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Subpart Y—Petroleum Refineries

§98.250 Definition of source category.

(a) A petroleum refinery is any facility engaged in producing gasoline, gasoline blending 

stocks, naphtha, kerosene, distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen) 

through distillation of petroleum or through redistillation, cracking, or reforming of unfinished 

petroleum derivatives, except as provided in paragraph (b) of this section.

(b) For the purposes of this subpart, facilities that distill only pipeline transmix (off-spec 

material created when different specification products mix during pipeline transportation) are not 

petroleum refineries, regardless of the products produced.

(c) This source category consists of the following sources at petroleum refineries: 

Catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; coke 

calcining units; asphalt blowing operations; blowdown systems; storage tanks; process 

equipment components (compressors, pumps, valves, pressure relief devices, flanges, and 

connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; 

flares; sulfur recovery plants; and non-merchant hydrogen plants (i.e., hydrogen plants that are 

owned or under the direct control of the refinery owner and operator).

§98.251 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a petroleum 

refineries process and the facility meets the requirements of either §98.2(a)(1) or (a)(2).

§98.252 GHGs to report.

You must report:

(a) CO2, CH4, and N2O combustion emissions from stationary combustion units and from 

each flare. Calculate and report the emissions from stationary combustion units under subpart C 
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of this part (General Stationary Fuel Combustion Sources) by following the requirements of 

subpart C, except for emissions from combustion of fuel gas. For CO2 emissions from 

combustion of fuel gas, use either Equation C-5 in subpart C of this part or the Tier 4 

methodology in subpart C of this part, unless either of the conditions in paragraphs (a)(1) or (2) 

of this section are met, in which case use either Equations C-1 or C-2a in subpart C of this part. 

For CH4 and N2O emissions from combustion of fuel gas, use the applicable procedures in 

§98.33(c) for the same tier methodology that was used for calculating CO2 emissions. (Use the 

default CH4 and N2O emission factors for “Fuel Gas” in Table C-2 of this part. For Tier 3, use 

either the default high heat value for fuel gas in Table C-1 of subpart C of this part or a 

calculated HHV, as allowed in Equation C-8 of subpart C of this part.) You may aggregate units, 

monitor common stacks, or monitor common (fuel) pipes as provided in §98.36(c) when 

calculating and reporting emissions from stationary combustion units. Calculate and report the 

emissions from flares under this subpart.

(1) The annual average fuel gas flow rate in the fuel gas line to the combustion unit, prior 

to any split to individual burners or ports, does not exceed 345 standard cubic feet per minute at 

60 °F and 14.7 pounds per square inch absolute and either of the conditions in paragraph (a)(1)(i) 

or (ii) of this section exist. Calculate the annual average flow rate using company records 

assuming total flow is evenly distributed over 525,600 minutes per year.

(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream 

common pipe.

(ii) The fuel gas line contains only vapors from loading or unloading, waste or 

wastewater handling, and remediation activities that are combusted in a thermal oxidizer or 

thermal incinerator.
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(2) The combustion unit has a maximum rated heat input capacity of less than 30 

mmBtu/hr and either of the following conditions exist:

(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream 

common pipe; or

(ii) The fuel gas line contains only vapors from loading or unloading, waste or 

wastewater handling, and remediation activities that are combusted in a thermal oxidizer or 

thermal incinerator.

(b) CO2, CH4, and N2O coke burn-off emissions from each catalytic cracking unit, fluid 

coking unit, and catalytic reforming unit under this subpart.

(c) CO2 emissions from sour gas sent off site for sulfur recovery operations under this 

subpart. You must follow the calculation methodologies from §98.253(f) and the monitoring and 

QA/QC methods, missing data procedures, reporting requirements, and recordkeeping

requirements of this subpart.

(d) CO2 process emissions from each on-site sulfur recovery plant under this subpart.

(e) CO2, CH4, and N2O emissions from each coke calcining unit under this subpart.

(f) CO2 and CH4 emissions from asphalt blowing operations under this subpart.

(g) CH4 emissions from equipment leaks, storage tanks, loading operations, delayed 

coking units, and uncontrolled blowdown systems under this subpart.

(h) CO2, CH4, and N2O emissions from each process vent not specifically included in 

paragraphs (a) through (g) of this section under this subpart.

(i) CO2 emissions from non-merchant hydrogen production process units (not including 

hydrogen produced from catalytic reforming units) following the calculation methodologies, 
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monitoring and QA/QC methods, missing data procedures, reporting requirements, and 

recordkeeping requirements of subpart P of this part.

§98.253 Calculating GHG emissions.

(a) Calculate GHG emissions required to be reported in §98.252(b) through (i) using the 

applicable methods in paragraphs (b) through (n) of this section.

(b) For flares, calculate GHG emissions according to the requirements in paragraphs 

(b)(1) through (b)(3) of this section. All gas discharged through the flare stack must be 

considered for the flare GHG emissions calculations with the exception of gas used for the flare 

pilots, which may be excluded.

(1) Calculate the CO2 emissions according to the applicable requirements in paragraphs 

(b)(1)(i) through (b)(1)(iii) of this section.

(i) Flow measurement. If you have a continuous flow monitor on the flare, you must use 

the measured flow rates when the monitor is operational and the flow rate is within the calibrated 

range of the measurement device to calculate the flare gas flow. If you do not have a continuous 

flow monitor on the flare and for periods when the monitor is not operational or the flow rate is 

outside the calibrated range of the measurement device, you must use engineering calculations, 

company records, or similar estimates of volumetric flare gas flow.

(ii) Heat value or carbon content measurement. If you have a continuous higher heating 

value monitor or gas composition monitor on the flare or if you monitor these parameters at least 

weekly, you must use the measured heat value or carbon content value in calculating the CO2

emissions from the flare using the applicable methods in paragraphs (b)(1)(ii)(A) and 

(b)(1)(ii)(B).
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(A) If you monitor gas composition, calculate the CO2 emissions from the flare using 

either Equation Y-1a or Equation Y-1b of this section. If daily or more frequent measurement 

data are available, you must use daily values when using Equation Y-1a or Equation Y-1b of this 

section; otherwise, use weekly values.

(Eq. Y-1a)

where:

CO2 = Annual CO2 emissions for a specific fuel type (metric tons/year).

0.98 = Assumed combustion efficiency of a flare.

0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).

n = Number of measurement periods. The minimum value for n is 52 (for weekly

measurements); the maximum value for n is 366 (for daily measurements during 

a leap year).

p = Measurement period index.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

(Flare)p = Volume of flare gas combusted during measurement period (standard cubic feet 

per period, scf/period). If a mass flow meter is used, measure flare gas flow rate 

in kg/period and replace the term “(MW)p/MVC” with “1”.

(MW)p = Average molecular weight of the flare gas combusted during measurement 

period (kg/kg-mole). If measurements are taken more frequently than daily, use 

the arithmetic average of measurement values within the day to calculate a daily

average.

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 pounds 

per square inch absolute (psia) or 836.6 scf/kg-mole at 60 °F and 14.7 psia).

(CC)p = Average carbon content of the flare gas combusted during measurement period 

(kg C per kg flare gas). If measurements are taken more frequently than daily, 

use the arithmetic average of measurement values within the day to calculate a 

daily average.
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(Eq. Y-1b)

where:

CO2 = Annual CO2 emissions for a specific fuel type (metric tons/year).

n = Number of measurement periods. The minimum value for n is 52 (for weekly

measurements); the maximum value for n is 366 (for daily measurements during 

a leap year).

p = Measurement period index.

(Flare)p = Volume of flare gas combusted during measurement period (standard cubic feet 

per period, scf/period). If a mass flow meter is used, you must determine the 

average molecular weight of the flare gas during the measurement period and 

convert the mass flow to a volumetric flow.

44 = Molecular weight of CO2 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 

836.6 scf/kg-mole at 60 °F and 14.7 psia).

0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).

(%CO2)p = Mole percent CO2 concentration in the flare gas stream during the measurement 

period (mole percent = percent by volume).

y = Number of carbon-containing compounds other than CO2 in the flare gas 

stream.

x = Index for carbon-containing compounds other than CO2.

0.98 = Assumed combustion efficiency of a flare (mole CO2 per mole carbon).

(%CX)p = Mole percent concentration of compound “x” in the flare gas stream during the 

measurement period (mole percent = percent by volume)

CMNX = Carbon mole number of compound “x” in the flare gas stream (mole carbon 

atoms per mole compound). E.g., CMN for ethane (C2H6) is 2; CMN for 

propane (C3H8) is 3.

(B) If you monitor heat content but do not monitor gas composition, calculate the CO2

emissions from the flare using Equation Y-2 of this section. If daily or more frequent 
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measurement data are available, you must use daily values when using Equation Y-2 of this

section; otherwise, use weekly values.

(Eq. Y-2)

Where:

CO2 = Annual CO2 emissions for a specific fuel type (metric tons/year).

0.98 = Assumed combustion efficiency of a flare.

0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).

n = Number of measurement periods. The minimum value for n is 52 (for weekly

measurements); the maximum value for n is 366 (for daily measurements during 

a leap year).

p = Measurement period index.

(Flare)p = Volume of flare gas combusted during measurement period (million (MM) 

scf/period). If a mass flow meter is used, you must also measure molecular 

weight and convert the mass flow to a volumetric flow as follows: 

Flare[MMscf] = 0.000001 × Flare[kg] × MVC/(MW)p, where MVC is the molar 

volume conversion factor [849.5 scf/kg-mole at 68 °F and 14.7 psia or 836.6 

scf/kg-mole at 60 °F and 14.7 psia depending on the standard conditions used 

when determining (HHV)p] and (MW)p is the average molecular weight of the 

flare gas combusted during measurement period (kg/kg-mole).

(HHV)p = Higher heating value for the flare gas combusted during measurement period 

(British thermal units per scf, Btu/scf = MMBtu/MMscf). If measurements are 

taken more frequently than daily, use the arithmetic average of measurement 

values within the day to calculate a daily average.

EmF = Default CO2 emission factor of 60 kilograms CO2/MMBtu (HHV basis).

(iii) Alternative to heat value or carbon content measurements. If you do not measure the 

higher heating value or carbon content of the flare gas at least weekly, determine the quantity of 

gas discharged to the flare separately for periods of routine flare operation and for periods of 

start-up, shutdown, or malfunction, and calculate the CO2 emissions as specified in paragraphs 

(b)(1)(iii)(A) through (b)(1)(iii)(C) of this section.
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(A) For periods of start-up, shutdown, or malfunction, use engineering calculations and 

process knowledge to estimate the carbon content of the flared gas for each start-up, shutdown, 

or malfunction event exceeding 500,000 scf/day.

(B) For periods of normal operation, use the average higher heating value measured for 

the fuel gas used as flare sweep or purge gas for the higher heating value of the flare gas. If 

higher heating value of the fuel gas is not measured, the higher heating value of the flare gas 

under normal operations may be estimated from historic data or engineering calculations.

(C) Calculate the CO2 emissions using Equation Y-3 of this section.

(Eq. Y-3)

Where:

CO2 = Annual CO2 emissions for a specific fuel type (metric tons/year).

0.98 = Assumed combustion efficiency of a flare.

0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).

FlareNorm = Annual volume of flare gas combusted during normal operations from company 

records, (million (MM) standard cubic feet per year, MMscf/year).

HHV = Higher heating value for fuel gas or flare gas from company records (British 

thermal units per scf, Btu/scf = MMBtu/MMscf).

EmF = Default CO2 emission factor for flare gas of 60 kilograms CO2/MMBtu (HHV 

basis).

n = Number of start-up, shutdown, and malfunction events during the reporting year 

exceeding 500,000 scf/day.

p = Start-up, shutdown, and malfunction event index.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).
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(FlareSSM)p = Volume of flare gas combusted during indexed start-up, shutdown, or 

malfunction event from engineering calculations, (scf/event).

(MW)p = Average molecular weight of the flare gas, from the analysis results or 

engineering calculations for the event (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 

836.6 scf/kg-mole at 60 °F and 14.7 psia).

(CC)p = Average carbon content of the flare gas, from analysis results or engineering 

calculations for the event (kg C per kg flare gas).

(2) Calculate CH4 using Equation Y-4 of this section.

(Eq. Y-4)

Where:

CH4 = Annual methane emissions from flared gas (metric tons CH4/year).

CO2 = Emission rate of CO2 from flared gas calculated in paragraph (b)(1) of this 

section (metric tons/year).

EmFCH4 = Default CH4 emission factor for “Fuel Gas” from Table C-2 of subpart C of this 

part (General Stationary Fuel Combustion Sources) (kg CH4/MMBtu).

EmF = Default CO2 emission factor for flare gas of 60 kg CO2/MMBtu (HHV basis).

0.02/0.98 = Correction factor for flare combustion efficiency.

16/44 = Correction factor ratio of the molecular weight of CH4 to CO2.

fCH4 = Weight fraction of carbon in the flare gas prior to combustion that is contributed 

by methane from measurement values or engineering calculations (kg C in 

methane in flare gas/kg C in flare gas); default is 0.4.

(3) Calculate N2O emissions using Equation Y-5 of this section.

(Eq. Y-5)

Where:

N2O = Annual nitrous oxide emissions from flared gas (metric tons N2O/year).
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CO2 = Emission rate of CO2 from flared gas calculated in paragraph (b)(1) of this 

section (metric tons/year).

EmFN2O = Default N2O emission factor for “Fuel Gas” from Table C-2 of subpart C of this 

part (General Stationary Fuel Combustion Sources) (kg N2O/MMBtu).

EmF = Default CO2 emission factor for flare gas of 60 kg CO2/MMBtu (HHV basis).

(c) For catalytic cracking units and traditional fluid coking units, calculate the GHG 

emissions using the applicable methods described in paragraphs (c)(1) through (c)(5) of this 

section.

(1) If you operate and maintain a CEMS that measures CO2 emissions according to 

subpart C of this part (General Stationary Fuel Combustion Sources), you must calculate and

report CO2 emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other 

catalytic cracking units and traditional fluid coking units must either install a CEMS that 

complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary

Combustion Sources), or follow the requirements of paragraphs (c)(2) or (3) of this section.

(i) Calculate CO2 emissions by following the Tier 4 Calculation Methodology specified 

in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General 

Stationary Fuel Combustion Sources).

(ii) For catalytic cracking units whose process emissions are discharged through a 

combined stack with other CO2 emissions (e.g., co-mingled with emissions from a CO boiler) 

you must also calculate the other CO2 emissions using the applicable methods for the applicable 

subpart (e.g., subpart C of this part in the case of a CO boiler). Calculate the process emissions 

from the catalytic cracking unit or fluid coking unit as the difference in the CO2 CEMS 

emissions and the calculated emissions associated with the additional units discharging through 

the combined stack.
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(2) For catalytic cracking units and fluid coking units with rated capacities greater than 

10,000 barrels per stream day (bbls/sd) that do not use a continuous CO2 CEMS for the final 

exhaust stack, you must continuously or no less frequently than hourly monitor the O2, CO2, and 

(if necessary) CO concentrations in the exhaust stack from the catalytic cracking unit regenerator 

or fluid coking unit burner prior to the combustion of other fossil fuels and calculate the CO2

emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section:

(i) Calculate the CO2 emissions from each catalytic cracking unit and fluid coking unit 

using Equation Y-6 of this section.

(Eq. Y-6)

Where:

CO2 = Annual CO2 mass emissions (metric tons/year).

Qr = Volumetric flow rate of exhaust gas from the fluid catalytic cracking unit 

regenerator or fluid coking unit burner prior to the combustion of other fossil 

fuels (dry standard cubic feet per hour, dscfh).

%CO2 = Hourly average percent CO2 concentration in the exhaust gas stream from the 

fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by

volume—dry basis).

%CO = Hourly average percent CO concentration in the exhaust gas stream from the 

fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by

volume—dry basis). When there is no post-combustion device, assume %CO to 

be zero.

44 = Molecular weight of CO2 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 

836.6 scf/kg-mole at 60 °F and 14.7 psia).

0.001 = Conversion factor (metric ton/kg).

n = Number of hours in calendar year.
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(ii) Either continuously monitor the volumetric flow rate of exhaust gas from the fluid 

catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other 

fossil fuels or calculate the volumetric flow rate of this exhaust gas stream using either Equation 

Y-7a or Equation Y-7b of this section.

(Eq. Y-7a)

where:

Qr = Volumetric flow rate of exhaust gas from the fluid catalytic cracking unit 

regenerator or fluid coking unit burner prior to the combustion of other fossil 

fuels (dscfh).

Qa = Volumetric flow rate of air to the fluid catalytic cracking unit regenerator or 

fluid coking unit burner, as determined from control room instrumentation 

(dscfh).

Qoxy = Volumetric flow rate of oxygen enriched air to the fluid catalytic cracking unit 

regenerator or fluid coking unit burner as determined from control room 

instrumentation (dscfh).

%O2 = Hourly average percent oxygen concentration in exhaust gas stream from the 

fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by

volume—dry basis).

%Ooxy = O2 concentration in oxygen enriched gas stream inlet to the fluid catalytic 

cracking unit regenerator or fluid coking unit burner based on oxygen purity 

specifications of the oxygen supply used for enrichment (percent by volume—

dry basis).

%CO2 = Hourly average percent CO2 concentration in the exhaust gas stream from the 

fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by

volume—dry basis).

%CO = Hourly average percent CO concentration in the exhaust gas stream from the 

fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by

volume—dry basis). When no auxiliary fuel is burned and a continuous CO 

monitor is not required under 40 CFR part 63 subpart UUU, assume %CO to be 

zero.

(Eq. Y-7b)
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where:

Qr = Volumetric flow rate of exhaust gas from the fluid catalytic cracking unit 

regenerator or fluid coking unit burner prior to the combustion of other fossil 

fuels (dscfh).

Qa = Volumetric flow rate of air to the fluid catalytic cracking unit regenerator or 

fluid coking unit burner, as determined from control room instrumentation 

(dscfh).

Qoxy = Volumetric flow rate of oxygen enriched air to the fluid catalytic cracking unit 

regenerator or fluid coking unit burner as determined from control room 

instrumentation (dscfh).

%N2,oxy = N2 concentration in oxygen enriched gas stream inlet to the fluid catalytic 

cracking unit regenerator or fluid coking unit burner based on measured value 

or maximum N2 impurity specifications of the oxygen supply used for 

enrichment (percent by volume—dry basis).

%N2,exhaust = Hourly average percent N2 concentration in the exhaust gas stream from the 

fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by

volume—dry basis).

(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than 

catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO2 emissions 

resulting from the combustion of these fuels or other materials following the requirements in 

subpart C and report those emissions by following the requirements of subpart C of this part.

(3) For catalytic cracking units and fluid coking units with rated capacities of 10,000 

barrels per stream day (bbls/sd) or less that do not use a continuous CO2 CEMS for the final 

exhaust stack, comply with the requirements in paragraph (c)(3)(i) of this section or paragraphs 

(c)(3)(ii) and (c)(3)(iii) of this section, as applicable.

(i) If you continuously or no less frequently than daily monitor the O2, CO2, and (if 

necessary) CO concentrations in the exhaust stack from the catalytic cracking unit regenerator or 

fluid coking unit burner prior to the combustion of other fossil fuels, you must calculate the CO2
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emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section, 

except that daily averages are allowed and the summation can be performed on a daily basis.

(ii) If you do not monitor at least daily the O2, CO2, and (if necessary) CO concentrations 

in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior 

to the combustion of other fossil fuels, calculate the CO2 emissions from each catalytic cracking 

unit and fluid coking unit using Equation Y-8 of this section.

(Eq. Y-8)

Where:

CO2 = Annual CO2 mass emissions (metric tons/year).

Qunit = Annual throughput of unit from company records (barrels (bbls) per year, 

bbl/yr).

CBF = Coke burn-off factor from engineering calculations (kg coke per barrel of feed); 

default for catalytic cracking units = 7.3; default for fluid coking units = 11.

0.001 = Conversion factor (metric ton/kg).

CC = Carbon content of coke based on measurement or engineering estimate (kg C 

per kg coke); default = 0.94.

44/12 = Ratio of molecular weight of CO2 to C (kg CO2 per kg C).

(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than 

catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO2 emissions 

resulting from the combustion of these fuels or other materials following the requirements in 

subpart C of this part (General Stationary Fuel Combustion Sources) and report those emissions 

by following the requirements of subpart C of this part.

(4) Calculate CH4 emissions using either unit specific measurement data, a unit-specific 

emission factor based on a source test of the unit, or Equation Y-9 of this section.
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(Eq. Y-9)

Where:

CH4 = Annual methane emissions from coke burn-off (metric tons CH4/year).

CO2 = Emission rate of CO2 from coke burn-off calculated in paragraphs (c)(1), (c)(2), 

(e)(1), (e)(2), (g)(1), or (g)(2) of this section, as applicable (metric tons/year).

EmF1 = Default CO2 emission factor for petroleum coke from Table C-1 of subpart C of 

this part (General Stationary Fuel Combustion Sources) (kg CO2/MMBtu).

EmF2 = Default CH4 emission factor for “PetroleumProducts” from Table C-2 of 

subpart C of this part (General Stationary Fuel Combustion Sources) (kg 

CH4/MMBtu).

(5) Calculate N2O emissions using either unit specific measurement data, a unit-specific 

emission factor based on a source test of the unit, or Equation Y-10 of this section.

(Eq. Y-10)

Where:

N2O = Annual nitrous oxide emissions from coke burn-off (mt N2O/year).

CO2 = Emission rate of CO2 from coke burn-off calculated in paragraphs (c)(1), (c)(2), 

(e)(1), (e)(2), (g)(1), or (g)(2) of this section, as applicable (metric tons/year).

EmF1 = Default CO2 emission factor for petroleum coke from Table C-1 of subpart C of 

this part (General Stationary Fuel Combustion Sources) (kg CO2/MMBtu).

EmF3 = Default N2O emission factor for “PetroleumProducts” from Table C-2 of 

subpart C of this part (kg N2O/MMBtu).

(d) For fluid coking units that use the flexicoking design, the GHG emissions from the 

resulting use of the low value fuel gas must be accounted for only once. Typically, these 

emissions will be accounted for using the methods described in subpart C of this part (General 

Stationary Fuel Combustion Sources). Alternatively, you may use the methods in paragraph (c) 
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of this section provided that you do not otherwise account for the subsequent combustion of this 

low value fuel gas.

(e) For catalytic reforming units, calculate the CO2 emissions using the applicable 

methods described in paragraphs (e)(1) through (e)(3) of this section and calculate the CH4 and 

N2O emissions using the methods described in paragraphs (c)(4) and (c)(5) of this section, 

respectively.

(1) If you operate and maintain a CEMS that measures CO2 emissions according to 

subpart C of this part (General Stationary Fuel Combustion Sources), you must calculate CO2

emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other catalytic 

reforming units must either install a CEMS that complies with the Tier 4 Calculation 

Methodology in subpart C of this part, or follow the requirements of paragraph (e)(2) or (e)(3) of 

this section.

(2) If you continuously or no less frequently than daily monitor the O2, CO2, and (if 

necessary) CO concentrations in the exhaust stack from the catalytic reforming unit catalyst 

regenerator prior to the combustion of other fossil fuels, you must calculate the CO2 emissions 

according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section.

(3) Calculate CO2 emissions from the catalytic reforming unit catalyst regenerator using 

Equation Y-11 of this section.

(Eq. Y-11)

Where:

CO2 = Annual CO2 emissions (metric tons/year).

CBQ = Coke burn-off quantity per regeneration cycle or measurement period from 

engineering estimates (kg coke/cycle or kg coke/measurement period).
Page 17 of 54

n = Number of regeneration cycles or measurement periods in the calendar year.

CC = Carbon content of coke based on measurement or engineering estimate (kg C 

per kg coke); default = 0.94.

44/12 = Ratio of molecular weight of CO2 to C (kg CO2 per kg C).

0.001 = Conversion factor (metric ton/kg).

(f) For on-site sulfur recovery plants and for sour gas sent off site for sulfur recovery, 

calculate and report CO2 process emissions from sulfur recovery plants according to the 

requirements in paragraphs (f)(1) through (f)(5) of this section, or, for non-Claus sulfur recovery

plants, according to the requirements in paragraph (j) of this section regardless of the 

concentration of CO2 in the vented gas stream. Combustion emissions from the sulfur recovery

plant (e.g., from fuel combustion in the Claus burner or the tail gas treatment incinerator) must 

be reported under subpart C of this part (General Stationary Fuel Combustion Sources). For the 

purposes of this subpart, the sour gas stream for which monitoring is required according to 

paragraphs (f)(2) through (f)(5) of this section is not considered a fuel.

(1) If you operate and maintain a CEMS that measures CO2 emissions according to 

subpart C of this part, you must calculate CO2 emissions under this subpart by following the Tier 

4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 

in subpart C of this part (General Stationary Fuel Combustion Sources). You must monitor fuel 

use in the Claus burner, tail gas incinerator, or other combustion sources that discharge via the 

final exhaust stack from the sulfur recovery plant and calculate the combustion emissions from 

the fuel use according to subpart C of this part. Calculate the process emissions from the sulfur 

recovery plant as the difference in the CO2 CEMS emissions and the calculated combustion 

emissions associated with the sulfur recovery plant final exhaust stack. Other sulfur recovery

plants must either install a CEMS that complies with the Tier 4 Calculation Methodology in 
Page 18 of 54

subpart C, or follow the requirements of paragraphs (f)(2) through (f)(5) of this section, or (for 

non-Claus sulfur recovery plants only) follow the requirements in paragraph (j) of this section to 

determine CO2 emissions for the sulfur recovery plant.

(2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the 

sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use the 

measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do 

not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour 

gas feed sent for off-site sulfur recovery, you must use engineering calculations, company 

records, or similar estimates of volumetric sour gas flow.

(3) Carbon content. If you have a continuous gas composition monitor capable of 

measuring carbon content on the sour gas feed to the sulfur recovery plant or the sour gas feed 

sent for off-site for sulfur recovery, or if you monitor gas composition for carbon content on a 

routine basis, you must use the measured carbon content value. Alternatively, you may develop a 

site-specific carbon content factor using limited measurement data or engineering estimates or 

use the default factor of 0.20.

(4) Calculate the CO2 emissions from each on-site sulfur recovery plant and for sour gas 

sent off-site for sulfur recovery using Equation Y-12 of this section.

(Eq. Y-12)

Where:

CO2 = Annual CO2 emissions (metric tons/year).

FSG = Volumetric flow rate of sour gas (including sour water stripper gas) fed to the 

sulfur recovery plant or the sour gas feed sent off-site for sulfur recovery

(scf/year).

44 = Molecular weight of CO2 (kg/kg-mole).
Page 19 of 54

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 

836.6 scf/kg-mole at 60 °F and 14.7 psia).

MFC = Mole fraction of carbon in the sour gas fed to the sulfur recovery plant or the 

sour gas feed sent off-site for sulfur recovery (kg-mole C/kg-mole gas); default 

= 0.20.

0.001 = Conversion factor, kg to metric tons.

(5) If tail gas is recycled to the front of the sulfur recovery plant and the recycled flow 

rate and carbon content is included in the measured data under paragraphs (f)(2) and (f)(3) of this 

section, respectively, then the annual CO2 emissions calculated in paragraph (f)(4) of this section 

must be corrected to avoid double counting these emissions. You may use engineering estimates 

to perform this correction or assume that the corrected CO2 emissions are 95 percent of the 

uncorrected value calculated using Equation Y-12 of this section.

(g) For coke calcining units, calculate GHG emissions according to the applicable 

provisions in paragraphs (g)(1) through (g)(3) of this section.

(1) If you operate and maintain a CEMS that measures CO2 emissions according to 

subpart C of this part, you must calculate and report CO2 emissions under this subpart by 

following the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). 

You must monitor fuel use in the coke calcining unit that discharges via the final exhaust stack 

from the coke calcining unit and calculate the combustion emissions from the fuel use according 

to subpart C of this part. Calculate the process emissions from the coke calcining unit as the 

difference in the CO2 CEMS emissions and the calculated combustion emissions associated with 

the coke calcining unit final exhaust stack. Other coke calcining units must either install a CEMS 

that complies with the Tier 4 Calculation Methodology in subpart C of this part, or follow the 

requirements of paragraph (g)(2) of this section.
Page 20 of 54

(2) Calculate the CO2 emissions from the coke calcining unit using Equation Y-13 of this 

section.

(Eq. Y-13)

Where:

CO2 = Annual CO2 emissions (metric tons/year).

Min = Annual mass of green coke fed to the coke calcining unit from facility records 

(metric tons/year).

CCGC = Average mass fraction carbon content of green coke from facility measurement 

data (metric ton carbon/metric ton green coke).

Mout = Annual mass of marketable petroleum coke produced by the coke calcining unit 

from facility records (metric tons petroleum coke/year).

Mdust = Annual mass of petroleum coke dust removed from the process through the dust 

collection system of the coke calcining unit from facility records (metric ton 

petroleum coke dust/year). For coke calcining units that recycle the collected 

dust, the mass of coke dust removed from the process is the mass of coke dust 

collected less the mass of coke dust recycled to the process.

CCMPC = Average mass fraction carbon content of marketable petroleum coke produced 

by the coke calcining unit from facility measurement data (metric ton 

carbon/metric ton petroleum coke).

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

(3) For all coke calcining units, use the CO2 emissions from the coke calcining unit 

calculated in paragraphs (g)(1) or (g)(2), as applicable, and calculate CH4 using the methods 

described in paragraph (c)(4) of this section and N2O emissions using the methods described in 

paragraph (c)(5) of this section.

(h) For asphalt blowing operations, calculate CO2 and CH4 emissions according to the 

requirements in paragraph (j) of this section regardless of the CO2 and CH4 concentrations or 

according to the applicable provisions in paragraphs (h)(1) and (h)(2) of this section.
Page 21 of 54

(1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled 

either by vapor scrubbing or by another non-combustion control device, calculate CO2 and CH4

emissions using Equations Y-14 and Y-15 of this section, respectively.

(Eq. Y-14)

Where:

CO2 = Annual CO2 emissions from uncontrolled asphalt blowing (metric tons 

CO2/year).

QAB = Quantity of asphalt blown (million barrels per year, MMbbl/year).

EFAB,CO2 = Emission factor for CO2 from uncontrolled asphalt blowing from facilityspecific test data (metric tons CO2/MMbbl asphalt blown); default = 1,100.

(Eq. Y-15)

Where:

CH4 = Annual methane emissions from uncontrolled asphalt blowing (metric tons 

CH4/year).

QAB = Quantity of asphalt blown (million barrels per year, MMbbl/year).

EFAB,CH4 = Emission factor for CH4 from uncontrolled asphalt blowing from facilityspecific test data (metric tons CH4/MMbbl asphalt blown); default = 580.

(2) For asphalt blowing operations controlled by either a thermal oxidizer, a flare, or

other vapor combustion control device, calculate CO2 using either Equation Y-16a or Equation 

Y-16b of this section and calculate CH4 emissions using Equation Y-17 of this section, provided 

these emissions are not already included in the flare emissions calculated in paragraph (b) of this 

section or in the stationary combustion unit emissions required under subpart C of this part 

(General Stationary Fuel Combustion Sources).

(Eq. Y-16a)
Page 22 of 54

where:

CO2 = Annual CO2 emissions from controlled asphalt blowing (metric tons CO2/year).

0.98 = Assumed combustion efficiency of the control device.

QAB = Quantity of asphalt blown (MMbbl/year).

CEFAB = Carbon emission factor from asphalt blowing from facility-specific test data 

(metric tons C/MMbbl asphalt blown); default = 2,750.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

(Eq. Y-16b)

where:

CO2 = Annual CO2 emissions from controlled asphalt blowing (metric tons CO2/year).

QAB = Quantity of asphalt blown (MMbbl/year).

0.98 = Assumed combustion efficiency of the control device.

EFAB,CO2 = Emission factor for CO2 from uncontrolled asphalt blowing from facilityspecific test data (metric tons CO2/MMbbl asphalt blown); default = 1,100.

CEFAB = Carbon emission factor from asphalt blowing from facility-specific test data 

(metric tons C/MMbbl asphalt blown); default = 2,750.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

(Eq. Y-17)

where:

CH4 = Annual methane emissions from controlled asphalt blowing (metric tons 

CH4/year).

0.02 = Fraction of methane uncombusted in the controlled stream based on assumed 

98% combustion efficiency.
Page 23 of 54

QAB = Quantity of asphalt blown (million barrels per year, MMbbl/year).

EFAB,CH4 = Emission factor for CH4 from uncontrolled asphalt blowing from facilityspecific test data (metric tons CH4/MMbbl asphalt blown); default = 580.

(i) For each delayed coking unit, calculate the CH4 emissions from delayed decoking 

operations (venting, draining, deheading, and coke-cutting) according to the requirements in 

paragraphs (i)(1) through (i)(5).

(1) Determine the typical dry mass of coke produced per cycle from company records of 

the mass of coke produced by the delayed coking unit. Alternatively, you may estimate the 

typical dry mass of coke produced per cycle based on the delayed coking unit vessel (coke drum)

dimensions and typical coke drum outage at the end of the coking cycle using Equation Y-18a of 

this section. 

 

2

coke bulk drum outage

π D

M ρ H H 

4

  

        (Eq. Y-18a)

Where:

Mcoke = Typical dry mass of coke in the delayed coking unit vessel at the end of the 

coking cycle (metric tons/cycle).

ρbulk = Bulk coke bed density (metric tons per cubic feet; mt/ft3). Use the default value 

of 0.0191 mt/ft3.

Hdrum = Internal height of delayed coking unit vessel (feet).

Houtage = Typical distance from the top of the delayed coking unit vessel to the top of the 

coke bed (i.e., coke drum outage) at the end of the coking cycle (feet) from 

company records or engineering estimates.

D = Diameter of delayed coking unit vessel (feet).

(2) Determine the typical mass of water in the delayed coking unit vessel at the end of the 

cooling cycle prior to venting to the atmosphere using Equation Y-18b of this section. 

 

2

coke

water water water

particle

π D M

M ρ H 

4 ρ

  

        (Eq. Y-18b)
Page 24 of 54

Where:

Mwater = Mass of water in the delayed coking unit vessel at the end of the cooling cycle 

just prior to atmospheric venting (metric tons/cycle).

ρwater = Density of water at average temperature of the delayed coking unit vessel at the 

end of the cooling cycle just prior to atmospheric venting (metric tons per cubic 

feet; mt/ft3). Use the default value of 0.0270 mt/ft3.

Hwater = Typical distance from the bottom of the coking unit vessel to the top of the 

water level at the end of the cooling cycle just prior to atmospheric venting 

(feet) from company records or engineering estimates.

Mcoke = Typical dry mass of coke in the delayed coking unit vessel at the end of the 

coking cycle (metric tons/cycle) as determined in paragraph (i)(1) of this 

section.

ρparticle = Particle density of coke (metric tons per cubic feet; mt/ft3). Use the default 

value of 0.0382 mt/ft3.

D = Diameter of delayed coking unit vessel (feet).

(3) Determine the average temperature of the delayed coking unit vessel when the drum 

is first vented to the atmosphere using either Equation Y-18c or Y-18d of this section, as 

appropriate, based on the measurement system available.

Tinitial =(Toverhead+ Tbottom)/2 (Eq. Y-18c)

Where:

Tinitial = Average temperature of the delayed coking unit vessel when the drum is first 

vented to the atmosphere (°F).

Toverhead = Temperature of the delayed coking unit vessel overhead line measured as near 

the coking unit vessel as practical just prior to venting to the atmosphere. If the 

temperature of the delayed coking unit vessel overhead line is less than 216 °F, 

use Toverhead = 216 °F.

Tbottom = Temperature of the delayed coking unit vessel near the bottom of the coke bed.

If the temperature at the bottom of the coke bed is less than 212 °F, use Tbottom = 

212 °F.

Tinitial = -0.039 Poverhead

2

+ 3.13 Poverhead+220		 (Eq. Y-18d)
Page 25 of 54

Where:

Tinitial= Average temperature of the 

Poverhead = Pressure of the 

(4) Determine the typical mass of steam 

 ConvLoss   water p,water coke p,coke   initial final

steam

vap

1 f M C M C T T

M 

H

      





(Eq. Y-18e)

Where:

Msteam = Mass of steam 

fConvLoss = fraction of total heat 

Mwater = Mass of water in the 

Cp,water = Heat capacity of 

Mcoke= Typical dry mass of coke in 

Cp,coke = Heat capacity of 

Tinitial= Average temperature of the 

Tfinal = Temperature of the delayed 

ΔHvap = Heat of vaporization 

(5) Calculate the CH4 emissions from decoking

CH4 s   M E team mFDCU   N 0.001 

(Eq. Y-18f)

Where:

CH4 = Annual methane emissions from the delayed coking unit decoking operations

(metric ton/year).

Msteam = Mass of steam generated and released per decoking cycle (metric tons/cycle) as 

determined in paragraph (i)(3) of this section.

EmFDCU = Methane emission factor for delayed coking unit (kilograms CH4 per metric ton 

of steam; kg CH4/mt steam) from unit-specific measurement data. If you do not 

have unit-specific measurement data, use the default value of 7.9 kg CH4/metric 

ton steam.N = Cumulative number of decoking cycles (or coke-cutting cycles)

for all delayed coking unit vessels associated with the delayed coking unit 

during the year.

0.001 = Conversion factor (metric ton/kg).

(j) For each process vent not covered in paragraphs (a) through (i) of this section that can 

reasonably be expected to contain greater than 2 percent by volume CO2 or greater than 0.5 
Page 26 of 54

percent by volume of CH4 or greater than 0.01 percent by volume (100 parts per million) of N2O, 

calculate GHG emissions using Equation Y-19 of this section. You must also use Equation Y-19 

of this section to calculate CH4 emissions for catalytic reforming unit depressurization and purge 

vents when methane is used as the purge gas, and CO2 and/or CH4 emissions, as applicable, if 

you elected this method as an alternative to the methods in paragraphs (f), (h), or (k) of this 

section.

(Eq. Y-19)

Where:

EX = Annual emissions of each GHG from process vent (metric ton/yr).

N = Number of venting events per year.

P = Index of venting events.

(VR)p = Average volumetric flow rate of process gas during the event (scf per hour) 

from measurement data, process knowledge, or engineering estimates.

(MFX)p = Mole fraction of GHG x in process vent during the event (kg-mol of GHG x/kgmol vent gas) from measurement data, process knowledge, or engineering 

estimates.

MWX = Molecular weight of GHG x (kg/kg-mole); use 44 for CO2 or N2O and 16 for 

CH4.

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 

836.6 scf/kg-mole at 60 °F and 14.7 psia).

(VT)p = Venting time for the event, (hours).

0.001 = Conversion factor (metric ton/kg).

(k) For uncontrolled blowdown systems, you must calculate CH4 emissions either using 

the methods for process vents in paragraph (j) of this section regardless of the CH4 concentration 

or using Equation Y-20 of this section. Blowdown systems where the uncondensed gas stream is 
Page 27 of 54

routed to a flare or similar control device are considered to be controlled and are not required to 

estimate emissions under this paragraph (k).

(Eq. Y-20)

Where:

CH4 = Methane emission rate from blowdown systems (mt CH4/year).

QRef = Quantity of crude oil plus the quantity of intermediate products received from 

off site that are processed at the facility (MMbbl/year).

EFBD = Methane emission factor for uncontrolled blown systems (scf CH4/MMbbl); 

default is 137,000.

16 = Molecular weight of CH4 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 

836.6 scf/kg-mole at 60 °F and 14.7 psia).

0.001 = Conversion factor (metric ton/kg).

(l) For equipment leaks, calculate CH4 emissions using the method specified in either 

paragraph (l)(1) or (l)(2) of this section.

(1) Use process-specific methane composition data (from measurement data or process 

knowledge) and any of the emission estimation procedures provided in the Protocol for 

Equipment Leak Emissions Estimates (EPA-453/R-95-017, NTIS PB96-175401).

(2) Use Equation Y-21 of this section.

(Eq. Y-21)

Where:

CH4 = Annual methane emissions from equipment leaks (metric tons/year).

NCD = Number of atmospheric crude oil distillation columns at the facility.
Page 28 of 54

NPU1 = Cumulative number of catalytic cracking units, coking units (delayed or fluid), 

hydrocracking, and full-range distillation columns (including depropanizer and 

debutanizer distillation columns) at the facility.

NPU2 = Cumulative number of hydrotreating/hydrorefining units, catalytic reforming 

units, and visbreaking units at the facility.

NH2 = Total number of hydrogen plants at the facility.

NFGS = Total number of fuel gas systems at the facility.

(m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate 

CH4 emissions using the applicable methods in paragraphs (m)(1) and (2) of this section.

(1) For storage tanks other than those processing unstabilized crude oil, you must either 

calculate CH4 emissions from storage tanks that have a vapor-phase methane concentration of 

0.5 volume percent or more using tank-specific methane composition data (from measurement 

data or product knowledge) and the emission estimation methods provided in AP 42, Section 7.1 

(incorporated by reference, see §98.7) or estimate CH4 emissions from storage tanks using 

Equation Y-22 of this section.

(Eq. Y-22)

Where:

CH4 = Annual methane emissions from storage tanks (metric tons/year).

0.1 = Default emission factor for storage tanks (metric ton CH4/MMbbl).

QRef = Quantity of crude oil plus the quantity of intermediate products received from 

off site that are processed at the facility (MMbbl/year).

(2) For storage tanks that process unstabilized crude oil, calculate CH4 emissions from 

the storage of unstabilized crude oil using either tank-specific methane composition data (from 

measurement data or product knowledge) and direct measurement of the gas generation rate or 

by using Equation Y-23 of this section.
Page 29 of 54

(Eq. Y-23)

Where:

CH4 = Annual methane emissions from storage tanks (metric tons/year).

Qun = Quantity of unstabilized crude oil received at the facility (MMbbl/year).

ΔP = Pressure differential from the previous storage pressure to atmospheric pressure 

(pounds per square inch, psi).

MFCH4 = Average mole fraction of CH4 in vent gas from the unstabilized crude oil 

storage tanks from facility measurements (kg-mole CH4/kg-mole gas); use 0.27 

as a default if measurement data are not available.

995,000 = Correlation Equation factor (scf gas per MMbbl per psi).

16 = Molecular weight of CH4 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 

836.6 scf/kg-mole at 60 °F and 14.7 psia).

0.001 = Conversion factor (metric ton/kg).

(3) You do not need to calculate CH4 emissions from storage tanks that meet any of the 

following descriptions:

(i) Units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or 

ships;

(ii) Pressure vessels designed to operate in excess of 204.9 kilopascals and without 

emissions to the atmosphere;

(iii) Bottoms receivers or sumps;

(iv) Vessels storing wastewater; or

(v) Reactor vessels associated with a manufacturing process unit.

(n) For crude oil, intermediate, or product loading operations for which the vapor-phase 

concentration of methane is 0.5 volume percent or more, calculate CH4 emissions from loading 
Page 30 of 54

operations using vapor-phase methane composition data (from measurement data or process 

knowledge) and the emission estimation procedures provided in AP 42, Section 5.2 (incorporated 

by reference, see §98.7). For loading operations in which the vapor-phase concentration of 

methane is less than 0.5 volume percent, you may assume zero methane emissions.

§98.254 Monitoring and QA/QC requirements.

(a) Fuel flow meters, gas composition monitors, and heating value monitors that are 

associated with sources that use a CEMS to measure CO2 emissions according to subpart C of 

this part or that are associated with stationary combustion sources must meet the applicable

monitoring and QA/QC requirements in §98.34.

(b) All gas flow meters, gas composition monitors, and heating value monitors that are 

used to provide data for the GHG emissions calculations in this subpart for sources other than 

those subject to the requirements in paragraph (a) of this section shall be calibrated according to 

the procedures specified by the manufacturer, or according to the procedures in the applicable 

methods specified in paragraphs (c) through (g) of this section. In the case of gas flow meters, all 

gas flow meters must meet the calibration accuracy requirements in §98.3(i). All gas flow 

meters, gas composition monitors, and heating value monitors must be recalibrated at the 

applicable frequency specified in paragraph (b)(1) or (b)(2) of this section.

(1) You must recalibrate each gas flow meter according to one of the following 

frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, 

biennially (every two years), or at the interval specified by the industry consensus standard 

practice used.

(2) You must recalibrate each gas composition monitor and heating value monitor 

according to one of the following frequencies. You may recalibrate at the minimum frequency
Page 31 of 54

specified by the manufacturer, annually, or at the interval specified by the industry standard 

practice used.

(c) For flare or sour gas flow meters and gas flow meters used to comply with the 

requirements in §98.253(j), operate, calibrate, and maintain the flow meter according to one of 

the following. You may use the procedures specified by the flow meter manufacturer, or a 

method published by a consensus-based standards organization. Consensus-based standards 

organizations include, but are not limited to, the following: ASTM International (100 Barr 

Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-

1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, 

NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American 

Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 

824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, 

http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).

(d) Except as provided in paragraph (g) of this section, determine gas composition and, if 

required, average molecular weight of the gas using any of the following methods. Alternatively, 

the results of chromatographic analysis of the fuel may be used, provided that the gas 

chromatograph is operated, maintained, and calibrated according to the manufacturer's 

instructions; and the methods used for operation, maintenance, and calibration of the gas 

chromatograph are documented in the written Monitoring Plan for the unit under §98.3(g)(5).

(1) Method 18 at 40 CFR part 60, appendix A-6.
Page 32 of 54

(2) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas 

Chromatography (incorporated by reference, see §98.7).

(3) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed 

Gas by Gas Chromatography (incorporated by reference, see §98.7).

(4) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas 

Chromatography (incorporated by reference, see §98.7).

(5) UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by 

reference, see §98.7).

(6) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular 

Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure 

(incorporated by reference, see §98.7).

(e) Determine flare gas higher heating value using any of the following methods. 

Alternatively, the results of chromatographic analysis of the fuel may be used, provided that the 

gas chromatograph is operated, maintained, and calibrated according to the manufacturer's 

instructions; and the methods used for operation, maintenance, and calibration of the gas 

chromatograph are documented in the written Monitoring Plan for the unit under §98.3(g)(5).

(1) ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid 

Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference, see

§98.7).

(2) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference, see §98.7).
Page 33 of 54

(3) ASTM D1826-94 (Reapproved 2003) Standard Test Method for Calorific (Heating) 

Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated by 

reference, see §98.7).

(4) ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating Heat Value, 

Compressibility Factor, and Relative Density of Gaseous Fuels (incorporated by reference, see

§98.7).

(5) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of 

Gases in Natural Gas Range by Stoichiometric Combustion (incorporated by reference, see

§98.7).

(f) For gas flow meters used to comply with the requirements in §98.253(c)(2)(ii), install, 

operate, calibrate, and maintain each gas flow meter according to the requirements in 40 CFR 

63.1572(c) and the following requirements.

(1) Locate the flow monitor at a site that provides representative flow rates. Avoid 

locations where there is swirling flow or abnormal velocity distributions due to upstream and 

downstream disturbances.

(2) [Reserved]

(3) Use a continuous monitoring system capable of correcting for the temperature, 

pressure, and moisture content to output flow in dry standard cubic feet (standard conditions as 

defined in §98.6).

(g) For exhaust gas CO2/CO/O2 composition monitors used to comply with the 

requirements in §98.253(c)(2), install, operate, calibrate, and maintain exhaust gas composition 

monitors according to the requirements in 40 CFR 60.105a(b)(2) or 40 CFR 63.1572(c) or 

according to the manufacturer's specifications and requirements.
Page 34 of 54

(h) Determine the mass of petroleum coke as required by Equation Y-13 of this subpart 

using mass measurement equipment meeting the requirements for commercial weighing 

equipment as described in Specifications, Tolerances, and Other Technical Requirements For 

Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated by reference, see 

§98.7). Calibrate the measurement device according to the procedures specified by NIST 

handbook 44 (incorporated by reference, see §98.7) or the procedures specified by the 

manufacturer. Recalibrate either biennially or at the minimum frequency specified by the 

manufacturer.

(i) Determine the carbon content of petroleum coke as required by Equation Y-13 of this 

subpart using any one of the following methods. Calibrate the measurement device according to 

procedures specified by the method or procedures specified by the measurement device 

manufacturer.

(1) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal 

and Coke (incorporated by reference, see §98.7).

(2) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for Instrumental 

Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants 

(incorporated by reference, see §98.7).

(3) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see §98.7).

(j) Determine the quantity of petroleum process streams using company records. These 

quantities include the quantity of coke produced per cycle, asphalt blown, quantity of crude oil 

plus the quantity of intermediate products received from off site, and the quantity of unstabilized 

crude oil received at the facility.
Page 35 of 54

(k) Determine temperature or pressure of delayed coking unit vessel using process 

instrumentation operated, maintained, and calibrated according to the manufacturer's 

instructions.

(l) The owner or operator shall document the procedures used to ensure the accuracy of 

the estimates of fuel usage, gas composition, and heating value including but not limited to 

calibration of weighing equipment, fuel flow meters, and other measurement devices. The 

estimated accuracy of measurements made with these devices shall also be recorded, and the 

technical basis for these estimates shall be provided.

§98.255 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations is 

required (e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, 

whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS 

malfunctions during unit operation or if a required fuel sample is not taken), a substitute data 

value for the missing parameter shall be used in the calculations.

(a) For stationary combustion sources, use the missing data procedures in subpart C of 

this part.

(b) For each missing value of the heat content, carbon content, or molecular weight of the 

fuel, substitute the arithmetic average of the quality-assured values of that parameter 

immediately preceding and immediately following the missing data incident. If the “after” value 

is not obtained by the end of the reporting year, you may use the “before” value for the missing 

data substitution. If, for a particular parameter, no quality-assured data are available prior to the 

missing data incident, the substitute data value shall be the first quality-assured value obtained 

after the missing data period.
Page 36 of 54

(c) For missing CO2, CO, O2, CH4, or N2O concentrations, gas flow rate, and percent 

moisture, the substitute data values shall be the best available estimate(s) of the parameter(s), 

based on all available process data (e.g., processing rates, operating hours, etc.). The owner or 

operator shall document and keep records of the procedures used for all such estimates.

(d) For hydrogen plants, use the missing data procedures in subpart P of this part.

§98.256 Data reporting requirements.

In addition to the reporting requirements of §98.3(c), you must report the information 

specified in paragraphs (a) through (q) of this section.

(a) For combustion sources, follow the data reporting requirements under subpart C of 

this part (General Stationary Fuel Combustion Sources).

(b) For hydrogen plants, follow the data reporting requirements under subpart P of this 

part (Hydrogen Production).

(c)-(d) [Reserved]

(e) For flares, owners and operators shall report:

(1) The flare ID number (if applicable).

(2) A description of the type of flare (steam assisted, air-assisted).

(3) A description of the flare service (general facility flare, unit flare, emergency only or 

back-up flare) and an indication of whether or not the flare is serviced by a flare gas recovery

system.

(4) The calculated CO2, CH4, and N2O annual emissions for each flare, expressed in 

metric tons of each pollutant emitted.

(5) A description of the method used to calculate the CO2 emissions for each flare (e.g., 

reference section and equation number).
Page 37 of 54

(6) If you use Equation Y-1a of §98.253, an indication of whether daily or weekly 

measurement periods are used, annual average carbon content of the flare gas (in kg carbon per 

kg flare gas), and, either the annual volume of flare gas combusted (in scf/year) and the annual 

average molecular weight (in kg/kg-mole), or, the annual mass of flare gas combusted (in kg/yr).

(7) If you use Equation Y-1b of §98.253, an indication of whether daily or weekly 

measurement periods are used, the annual volume of flare gas combusted (in scf/year), the 

annual average CO2 concentration (volume or mole percent), the number of carbon containing 

compounds other than CO2 in the flare gas stream, and for each of the carbon containing 

compounds other than CO2 in the flare gas stream:

(i) The annual average concentration of the compound (volume or mole percent).

(ii) [Reserved]

(8) If you use Equation Y-2 of this subpart, an indication of whether daily or weekly 

measurement periods are used, the annual volume of flare gas combusted (in million (MM) 

scf/year), the annual average higher heating value of the flare gas (in mmBtu/mmscf), and an 

indication of whether the annual volume of flare gas combusted and the annual average higher 

heating value of the flare gas were determined using standard conditions of 68 °F and 14.7 psia 

or 60 °F and 14.7 psia.

(9) If you use Equation Y-3 of §98.253, the number of SSM events exceeding 500,000 

scf/day.

(10) The basis for the value of the fraction of carbon in the flare gas contributed by

methane used in Equation Y-4 of §98.253.

(f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming 

units, owners and operators shall report:
Page 38 of 54

(1) The unit ID number (if applicable).

(2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic 

cracking unit, traditional fluid coking unit, or catalytic reforming unit).

(3) Maximum rated throughput of the unit, in bbl/stream day.

(4) The calculated CO2, CH4, and N2O annual emissions for each unit, expressed in 

metric tons of each pollutant emitted.

(5) A description of the method used to calculate the CO2 emissions for each unit (e.g., 

reference section and equation number).

(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 

Calculation Methodology, the CO2 annual emissions as measured by the CEMS (unadjusted to 

remove CO2 combustion emissions associated with additional units, if present) and the process 

CO2 emissions as calculated according to §98.253(c)(1)(ii). Report the CO2 annual emissions 

associated with sources other than those from the coke burn-off in accordance with the 

applicable subpart (e.g., subpart C of this part in the case of a CO boiler).

(7) If you use Equation Y-6 of §98.253, the annual average exhaust gas flow rate, %CO2, 

and %CO.

(8) If you use Equation Y-7a of this subpart, the annual average flow rate of inlet air and 

oxygen-enriched air, %O2, %Ooxy, %CO2, and %CO.

(9) If you use Equation Y-7b of this subpart, the annual average flow rate of inlet air and 

oxygen-enriched air, %N2,oxy, and %N2,exhaust.

(10) If you use Equation Y-8 of §98.253, the basis for the value of the average carbon 

content of coke.
Page 39 of 54

(11) Indicate whether you use a measured value, a unit-specific emission factor, or a 

default for CH4 emissions. If you use a unit-specific emission factor for CH4, report the basis for 

the factor.

(12) Indicate whether you use a measured value, a unit-specific emission factor, or a 

default emission factor for N2O emissions. If you use a unit-specific emission factor for N2O, 

report the basis for the factor.

(13) If you use Equation Y-11 of §98.253, the number of regeneration cycles or 

measurement periods during the reporting year and the average coke burn-off quantity per cycle 

or measurement period.

(g) For fluid coking unit of the flexicoking type, the owner or operator shall report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit.

(3) Maximum rated throughput of the unit, in bbl/stream day.

(4) Indicate whether the GHG emissions from the low heat value gas are accounted for in 

subpart C of this part or §98.253(c).

(5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, 

also report the calculated annual CO2, CH4, and N2O emissions for each unit, expressed in metric 

tons of each pollutant emitted, and the applicable equation input parameters specified in 

paragraphs (f)(7) through (f)(13) of this section.

(h) For on-site sulfur recovery plants and for emissions from sour gas sent off-site for 

sulfur recovery, the owner and operator shall report:

(1) The plant ID number (if applicable).
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(2) For each on-site sulfur recovery plant, the maximum rated throughput (metric tons 

sulfur produced/stream day), a description of the type of sulfur recovery plant, and an indication 

of the method used to calculate CO2 annual emissions for the sulfur recovery plant (e.g., CO2

CEMS, Equation Y-12, or process vent method in §98.253(j)).

(3) The calculated CO2 annual emissions for each on-site sulfur recovery plant, expressed 

in metric tons. The calculated annual CO2 emissions from sour gas sent off-site for sulfur 

recovery, expressed in metric tons.

(4) [Reserved]

(5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether the 

recycled flow rate and carbon content are included in the measured data under §98.253(f)(2) and 

(3). Indicate whether a correction for CO2 emissions in the tail gas was used in Equation Y-12 of 

§98.253. If so, then report:

(i) Indicate whether you used the default (95 percent) or a unit specific correction, and if 

a unit-specific correction was used, report the value of the correction and the approach used.

(ii) If the following data are not used to calculate the recycling correction factor, report 

the information specified in paragraphs (h)(5)(ii)(A) through (B) of this section.

(A) The annual volume of recycled tail gas (in scf/year).

(B) The annual average mole fraction of carbon in the tail gas (in kg-mole C/kg-mole 

gas).

(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 

Calculation Methodology, the CO2 annual emissions as measured by the CEMS and the annual 

process CO2 emissions calculated according to §98.253(f)(1). Report the CO2 annual emissions 
Page 41 of 54

associated with fuel combustion in accordance with subpart C of this part (General Stationary

Fuel Combustion Sources).

(7) If you use the process vent method in §98.253(j) for a non-Claus sulfur recovery

plant, the relevant information required under paragraph (l)(5) of this section.

(i) For coke calcining units, the owner and operator shall report:

(1) The unit ID number (if applicable).

(2) Maximum rated throughput of the unit, in metric tons coke calcined/stream day.

(3) The calculated CO2, CH4, and N2O annual emissions for each unit, expressed in 

metric tons of each pollutant emitted.

(4) A description of the method used to calculate the CO2 emissions for each unit (e.g., 

reference section and equation number).

(5) If you use Equation Y-13 of §98.253, an indication of whether coke dust is recycled 

to the unit (e.g., all dust is recycled, a portion of the dust is recycled, or none of the dust is 

recycled).

(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 

Calculation Methodology, the CO2 annual emissions as measured by the CEMS and the annual 

process CO2 emissions calculated according to §98.253(g)(1). 

(7) Indicate whether you use a measured value, a unit-specific emission factor or a 

default emission factor for CH4 emissions. If you use a unit-specific emission factor for CH4, 

report the basis for the factor.

(8) Indicate whether you use a measured value, a unit-specific emission factor, or a 

default emission factor for N2O emissions. If you use a unit-specific emission factor for N2O, 

report the basis for the factor.
Page 42 of 54

(j) For asphalt blowing operations, the owner or operator shall report:

(1) The unit ID number (if applicable).

(2) [Reserved]

(3) The type of control device used to reduce methane (and other organic) emissions from 

the unit.

(4) The calculated annual CO2 and CH4 emissions for each unit, expressed in metric tons 

of each pollutant emitted.

(5) If you use Equation Y-14 of §98.253, the basis for the CO2 emission factor used.

(6) If you use Equation Y-15 of §98.253, the basis for the CH4 emission factor used.

(7) If you use Equation Y-16a of §98.253, the basis for the carbon emission factor used.

(8) If you use Equation Y-16b of §98.253, the basis for the CO2 emission factor used and 

the basis for the carbon emission factor used.

(9) If you use Equation Y-17 of §98.253, the basis for the CH4 emission factor used.

(10) If you use Equation Y-19 of this subpart, the relevant information required under 

paragraph (l)(5) of this section.

(k) For each delayed coking unit, the owner or operator shall report:

(1) The unit ID number (if applicable).

(2) Maximum rated throughput of the unit, in bbl/stream day.

(3) Annual quantity of coke produced in the unit during the reporting year, in metric tons.

(4) The calculated annual CH4 emissions (in metric tons of CH4) for the delayed coking 

unit.

(5) The total number of delayed coking vessels (or coke drums) associated with the 

delayed coking unit.
Page 43 of 54

(6) The basis for the typical dry mass of coke in the delayed coking unit vessel at the end 

of the coking cycle (mass measurements from company records or calculated using Equation Y18a).

(7) An indication of the method used to estimate the average temperature of the coke bed, 

Tinitial (overhead temperature and Equation Y-18c or pressure correlation and Equation Y-18d).

(8) An indication of whether a unit-specific methane emissions factor or the default 

methane emission factor was used for the delayed coking unit.

(l) For each process vent subject to §98.253(j), the owner or operator shall report:

(1) The vent ID number (if applicable).

(2) The unit or operation associated with the emissions.

(3) The type of control device used to reduce methane (and other organic) emissions from 

the unit, if applicable.

(4) The calculated annual CO2, CH4, and N2O emissions for each vent, expressed in 

metric tons of each pollutant emitted.

(5) The annual volumetric flow discharged to the atmosphere (in scf), and an indication 

of the measurement or estimation method, annual average mole fraction of each GHG above the 

concentration threshold or otherwise required to be reported and an indication of the 

measurement or estimation method, and for intermittent vents, the number of venting events and 

the cumulative venting time.

(m) For uncontrolled blowdown systems, the owner or operator shall report:

(1) An indication of whether the uncontrolled blowdown emission are reported under 

§98.253(k) or §98.253(j) or a statement that the facility does not have any uncontrolled 

blowdown systems.
Page 44 of 54

(2) The cumulative annual CH4 emissions (in metric tons of CH4) for uncontrolled 

blowdown systems.

(3) For uncontrolled blowdown systems reporting under §98.253(k), the basis for the 

value of the methane emission factor used for uncontrolled blowdown systems.

(4) For uncontrolled blowdown systems reporting under §98.253(j), the relevant 

information required under paragraph (l)(5) of this section.

(n) For equipment leaks, the owner or operator shall report:

(1) The cumulative CH4 emissions (in metric tons of each pollutant emitted) for all 

equipment leak sources.

(2) The method used to calculate the reported equipment leak emissions.

(3) The number of each type of emission source listed in Equation Y-21 of this subpart at 

the facility.

(o) For storage tanks, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of CH4) for all storage tanks, 

except for those used to process unstabilized crude oil.

(2) For storage tanks other than those processing unstabilized crude oil:

(i) The method used to calculate the reported storage tank emissions for storage tanks 

other than those processing unstabilized crude (i.e., either AP 42, Section 7.1 (incorporated by 

reference, see §98.7), or Equation Y-22 of this section).

(ii) [Reserved]

(3) The cumulative CH4 emissions (in metric tons of CH4) for storage tanks used to 

process unstabilized crude oil or a statement that the facility did not receive any unstabilized 

crude oil during the reporting year.
Page 45 of 54

(4) For storage tanks that process unstabilized crude oil:

(i) The method used to calculate the reported unstabilized crude oil storage tank 

emissions.

(ii)-(iv) [Reserved]

(v) The basis for the mole fraction of CH4 in vent gas from unstabilized crude oil storage 

tanks.

(vi) If you did not use Equation Y-23, the tank-specific methane composition data and the

annual gas generation volume (scf/yr) used to estimate the cumulative CH4 emissions for storage 

tanks used to process unstabilized crude oil.

(5)-(7) [Reserved]

(p) For loading operations, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for 

loading operations.

(2) The types of materials loaded that have an equilibrium vapor-phase concentration of 

methane of 0.5 volume percent or greater, and the type of vessel (barge, tanker, marine vessel, 

etc.) in which each type of material is loaded.

(3) The type of control system used to reduce emissions from the loading of material with 

an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, if any

(submerged loading, vapor balancing, etc.).

(q) Name of each method listed in §98.254 or a description of manufacturer's 

recommended method used to determine a measured parameter.
Page 46 of 54

§98.257 Records that must be retained.

In addition to the records required by §98.3(g), you must retain the records specified in 

paragraphs (a) and (b) of this section.

(a) The records of all parameters monitored under §98.255. If you comply with the 

combustion methodology in §98.252(a), then you must retain under this subpart the records 

required for the Tier 3 and/or Tier 4 Calculation Methodologies in §98.37 and you must keep 

records of the annual average flow calculations.

(b) Verification software records. You must keep a record of the file generated by the 

verification software specified in §98.5(b) for the applicable data specified in paragraphs (b)(1) 

through (73) of this section. Retention of this file satisfies the recordkeeping requirement for the 

data in paragraphs (b)(1) through (73) of this section.

(1) Volume of flare gas combusted during measurement period (scf) (Equation Y-1b of 

§98.253).

(2) Mole percent CO2 concentration in the flare gas stream during the measurement 

period (mole percent) (Equation Y-1b).

(3) Mole percent concentration of compound “x” in the flare gas stream during the 

measurement period (mole percent) (Equation Y-1b).

(4) Carbon mole number of compound “x” in the flare gas stream during the 

measurement period (mole carbon atoms per mole compound) (Equation Y-1b).

(5) Molar volume conversion factor (scf per kg-mole) (Equation Y-1b).

(6) Annual volume of flare gas combusted for each flare during normal operations from 

company records (million (MM) standard cubic feet per year, MMscf/year) (Equation Y-3 of 

§98.253).
Page 47 of 54

(7) Higher heating value for fuel gas or flare gas for each flare from company records 

(British thermal units per scf, Btu/scf = MMBtu/MMscf) (Equation Y-3).

(8) Volume of flare gas combusted during indexed start-up, shutdown, or malfunction 

event from engineering calculations (scf) (Equation Y-3).

(9) Average molecular weight of the flare gas, from the analysis results or engineering 

calculations for the event (kg/kg-mole) (Equation Y-3).

(10) Molar volume conversion factor (scf per kg-mole) (Equation Y-3).

(11) Average carbon content of the flare gas, from analysis results or engineering 

calculations for the event (kg C per kg flare gas) (Equation Y-3).

(12) Weight fraction of carbon in the flare gas prior to combustion in each flare that is 

contributed by methane from measurement values or engineering calculations (kg C in methane 

in flare gas/kg C in flare gas) (Equation Y-4 of §98.253).

(13) Annual throughput of unit from company records for each catalytic cracking unit or 

fluid coking unit (barrels/year) (Equation Y-8 of §98.253).

(14) Coke burn-off factor from engineering calculations (default for catalytic cracking 

units = 7.3; default for fluid coking units = 11) (kg coke per barrel of feed) (Equation Y-8).

(15) Carbon content of coke based on measurement or engineering estimate (kg C per kg 

coke) (Equation Y-8).

(16) Value of unit-specific CH4 emission factor, including the units of measure, for each 

catalytic cracking unit, traditional fluid coking unit, catalytic reforming unit, and coke calcining 

unit (calculation method in §98.253(c)(4)).

(17) Annual activity data (e.g., input or product rate), including the units of measure, in 

units of measure consistent with the emission factor, for each catalytic cracking unit, traditional 
Page 48 of 54

fluid coking unit, catalytic reforming unit, and coke calcining unit (calculation method in 

§98.253(c)(4)).

(18) Value of unit-specific N2O emission factor, including the units of measure, for each 

catalytic cracking unit, traditional fluid coking unit, catalytic reforming unit, and coke calcining 

unit (calculation method in §98.253(c)(5)).

(19) Annual activity data (e.g., input or product rate), including the units of measure, in 

units of measure consistent with the emission factor, for each catalytic cracking unit, traditional 

fluid coking unit, catalytic reforming unit, and coke calcining unit (calculation method in 

§98.253(c)(5)).

(20) Carbon content of coke based on measurement or engineering estimate (default = 

0.94) (kg C per kg coke) (Equation Y-11 of §98.253).

(21) Volumetric flow rate of sour gas (including sour water stripper gas) feed sent off site 

for sulfur recovery in the year (scf/year) (Equation Y-12 of §98.253).

(22) Mole fraction of carbon in the sour gas feed sent off site for sulfur recovery (kgmole C/kg-mole gas) (Equation Y-12).

(23) Molar volume conversion factor for sour gas sent off site (scf per kg-mole) 

(Equation Y-12).

(24) Volumetric flow rate of sour gas (including sour water stripper gas) fed to the onsite 

sulfur recovery plant (scf/year) (Equation Y-12).

(25) Mole fraction of carbon in the sour gas fed to the onsite sulfur recovery plant (kgmole C/kg-mole gas) (Equation Y-12).

(26) Molar volume conversion factor for onsite sulfur recovery plant (scf per kg-mole) 

(Equation Y-12).
Page 49 of 54

(27) Annual mass of green coke fed to the coke calcining unit from facility records 

(metric tons/year) (Equation Y-13 of §98.253).

(28) Annual mass of marketable petroleum coke produced by the coke calcining unit 

from facility records (metric tons/year) (Equation Y-13).

(29) Annual mass of petroleum coke dust removed from the process through the dust 

collection system of the coke calcining unit from facility records. For coke calcining units that 

recycle the collected dust, the mass of coke dust removed from the process is the mass of coke 

dust collected less the mass of coke dust recycled to the process (metric tons/year) (Equation Y13).

(30) Average mass fraction carbon content of green coke from facility measurement data 

(metric tons C per metric ton green coke) (Equation Y-13).

(31) Average mass fraction carbon content of marketable petroleum coke produced by the 

coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke 

(Equation Y-13).

(32) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year 

(MMbbl/year)) (Equation Y-14 of §98.253).

(33) Emission factor for CO2 from uncontrolled asphalt blowing from facility-specific 

test data for each asphalt blowing unit (metric tons CO2/MMbbl asphalt blown) (Equation Y-14).

(34) Emission factor for CH4 from uncontrolled asphalt blowing from facility-specific 

test data for each asphalt blowing unit (metric tons CH4/MMbbl asphalt blown) (Equation Y-15 

of §98.253).

(35) Quantity of asphalt blown (million barrels/year (MMbbl/year)) (Equation Y-16a of 

§98.253).
Page 50 of 54

(36) Carbon emission factor from asphalt blowing from facility-specific test data (metric 

tons C/MMbbl asphalt blown) (Equation Y-16a).

(37) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year 

(MMbbl/year)) (Equation Y-16b of §98.253).

(38) Emission factor for CO2 from uncontrolled asphalt blowing from facility-specific 

test data for each asphalt blowing unit (metric tons CO2/MMbbl asphalt blown) (Equation Y16b).

(39) Carbon emission factor from asphalt blowing from facility-specific test data for each 

asphalt blowing unit (metric tons C/MMbbl asphalt blown) (Equation Y-16b).

(40) Emission factor for CH4 from uncontrolled asphalt blowing from facility-specific 

test data for each asphalt blowing unit (metric tons CH4/MMbbl asphalt blown) (Equation Y-17 

of §98.253).

(41) Typical dry mass of coke in the delayed coking unit vessel at the end of the coking 

cycle (metric tons/cycle) from company records or calculated using Equation Y-18a (Equations 

Y-18a, Y-18b and Y-18e of § 98.253) for each delayed coking unit. (42) Internal height of 

delayed coking unit vessel (feet) (Equation Y-18a) for each delayed coking unit.

(43) Typical distance from the top of the delayed coking unit vessel to the top of the coke 

bed (i.e., coke drum outage) at the end of the coking cycle (feet) from company records or 

engineering estimates (Equation Y-18a) for each delayed coking unit.

(44) Diameter of delayed coking unit vessel (feet) (Equation Y-18a and Y-18b) for each 

delayed coking unit.
Page 51 of 54

(45) Mass of water in the delayed coking unit vessel at the end of the cooling cycle prior 

to atmospheric venting (metric ton/cycle) (Equations Y-18b and Y-18e) for each delayed coking 

unit.

(46) Typical distance from the bottom of the coking unit vessel to the top of the water 

level at the end of the cooling cycle just prior to atmospheric venting (feet) from company 

records or engineering estimates (Equation Y-18b) for each delayed coking unit.

(47) Mass of steam generated and released per decoking cycle (metric tons/cycle) 

(Equations Y-18e and Y-18f of § 98.253) for each delayed coking unit.

(48) Average temperature of the delayed coking unit vessel when the drum is first vented 

to the atmosphere (°F) (Equations Y-18c, Y-18d, and Y-18e of § 98.253) for each delayed 

coking unit.

(49) Temperature of the delayed coking unit vessel overhead line measured as near the 

coking unit vessel as practical just prior to venting the atmosphere (Equation Y-18c) for each 

delayed coking unit.

(50) Pressure of the delayed coking unit vessel just prior to opening the atmospheric vent

(psig) (Equation Y-18d) for each delayed coking unit.

(51) Methane emission factor for delayed coking unit (kilograms CH4 per metric ton of 

steam; kg CH4/mt steam) (Equation Y-18f) for each delayed coking unit.

(52) Cumulative number of decoking cycles (or coke-cutting cycles) for all delayed 

coking unit vessels associated with the delayed coking unit during the year (Equation Y-18f) for 

each delayed coking unit.
Page 52 of 54

(53) Average volumetric flow rate of process gas during the event from measurement 

data, process knowledge, or engineering estimates for each set of coke drums or vessels of the 

same size (scf per hour) (Equation Y-19 of §98.253).

(54) Mole fraction of methane in process vent during the event from measurement data, 

process knowledge, or engineering estimates for each set of coke drums or vessels of the same 

size (kg-mole CH4/kg-mole gas) (Equation Y-19).

(55) Venting time for the event for each set of coke drums or vessels of the same size 

(hours) (Equation Y-19).

(56) Molar volume conversion factor for each set of coke drums or vessels of the same 

size (scf per kg-mole) (Equation Y-19).

(57) Quantity of crude oil plus the quantity of intermediate products received from off 

site that are processed at the facility (MMbbl/year) (Equation Y-20 of §98.253).

(58) Molar volume conversion factor (scf per kg-mole) (Equation Y-20).

(59) Methane emission factor for uncontrolled blown systems (scf CH4/MMbbl) 

(Equation Y-20).

(60) Quantity of crude oil plus the quantity of intermediate products received from off 

site that are processed at the facility (MMbbl/year) (Equation Y-22 of §98.253).

(61) Quantity of unstabilized crude oil received at the facility (MMbbl/year) (Equation Y23 of §98.253).

(62) Pressure differential from the previous storage pressure to atmospheric pressure (psi) 

(Equation Y-23).

(63) Average mole fraction of CH4 in vent gas from the unstabilized crude oil storage 

tanks from facility measurements (kg-mole CH4/kg-mole gas) (Equation Y-23).
Page 53 of 54

(64) Molar volume conversion factor (scf per kg-mole) (Equation Y-23).

(65) Specify whether the calculated or default loading factor L specified in §98.253(n) is 

entered, for each liquid loaded to each vessel (methods specified in §98.253(n)).

(66) Saturation factor specified in §98.253(n), for each liquid loaded to each vessel 

(methods specified in §98.253(n)).

(67) True vapor pressure of liquid loaded, for each liquid loaded to each vessel (psia) 

(methods specified in §98.253(n)).

(68) Molecular weight of vapors (lb per lb-mole), for each liquid loaded to each vessel 

(methods specified in §98.253(n)).

(69) Temperature of bulk liquid loaded, for each liquid loaded to each vessel (°R, degrees 

Rankine) (methods specified in §98.253(n)).

(70) Total loading loss (without efficiency correction), for each liquid loaded to each 

vessel (pounds per 1000 gallons loaded) (methods specified in §98.253(n)).

(71) Overall emission control system reduction efficiency, including the vapor collection 

system efficiency and the vapor recovery or destruction efficiency (enter zero if no emission 

controls), for each liquid loaded to each vessel (percent) (methods specified §98.253(n)).

(72) Vapor phase concentration of methane in liquid loaded, for each liquid loaded to 

each vessel (percent by volume) (methods specified in §98.253(n)).

(73) Quantity of material loaded, for each liquid loaded to each vessel (thousand gallon 

per year) (methods specified in §98.253(n)).

§98.258 Definitions.

All terms used in this subpart have the same meaning given in the Clean Air Act and 

subpart A of this part.
Page 54 of 54