(a) Calculate GHG emissions required to be reported in Sec. 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.
(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.[GRAPHIC] [TIFF OMITTED] TR17DE10.005 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 [deg]F and
14.7 pounds per square inch absolute (psia) or 836.6 scf/kg-
mole at 60 [deg]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.
[GRAPHIC] [TIFF OMITTED] TR17DE10.006
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 [deg]F and
14.7 psia or 836.6 scf/kg-mole at 60 [deg]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.[GRAPHIC] [TIFF OMITTED] TR30OC09.088 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 x Flare[kg] x MVC/(MW)p, where MVC is the
molar volume conversion factor [849.5 scf/kg-mole at 68 [deg]F
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]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 heating value measured for the fuel gas for the heating value of the flare gas. If heating value is not measured, the heating value may be estimated from historic data or engineering calculations.
(C) Calculate the CO2 emissions using Equation Y-3 of this section. [GRAPHIC] [TIFF OMITTED] TR30OC09.089 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 [deg]F and
14.7 psia or 836.6 scf/kg-mole at 60 [deg]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. [GRAPHIC] [TIFF OMITTED] TR30OC09.090 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. [GRAPHIC] [TIFF OMITTED] TR30OC09.091 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 Sec. 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. [GRAPHIC] [TIFF OMITTED] TR30OC09.092 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 [deg]F and
14.7 psia or 836.6 scf/kg-mole at 60 [deg]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.[GRAPHIC] [TIFF OMITTED] TR17DE10.007 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.
[GRAPHIC] [TIFF OMITTED] TR17DE10.008
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. [GRAPHIC] [TIFF OMITTED] TR30OC09.094 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. [GRAPHIC] [TIFF OMITTED] TR30OC09.095 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/
(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. [GRAPHIC] [TIFF OMITTED] TR30OC09.096 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/
(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.[GRAPHIC] [TIFF OMITTED] TR30OC09.097 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) 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 Sec. 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.[GRAPHIC] [TIFF OMITTED] TR30OC09.098 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 [deg]F and
14.7 psia or 836.6 scf/kg-mole at 60 [deg]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 Sec. 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.[GRAPHIC] [TIFF OMITTED] TR30OC09.099 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 by vapor scrubbing, calculate CO2 and CH4 emissions using Equations Y-14 and Y-15 of this section, respectively.[GRAPHIC] [TIFF OMITTED] TR30OC09.100 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.
[GRAPHIC] [TIFF OMITTED] TR30OC09.101
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 thermal oxidizer or flare, 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).[GRAPHIC] [TIFF OMITTED] TR17DE10.009 where: CO2 = Annual CO2 emissions from controlled asphalt
blowing (metric tons CO2/year).0.98 = Assumed combustion efficiency of thermal oxidizer or flare.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).[GRAPHIC] [TIFF OMITTED] TR17DE10.010 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 thermal oxidizer or flare.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).[GRAPHIC] [TIFF OMITTED] TR17DE10.011 where: CH4 = Annual methane emissions from controlled asphalt
blowing (metric tons CH4/year).0.02 = Fraction of methane uncombusted in thermal oxidizer or flare
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 delayed coking units, calculate the CH4 emissions from the depressurization of the coking unit vessel (i.e., the ``coke drum'') to atmosphere using either of the methods provided in paragraphs (i)(1) or (i)(2), provided no water or steam is added to the vessel once it is vented to the atmosphere. You must use the method in paragraph (i)(1) of this section if you add water or steam to the vessel after it is vented to the atmosphere.
(1) Use the process vent method in paragraph (j) of this section to calculate the CH4 emissions from the depressurization of the coke drum or vessel regardless of the CH4 concentration and also calculate the CH4 emissions from the subsequent opening of the vessel for coke cutting operations using Equation Y-18 of this section. If you have coke drums or vessels of different dimensions, use the process vent method in paragraph (j) of this section and Equation Y-18 for each set of coke drums or vessels of the same size and sum the resultant emissions across each set of coke drums or vessels to calculate the CH4 emissions for all delayed coking units.[GRAPHIC] [TIFF OMITTED] TR30OC09.104 Where: CH4 = Annual methane emissions from the delayed coking unit
vessel opening (metric ton/year).N = Cumulative number of vessel openings for all delayed coking unit
vessels of the same dimensions during the year.H = Height of coking unit vessel (feet).PCV = Gauge pressure of the coking vessel when opened to the
atmosphere prior to coke cutting or, if the alternative method
provided in paragraph (i)(2) of this section is used, gauge
pressure of the coking vessel when depressurization gases are
first routed to the atmosphere (pounds per square inch gauge,
psig).14.7 = Assumed atmospheric pressure (pounds per square inch, psi).fvoid = Volumetric void fraction of coking vessel prior to
steaming (cf gas/cf of vessel); default = 0.6.D = Diameter of coking unit vessel (feet).16 = Molecular weight of CH4 (kg/kg-mole).MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F and
14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).MFCH4 = Mole fraction of methane in coking vessel gas (kg-
mole CH4/kg-mole gas, wet basis); default value is
0.01.0.001 = Conversion factor (metric ton/kg).
(2) Calculate the CH4 emissions from the depressurization vent and subsequent opening of the vessel for coke cutting operations using Equation Y-18 of this section and the pressure of the coking vessel when the depressurization gases are first routed to the atmosphere. If you have coke drums or vessels of different dimensions, use Equation Y-18 for each set of coke drums or vessels of the same size and sum the resultant emissions across each set of coke drums or vessels to calculate the CH4 emissions for all delayed coking units.
(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, CH4 emissions if you elected to use the method in paragraph (i)(1) of this section, 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.[GRAPHIC] [TIFF OMITTED] TR30OC09.105 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/kg-mole); use 44 for
CO2 or N2O and 16 for CH4.MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F and
14.7 psia or 836.6 scf/kg-mole at 60 [deg]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 routed to a flare or similar control device are considered to be controlled and are not required to estimate emissions under this paragraph (k).[GRAPHIC] [TIFF OMITTED] TR30OC09.106 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 [deg]F and
14.7 psia or 836.6 scf/kg-mole at 60 [deg]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.
[GRAPHIC] [TIFF OMITTED] TR30OC09.107
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.
(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 Sec. 98.7) or estimate CH4 emissions from storage tanks using Equation Y-22 of this section.[GRAPHIC] [TIFF OMITTED] TR30OC09.108 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.[GRAPHIC] [TIFF OMITTED] TR30OC09.109 Where: CH4 = Annual methane emissions from storage tanks (metric
tons/year).Qun = Quantity of unstabilized crude oil received at the
facility (MMbbl/year).[Delta]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 at 68 [deg]F and
14.7 psia or 836.6 scf/kg-mole at 60 [deg]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 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 Sec. 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 56374, Oct. 30, 2009, as amended at 75 FR 79160, Dec. 17, 2010; 78 FR 71963, Nov. 29, 2013]