 

demonstrate compliance. The owner or operator must begin monitoring according to the requirements 

in paragraphs (a)(1) or (a)(2) of this section as soon as practicable, but in no case later than 180 days 

after the operation change. During daily stain tube sampling, a daily sample exceeding 162 ppmv is an 

exceedance of the 3-hour H2S concentration limit. The owner or operator of a fuel gas combustion 

device must also determine a rolling 365-day average using the stain sampling results; an average 

H2S concentration of 5 ppmv must be used for days within the rolling 365-day period prior to the 

operation change.

(c) Process heaters complying with the NOX concentration-based limit. The owner or operator of a 

process heater subject to the NOX emissions 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 NOX emissions into the atmosphere according to the 

requirements in paragraphs (c)(1) through (5) of this section, except as provided in paragraph (c)(6) of 

this section. The monitor must include an O2 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 NOX monitor according to Performance Specification 2 of Appendix B to 

part 60. The span value of this NOX monitor must be between 2 and 3 times the applicable emissions 

limit, inclusive.

(2) The owner or operator shall conduct performance evaluations of each NOX monitor according 

to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The owner 

or operator shall use Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas 

Analyses,” (incorporated by 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 O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be 

selected between 10 and 25 percent, inclusive.

(4) The owner or operator shall conduct performance evaluations of each O2 monitor according to 

the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 

3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative accuracy evaluations. 

The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

(5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 of 

appendix F to part 60 for each NOX and O2 monitor, including quarterly accuracy determinations for 

NOX monitors, annual accuracy determinations for O2 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 NOX emissions (i.e.,

low-NOX burners, ultra-low-NOX burners) 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 according to the requirements in §60.104a(i), establish 

a maximum excess O2 operating limit or operating curve according to the requirements in §60.104a(i)

(6) and comply with the O2 monitoring requirements in paragraphs (c)(3) through (5) of this section to 

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demonstrate compliance. If an O2 operating curve is used (i.e., if different O2 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 (as 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 NOX emissions 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 NOX emissions into the atmosphere and shall determine the F factor of 

the fuel gas stream no less frequently than once per day according to the monitoring requirements in 

paragraphs (d)(1) through (4) of this section. The owner or operator of a co-fired process heater 

subject to the NOX emissions 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 recording the concentration (dry basis, 0-percent excess 

air) of NOX emissions 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 NOX monitor according to the requirements in paragraphs (c)(1) through 

(5) of this section. The monitor must include an O2 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 representative of the fuel gas fed to the affected process 

heater(s).

(3) As an alternative to the requirements in paragraph (d)(2) of this section, the owner or operator 

of a gas-fired process heater shall install, operate and maintain a gas composition analyzer and 

determine the average F factor of the fuel gas using the factors in Table 1 of this subpart and Equation 

10 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).

View or download PDF

Where:

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

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

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

MHCi = molar heat content, Btu per mole (Btu/mol).

1,000,000 = unit conversion, Btu per MMBtu.

eCFR —Code of Federal Regulations Page 37 of 48

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(4) The owner or operator shall conduct performance evaluations of each compositional monitor 

according to the requirements in Performance Specification 9 of Appendix B to part 60. 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 with 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 requirements in §60.13 and Performance Specification 6 of 

Appendix B to part 60. Any of the following methods shall be used for conducting the relative accuracy 

evaluations:

(i) 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 Standards, 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:

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(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) (incorporated by reference-see §60.17).

(iv) ASTM D1946-90 (Reapproved 2006) (incorporated by reference-see §60.17).

(v) ASTM D3588-98 (Reapproved 2003) (incorporated by reference-see §60.17).

(vi) ASTM D4809-06 (incorporated by reference-see §60.17).

(vii) ASTM D4891-89 (Reapproved 2006) (incorporated 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, except that 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 modification based technology to reduce NOX emissions (i.e.,

low-NOX burners or ultra-low NOX burners) may elect to comply with the monitoring requirements in 

paragraphs (d)(1) through (7) of this section or, alternatively, the owner or operator of such a process 

heater shall conduct biennial performance tests according to the requirements in §60.104a(i), establish 

a maximum excess O2 operating limit or operating curve according to the requirements in §60.104a(i)

(6) and comply with the O2 monitoring requirements in paragraphs (c)(3) through (5) of this section to 

demonstrate compliance. If an O2 operating curve is used (i.e., if different O2 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 (as 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 cause 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 

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line directed to the affected flare in accordance with either paragraph (e)(1), (e)(2) or (e)(3) of this 

section. Different options may be elected for different gas lines. If a monitoring system is in place that 

is capable of complying with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this 

section, the owner or operator of a modified flare must comply with the requirements related to either 

paragraph (e)(1), (e)(2) or (e)(3) of this section upon startup of the modified flare. If a monitoring 

system is not in place that is capable of complying with the requirements related to either paragraph 

(e)(1), (e)(2) or (e)(3) of this section, the owner or operator of a modified flare must comply 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 comply with the requirements of this paragraph and 

paragraph (a)(2) of this section provided the applicable span specifications are met.

(ii) The owner or operator shall conduct performance 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 relative 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) H2S monitoring requirements. The owner or operator shall install, operate, calibrate, and 

maintain an instrument for continuously monitoring and recording the concentration of H2S 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 calculate 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 H2S monitor according to 

Performance Specification 7 of Appendix B to part 60. The span value should be determined based on 

the maximum sulfur content of gas that can be discharged to the flare (e.g., roughly 1.1 to 1.3 times 

the maximum anticipated sulfur concentration), but may be no less than 5,000 ppmv. A single dual 

range H2S 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 conduct performance evaluations of each H2S 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 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 relative 

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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 H2S 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 least 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-H2S ratio and 95-percent 

confidence interval as follows:

(A) Calculate the ratio of the total sulfur concentration to the H2S concentration for each day 

during which samples are collected.

(B) Determine the 10-day average total sulfur-to-H2S 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 ratios 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.

RatioAvg = 10-day average total sulfur-to-H2S 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-H2S concentration ratios used to develop the 

10-day average total sulfur-to-H2S concentration ratio, unitless.

(vii) For each day during the period when data are being collected to develop a 10-day average, 

the owner or operator shall estimate the total sulfur concentration using the measured total sulfur 

concentration measured for that day.

(viii) For all days other than those during 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-H2S ratio 

by the daily average H2S 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-H2S 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 

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average ratio and acceptable range based on data for the outlying weekly sample plus data collected 

over the following 9 operating days.

(3) SO2 monitoring requirements. The owner or operator shall install, operate, calibrate and 

maintain an instrument for continuously monitoring and recording the concentration of SO2 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 requirements 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 SO2) in the 

fuel gas using Equation 12 of this section.

View or download PDF

Where:

TSFG = Total sulfur concentration, as SO2, in the fuel gas, ppmv.

CSO2 = Concentration of SO2 in the exhaust gas, ppmv (dry basis at 0-percent excess air).

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

HHVFG = Higher heating value of the fuel gas, MMBtu/scf.

(4) Exemptions from sulfur monitoring requirements. Flares identified in paragraphs (e)(4)(i) 

through (iv) of this section are exempt from the requirements in paragraphs (e)(1) through (3) of this 

section. For each such flare, except as provided in paragraph (e)(4)(iv), engineering calculations shall 

be used to calculate the SO2 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 H2S 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 systems 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 measured by the sulfur monitor on the primary flare should 

be used to calculate SO2 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 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.

eCFR —Code of Federal Regulations Page 42 of 48

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(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 sensitivity of no more than 5 percent of the flow rate or 

10 cubic feet per minute, whichever is greater.

(iii) Use a flow monitor that is maintainable online, is able to continuously correct for temperature 

and pressure and is able to record flow in standard conditions (as defined in §60.2) over one-minute 

averages.

(iv) At least quarterly, perform a visual inspection of all 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 except those resulting from startup, shutdown or 

malfunction are not required to install continuous flow monitors; provided, however, that for any such 

flare, the owner or operator shall comply with the monitoring alternative in paragraph (g) of this 

section.

(g) Alternative monitoring for certain flares equipped with water seals. The owner or operator of an 

affected flare subject to §60.103a(c) through (e) that can be classified as either an emergency flare, a 

secondary flare or a flare equipped with a flare gas recovery system designed, sized and operated to 

capture all flows except those resulting from startup, shutdown or malfunction may, as an alternative to 

the sulfur and flow monitoring requirements of paragraphs (e) and (f) of this section, install, operate, 

calibrate and maintain, in accordance with the requirements in paragraphs (g)(1) through (7) of this 

section, a CPMS to measure and record the 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 pressure 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 

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any 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 subject to the emissions limitations in §60.102a(g) and 

flares subject to the concentration requirement in §60.103a(h) are defined as specified in paragraphs 

(i)(1) through (5) of this section. Determine a rolling 3-hour or a rolling daily average as the arithmetic 

average of the applicable 1-hour averages (e.g., a rolling 3-hour average is the arithmetic average of 

three contiguous 1-hour averages). Determine a rolling 30-day or a rolling 365-day average as the 

arithmetic average of the applicable daily averages (e.g., a rolling 30-day average is the arithmetic 

average of 30 contiguous daily averages).

(1) SO2 or H2S limits for fuel gas combustion devices. (i) If the owner or operator of a fuel gas 

combustion device elects to comply with the SO2 emission limits in §60.102a(g)(1)(i), each rolling 

3-hour period during which the average concentration of SO2 as measured by the SO2 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 SO2 as measured by the SO2 continuous 

monitoring system required under paragraph (a)(1) of this section exceeds 8 ppmv.

(ii) If the owner or operator of a fuel gas combustion device elects to comply with the H2S 

concentration limits in §60.102a(g)(1)(ii), each rolling 3-hour period during which the average 

concentration of H2S as measured by the H2S 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 H2S continuous monitoring system under paragraph (a)(2) 

of this section exceeds 60 ppmv.

(iii) If the owner or operator of a fuel gas combustion device becomes subject to the requirements 

of daily stain tube sampling in paragraph (b)(3)(iii) of this section, each day during which the daily 

concentration of H2S exceeds 162 ppmv and each rolling 365-day period during which the average 

concentration of H2S exceeds 60 ppmv.

(2) H2S concentration limits for flares. (i) Each rolling 3-hour period during which the average 

concentration of H2S as measured by the H2S 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 H2S 

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 NOX as measured by the NOX continuous 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

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(iii) For a co-fired process heater electing to comply with the NOX limit 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 

NOX as measured by the NOX continuous 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 O2 limits for fuel gas combustion devices. Each day during which the concentration of O2

as measured by the O2 continuous monitoring system required under paragraph (c)(6) of this section 

exceeds the O2 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 emissions limitations in §60.102a shall comply with the 

notification, recordkeeping, and reporting requirements in §60.7 and other requirements as specified in 

this section.

(b) Each owner or operator subject to an emissions limitation in §60.102a shall notify the 

Administrator of the specific monitoring provisions 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 definition of a co-fired process heater in §60.101a. 

Notifications required by this paragraph shall be submitted with the notification of initial startup 

required by §60.7(a)(3).

(c) The owner or operator shall maintain the following records:

(1) A copy of the flare management plan.

(2) Records of information to document conformance with bag leak detection system operation 

and maintenance requirements in §60.105a(c).

(3) Records of bag leak detection system alarms and actions according to §60.105a(c).

(4) For each FCCU and fluid coking unit 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 apply for each fuel stream. If the owner or operator 

applies for the exemption described in §60.107a(a)(3)(iv), the owner or operator must keep a copy of 

the application as well as the letter from the Administrator granting approval of the application.

(6) Records of discharges greater than 500 lb SO2 in any 24-hour period from any affected flare, 

discharges greater than 500 lb SO2 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:

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(i) A description of the discharge.

(ii) The date and time the discharge was first identified and the duration of the discharge.

(iii) The measured or calculated cumulative quantity of gas discharged over the discharge 

duration. If the discharge duration exceeds 24 hours, record the discharge quantity for each 24-hour 

period. For a flare, record the measured or calculated cumulative quantity of gas discharged to the 

flare over the discharge duration. If the discharge duration exceeds 24 hours, record the quantity of 

gas discharged to the flare for each 24-hour period. Engineering calculations are allowed for fuel gas 

combustion devices, 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 SO2 in any 24-hour period from a flare, the measured 

total sulfur concentration or both the measured H2S 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 SO2 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 H2S in 

the fuel gas or the measured concentration of SO2 in the stream discharged to the atmosphere. 

Process knowledge can be used to make these estimates for fuel gas combustion devices, but cannot 

be used to make these estimates for flares, except as provided in §60.107a(e)(4).

(vi) For each discharge greater than 500 lb SO2 in excess of the allowable limits from a sulfur 

recovery plant, either the measured concentration of reduced sulfur or SO2 discharged to the 

atmosphere.

(vii) For each discharge greater than 500 lb SO2 in any 24-hour period from any affected flare or 

discharge greater than 500 lb SO2 in excess of the allowable limits from a fuel gas combustion device 

or sulfur recovery plant, the cumulative quantity of H2S and SO2 released into the atmosphere. For 

releases controlled by flares, assume 99-percent conversion of reduced sulfur or total sulfur to SO2. 

For fuel gas combustion devices, assume 99-percent conversion of H2S to SO2.

(viii) The steps that the owner or operator took to limit the emissions during the discharge.

(ix) The root cause analysis and corrective action 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 that is the result of a planned startup or shutdown 

of a refinery process unit or ancillary equipment connected to the affected flare, a statement that a root 

cause analysis and corrective action analysis are not necessary because the owner or operator 

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 H2S 

and total sulfur analyses of each grab or integrated sample, the calculated daily total sulfur-to-H2S 

ratios, the calculated 10-day average total sulfur-to-H2S ratios and the 95-percent confidence intervals 

for each 10-day average total sulfur-to-H2S ratio.

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(d) Each owner or operator subject to this subpart shall submit an excess emissions report for all 

periods of excess emissions according to the requirements of §60.7(c) except that the report shall 

contain the information specified in paragraphs (d)(1) through (7) of this section.

(1) The date that the exceedance occurred;

(2) An explanation of the exceedance;

(3) Whether the exceedance was concurrent with a startup, shutdown, or malfunction of an 

affected facility or control system; and

(4) A description of the action taken, if any.

(5) The information described in paragraph (c)(6) of this section for all discharges listed in 

paragraph (c)(6) of this section. For a flare complying with the monitoring alternative under §60.107a

(g), following the fifth discharge required to be recorded under paragraph (c)(6) of this section and 

reported under this paragraph, the owner or operator shall include notification that monitoring systems 

will be installed according to §60.107a(e) and (f) within 180 days following the fifth discharge.

(6) For any periods for which monitoring data are not available, any changes made in operation of 

the emission control system during the period of data unavailability which could affect the ability of the 

system to meet the applicable emission limit. Operations of the control system and affected facility 

during periods of data unavailability are to be compared with operation of the control system and 

affected facility before 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]

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§60.109a Delegation of authority.

(a) This subpart can be implemented and enforced by the U.S. EPA or a delegated authority such 

as a State, local, or tribal agency. You should contact your U.S. EPA Regional Office to find out if this 

subpart is delegated to a State, local, or tribal agency within your State.

(b) In delegating implementation and enforcement authority of this subpart to a state, local or tribal 

agency, the approval authorities contained in paragraphs (b)(1) through (4) of this section are retained 

by the Administrator of the U.S. EPA and are not transferred to the state, local or tribal agency.

(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]

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eCFR —Code of Federal Regulations Page 47 of 48

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Table 1 to Subpart Ja of Part 60—Molar Exhaust Volumes and Molar Heat Content of Fuel Gas 

Constituents

Constituent

MEVa

dscf/mol

MHCb

Btu/mol

Methane (CH4) 7.29 842

Ethane (C2H6) 12.96 1,475

Hydrogen (H2) 1.61 269

Ethene (C2H4) 11.34 1,335

Propane (C3H8) 18.62 2,100

Propene (C3H6) 17.02 1,947

Butane (C4H10) 24.30 2,717

Butene (C4H8) 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]

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eCFR —Code of Federal Regulations Page 48 of 48

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