['Air Programs']
['Greenhouse Gases']
03/13/2024
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(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 (3) of this section. All gas discharged through the flare stack must be included in 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).
(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.
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.
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 measurement data are available, you must use daily values when using Equation Y–2 of this section; otherwise, use weekly values.
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.
(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.
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).
(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.
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.
Where:
N2O = Annual nitrous oxide emissions from flared gas (metric tons N2O/year).
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.
(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.
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.
(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.
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.
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 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.
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.
Where:
CH4 = Annual methane emissions from coke burn-off (metric tons CH4/year).
CO2 = Emission rate of CO2 from coke burnoff 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.
Where:
N2O = Annual nitrous oxide emissions from coke burn-off (mt N2O/year).
CO2 = Emission rate of CO2 from coke burnoff 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) 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.
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).
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) Other sulfur recovery plants must either install a CEMS that complies with the Tier 4 Calculation Methodology in 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. 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 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.
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).
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.
(2) Calculate the CO2 emissions from the coke calcining unit using Equation Y–13 of this section.
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.
(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.
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 facility-specific test data (metric tons CO2/MMbbl asphalt blown); default = 1,100.
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 facility-specific 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 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).
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).
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 facility-specific 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).
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.
QAB = Quantity of asphalt blown (million barrels per year, MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from uncontrolled asphalt blowing from facility-specific 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 (5) of this section.
(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.
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.
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.
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.
Where:
Tinitial = Average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere (°F).
Poverhead = Pressure of the delayed coking unit vessel just prior to opening the atmospheric vent (pounds per square inch gauge, psig).
(4) Determine the typical mass of steam generated and released per decoking cycle using Equation Y-18e of this section.
Where:
Msteam = Mass of steam generated and released per decoking cycle (metric tons/cycle).
fConvLoss = fraction of total heat loss that is due to convective heat loss from the sides of the coke vessel (unitless). Use the default value of 0.10.
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).
Cp,water = Heat capacity of water (British thermal units per metric ton per degree Fahrenheit; Btu/mt-°F). Use the default value of 2,205 Btu/mt-°F.
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.
Cp,coke = Heat capacity of petroleum coke (Btu/mt-°F). Use the default value of 584 Btu/mt-°F.
Tinitial = Average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere (°F) as determined in paragraph (i)(3) of this section.
Tfinal = Temperature of the delayed coking unit vessel when steam generation stops (°F). Use the default value of 212°F.
ΔHvap = Heat of vaporization of water (British thermal units per metric ton; Btu/mt). Use the default value of 2,116,000 Btu/mt.
(5) Calculate the CH4 emissions from decoking operations at each delayed coking unit using Equation Y-18f of this section.
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 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 paragraph (f), (h), or (k) of this section.
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/kg-mol vent gas) from measurement data, process knowledge, or engineering estimates.
MWx = Molecular weight of GHG x (kg/kgmole); use 44 for CO2 or N2O and 16 for CH4.
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
(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 routed to a flare or similar control device are considered to be controlled and are not required to estimate emissions under this paragraph (k).
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.
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.
Where:
CH4 = Annual methane emissions from equipment leaks (metric tons/year).
NCD = Number of atmospheric crude oil distillation columns at the facility.
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. [Change Notice][Previous Text]
(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.
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.
Where:
CH4 = Annual methane emissions from storage tanks (metric tons/year).
Qun = Quantity of unstabilized crude oil received at the facility (MMbbl/year).
∆P = 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).
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 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.
[74 FR 56451, Oct. 30, 2009; 75 FR 79160, Dec. 17, 2010; 78 FR 71963, Nov. 29, 2013; 81 FR 89261, Dec. 9, 2016]
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['Greenhouse Gases']