(2)  If you have a continuous gas composition analyzer on gas to the flare, you must use these compositions in calculating emissions.  If you do not have a continuous gas composition analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare as follows:
(i)  For onshore natural gas production, determine natural gas composition using (u)(2)(i) of this section.
(ii)  For onshore natural gas processing, when the stream going to flare is natural gas,  use the GHG mole percent in feed natural gas for all streams upstream of the de-methanizer or dew point control, and GHG mole percent in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities.
(iii)  When the stream going to the flare is a hydrocarbon product stream, such as ethane, propane, butane, pentane-plus and mixed light hydrocarbons, then use a representative composition from the source for the stream determined by engineering calculation based on process knowledge and best available data.
(3)  Determine flare combustion efficiency from manufacturer.  If not available, assume that flare combustion efficiency is 98 percent.
(4)  Calculate GHG volumetric emissions at actual conditions using Equations W-19, W-20, and W-21 of this section.
		(Eq. W-19)
	 	(Eq. W-20)
		(Eq. W-21)
Where:
Ea,CH4(un-combusted)	=	Contribution of annual un-combusted CH4 emissions from flare stack in cubic feet, under actual conditions.
Ea,CO2(un-combusted)	=	Contribution of annual un-combusted CO2 emissions from flare stack in cubic feet, under actual conditions.
Ea,CO2(combusted)	=	Contribution of annual combusted CO2 emissions from flare stack in cubic feet, under actual conditions.
Va	=	Volume of gas sent to flare in cubic feet, during the year.
η	=	Fraction of gas combusted by a burning flare (default is 0.98).  For gas sent to an unlit flare, η is zero.
XCH4	= 	Mole fraction of CH4 in gas to the flare.
XCO2	= 	Mole fraction of CO2 in gas to the flare.
Yj 	=	Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes-plus).
Rj	=	Number of carbon atoms in the gas hydrocarbon constituent j: 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus).
(5)  Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(6)  Calculate both CH4 and CO2 mass emissions from volumetric CH4 and CO2 emissions using calculation in paragraph (v) of this section.
(7)  Calculate total annual emission from flare stacks by summing Equation W-40, Equation W-19, Equation W-20 and Equation W-21 of this section.
(8)  Calculate N2O emissions from flare stacks using Equation W-40 in paragraph (z) of this section.
(9)  The flare emissions determined under paragraph (n) of this section must be corrected for flare emissions calculated and reported under other paragraphs of this section to avoid double counting of these emissions.
(o)  Centrifugal compressor venting.  Calculate CH4, CO2 and N2O (when flared) emissions from both wet seal and dry seal centrifugal compressor vents as follows:
(1)  For each centrifugal compressor covered by §98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) you must conduct an annual measurement in the operating mode in which it is found.  Measure emissions from all vents (including emissions manifolded to common vents) including wet seal oil degassing vents, unit isolation valve vents, and blowdown valve vents.  Record emissions from the following vent types in the specified compressor modes during the annual measurement.
      (i)  Operating mode, blowdown valve leakage through the blowdown vent, wet seal and dry seal compressors.
      (ii)  Operating mode, wet seal oil degassing vents.
      (iii)  Not operating, depressurized mode, unit isolation valve leakage through open blowdown vent, without blind flanges, wet seal and dry seal compressors.
      (A)  For the not operating, depressurized mode, each compressor must be measured at least once in any three consecutive calendar years.  If a compressor is not operated and has blind flanges in place throughout the 3 year period, measurement is not required in this mode.  If the compressor is in standby depressurized mode without blind flanges in place and is not operated throughout the 3 year period, it must be measured in the standby depressurized mode.
      (2)  For wet seal oil degassing vents, determine vapor volumes sent to an atmospheric vent or flare, using a temporary meter such as a vane anemometer or permanent flow meter according to 98.234(b) of this section.  If you do not have a permanent flow meter, you may install a permanent flow meter on the wet seal oil degassing tank vent.
      (3)  For blowdown valve leakage and unit isolation valve leakage to open ended vents, you can use one of the following methods:  calibrated bagging or high volume sampler according to methods set forth in §98.234(c) and §98.234(d), respectively.  For through valve leakage, such as isolation valves, you may use an acoustic leak detection device according to methods set forth in §98.234(a).  If you do not have a flow meter, you may install a port for insertion of a temporary meter, or a permanent flow meter, on the vents.
(4)  Estimate annual emissions using the flow measurement and Equation W-22 of this section.
                                  	(Eq. W-22)
Where:
Es,i,m	=	Annual GHG i (either CH4 or CO2) volumetric emissions at standard conditions, in cubic feet.
MTm	=	Measured gas emissions in standard cubic feet per hour.
Tm	=	Total time the compressor is in the mode for which Es,i is being calculated, in the calendar year in hours.
Mi,m	=	Mole fraction of GHG i in the vent gas; use the appropriate gas compositions in paragraph (u)(2) of this section.
Bm	=	Fraction of operating time that the vent gas is sent to vapor recovery or fuel gas as determined by keeping logs of the number of operating hours for the vapor recovery system and the time that vent gas is directed to the fuel gas system or sales.
(5)  Calculate annual emissions from each centrifugal compressor using Equation W-23 of this section.
		(Eq. W-23)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from each centrifugal compressor in cubic feet.
EFm	=	Reporter emission factor for each mode m, in cubic feet per hour, from Equation W-24 of this section as calculated in paragraph 6.
Tm	=	Total time in hours per year the compressor was in each mode, as listed in paragraph (o)(1)(i) through (o)(1)(iii).
GHGi	=	For onshore natural gas processing facilities, concentration of GHG i, CH4 or CO2, in produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8),GHGi equals 1.
(6)  You shall use the flow measurements of operating mode wet seal oil degassing vent, operating mode blowdown valve vent and not operating depressurized mode isolation valve vent for all the reporter's compressor modes not measured in the calendar year to develop the following emission factors using Equation W-24 of this section for each emission source and mode as listed in paragraph (o)(1)(i) through (o)(1)(iii).
		(Eq. W-24)
Where:
EFm	=	Reporter emission factors for compressor in the three modes m (as listed in paragraph (o)(1)(i) through (o)(1)(iii)) in cubic feet per hour.
MTm	=	Flow Measurements from all centrifugal compressor vents in each mode in (o)(1)(i) through (o)(1)(iii) of this section in cubic feet per hour.
Countm	=	Total number of compressors measured.
m	=	Compressor mode as listed in paragraph (o)(1)(i) through (o)(1)(iii).
 (i)  The emission factors must be calculated annually. You must use all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar years of measurements in paragraph (o)(6) of this section.
(ii)  [Reserved]
(7)  Onshore petroleum and natural gas production shall calculate emissions from centrifugal compressor wet seal oil degassing vents as follows:
		(Eq. W-25)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from centrifugal compressor wet seals in cubic feet.
Count	=	Total number of centrifugal compressors for the reporter.
EFi	=	Emission factor for GHG i.  Use 12.2 million standard cubic feet per year per compressor for CH4 and 538 thousand standard cubic feet per year per compressor for CO2 at 68°F and 14.7 psia or 12 million standard cubic feet per year per compressor for CH4 and 530 thousand standard cubic feet per year per compressor for CO2 at 60°F and 14.7 psia.

(8)  Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
(9)  Calculate emissions from seal oil degassing vent vapors to flares as follows:
(i)  Use the seal oil degassing vent vapor volume and gas composition as determined in paragraphs (o)(5) of this section.
(ii)  Use the calculation methodology of flare stacks in paragraph (n) of this section to determine degassing vent vapor emissions from the flare.
(p)  Reciprocating compressor venting.  Calculate CH4 and CO2 emissions from all reciprocating compressor vents as follows.  For each reciprocating compressor covered in §98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must conduct an annual measurement for each compressor in the mode in which it is found during the annual measurement, except as specified in paragraph (p)(9) of this section.  Measure emissions from (including emissions manifolded to common vents) reciprocating rod packing vents, unit isolation valve vents, and blowdown valve vents.  Record emissions from the following vent types in the specified compressor modes during the annual measurement as follows:
      (1)  Operating or standby pressurized mode, blowdown vent leakage through the blowdown vent stack.
      (2)  Operating mode, reciprocating rod packing emissions.
      (3)  Not operating, depressurized mode, unit isolation valve leakage through the blowdown vent stack, without blind flanges.
      (i)  For the not operating, depressurized mode, each compressor must be measured at least once in any three consecutive calendar years if this mode is not found in the annual measurement.  If a compressor is not operated and has blind flanges in place throughout the 3 year period, measurement is not required in this mode.  If the compressor is in standby depressurized mode without blind flanges in place and is not operated throughout the 3 year period, it must be measured in the standby depressurized mode.
      (ii)  [Reserved]
      (4)  If reciprocating rod packing and blowdown vent are connected to an open-ended vent line use one of the following two methods to calculate emissions:
(i)  Measure emissions from all vents (including emissions manifolded to common vents) including rod packing, unit isolation valves, and blowdown vents using either calibrated bagging or high volume sampler according to methods set forth in §98.234 (c) and §98.234(d), respectively.
(ii)  Use a temporary meter such as a vane anemometer or a permanent meter such as an orifice meter to measure emissions from all vents (including emissions manifolded to a common vent) including rod packing vents and unit isolation valve leakage through blowdown vents according to methods set forth in §98.234(b).  If you do not have a permanent flow meter, you may install a port for insertion of a temporary meter or a permanent flow meter on the vents.  For through-valve leakage to open ended vents, such as unit isolation valves on not operating, depressurized compressors and blowdown valves on pressurized compressors, you may use an acoustic detection device according to methods set forth in §98.234(a).
      (5)  If reciprocating rod packing is not equipped with a vent line use the following method to calculate emissions:
(i)  You must use the methods described in §98.234 (a) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or from the compressor crank case breather cap or other vent with a closed distance piece.
(ii)  Measure emissions found in paragraph (p)(5)(i) of this section using an appropriate meter, or calibrated bag, or high volume sampler according to methods set forth in §98.234(b), (c), and (d), respectively.
(6)  Estimate annual emissions using the flow measurement and Equation W-26 of this section.
		(Eq. W-26)
Where:
Es,i,m	=	Annual GHG i (either CH4 or CO2) volumetric emissions at standard conditions, in cubic feet.
MTm	=	Measured gas emissions in standard cubic feet per hour.
Tm	=	Total time the compressor is in the mode for which Es,i,m is being calculated, in the calendar year in hours.
Mi,m	=	Mole fraction of GHG i in gas; use the appropriate gas compositions in paragraph (u)(2) of this section.
(7)  Calculate annual emissions from each reciprocating compressor using Equation W-27 of this section.
		(Eq. W-27)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from each reciprocating compressor in cubic feet.
EFm	=	Reporter emission factor for each mode, m, in cubic feet per hour, from Equation W-28 of this section as calculated in paragraph (p)(7)(i) of this section.
Tm	=	Total time in hours per year the compressor was in each mode, m, as listed in paragraph (p)(1) through (p)(3).
GHGi	=	For onshore natural gas processing facilities, concentration of GHG i, CH4 or CO2, in produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8), GHGi equals 1.
m	=	Compressor mode as listed in paragraph (p)(1) through (p)(3).

(i)  You shall use the flow meter readings from measurements of operating and standby pressurized blowdown vent, operating mode vents, not operating depressurized isolation valve vent for all the reporter's compressor modes not measured in the calendar year to develop the following emission factors using Equation W-28 of this section for each mode as listed in paragraph (p)(1) through (p)(3).
		(Eq. W-28)
Where:
EFm	=	Reporter emission factors for compressor in the three modes, m, in cubic feet per hour.
MTm	=	Meter readings from all reciprocating compressor vents in each and mode, m, in cubic feet per hour.
Countm	=	Total number of compressors measured in each mode, m.
m	=	Compressor mode as listed in paragraph (p)(1) through (p)(3).
(A)  You must combine emissions for blowndown vents, measured in the operating and standby pressurized modes.
(B)  The emission factors must be calculated annually. You must use all measurements from the current calendar year and the preceding two calendar years, totaling three consecutive calendar years of measurements.
(ii)  [Reserved]
(8)  Determine if the reciprocating compressor vent vapors are sent to a vapor recovery system.
(i)  Adjust the emissions estimated in paragraphs (p)(7) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data.
(ii)  [Reserved]

(9)  Onshore petroleum and natural gas production shall calculate emissions from reciprocating compressors as follows:
		(Eq. W-29)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from reciprocating compressors in cubic feet.
Count	=	Total number of reciprocating compressors for the reporter.
EFi	=	Emission factor for GHG i.  Use 9.63 thousand standard cubic feet per year per compressor for CH4 and 0.535 thousand standard cubic feet per year per compressor for CO2 at 68°F and 14.7 psia or 9.48 thousand standard cubic feet per year per compressor for CH4 and 0.527 thousand standard cubic feet per year per compressor for CO2. at 60°F and 14.7 psia.
(10)  Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in paragraphs (u) and (v) of this section.
(q)  Leak detection and leaker emission factors.  You must use the methods described in §98.234(a) to conduct leak detection(s) of equipment leaks from all sources listed in §98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1).  This paragraph (q) applies to emissions sources in streams with gas content greater than 10 percent CH4  plus CO2 by weight.  Emissions sources in streams with gas content less than 10 percent CH4 plus CO2 by weight do not need to be reported.  Tubing systems equal to or less than one half inch diameter are exempt from the requirements of this paragraph (q) and do not need to be reported.  If equipment leaks are detected for sources listed in this paragraph (q), calculate equipment leak emissions per source per reporting facility using Equation W-30 of this section for each source with equipment leaks.
		(Eq. W-30)
Where:
Es,i	=	Annual total volumetric GHG emissions at standard conditions from each equipment leak source in cubic feet.
x	=	Total number of this type of emissions source found to be leaking during Tx.
EFs	=	Leaker emission factor for specific sources listed in Table W-2 through Table W-7 of this subpart.
GHGi	=	For onshore natural gas processing facilities, concentration of GHGi, CH4 or CO2, in the total hydrocarbon of the feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8), GHGi equals 1 for CH4 and 1.1 x 10[-2] for CO2.
Tx	=	The total time the component was found leaking and operational, in hours. If one leak detection survey is conducted, assume the component was leaking for the entire calendar year. If multiple leak detection surveys are conducted, assume that the component found to be leaking has been leaking since the previous survey or the beginning of the calendar year. For the last leak detection survey in the calendar year, assume that all leaking components continue to leak until the end of the calendar year.
(1)  You must select to conduct either one leak detection survey in a calendar year or multiple complete leak detection surveys in a calendar year.  The number of leak detection surveys selected must be conducted during the calendar year.
(2)  Calculate GHG mass emissions in carbon dioxide equivalent at standard conditions using calculations in paragraph (v) of this section.
(3)  Onshore natural gas processing facilities shall use the appropriate default leaker emission factors listed in Table W-2 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters.
(4)  Onshore natural gas transmission compression facilities shall use the appropriate default leaker emission factors listed in Table W-3 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters.
(5)  Underground natural gas storage facilities for storage stations shall use the appropriate default leaker emission factors listed in Table W-4 of this subpart for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters.
(6)  LNG storage facilities shall use the appropriate default leaker emission factors listed in Table W-5 of this subpart for equipment leaks detected from valves, pump seals, connectors, and other.
(7)  LNG import and export facilities shall use the appropriate default leaker emission factors listed in Table W-6 of this subpart for equipment leaks detected from valves, pump seals, connectors, and other.
(8)  Natural gas distribution facilities for above ground meters and regulators at city gate stations at custody transfer, shall use the appropriate default leaker emission factors listed in Table W-7 of this subpart for equipment leak detected from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open ended lines.
(r)  Population count and emission factors.  This paragraph applies to emissions sources listed in §98.232 (c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4) and (i)(5), on streams with gas content greater than 10 percent CH4  plus CO2 by weight.  Emissions sources in streams with gas content less than 10 percent CH4 plus CO2 by weight do not need to be reported.  Tubing systems equal or less than one half inch diameter are exempt from the requirements of paragraph (r) of this section and do not need to be reported.  Calculate emissions from all sources listed in this paragraph using Equation W-31 of this section.
		(Eq. W-31)
Where:
Es,i	=	Annual volumetric GHG emissions at standard conditions from each equipment leak source in cubic feet.
Counts	=	Total number of this type of emission source at the facility.  Average component counts are provided by major equipment piece in Tables W-1B and Table W-1C of this subpart.  Use average component counts as appropriate for operations in Eastern and Western U.S., according to Table W-1D of this subpart.EFs	=	Population emission factor for the specific source, s listed in Table W-1A and Tables W-3 through Table W-7 of this subpart.  Use appropriate population emission factor for operations in Eastern and Western U.S., according to Table W-1D of this subpart.  EF for non-custody transfer city gate stations is determined in Equation W-32.
GHGi	=	For onshore petroleum and natural gas production facilities and onshore natural gas processing facilities, concentration of GHG i, CH4 or CO2, in produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8),GHGi equals 1 for CH4 and 1.1 x 10[-2] for CO2.
Ts	=	Total time the specific source s associated with the equipment leak emission was operational in the calendar year, in hours.

(1)  Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
(2)  Onshore petroleum and natural gas production facilities shall use the appropriate default population emission factors listed in Table W-1A of this subpart for equipment leaks from valves, connectors, open ended lines, pressure relief valves, pump, flanges, and other.  Major equipment and components associated with gas wells are considered gas service components in reference to Table 1-A of this subpart and major natural gas equipment in reference to Table W-1B of this subpart.    Major equipment and components associated with crude oil wells are considered crude service components in reference to Table 1-A of this subpart and major crude oil equipment in reference to Table W-1C of this subpart.  Where facilities conduct EOR operations the emissions factor listed in Table W-1A of this subpart shall be used to estimate all streams of gases, including recycle CO2 stream.  The component count can be determined using either of the methodologies described in this paragraph (r)(2).  The same methodology must be used for the entire calendar year.
(i)  Component Count Methodology 1.  For all onshore petroleum and natural gas production operations in the facility perform the following activities:
(A)  Count all major equipment listed in Table W-1B and Table W-1C of this subpart.
(B)  Multiply major equipment counts by the average component counts listed in Table W-1B and W-1C of this subpart for onshore natural gas production and onshore oil production, respectively. Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart.
(ii)  Component Count Methodology 2.  Count each component individually for the facility.  Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart.
(3)  Underground natural gas storage facilities for storage wellheads shall use the appropriate default population emission factors listed in Table W-4 of this subpart for equipment leak from connectors, valves, pressure relief valves, and open ended lines.
(4)  LNG storage facilities shall use the appropriate default population emission factors listed in Table W-5 of this subpart for equipment leak from vapor recovery compressors.
(5)  LNG import and export facilities shall use the appropriate default population emission factor listed in Table W-6 of this subpart for equipment leak from vapor recovery compressors.
(6)  Natural gas distribution facilities shall use the appropriate emission factors as described in paragraph (r)(6) of this section.
(i)  Below grade meters and regulators; mains; and services, shall use the appropriate default population emission factors listed in Table W-7 of this subpart.
(ii)  Above grade meters and regulators at city gate stations not at custody transfer as listed in §98.232(i)(2), shall use the total volumetric GHG emissions at standard conditions for all equipment leak sources calculated in paragraph (q)(8) of this section to develop facility emission factors using Equation W-32 of this section.  The calculated facility emission factor from Equation W-32 of this section shall be used in Equation W-31 of this section.
		(Eq. W-32)
Where:
EF	=	Facility emission factor for a meter at above grade M&R at city gate stations not at custody transfer in cubic feet per meter per year.
Es,i	=	Annual volumetric GHG emissions at standard condition from all equipment leak sources at all above grade M&R city gate stations at custody transfer, from paragraph (q) of this section.
Count	=	Total number of meter runs at all above grade M&R city gate stations at custody transfer.
(s)  Offshore petroleum and natural gas production facilities.  Report CO2, CH4, and N2O emissions for offshore petroleum and natural gas production from all equipment leaks, vented emission, and flare emission source types as identified in the data collection and emissions estimation study conducted by BOEMRE in compliance with 30 CFR 250.302 through 304.
(1) Offshore production facilities under BOEMRE jurisdiction shall report the same annual emissions as calculated and reported by BOEMRE in data collection and emissions estimation study published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS).
(i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication year, report the most recent BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS).  Adjust emissions based on the operating time for the facility relative to the operating time in the most recent BOEMRE published study.
(ii)  [Reserved]
(2) Offshore production facilities that are not under BOEMRE jurisdiction shall use monitoring methods and calculation methodologies published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS).
(i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication, report the most recent reported emissions data with emissions adjusted based on the operating time for the facility relative to operating time in the previous reporting period.
(ii)  [Reserved]
(3) If BOEMRE discontinues or delays their data collection effort by more than 4 years, then offshore reporters shall once in every 4 years use the most recent BOEMRE data collection and emissions estimation methods to report emission from the facility sources.
(4) For either first or subsequent year reporting, offshore facilities either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle shall use the most recent BOEMRE data collection and emissions estimation methods published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS) to report emissions.
(t)  Volumetric emissions.  Calculate volumetric emissions at standard conditions as specified in paragraphs (t)(1) or (2) of this section determined by engineering estimate based on best available data unless otherwise specified.
(1)  Calculate natural gas volumetric emissions at standard conditions by converting actual temperature and pressure of natural gas emissions to standard temperature and pressure of natural gas using Equation W-33 of this section.
		(Eq. W-33)
Where:
Es,n 	=	Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet.
Ea,n 	=	Natural gas volumetric emissions at actual conditions in cubic feet.
Ts  	=	Temperature at standard conditions ([o]F).
Ta  	=	Temperature at actual emission conditions ([o]F).
Ps  	=	Absolute pressure at standard conditions (psia).
Pa  	=	Absolute pressure at actual conditions (psia).

(2)  Calculate GHG volumetric emissions at standard conditions by converting actual temperature and pressure of GHG emissions to standard temperature and pressure using Equation W-34 of this section.
	



s
a
a
s
i
a
i
s
P
T
P
T
E
E
*
67
.
459
*
67
.
459
*
,
,



	(Eq. W-34)Where:
Es,i 	=	GHG i volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet.
Ea,i 	=	GHG i volumetric emissions at actual conditions in cubic feet.
Ts  	=	Temperature at standard conditions ([o]F).
Ta  	=	Temperature at actual emission conditions ([o]F).
Ps  	=	Absolute pressure at standard conditions (psia).
Pa  	=	Absolute pressure at actual conditions (psia).

(u)  GHG volumetric emissions.  Calculate GHG volumetric emissions at standard conditions as specified in paragraphs (u)(1) and (2) of this section determined by engineering estimate based on best available data unless otherwise specified.
(1)  Estimate CH4 and CO2 emissions from natural gas emissions using Equation W-35 of this section.
		(Eq. W-35)
Where:
Es,i	=	GHG i (either CH4 or CO2) volumetric emissions at standard conditions in cubic feet.
Es,n	=	Natural gas volumetric emissions at standard conditions in cubic feet.
Mi	=	Mole fraction of GHG i in the natural gas.

(2)  For Equation W-35 of this section, the mole fraction, Mi, shall be the annual average mole fraction for each facility, as specified in paragraphs (u)(2)(i) through (vii) of this section.
(i)  GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities.  If you have a continuous gas composition analyzer for produced natural gas, you must use these values for determining the mole fraction.  If you do not have a continuous gas composition analyzer, then you must use your most recent gas composition based on available sample analysis of the field.
(ii)  GHG mole fraction in feed natural gas for all emissions sources upstream of the de-methanizer or dew point control and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities.  If you have a continuous gas composition analyzer on feed natural gas, you must use these values for determining the mole fraction.  If you do not have a continuous gas composition analyzer, then annual samples must be taken according to methods set forth in §98.234(b).
(iii)  GHG mole fraction in transmission pipeline natural gas that passes through the facility for onshore natural gas transmission compression facilities.
(iv)  GHG mole fraction in natural gas stored in underground natural gas storage facilities.
(v)  GHG mole fraction in natural gas stored in LNG storage facilities.
(vi)  GHG mole fraction in natural gas stored in LNG import and export facilities.
(vii)  GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities.
(v)  GHG mass emissions.  Calculate GHG mass emissions in carbon dioxide equivalent at standard conditions by converting the GHG volumetric emissions into mass emissions using Equation W-36 of this section.
		(Eq. W-36)
Where:
Masss,i	=	GHG i (either CH4 or CO2) mass emissions at standard conditions in metric tons CO2e.
Es,i	=	GHG i (either CH4 or CO2) volumetric emissions at standard conditions, in cubic feet.
	=	Density of GHG i. Use 0.0520 kg/ft[3] for CO2 and N2O, and 0.0190 kg/ft[3] for CH4 at 68°F and 14.7 psia or 0.0530 kg/ft[3] for CO2 and N2O, and 0.0193 kg/ft[3] for CH4 at 60°F and 14.7 psia .
GWP	=	Global warming potential, 1 for CO2, 21 for CH4, and 310 for N2O.

(w)  EOR injection pump blowdown.  Calculate CO2 pump blowdown emissions as follows:
(1)  Calculate the total volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves.
(2)  Retain logs of the number of blowdowns per calendar year.
(3)  Calculate the total annual venting emissions using Equation W-37 of this section:

		(Eq. W-37)
Where:
Massc,i	=	Annual EOR injection gas venting emissions in metric tons at critical conditions "c" from blowdowns.
N	=	Number of blowdowns for the equipment in the calendar year.
Vv	=	Total volume in cubic feet of blowdown equipment chambers (including pipelines, manifolds and vessels) between isolation valves.
Rc	=	Density of critical phase EOR injection gas in kg/ft[3]. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice to determine density of super critical EOR injection gas.
GHGi	=	Mass fraction of GHGi in critical phase injection gas.
1 x 10[-3]	=	Conversion factor from kilograms to metric tons.
(x)  EOR hydrocarbon liquids dissolved CO2.  Calculate dissolved CO2 in hydrocarbon liquids produced through EOR operations as follows:
(1)  Determine the amount of CO2 retained in hydrocarbon liquids after flashing in tankage at STP conditions.  Annual samples must be taken according to methods set forth in §98.234(b) to determine retention of CO2 in hydrocarbon liquids immediately downstream of the storage tank.  Use the annual analysis for the calendar year.
(2)  Estimate emissions using Equation W-38 of this section.
	Masss,CO2 = Shl * Vhl	(Eq. W-38)
Where:
Masss,CO2 =		Annual CO2 emissions from CO2 retained in hydrocarbon liquids produced through EOR operations beyond tankage, in metric tons.
Shl	=	Amount of CO2 retained in hydrocarbon liquids in metric tons per barrel, under standard conditions.
Vhl	=	Total volume of hydrocarbon liquids produced at the EOR operations in barrels in the calendar year.

(y)  [Reserved]
(z)  Onshore petroleum and natural gas production and natural gas distribution combustion emissions.  Calculate CO2 CH4, and N2O combustion-related emissions from stationary or portable equipment, except as specified in paragraph (z)(3) of this section, as follows:
(1)  If the fuel combusted in the stationary or portable equipment is listed in Table C-1 of subpart C of this part, or is a blend of fuels listed in Table C-1, use the Tier 1 methodology described in subpart C of this part (General Stationary Fuel Combustion Sources).  If the fuel combusted is natural gas and is pipeline quality and has a minimum high heat value of 950 Btu per standard cubic foot, then the natural gas emission factor and high heat values listed in Tables C-1 and C-2 of this part may be used.
(2)  For fuel combustion units that combust field gas or process vent gas, or any blend of field gas or process vent gas and fuels listed in Table C-1 of subpart C of this part, calculate combustion emissions as follows:
(i)  If you have a continuous flow meter on the combustion unit, you must use the measured flow volumes to calculate the total flow of gas to the unit.  If you do not have a permanent flow meter on the combustion unit, you may install a permanent flow meter on the combustion unit, or use company records or engineering calculations based on best available data on heat duty or horsepower to estimate volumetric unit gas flow.
(ii)  If you have a continuous gas composition analyzer on fuel to the combustion unit, you must use these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to the unit.  If you do not have a continuous gas composition analyzer on gas to the combustion unit, you must use the appropriate gas compositions for each stream of hydrocarbons going to the combustion unit as specified in paragraph (u)(2)(i) of this section.
(iii)  Calculate GHG volumetric emissions at actual conditions using Equations W-39 of this section.

		(Eq. W-39A)
		(Eq. W-39B)
Where:
Ea,CO2 	= 	Contribution of annual emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions.
Ea,CH4 	= 	Contribution of annual CH4 emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions.
η	=	Combustion efficiency for portable and stationary equipment determined based on engineering estimation.

Va	=	Volume of gas sent to combustion unit in cubic feet, during the year.
Yj 	=	Concentration of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes plus) in gas sent to combustion unit.
YCH4	=    Concentration of methane constituent in gas sent to combustion unit.

YCO2	=    Concentration of CO2 constituent in gas sent to combustion unit.

Rj	=	Number of carbon atoms in the gas hydrocarbon constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus) in gas sent to combustion unit.

(iv)  Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(v)  Calculate both combustion-related CH4 and CO2 mass emissions from volumetric CH4 and CO2 emissions using calculation in paragraph (v) of this section.
      (vi)  Calculate N2O mass emissions using Equation W-40 of this section.

		(Eq. W-40)

Where:
N2O 	= 	Annual N2O emissions from the combustion of a particular type of fuel (metric tons).
Fuel	=	Mass or volume of the fuel combusted (mass or volume per year, choose appropriately to be consistent with the units of HHV).
HHV 	=	For the high heat value for field gas or process vent gas, use 1.235 x 10[-3] mmBtu/scf for HHV
EF		=	Use 1.0 x 10[-4] kg N2O/mmBtu.
1 x 10[-3]		=	Conversion factor from kilograms to metric tons.

(3)  External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissions or include these emissions for threshold determination in §98.231(a).  You must report the type and number of each external fuel combustion unit.

§98.234  Monitoring and QA/QC requirements.
The GHG emissions data for petroleum and natural gas emissions sources must be quality assured as applicable as specified in this section. Offshore petroleum and natural gas production facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 250.
(a)  You must use any of the methods described as follows in this paragraph to conduct leak detection(s) of equipment leaks and through-valve leakage from all source types listed in §98.233(k), (o), (p) and (q) that occur during a calendar year, except as provided in paragraph (a)(4) of this section.
(1)  Optical gas imaging instrument.  Use an optical gas imaging instrument for equipment leak detection in accordance with 40 CFR part 60, subpart A, §60.18(i)(1) and (2) of the Alternative work practice for monitoring equipment leaks.  Any emissions detected by the optical gas imaging instrument is a leak unless screened with Method 21 (40 CFR part 60, appendix A-7) monitoring, in which case 10,000 ppm or greater is designated a leak.  In addition, you must operate the optical gas imaging instrument to image the source types required by this subpart in accordance with the instrument manufacturer's operating parameters.
(2)  Method 21.  Use the equipment leak detection methods in 40 CFR part 60, appendix A-7, Method 21.  If using Method 21 monitoring, if an instrument reading of 10,000 ppm or greater is measured, a leak is detected.  Inaccessible emissions sources, as defined in 40 CFR part 60, are not exempt from this subpart.  Owners or operators must use alternative leak detection devices as described in paragraph(a)(1) of this section to monitor inaccessible equipment leaks or vented emissions.
(3)  Infrared laser beam illuminated instrument.  Use an infrared laser beam illuminated instrument for equipment leak detection.  Any emissions detected by the infrared laser beam illuminated instrument is a leak unless screened with Method 21 monitoring, in which case 10,000 ppm or greater is designated a leak.  In addition, you must operate the infrared laser beam illuminated instrument to detect the source types required by this subpart in accordance with the instrument manufacturer's operating parameters.
(4)  Optical gas imaging instrument.  An optical gas imaging instrument must be used for all source types that are inaccessible and cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface.
(5)  Acoustic leak detection device.  Use the acoustic leak detection device to detect through-valve leakage.  When using the acoustic leak detection device to quantify the through-valve leakage, you must use the instrument manufacturer's calculation methods to quantify the through-valve leak.  When using the acoustic leak detection device, if a leak of 3.1 scf per hour or greater is calculated, a leak is detected.  In addition, you must operate the acoustic leak detection device to monitor the source valves required by this subpart in accordance with the instrument manufacturer's operating parameters.
(b)  You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure quantities reported in §98.233 according to the procedures in §98.3(i) and the procedures in paragraph (b) of this section.  You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice.  Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(c)  Use calibrated bags (also known as vent bags) only where the emissions are at near-atmospheric pressures such that it is safe to handle and can capture all the emissions, below the maximum temperature specified by the vent bag manufacturer, and the entire emissions volume can be encompassed for measurement.
(1)  Hold the bag in place enclosing the emissions source to capture the entire emissions and record the time required for completely filling the bag.  If the bag inflates in less than one second, assume one second inflation time.
(2)  Perform three measurements of the time required to fill the bag, report the emissions as the average of the three readings.
(3)  Estimate natural gas volumetric emissions at standard conditions using calculations in §98.233(t).
(4)  Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in §98.233(u) and (v).
(d)  Use a high volume sampler to measure emissions within the capacity of the instrument.
(1)  A technician following manufacturer instructions shall conduct measurements, including equipment manufacturer operating procedures and measurement methodologies relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creating backpressure on the source.
(2)  If the high volume sampler, along with all attachments available from the manufacturer, is not able to capture all the emissions from the source then use anti-static wraps or other aids to capture all emissions without violating operating requirements as provided in the instrument manufacturer's manual.
(3)  Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in §98.233(u) and (v).
(4)  Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH4 by using calibrated gas samples and by following manufacturer's instructions for calibration.
(e)  Peng Robinson Equation of State means the equation of state defined by Equation W-41 of this section:
		(Eq. W-41)
Where:
p	=	Absolute pressure.
R	=	Universal gas constant.
T	=	Absolute temperature.
Vm	=	Molar volume.
	a =
	b =
	α =
Where:

ω	=	Acentric factor of the species.
Tc	=	Critical temperature.
Pc	=	Critical pressure.

(f)  Special reporting provisions
(1)  Best available monitoring methods.  EPA will allow owners or operators to use best available monitoring methods for parameters in §98.233 Calculating GHG Emissions as specified in paragraphs (f)(2), (f)(3), and (f)(4) of this section.  If the reporter anticipates the potential need for best available monitoring for sources for which they need to petition EPA and the situation is unresolved at the time of the deadline, reporters should submit written notice of this potential situation to EPA by the specified deadline for requests to be considered.  EPA reserves the right to review petitions after the deadline but will only consider and approve late petitions which demonstrate extreme or unusual circumstances.  The Administrator reserves to right to request further information in regard to all petition requests.  The owner or operator must use the calculation methodologies and equations in §98.233 Calculating GHG Emissions.  Best available monitoring methods means any of the following methods specified in paragraph (f)(1) of this section:
(i)  Monitoring methods currently used by the facility that do not meet the specifications of this subpart.
(ii)  Supplier data.
(iii)  Engineering calculations.
(iv)  Other company records.
(2)  Best available monitoring methods for well-related emissions.  During January 1, 2011 through June 30, 2011, owners or operators may use best available monitoring methods for any well-related data that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart, and only where required measurements cannot be duplicated due to technical limitations after June 30, 2011.  These well-related sources are:
(i)  Gas well venting during well completions and workovers with hydraulic fracturing as specified in §98.233(g).
(ii)  Well testing venting and flaring as specified in §98.233(l).
(3)  Best available monitoring methods for specified activity data.  During January 1, 2011 through June 30, 2011, owners or operators may use best available monitoring methods for activity data as listed below that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart, specifically for events that generate data that can be collected only between January 1, 2011 and June 30, 2011 and cannot be duplicated after June 30, 2011.  These sources are:
(i)  Cumulative hours of venting, days, or times of operation in §98.233(e), (f), (g), (h), (l), (o), (p), (q), and (r).
(ii)  Number of blowdowns, completions, workovers, or other events in §98.233(f), (g), (h), (i), and (w).
(iii)  Cumulative volume produced, volume input or output, or volume of fuel used in paragraphs §98.233(d), (e), (j), (k), (l), (m), (n), (x), (y), and (z).
(4)  Best available monitoring methods for leak detection and measurement.  The owner or operator may request use of best available monitoring methods between January 1, 2011 and December 31, 2011 for sources requiring leak detection and/or measurement.  These sources include:
(i)  Reciprocating compressor rod packing venting in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in §98.232 (d)(1), (e)(1), (f)(1), (g)(1), and (h)(1).
(ii)  Centrifugal compressor wet seal oil degassing venting in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in §98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2).
(iii)  Acid gas removal vent stacks in onshore petroleum and natural gas production and onshore natural gas processing as specified in §98.232(c)(17) and (d)(6).
(iv)  Equipment leak emissions from valves, connectors, open ended lines, pressure relief valves, block valves, control valves, compressor blowdown valves, orifice meters, other meters, regulators, vapor recovery compressors, centrifugal compressor dry seals, and/or other equipment leaks in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, and natural gas distribution as specified in §98.232 (d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1).
(v)  Condensate (oil and/or water) storage tanks in onshore natural gas transmission compression as specified in §98.232(e)(3).
(5)  Requests for the use of best available monitoring methods.  The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods.
(i)  No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and June 30, 2011 for the sources specified in paragraph (f)(2) of this section.
(ii)  No request or approval by the Administrator is necessary to use best available monitoring methods between January 1, 2011 and June 30, 2011 for the sources specified in paragraph (f)(3) of this section.
(iii)  Owners or operators must submit a request and receive approval by the Administrator to use best available monitoring methods between January 1, 2011 and December 31, 2011 for sources specified in paragraph (f)(4) of this section.
(A)  Timing of request.  The request to use best available monitoring methods for paragraph (f)(4) of this section must be submitted to EPA no later than April 30, 2011.
(B)  Content of request.  Requests must contain the following information for sources listed in paragraph (f)(4) of this section:
(1)  A list of specific source types and specific equipment, monitoring instrumentation, and/or services for which the request is being made and the locations where each piece of monitoring instrumentation will be installed or monitoring service will be supplied.
(2)  Identification of the specific rule requirements (by subpart, section, and paragraph number) for which the instrumentation or monitoring service is needed.
(3)  Documentation which demonstrates that the owner or operator made all reasonable efforts to obtain the information, services or equipment necessary to comply with subpart W reporting requirements, including evidence of specific service or equipment providers contacted and why services or information could not be obtained during 2011.
(4)  A description of the specific actions the facility will take to obtain and/or install the equipment or obtain the monitoring service as soon as reasonably feasible and the expected date by which the equipment will be obtained and operating or service will be provided.
(C)  Approval criteria.  To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that it does not own the required monitoring equipment, and it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment or to obtain leak detection or measurement services in order to meet the requirements of this subpart for 2011.
(iv) EPA does not anticipate a need to approve the use of best available monitoring methods for sources not listed in paragraphs(f)(2), (f)(3), and (f)(4) of this section; however, EPA will review such requests if submitted in accordance with paragraph (f)(5)(iv)(A)-(C) of this section.
(A)  Timing of request.  The request to use best available monitoring methods for sources not listed in paragraphs (f)(2), (f)(3), and (f)(4) of this section must be submitted to EPA no later than April 30, 2011.
(B)  Content of request.  Requests must contain the following information:
(1)  A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods.
(2)  A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner or operator is requesting use of best available monitoring methodologies.
(3)  A detailed explanation and supporting documentation of how and when the owner or operator will receive the services or equipment to comply with all subpart W reporting requirements.
(C)  Approval criteria.  To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that the owner or operator faces unique safety, technical or legal issues rendering them unable to   meet the requirements of this subpart for 2011.
(6)  Requests for extension of the use of best available monitoring methods through December 31, 2011 for sources in paragraph (f)(2) of this section.  The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods described in paragraph (f)(2) of this section beyond June 30, 2011.
(i)  Timing of request.  The extension request must be submitted to EPA no later than April 30, 2011.
(ii)  Content of request.  Requests must contain the following information:
(A)  A list of specific source types and specific equipment, monitoring instrumentation, contract modifications, and/or services for which the request is being made and the locations where each piece of monitoring instrumentation will be installed, monitoring service will be supplied, or contracts will be modified.
(B)  Identification of the specific rule requirements (by subpart, section, and paragraph number) for which the instrumentation, contract modification, or monitoring service is needed.
(C)  A description and applicable correspondence outlining the diligent efforts of the owner or operator in obtaining the needed equipment or service and why they could not be obtained and installed in a period of time enabling completion of applicable requirements of this subpart within the 2011 calendar year.
(D)  If the reason for the extension is that the owner or operator cannot collect data from a service provider or relevant organization in order for the owner or operator to meet requirements of this subpart for the 2011 calendar year, the owner or operator must demonstrate a good faith effort that it is not possible to obtain the necessary information, service or hardware which may include providing correspondence from specific service providers or other relevant entities to the owner or operator, whereby the service provider states that it is unable to provide the necessary data or services requested by the owner or operator that would enable the owner or operator to comply with subpart W reporting requirements by June 30, 2011.
(E)  A description of the specific actions the owner or operator will take to comply with monitoring requirements in 2012 and beyond.
(iii)  Approval criteria.  To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to obtain the data necessary to meet the requirements of this subpart for the sources specified in paragraph (f)(2) of this section by June 30, 2011.
(7)  Requests for extension of the use of best available monitoring methods through December 31, 2011 for sources in paragraph (f)(3) of this section.  The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods described in paragraph (f)(3) of this section beyond June 30, 2011.
(i)  Timing of request. The extension request must be submitted to EPA no later than April 30, 2011.
(ii)  Content of request. Requests must contain the following information:
(A)  A list of specific source types for which data collection could not be implemented.
(B)  Identification of the specific rule requirements (by subpart, section, and paragraph number) for which the data collection could not be implemented.
(C)  A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner or operator is requesting use of best available  monitoring methodologies for which data collection could not be implemented in the 2011 calendar year.
(iii)  Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to implement the data collection for the sources described in paragraph (f)(3) of this section for the methods required in this subpart by June, 30, 2011.
(8)  Requests for extension of the use of best available monitoring methods beyond 2011 for sources listed in paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this section and other sources in this subpart.  EPA does not anticipate a need for approving the use of best available methods beyond December 31, 2011, except in extreme circumstances, which include safety, a requirement being technically infeasible or counter to other local, State, or Federal regulations.
(i)  Timing of request.  The request to use best available monitoring methods for paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this section and sources not listed in paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this section must be submitted to EPA no later than September 30, 2011.
(ii)  Content of request.  Requests must contain the following information:
(iii)  A list of specific source categories and parameters for which the owner or operator is seeking use of best available monitoring methods.
(iv)  A description of the data collection methodologies that do not meet safety regulations, technical infeasibility, or specific laws or regulations that conflict with each specific source for which an owner or operator is requesting use of best available monitoring methodologies.
(v)  A detailed explanation and supporting documentation of how and when the owner or operator will receive the services or equipment to comply with all of this subpart W reporting requirements.
(C)  Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that the owner or operator faces unique safety, technical or legal issues rendering them unable to    meet the requirements of this subpart.

§98.235 Procedures for estimating missing data.
A complete record of all estimated and/or measured parameters used in the GHG emissions calculations is required.  If data are lost or an error occurs during annual emissions estimation or measurements, you must repeat the estimation or measurement activity for those sources as soon as possible, including in the subsequent calendar year if missing data are not discovered until after December 31 of the year in which data are collected, until valid data for reporting is obtained.  Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used for that subsequent year's emissions estimation.  Where missing data procedures are used for the previous year, at least 30 days must separate emissions estimation or measurements for the previous year and emissions estimation or measurements for the current year of data collection. For missing data which are continuously monitored or measured, (for example flow meters), or for missing temperature or pressure data that are required under §98.236, the reporter may use best available data for use in emissions determinations.  The reporter must record and report the basis for the best available data in these cases.
§98.236  Data reporting requirements.
In addition to the information required by §98.3(c), each annual report must contain reported emissions and related information as specified in this section.
(a)  Report annual emissions separately for each of the industry segments listed in paragraphs (a)(1) through (8) of this section in metric tons CO2e per year at standard conditions.  For each segment, report emissions from each source type §98.232(a) in the aggregate, unless specified otherwise.  For example, an onshore natural gas production operation with multiple reciprocating compressors must report emissions from all reciprocating compressors as an aggregate number.
(1)  Onshore petroleum and natural gas production.
(2)  Offshore petroleum and natural gas production.
(3)  Onshore natural gas processing.
(4)  Onshore natural gas transmission compression.
(5)  Underground natural gas storage.
(6)  LNG storage.
(7)  LNG import and export.
(8)  Natural gas distribution.  Report each source in the aggregate for pipelines and for Metering and Regulating (M&R) stations.
(b)  Offshore petroleum and natural gas production is not required to report activity data and emissions for each aggregated source under §98.236 (c). Reporting requirements for offshore petroleum and natural gas production is set forth by BOEMRE in compliance with 30 CFR 250.302 through 304.
(c)  For each aggregated source, unless otherwise specified, report activity data and emissions (in metric tons CO2e per year at standard conditions) for each aggregated source type as follows:
(1)  For natural gas pneumatic devices (refer to Equation W-1 of §98.233), report the following:
(i)  Actual count and estimated count separately of natural gas pneumatic high bleed devices as applicable.
(ii)  Actual count and estimated count separately of natural gas pneumatic low bleed devices as applicable.
(iii)  Actual count and estimated count separately of natural gas pneumatic intermittent bleed devices as applicable.
(iv)  Report emissions collectively.
(2)  For natural gas driven pneumatic pumps (refer to Equation W-2 of §98.233), report the following,
(i)  Count of natural gas driven pneumatic pumps.
(ii)  Report emissions collectively.
(3)  For each acid gas removal unit (refer to Equation W-3 and Equation W-4 of §98.233), report the following:
(i)  Total throughput off the acid gas removal unit using a meter or engineering estimate based on process knowledge or best available data in million cubic feet per year.
(ii)  For Calculation Methodology 1 and Calculation Methodology 2 of §98.233(d), fraction of CO2 content in the vent from the acid gas removal unit (refer to §98.233(d)(6)).
(iii)  For Calculation Methodology 3 of §98.233(d), volume fraction of CO2 content of natural gas into and out of the acid gas removal unit (refer to §98.233(d)(7) and (d)(8)).
(iv)	Report emissions from the AGR unit recovered and transferred outside the facility.
(v)  Report emissions individually.
(4)  For dehydrators, report the following:
(i)  For each Glycol dehydrator with a throughput greater than or equal to 0.4 MMscfd (refer to §98.233(e)(1)), report the following:
(A)  Glycol dehydrator feed natural gas flow rate in MMscfd, determined by engineering estimate based on best available data.
(B)  Glycol dehydrator absorbent circulation pump type.
(C)  Whether stripper gas is used in glycol dehydrator.
(D)  Whether a flash tank separator is used in glycol dehydrator.
(E)  Type of absorbent.
(F)  Total time the glycol dehydrator is operating in hours.
(G)  Temperature, in degrees Fahrenheit and pressure, in psig, of the wet natural gas.
(H)  Concentration of CH4 and CO2 in natural gas.
(I)  What vent gas controls are used (refer to §98.233(e)(3) and (e)(4)).
(J)  Report vent and flared emissions individually.
(ii)  For all glycol dehydrators with a throughput less than 0.4 MMscfd (refer to §98.233, Equation W-5 of §98.233), report the following:
(A)  Count of glycol dehydrators.
(B)  Whether any vent gas controls are used (refer to §98.233(e)(3) and (e)(4)).
(C)  Report vent emissions collectively.
(iii)  For absorbent desiccant dehydrators (refer to Equation W-6 of §98.233), report the following:
(A)  Count of desiccant dehydrators.
(B)  Report emissions collectively.
(5)  For well venting for liquids unloading (refer to Equations W-7, W-8 and W-9 of §98.233), report the following by field:
(i)  Count of wells vented to the atmosphere for liquids unloading.
(ii)  Count of plunger lifts.
(iii)  Cumulative number of unloadings vented to the atmosphere.
(iv)  Average flow rate of the measured well venting in cubic feet per hour (refer to §98.233(f)(1)(i)(A)).
(v)  Average casing diameter in inches.
(vi)  Report emissions collectively.
(6)  For well completions and workovers, report the following for each field:
(i)  For gas well completions and workovers with hydraulic fracturing (refer to Equation W-10 of §98.233):
(A)  Total count of completions in calendar year.
(B)  Average flow rate of the measured well completion venting in cubic feet per hour (refer to §98.233(g)(1)(i) or (g)(1)(ii)).
(C)  Total count of workovers in calendar year.
(D)  Average flow rate of the measured well workover venting in cubic feet per hour (refer to §98.233(g)(1)(i) or (g)(1)(ii)).
(E)  Total number of days of gas venting to the atmosphere during backflow for completion.
(F)  Total number of days of gas venting to the atmosphere during backflow for workovers.
(G)  Report number of completions and workovers employing reduced emissions completions and engineering estimate based on best available data of the amount of gas recovered to sales.
(H)   Report vent emissions collectively. Report flared emissions collectively.
Report vent emissions collectively.  Report flared emissions collectively.
(ii)  For gas well completions and workovers without hydraulic fracturing (refer to Equation W-13 of §98.233):
(A)  Total count of completions in calendar year.
(B)  Total count of workovers in calendar year that flare gas or vent gas to the atmosphere.
(C)  Total number of days of gas venting to the atmosphere during backflow for completion.
(D)  Report vent emissions collectively. Report flared emissions collectively.
(7)  For each blowdown vent stack (refer to Equation W-14 of §98.233), report the following:
(i)  Total number of blowdowns per unique volume type in calendar year.
(ii)  Report emissions collectively per equipment type.
(8)  For gas emitted from produced oil sent to atmospheric tanks:
(i)  For wellhead gas-liquid separator with oil throughput greater than or equal to 10 barrels per day, using Calculation Methodology 1 and 2 of §98.233(j), report the following by field:
(A)  Number of wellhead separators sending oil to atmospheric tanks.
(B)  Estimated average separator temperature, in degrees Fahrenheit, and estimated average pressure, in psig.
(C)  Estimated average sales oil stabilized API gravity, in degrees.
(D)  Count of hydrocarbon tanks at well pads.
(E)  Best estimate of count of stock tanks not at well pads receiving your oil.
(F)  Total volume of oil from all wellhead separators sent to tank(s) in barrels per year.
(G)  Count of tanks with emissions control measures, either vapor recovery system or flaring, for tanks at well pads.
(H)  Best estimate of count of stock tanks assumed to have emissions control measures not at well pads, receiving your oil.
(I)  Range of concentrations of flash gas, CH4 and CO2.
(J)  Report emissions individually for Calculation Methodology 1 and 2 of §98.233(j).
(ii)  For wells with oil production greater than or equal to 10 barrels per day, using Calculation Methodology 3 and 4 of §98.233(j), report the following by field:
(A)  Total volume of sales oil from all wells in barrels per year.
(B)  Total number of wells sending oil directly to tanks.
(C)  Total number of wells sending oil to separators off the well pads.
(D)  Sales oil API gravity range for (B) and (C) of this section, in degrees.
(E)  Count of hydrocarbon tanks on wellpads
(F)  Count of hydrocarbon tanks, both on and off well pads assumed to have emissions control measures: either vapor recovery system or flaring of tank vapors.
(G)  Report emissions collectively for Calculation Methodology 3 and 4 of §98.233(j).
(iii)  For wellhead gas-liquid separators and wells with throughput less than 10 barrels per day, using Calculation Methodology 5 of §98.233(j) Equation W-15 of §98.233), report the following:
(A)  Number of wellhead separators.
(B)  Number of wells without wellhead separators.
(C)  Total volume of oil production in barrels per year.
(D)  Best estimate of fraction of production sent to tanks with assumed control measures: either vapor recovery system or flaring of tank vapors.
(E) Count of hydrocarbon tanks on well pads.
(F)  Report CO2  and CH4 emissions collectively.
(iv)  If wellhead separator dump valve is functioning improperly during the calendar year (refer to Equation W-16 of §98.233), report the following:
(A)  Count of wellhead separators that dump valve factor is applied.
(9)  For transmission tank emissions identified using optical gas imaging instrument per §98.234(a) (refer to §98.233(k)), or acoustic leak detection of scrubber dump valves report the following for each tank:
(i)  Report emissions individually.
(ii)  [Reserved]
(10)  For well testing (refer to Equation W-17 of §98.233), report the following for each basin:
(i)  Number of wells tested per basin in calendar year.
(ii)  Average gas to oil ratio for each basin.
(iii)  Average number of days the well is tested in a basin.
(iv)  Report emissions of the venting gas collectively.
(11)  For associated natural gas venting (refer to Equation W-18 of §98.233), report the following for each basin:
(i)  Number of wells venting or flaring associated natural gas in a calendar year.
(ii)  Average gas to oil ratio for each basin.
(iii)  Report emissions of the flaring gas collectively.
(12)  For flare stacks (refer to Equation W-19, W-20, and W-21 of §98.233), report the following for each flare:
(i)  Whether flare has a continuous flow monitor.
(ii)  Volume of gas sent to flare in cubic feet per year.
(iii)  Percent of gas sent to un-lit flare determined by engineering estimate and process knowledge based on best available data and operating records.
(iv)  Whether flare has a continuous gas analyzer.
(v)  Flare combustion efficiency.
(vi)  Report uncombusted and combusted CO2 and CH4 emissions separately.
(13)  For each centrifugal compressor:
(i)  For compressors with wet seals in operational mode (refer to Equations W-22 through W-24 of §98.233), report the following for each degassing vent:
(A)  Number of wet seals connected to the degassing vent.
(B)  Fraction of vent gas recovered for fuel or sales or flared.
(C)  Annual throughput in million scf, use an engineering calculation based on best available data.
(D)  Type of meters used for making measurements.
(E)  Reporter emission factor for wet seal oil degassing vents in cubic feet per hour (refer to Equation W-24 of §98.233).
(F)  Total time the compressor is operating in hours.
(G)  Report seal oil degassing vent emissions for compressors measured (refer to Equation W-22 of §98.233) and for compressors not measured (refer to Equation W-23 and Equation W-24 of §98.233).
(ii)  For wet and dry seal centrifugal compressors in operating mode, (refer to Equations W-22 through W-24 of §98.233), report the following:
(A)  Total time in hours the compressor is in operating mode.
(B)  Reporter emission factor for blowdown vents in cubic feet per hour (refer to Equation W-24 of §98.233).
(C)  Report blowdown vent emissions when in operating mode (refer to Equation W-23 and Equation W-24 of §98.233).
(iii)  For wet and dry seal centrifugal compressors in not operating, depressurized mode (refer to Equations W-22 through W-24 of §98.233), report the following:
(A)  Total time in hours the compressor is in shutdown, depressurized mode.
(B)  Reporter emission factor for isolation valve emissions in shutdown, depressurized mode in cubic feet per hour (refer to Equation W-24 of §98.233).
(C)  Report the isolation valve leakage emissions in not operating, depressurized mode in cubic feet per hour (refer to Equation W-23 and Equation W-24 of §98.233).
(iv)  Report total annual compressor emissions from all modes of operation (refer to Equation W-24 of §98.233).
(v)  For centrifugal compressors in onshore petroleum and natural gas production (refer to Equation W-25 of §98.233), report the following:
(A)  Count of compressors.
(B)  Report emissions (refer to Equation W-25 of §98.233) collectively.
(14) For reciprocating compressors:
(i)  For reciprocating compressors rod packing emissions with or without a vent in operating mode, report the following:
(A)  Annual throughput in million scf, use an engineering calculation based on best available data.
(B)  Total time in hours the reciprocating compressor is in operating mode.
(C)  Report rod packing emissions for compressors measured (refer to Equation W-26 of §98.233) and for compressors not measured (refer to Equation W-27 and Equation W-28 of §98.233).
(ii)  For reciprocating compressors blowdown vents not manifold to rod packing vents, in operating and standby pressurized mode (refer to Equations W-26 through W-28 of §98.233), report the following:
(A)  Total time in hours the compressor is in standby, pressurized mode.
(B)  Reporter emission factor for blowdown vents in cubic feet per hour (refer to §98.233, Equation W-28).
(C)  Report blowdown vent emissions when in operating and standby pressurized modes (refer to Equation W-27 and Equation W-28 of §98.233).
(iii)  For reciprocating compressors in not operating, depressurized mode (refer to Equations W-26 through W-28 of §98.233), report the following:
(A)  Total time the compressor is in not operating, depressurized mode.
(B)  Reporter emission factor for isolation valve emissions in not operating, depressurized mode in cubic feet per hour (refer to Equation W-28 of §98.233).
(C)  Report the isolation valve leakage emissions in not operating, depressurized mode.
(iv) Report total annual compressor emissions from all modes of operation (refer to Equation W-27 and Equation W-28 of §98.233).
(v)  For reciprocating compressors in onshore petroleum and natural gas production (refer to Equation W-29 of §98.233), report the following:
(A)  Count of compressors.
(B)  Report emissions collectively.
(15)  For each equipment leak sources that uses emission factors for estimating emissions (refer to §98.233(q) and (r).
(i)  For equipment leaks found in each leak survey (refer to §98.233(q)), report the following:
(A)  Total count of leaks found in each complete survey listed by date of survey and each type of leak source for which there is a leaker emission factor in Tables W-2, W-3, W-4, W-5, W-6, and W-7 of this subpart.
(B)  Concentration of CH4 and CO2 as described in Equation W-30 of §98.233.
(C)  Report CH4 and CO2 emissions (refer to Equation W-30 of §98.233) collectively by equipment type.
(ii)  For equipment leaks calculated using population counts and factors (refer to §98.233(r)), report the following:
(A)  For source categories §98.230(a)(3), (a)(4), (a)(5), (a)(6), and (a)(7), total count for each type of leak source in Tables W-2, W-3, W-4, W-5, and W-6 of this subpart for which there is a population emission factor, listed by major heading and component type.
(B)  For onshore production (refer to §98.230 paragraph (a)(2)), total count for each type of major equipment in Table W-1B and Table W-1C of this subpart, by field.
(C)  Report CH4 and CO2 emissions (refer to Equation W-31 of §98.233) collectively by equipment type.
(16)  For local distribution companies, report the following:
(i)  Number of custody transfer gate stations.
(ii)  Number of non-custody transfer gate stations.
(iii)  Custody transfer gate station meter run leak factor (refer to Equation W-32 of §98.233).
(iv) Number of below grade M&R stations with inlet pressure greater than 300 psig.
(v)  Number of below grade M&R stations with inlet pressure between 100 and 300 psig.
(vi) Number of below grate M&R stations with inlet pressure less than 100 psig.
(vii) Number of miles of unprotected steel distribution mains.
(viii) Number of miles of protected steel distribution mains.
(ix) Number of miles of plastic distribution mains.
(x) Number of miles of cast iron distribution mains.
(xi) Number of unprotected steel distribution services.
(xii) Number of protected steel distribution services.
(xiii) Number of plastic distribution services.
(xiv) Number of copper distribution services.
(xv) Total emissions from each natural gas distribution facility.
(17)  For each EOR injection pump blowdown (refer to Equation W-37 of §98.233), report the following:
(i)  Pump capacity, in barrels per day.
(ii)  Volume of critical phase gas between isolation valves.
(iii)  Number of blowdowns per year.
(iv)  Critical phase EOR injection gas density.
(v)  Report emissions collectively.
(18)  For EOR hydrocarbon liquids dissolved CO2 for each field (refer to Equation W-38 of §98.233), report the following:
(i)  Volume of crude oil produced in barrels per year.
(ii)  Amount of CO2 retained in hydrocarbon liquids in metric tons per barrel, under standard conditions.
(iii)  Report emissions individually.
(19) For onshore petroleum and natural gas production and natural gas distribution combustion emissions, report the following:
(i) Cumulative number of external fuel combustion units with a rated heat capacity equal to or less than 5 mmBtu/hr, by type of unit.
(ii) Cumulative number of external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by type of unit.
(iii) Cumulative emissions from external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by type of unit.
(iv) Cumulative volume of fuel combusted in external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by fuel type.
(v)  Cumulative number of all internal combustion units, by type of unit.
(vi)  Cumulative emissions from internal combustion units, by type of unit.
(vii) Cumulative volume of fuel combusted in internal combustion units, by fuel type.
(d)  Report annual throughput as determined by engineering estimate based on best available data for each  industry segment listed in paragraphs (a)(1) through (a)(8) of this section.

§98.237 Records that must be retained.
Monitoring Plans, as described in §98.3(g)(5), must be completed by April 1, 2011.  In addition to the information required by §98.3(g), you must retain the following records:
(a)  Dates on which measurements were conducted.
(b)  Results of all emissions detected and measurements.
(c)  Calibration reports for detection and measurement instruments used.
(d)  Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions.
§98.238  Definitions.
Except as provided in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Acid gas means hydrogen sulfide (H2S) and/or carbon dioxide (CO2) contaminants that are separated from sour natural gas by an acid gas removal unit.
Acid gas removal unit (AGR) means a process unit that separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid or solid absorbents or membrane separators.
Acid gas removal vent emissions mean the acid gas separated from the acid gas absorbing medium (e.g., an amine solution) and released with methane and other light hydrocarbons to the atmosphere or a flare.
Basin means geologic provinces as defined by the American Association of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991) (incorporated by reference, see §98.7) and the Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see §98.7).
Component means each metal to metal joint or seal of non-welded connection separated by a compression gasket, screwed thread (with or without thread sealing compound), metal to metal compression, or fluid barrier through which natural gas or liquid can escape to the atmosphere.
Compressor means any machine for raising the pressure of a natural gas or CO2 by drawing in low pressure natural gas or CO2 and discharging significantly higher pressure natural gas or CO2.
Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at storage conditions.
Engineering estimation, for purposes of subpart W, means an estimate of emissions based on engineering principles applied to measured and/or approximated physical parameters such as dimensions of containment, actual pressures, actual temperatures, and compositions.
Enhanced oil recovery (EOR) means the use of certain methods such as water flooding or gas injection into existing wells to increase the recovery of crude oil from a reservoir.  In the context of this subpart, EOR applies to injection of critical phase or immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil.
Equipment leak means those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening.
Equipment leak detection means the process of identifying emissions from equipment, components, and other point sources.
External combustion means fired combustion in which the flame and products of combustion are separated from contact with the process fluid to which the energy is delivered.  Process fluids may be air, hot water, or hydrocarbons.  External combustion equipment may include fired heaters, industrial boilers, and commercial and domestic combustion units.
Facility with respect to natural gas distribution for purposes of this subpart and for subpart A means the collection of all distribution pipelines, metering stations, and regulating stations that are operated by a Local Distribution Company (LDC) that is regulated as a separate operating company by a public utility commission or that are operated as an independent municipally-owned distribution system.
Facility with respect to onshore petroleum and natural gas production for purposes of this subpart and for subpart A means all petroleum or natural gas equipment on a well pad or associated with a well pad and CO2 EOR operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore petroleum and natural gas production owner or operator and that are located in a single hydrocarbon basin as defined in §98.238.  Where a person or entity owns or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility.
Farm Taps are pressure regulation stations that deliver gas directly from transmission pipelines to generally rural customers. The gas may or may not be metered, but always does not pass through a city gate station. In some cases a nearby LDC may handle the billing of the gas to the customer(s).
Field means oil and gas fields identified in the United States as defined by the Energy Information Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see §98.7).
Flare stack emissions means CO2 and N2O from partial combustion of hydrocarbon gas sent to a flare plus CH4 emissions resulting from the incomplete combustion of hydrocarbon gas in flares.
Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole basis, that is combusted at the flare burner tip.
Gas well means a well completed for production of natural gas (including condensate) from one or more gas zones or reservoirs. Such wells contain no completions for the production of crude oil.
Internal combustion means the combustion of a fuel that occurs with an oxidizer (usually air) in a combustion chamber. In an internal combustion engine the expansion of the high-temperature and  - pressure gases produced by combustion applies direct force to a component of the engine, such as pistons, turbine blades, or a nozzle. This force moves the component over a distance, generating useful mechanical energy. Internal combustion equipment may include gasoline and diesel industrial engines, natural gas-fired reciprocating engines, and gas turbines.
Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric pressure.
LNG boil-off gas means natural gas in the gaseous phase that vents from LNG storage tanks due to ambient heat leakage through the tank insulation and heat energy dissipated in the LNG by internal pumps.
Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act.
      Oil well means a well completed for the production of crude oil from at least one oil zone or reservoir.
Onshore petroleum and natural gas production owner or operator means the person or entity who holds the permit to operate petroleum and natural gas wells on the drilling permit or an operating permit where no drilling permit is issued, which operates an onshore petroleum and/or natural gas production facility (as described in §98.230(a)(2).  Where petroleum and natural gas wells operate without a drilling or operating permit, the person or entity that pays the State or Federal business income taxes is considered the owner or operator.
Operating pressure means the containment pressure that characterizes the normal state of gas or liquid inside a particular process, pipeline, vessel or tank.
Pump means a device used to raise pressure, drive, or increase flow of liquid streams in closed or open conduits.
Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon dioxide containing light liquids from escaping the inside of a pump case to the atmosphere.
Pump seal emissions means hydrocarbon gas released from the seal face between the pump internal chamber and the atmosphere.
Reservoir means a porous and permeable underground natural formation containing significant quantities of hydrocarbon liquids and/or gases.
Residue Gas and Residue Gas Compression mean, respectively, production lease natural gas from which gas liquid products and, in some cases, non-hydrocarbon components have been extracted such that it meets the specifications set by a pipeline transmission company, and/or a distribution company; and the compressors operated by the processing facility, whether inside the processing facility boundary fence or outside the fence-line, that deliver the residue gas from the processing facility to a transmission pipeline.
Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase.
Transmission pipeline means high pressure cross country pipeline transporting saleable quality natural gas from production or natural gas processing to natural gas distribution pressure let-down, metering, regulating stations where the natural gas is typically odorized before delivery to customers.
Turbine meter means a flow meter in which a gas or liquid flow rate through the calibrated tube spins a turbine from which the spin rate is detected and calibrated to measure the fluid flow rate.
Vented emissions means intentional or designed releases of CH4 or CO2 containing natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process designed flow to the atmosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas used to power equipment (such as pneumatic devices).
Table W-1A to Subpart W of Part 98--Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production

                 Onshore petroleum and natural gas production
                     Emission Factor (scf/hour/component)
Eastern U.S.

Population Emission Factors - All Components, Gas Service[1]

Valve
                                                                          0.027
Connector
                                                                          0.004
Open-ended Line
                                                                          0.062
Pressure Relief Valve
                                                                          0.041
Low Continuous Bleed Pneumatic Device Vents[2]
                                                                           1.80
High Continuous Bleed Pneumatic Device Vents[2]
                                                                           48.1
Intermittent Bleed Pneumatic Device Vents[2]
                                                                           17.4
Pneumatic Pumps[3]
                                                                           13.3
Population Emission Factors - All Components, Light Crude Service[4]

Valve
                                                                           0.04
Flange
                                                                          0.002
Connector
                                                                          0.005
Open-ended Line
                                                                           0.04
Pump
                                                                           0.01
Other[5]
                                                                           0.23
Population Emission Factors - All Components, Heavy Crude Service[6]

Valve
                                                                         0.0004
Flange
                                                                         0.0007
Connector (other)
                                                                         0.0002
Open-ended Line
                                                                          0.004
Other[5]
                                                                          0.002
Western U.S.

Population Emission Factors - All Components, Gas Service[1]

Valve
                                                                          0.123
Connector
                                                                          0.017
Open-ended Line
                                                                          0.032
Pressure Relief Valve
                                                                          0.196
Low Continuous Bleed Pneumatic Device Vents[2]
                                                                           1.80
High Continuous Bleed Pneumatic Device Vents[2]
                                                                           48.1
Intermittent Bleed Pneumatic Device Vents[2]
                                                                           17.4
Pneumatic Pumps[3]
                                                                           13.3
Population Emission Factors - All Components, Light Crude Service[4]

Valve
                                                                           0.04
Flange
                                                                          0.002
Connector (other)
                                                                          0.005
Open-ended Line
                                                                           0.04
Pump
                                                                           0.01
Other[5]
                                                                           0.23
Population Emission Factors - All Components, Heavy Crude Service[6]

Valve
                                                                         0.0004
Flange
                                                                         0.0007
Connector (other)
                                                                         0.0002
Open-ended Line
                                                                          0.004
Other[5]
                                                                          0.002
[1] For multi-phase flow that includes gas, use the gas service emissions factors
[2] Emission Factor is in units of "scf/hour/device"
[3] Emission Factor is in units of "scf/hour/pump"
[4] Hydrocarbon liquids greater than or equal to 20˚API are considered "light crude"
[5] "Others" category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents.
[6] Hydrocarbon liquids less than 20˚API are considered "heavy crude"

Table W-1B to Subpart W of Part 98--Default Average Component Counts for Major Onshore Natural Gas Production Equipment

Major Equipment
                                    Valves
                                  Connectors
                               Open-ended Lines
                            Pressure relief valves
Eastern U.S.

Wellheads
                                       8
                                      38
                                      0.5
                                       0
Separators
                                       1
                                       6
                                       0
                                       0
meters/piping
                                      12
                                      45
                                       0
                                       0
Compressors
                                      12
                                      57
                                       0
                                       0
In-line heaters
                                      14
                                      65
                                       2
                                       1
Dehydrators
                                      24
                                      90
                                       2
                                       2
Western U.S.

Wellheads
                                      11
                                      36
                                       1
                                       0
Separators
                                      34
                                      106
                                       6
                                       2
meters/piping
                                      14
                                      51
                                       1
                                       1
Compressors
                                      73
                                      179
                                       3
                                       4
In-line heaters
                                      14
                                      65
                                       2
                                       1
Dehydrators
                                      24
                                      90
                                       2
                                       2

Table W-1C to Subpart W of Part 98--Default Average Component Counts For Major Crude Oil Production Equipment

Major Equipment
Valves
Flanges
Connectors
Open-ended Lines
Other Components
Eastern U.S.

Wellhead
5
10
4
0
1
Separator
6
12
10
0
0
Heater-treater
8
12
20
0
0
Header
5
10
4
0
0
Western U.S.

Wellhead
5
10
4
0
1
Separator
6
12
10
0
0
Heater-treater
8
12
20
0
0
Header
5
10
4
0
0

Table W-1D of Subpart W of Part 98--Designation Of Eastern And Western U.S.

Eastern U.S.
Western U.S.
Connecticut
Alabama
Delaware
Alaska
Florida
Arizona
Georgia
Arkansas
Illinois
California
Indiana
Colorado
Kentucky
Hawaii
Maine
Idaho
Maryland
Iowa
Massachusetts
Kansas
Michigan
Louisiana
New Hampshire
Minnesota
New Jersey
Mississippi
New York
Missouri
North Carolina
Montana
Ohio
Nebraska
Pennsylvania
Nevada
Rhode Island
New Mexico
South Carolina
North Dakota
Tennessee
Oklahoma
Vermont
Oregon
Virginia
South Dakota
West Virginia
Texas
Wisconsin
Utah

Washington

Wyoming

Table W-2 to Subpart W of Part 98--Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Processing

                        Onshore natural gas processing
                     Emission Factor (scf/hour/component)
Leaker Emission Factors - Compressor Components, Gas Service
Valve[1]
                                                                          15.07
Connector
                                                                           5.68
Open-Ended Line
                                                                          17.54
Pressure Relief Valve
                                                                          40.27
Meter
                                                                          19.63
Leaker Emission Factors  -  Non-Compressor Components, Gas Service
Valve
                                                                           6.52
Connector
                                                                           5.80
Open-Ended Line
                                                                          11.44
Pressure Relief Valve
                                                                           2.04
Meter
                                                                           2.98
1 Valves include control valves, block valves and regulator valves.

Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Transmission Compression

                 Onshore natural gas transmission compression
                     Emission Factor (scf/hour/component)
Leaker Emission Factors - Compressor Components, Gas Service
Valve[1]
                                                                          15.07
Connector
                                                                           5.68
Open-Ended Line
                                                                          17.54
Pressure Relief Valve
                                                                          40.27
Meter
                                                                          19.63
Leaker Emission Factors  -  Non-Compressor Components, Gas Service
Valve[1]
                                                                           6.52
Connector
                                                                           5.80
Open-Ended Line
                                                                          11.44
Pressure Relief Valve
                                                                           2.04
Meter
                                                                           2.98
Population Emission Factors  -  Gas Service
Low Continuous Bleed Pneumatic Device Vents[2]
                                                                           1.79
High Continuous Bleed Pneumatic Device Vents[2]
                                                                           20.1
Intermittent Bleed Pneumatic Device Vents[2]
                                                                           20.1
[1] Valves include control valves, block valves and regulator valves.
[2] Emission Factor is in units of "scf/hour/device"

Table W-4 to Subpart W of Part 98 -- Default Total Hydrocarbon Emission Factors for Underground Natural Gas Storage

Underground natural gas storage
Emission Factor (scf/hour/component)
Leaker Emission Factors - Storage Station, Gas Service
Valve[1]
                                                                         15.07
Connector
                                                                          5.68
Open-Ended Line
                                                                         17.54
Pressure Relief Valve
                                                                         40.27
Meter
                                                                          19.63
Population Emission Factors - Storage Wellheads, Gas Service
Connector
                                                                          0.01
Valve
                                                                           0.10
Pressure Relief Valve
                                                                           0.17
Open-ended Line
                                                                           0.03
Population Emission Factors - Other Components, Gas Service
Low Continuous Bleed Pneumatic Device Vents[2]
                                                                           1.79
High Continuous Bleed Pneumatic Device Vents[2]
                                                                           20.1
Intermittent Bleed Pneumatic Device Vents[2]
                                                                           20.1
[1] Valves include control valves, block valves and regulator valves.
2 Emission Factor is in units of "scf/hour/device"

Table W-5 to Subpart W of Part 98 -- Default Methane Emission Factors for Liquefied Natural Gas (LNG) Storage

LNG Storage
Emission Factor (scf/hour/component)
Leaker Emission Factors - LNG Storage Components, LNG Service
Valve
                                                                           1.21
Pump Seal
                                                                           4.06
Connector
                                                                           0.35
Other[1]
                                                                           1.80
Population Emission Factors - LNG Storage Compressor, Gas Service
Vapor Recovery Compressor[2]
                                                                           4.23
[1] "other" equipment type should be applied for any equipment type other than connectors, pumps, or valves.
[2] Emission Factor is in units of "scf/hour/compressor"

Table W-6 to Subpart W of Part 98 -- Default Methane Emission Factors for LNG Import and Export Equipment

LNG import and export equipment
Emission Factor (scf/hour/component)
Leaker Emission Factors - LNG Terminals Components, LNG Service
Valve
                                                                           1.21
Pump Seal
                                                                           4.06
Connector
                                                                           0.35
Other[1]
                                                                           1.80
Population Emission Factors - LNG Terminals Compressor, Gas Service
Vapor Recovery Compressor[2]
                                                                           4.23
[1] "other" equipment type should be applied for any equipment type other than connectors, pumps, or valves.
[2] Emission Factor is in units of "scf/hour/compressor"

Table W-7 to Subpart W of Part 98 -- Default Methane Emission Factors for Natural Gas Distribution

                           Natural gas distribution
                     Emission Factor (scf/hour/component)
Leaker Emission Factors - Above Grade M&R at City Gate Stations[1] Components, Gas Service
Connector
                                                                           1.72
Block Valve
                                                                          0.566
Control Valve
                                                                           9.48
Pressure Relief Valve
                                                                          0.274
Orifice Meter
                                                                          0.215
Regulator
                                                                          0.784
Open-ended Line
                                                                         26.533
Population Emission Factors - Below Grade M&R[2] Components, Gas Service[3]
Below Grade M&R Station, Inlet Pressure > 300 psig
                                                                           1.32
Below Grade M&R Station, Inlet Pressure 100 to 300 psig
                                                                           0.20
Below Grade M&R Station, Inlet Pressure < 100 psig
                                                                           0.10
Population Emission Factors - Distribution Mains, Gas Service[4]
Unprotected Steel
                                                                          12.77
Protected Steel
                                                                           0.36
Plastic
                                                                           1.15
Cast Iron
                                                                          27.67
Population Emission Factors - Distribution Services, Gas Service[5]
Unprotected Steel
                                                                           0.19
Protected Steel
                                                                           0.02
Plastic
                                                                          0.001
Copper
                                                                           0.03
[1] City gate stations at custody transfer and excluding customer meters
[2] Excluding customer meters
[3] Emission Factor is in units of "scf/hour/station"
[4] Emission Factor is in units of "scf/hour/mile"
5 Emission Factor is in units of "scf/hour/number of services"

Subpart FF  -  Underground Coal Mines
§98.320  Definition of the source category.
(a)  This source category consists of active underground coal mines, and any underground mines under development that have operational pre-mining degasification systems.  An underground coal mine is a mine at which coal is produced by tunneling into the earth to the coalbed, which is then mined with underground mining equipment such as cutting machines and continuous, longwall, and shortwall mining machines, and transported to the surface. Underground coal mines are categorized as active if any one of the following five conditions apply:
(1)  Mine development is underway.
(2)  Coal has been produced within the last 90 days.
(3)  Mine personnel are present in the mine workings.
(4)  Mine ventilation fans are operative.
(5)  The mine is designated as an "intermittent" mine by the Mine Safety and Health Administration (MSHA).
(b)  This source category includes the following:
(1)  Each ventilation well or shaft, including both those wells and shafts where gas is emitted and those where gas is sold, used onsite, or otherwise destroyed (including by flaring).
(2)  Each degasification system well or shaft, including degasification systems deployed before, during, or after mining operations are conducted in a mine area. This includes both those wells and shafts where gas is emitted, and those where gas is sold, used onsite, or otherwise destroyed (including by flaring).
(c)  This source category does not include abandoned or closed mines, surface coal mines, or post-coal mining activities (e.g., storage or transportation of coal).
§98.321  Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an active underground coal mine and the facility meets the requirements of §98.2(a)(1).
§98.322  GHGs to report.
(a)  You must report CH4 liberated from ventilation and degasification systems.
(b)  You must report CH4 destruction from systems where gas is sold, used onsite, or otherwise destroyed (including by flaring).
(c)  You must report net CH4 emissions from ventilation and degasification systems.
(d)  You must report under this subpart the CO2 emissions from coal mine gas CH4 destruction occuring at the facility, where the gas is not a fuel input for energy generation or use (e.g., flaring).
(e)  You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the CO2, CH4, and N2O emissions from each stationary fuel combustion unit by following the requirements of subpart C.  Report emissions from both the combustion of collected coal mine CH4 and any other fuels.
(f)  An underground coal mine that is subject to this part because emissions from source categories described in Tables A-3, A-4 or A-5, or from stationary combustion (subpart C),  is not required to report emissions under subpart FF of this part unless the coal mine liberates 36,500,000 actual (acf) or more of methane per year from its ventilation system.
§98.323  Calculating GHG emissions.
(a)  For each ventilation shaft, vent hole, or centralized point into which CH4 from multiple shafts and/or vent holes are collected, you must calculate the quarterly CH4 liberated from the ventilation system using Equation FF-1 of this section.  You must measure CH4 content, flow rate, temperature, pressure, and moisture content of the gas using the procedures outlined in §98.324.
		(Eq. FF-1)
Where:
CH4V 	=	Quarterly CH4 liberated from a ventilation monitoring point (metric tons CH4).
V 		=	Volumetric flow rate for the quarter
		(cfm) based on sampling or a flow rate meter.  If a flow rate meter is used and the meter automatically corrects for temperature and pressure, replace "520°R/T x P/1 atm" with "1".
MCF 	=	Moisture correction factor for the measurement period, volumetric basis.
	=	1 when V and C are measured on a dry basis or if both are measured on a wet basis.
	=	1-(fH2O)n when V is measured on a wet basis and C is measured on a dry basis.
	=	1/[1-(fH2O)] when V is measured on a dry basis and C is measured on a wet basis.
(fH2O)	=	Moisture content of the methane emitted during the measurement period, volumetric basis (cubic feet water per cubic feet emitted gas)
C 	=	CH4 concentration of ventilation gas for the quarter (%).
n	=	The number of days in the quarter where active ventilation of mining operations is taking place at the monitoring point.
0.0423	=	Density of CH4 at 520°R (60°F) and 1 atm (lb/scf).
520 [o]R	=	520 degrees Rankine.
T 	=	Temperature at which flow is measured (°R) for the quarter.
P 	=	Pressure at which flow is measured (atm) for the quarter.  The annual average barometric pressure from the nearest NOAA weather service station may be used as a default.

1,440 	=	Conversion factor (min/day).
0.454/1,000	=	Conversion factor (metric ton/lb).
(1)  Consistent with MSHA inspections, the quarterly periods are:
       (i)		January 1  -  March 31.
       (ii)		April 1 - June 30.
       (iii)	July 1 - September 30.
       (iv)		October 1 - December 31.

(2)  Values of V, , C, T, P, and fH2O, if applicable, must be based on measurements taken at least once each quarter with no fewer than 6 weeks between measurements.  If measurements are taken more frequently than once per quarter, then use  the average value for all measurements taken.  If continous measurements are taken, then use the average value over the time period of continuous monitoring.
(3)  If a facility has more than one monitoring point, the facility must calculate total CH4 liberated from ventilation systems (CH4vTotal) as the sum of the CH4 from all ventilation monitoring points in the mine, as follows:
		(Eq. FF-2)
Where:
CH4VTotal 	=	Total quarterly CH4 liberated from ventilation    systems (metric tons CH4).
CH4V		=	Quarterly CH4 liberated from each ventilation monitoring point (metric tons CH4).
m		=  Number of ventilation monitoring points.

(b)  For each monitoring point in the degasification system (this could be at each degasification well and/or vent hole, or at more centralized points into which CH4 from multiple wells and/or vent holes are collected), you must calculate the weekly CH4 liberated from the mine using CH4 measured weekly or more frequently (including by CEMS) according to 98.234(c), CH4 content, flow rate, temperature, pressure, and moisture content, and Equation FF-3 of this section.
		(Eq. FF-3)
Where:
CH4D 	=	Weekly CH4 liberated from at the monitoring point(metric tons CH4).
Vi 	=	Measured volumetric flow rate for the days in the week when the degasification system is in operation at that monitoring point, based on sampling or a flow rate meter (cfm).If a flow rate meter is used and the meter automatically corrects for temperature and pressure, replace "520°R/Ti x Pi/1 atm" with "1".
MCFi 	=	Moisture correction factor for the measurement period, volumetric basis.
	=	1 when Vi and Ci are measured on a dry basis or if both are measured on a wet basis.
	=	1-(fH2O)i when Vi is measured on a wet basis and Ci is measured on a dry basis.
	=	1/[1-(fH2O)i] when Vi is measured on a dry basis and Ci is measured on a wet basis.
(fH2O)	=	Moisture content of the CH4 emitted during the measurement period, volumetric basis (cubic feet water per cubic feet emitted gas)
Ci 	=	CH4 concentration of gas for the days in the week when the degasification system is in operation at that monitoring point (%).
n 	=	The number of days in the week that the system is operational at that measurement point.
0.0423	=	Density of CH4 at 520°R (60°F) and 1 atm (lb/scf).
520 [o]R	=	520 degrees Rankine.
Ti 	=	Temperature at which flow is measured (°R).
Pi 	=	Pressure at which flow is measured (atm).
1,440 	=	Conversion factor (minutes/day).
0.454/1,000	=	Conversion factor (metric ton/lb).

(1)  Values for V, C, T, P, and fH2O, if applicable, must be based on measurements taken at least once each calendar week with at least 3 days between measurements.  If measurements are taken more frequently than once per week, then use the average value for all measurements taken that week.  If continuous measurements are taken, then use the average values over the time period of continuous monitoring when the continuous monitoring equipment is properly functioning.
(2)  Quarterly total CH4 liberated from degasification systems for the mine should be determined as the sum of CH4 liberated determined at each of the monitoring points in the mine, summed over the number of weeks in the quarter, as follows:
	             	(Eq. FF-4)
Where:
CH4DTotal	=	Quarterly CH4 liberated from all degasification monitoring points (metric tons CH4).
CH4D	=	Weekly CH4 liberated from a degasification monitoring point (metric tons CH4).
m	=   Number of monitoring points.
w	=	Number of weeks in the quarter during which the degasification system is operated.
(c)  If gas from degasification system wells or ventilation shafts is sold, used onsite, or otherwise destroyed (including by flaring), you must calculate the quarterly CH4 destroyed for each destruction device and each point of offsite transport to a destruction device, using Equation FF-5 of this section.  You must measure CH4 content and flow rate according to the provisions in §98.324, and calculate the methane routed to the destruction device (CH4) using either Eq. FF-1 or Eq. FF-3, as applicable.
	CH4Destroyed = CH4 x DE	(Eq. FF-5)
Where:
CH4Destroyed	=	Quarterly CH4 destroyed (metric tons).
CH4 	=	Quarterly CH4 routed to the destruction device or offsite transfer point (metric tons).
 DE          =	Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1.

(1)  Calculate total CH4 destroyed as the sum of the methane destroyed at all destruction devices (onsite and offsite), using Equation FF-6 of this section.
		 (Eq. FF-6)
Where:
CH4DestroyedTotal	=	Quarterly total CH4 destroyed at the mine (metric tons CH4).
		=	Quarterly CH4 destroyed from each destruction device or offsite transfer point.
d		=	Number of onsite destruction devices and points of ofsite transport.

(d)  You must calculate the quarterly measured net CH4 emissions to the atmosphere using Equation FF-7 of this section.
	CH4 emitted (net) = CH4VTotal + CH4DTotal  -  CH4destroyedTotal	(Eq. FF-7)
Where:
CH4 emitted (net)=	Quarterly CH4 emissions from the mine (metric tons).
CH4VTotal 	=	Quarterly sum of the CH4 liberated from all mine ventilation monitoring points (CH4V), calculated using Equation FF-2 of this section (metric tons).
CH4DTotal 	=	Quarterly sum of the CH4 liberated from all mine degasification monitoring points(CH4D), calculated using Equation FF-4 of this section (metric tons).
CH4DestroyedTotal	=	Quarterly sum of the measured CH4 destroyed from all mine ventilation and degasification systems, calculated using Equation FF-6 of this section (metric tons).

(e)  For the methane collected from degasification and/or ventilation systems that is destroyed on site and is not a fuel input for energy generation or use (those emissions are monitored and reported under Subpart C of this part), you must estimate the CO2 emissions using Equation FF-8 of this section.
	CO2 = CH4Destroyedonsite * 44/16	(Eq. FF-8)
Where:
  CO2		=	Total quarterly CO2 emissions from CH4 destruction (metric tons).
  CH4Destroyedonsite	=	Quarterly sum of the CH4 destroyed, calculated as the sum of CH4 destroyed for each onsite, non-energy use, as calculated individually in Equation FF-5 of this section (metric tons).
  44/16		=	Ratio of molecular weights of CO2 to CH4.
§98.324  Monitoring and QA/QC requirements.
(a)  For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in §98.3(d)(1)(i) through (iv).  The request must be submitted no later than [INSERT DATE 90 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER] and must contain the information in §98.3(d)(2)(ii).  To obtain approval, the request must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2011.  The use of best available monitoring methods will not be approved beyond December 31, 2011.
(b)  For CH4 liberated from ventilation systems, determine whether CH4 will be monitored from each ventilation well and shaft, from a centralized monitoring point, or from a combination of the two options.  Operators are allowed flexibility for aggregating emissions from more than one ventilation well or shaft, as long as emissions from all are addressed, and the methodology for calculating total emissions documented.  Monitor by one of the following options:
(1)  Collect quarterly or more frequent grab samples (with no fewer than 6 weeks between measurements) for methane concentration and make quarterly measurements of flow rate, temperature, pressure, and moisture content, if applicable..  The sampling and measurements must be made at the same locations as MSHA inspection samples are taken, and should be taken when the mine is operating under normal conditions.  You must follow MSHA sampling procedures as set forth in the MSHA Handbook entitled, General Coal Mine Inspection Procedures and Inspection Tracking System Handbook Number: PH-08-V-1, January 1, 2008 (incorporated by reference, see §98.7).  You must record the date of sampling, flow, temperature, pressure, and moisture
measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.
(2)  Obtain results of the quarterly (or more frequent) testing performed by MSHA for the methane flowrate.  At the time and location of the MSHA sampling, make measurements of temperature, pressure and moisture content using the same procedures specified in paragraph (b)(1) of this section.  If the MSHA data for methane flow is provided in the units of actual cubic feet of methane per day, the methane flow data is inserted into Equation FF-1 of this section in place of the value for V and the variables MCF, C/100%, and 1440 are removed from the equation.
(3)  Monitor emissions through the use of one or more continuous emission monitoring systems (CEMS).  If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems.
(c)  For CH4 liberated at degasification systems, determine whether CH4 will be monitored from each well and gob gas vent hole, from a centralized monitoring point, or from a combination of the two options.  Operators are allowed flexibility for aggregating emissions from more than one well or gob gas vent hole, as long as emissions from all are addressed, and the methodology for calculating total emissions is documented.  Monitor both gas volume and methane concentration by one of the following two options:
(1)  Monitor emissions through the use of one or more continuous emissions monitoring systems (CEMS).  If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems.
(2)  Collect weekly (once each calendar week, with at least three days between measurements) or more frequent samples, for all degasification wells and gob gas vent holes.  Determine weekly or more frequent flow rates, methane concentration, temperature, and pressure from these degasification wells and gob gas vent holes.  Methane composition should be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasification well site.  Follow the sampling protocols for sampling of methane emissions from ventilation shafts, as described in §98.324(b)(1).  You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.
(3)  If the CH4 concentration is determined on a dry basis and flow is determined on a wet basis or CH4 concentration is determined on a wet basis and flow is determined on a dry basis, and the flow meter does not automatically correct for moisture content, determine the moisture content in the gas in a location near or representative of the location of:
(i)  The gas flow meter at least once each calendar week; if measuring with CEMS. If only one measurement is made each calendar week, there must be at least three days between measurements; and
(ii)	 The grab sample, if using grab samples, at the time of the sample.
(d)  Monitoring must adhere to one of the methods specified in paragraphs (d)(1) through (d)(2) of this section.
    (1)        ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; or ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see §98.7).
    (2)       As an alternative to the gas chromatography methods provided in paragraph (d)(1) of this section, you may use gaseous organic concentration analyzers and a correction factor to calculate the CH4 concentration following the requirements in paragraphs (d)(2)(i) through (d)(2)(iii) of this section.
       (i)  Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine gaseous organic concentration as required in §98.323 and in paragraphs (b) and (c) of this section.  You must calibrate the instrument with CH4 and determine the total gaseous organic concentration as carbon (or as CH4; K=1 in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7).
      (ii)  Determine a correction factor that will be used with the gaseoue organic concentrations measured in paragraph (i) of this section.  The correction factor must be determined at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(C) of this section.
      (A)  Take a minimum of three grab samples of the gas with a minimum of 20 minutes between samples and determine the methane composition of the gas using one of the methods specified in paragraph (d)(1) of this section.
      (B)  As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the gaseous organic concentration of the gas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (d)(2)(i) of this section.
      (C)  Determine the arithmetic average methane concentration and the arithmetic average gaseous organic concentration of the samples analyzed according to paragraphs (d)(2)(ii)(A) and (d)(2)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration.  If the ratio exceeds 1, use 1 for the correction factor.
      (iii)  Calculate the CH4 concentration as specified in Equation FF-9 of this section.
      	CCH4 = fNMOC x CTGOC	(Eq. FF-9)
      Where:
      CCH4	=	Methane (CH4) concentration in the gas(volume %) for use in Equations FF-1 and FF-3 of this subpart.
      fNMOC 	=   Correction factor from the most recent determination of the correction factor as specified in paragraph (d)(2)(ii) of this section (unitless).
      CTGOC 	=	Gaseous organic carbon concentration measured using Method 25A or 25B at 40 CFR part 60, appendix A-7 during routine monitoring of the gas (volume %).

(e)  All flow meters and gas composition monitors that are used to provide data for the GHG emissions calculations shall be calibrated prior to the first reporting year, using the applicable methods specified in paragraphs (d) and (e)(1) through (e)(7) of this section.  Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Flow meters and gas composition monitors  shall be recalibrated either annually or at the minimum frequency specified by the manufacturer  The operator shall operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH4 in the gas using one of the methods specified in paragraph (d) of this section.  The operator shall operate, maintain, and calibrate the flow meter using any of the following test methods or follow the procedures specified bythe flow meter manufacturer.  Flow meters must meet the accuracy requirements in §98.3(i).