(C) For components subject to the well site and compressor station fugitive emissions standards in an applicable approved state plan or applicable Federal plan in part 62 of this chapter, each survey conducted in accordance with the applicable approved state plan or applicable Federal plan in part 62 of this chapter will be considered a complete leak detection survey for purposes of this section.
(D) For an onshore petroleum and natural gas production facility electing to conduct leak detection surveys according to paragraph (q)(1)(iv) of this section, a survey of all required components at a single well-pad will be considered a complete leak detection survey for purposes of this section.
(E) For an onshore petroleum and natural gas gathering and boosting facility electing to conduct leak detection surveys according to paragraph (q)(1)(iv) of this section, a survey of all required components at a gathering compressor station or centralized oil production site, as defined in § 98.238, will be considered a complete leak detection survey for purposes of this section.
(F) For an onshore natural gas processing facility subject to the equipment leak standards for onshore natural gas processing plants in [reference to equipment leak standards for onshore natural gas processing plants in 40 CFR part 60, subpart OOOOb] or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, each survey conducted in accordance with [reference to equipment leak standards for onshore natural gas processing plants in 40 CFR part 60, subpart OOOOb] or an applicable approved state plan or applicable Federal plan in part 62 of this chapter will be considered a complete leak detection survey for the purposes of calculating emissions using the procedures specified in either paragraph (q)(2) or (3) of this section. However, this provision does not absolve you of the responsibility to conduct a complete leak detection survey of all components listed in § 98.232(d)(7) and subject to this paragraph (q) at least once during the calendar year.
(G) For natural gas distribution facilities that choose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years as provided in paragraph (q)(1)(vii) of this section, a survey of all required components at the above grade transmission-distribution transfer stations monitored during the calendar year will be considered a complete leak detection survey for purposes of this section.
(vii) Natural gas distribution facilities are required to perform equipment leak surveys only at above grade stations that qualify as transmission-distribution transfer stations. Below grade transmission-distribution transfer stations and all metering-regulating stations that do not meet the definition of transmission-distribution transfer stations are not required to perform equipment leak surveys under this section. Natural gas distribution facilities may choose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years "n," not exceeding a five-year period to cover all above grade transmission-distribution transfer stations. If the facility chooses to use the multiple year option, then the number of transmission-distribution transfer stations that are monitored in each year should be approximately equal across all years in the cycle.
(2) Calculation Method 1: Leaker emission factor calculation methodology. If you elect to use this method, you must use this method for all components included in a complete leak survey. For industry segments listed in § 98.230(a)(2) through (9), if equipment leaks are detected during surveys required or elected for components listed in paragraphs (q)(1)(i) through (iv) of this section, then you must calculate equipment leak emissions per component type per reporting facility using Equation W-30 of this section and the requirements specified in paragraphs (q)(2)(i) through (ix) of this section. For the industry segment listed in § 98.230(a)(8), the results from Equation W-30 are used to calculate population emission factors on a meter/regulator run basis using Equation W-31 of this section. If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, "n," according to paragraph (q)(1)(vii) of this section, then you must calculate the emissions from all above grade transmission-distribution transfer stations as specified in paragraph (q)(2)(xi) of this section.
*	*	*	*	*
EFs,p	=	Leaker emission factor for specific component types by leak detection method listed in Tables W-1E, W-2A, W-3A, W-4A, W-5A, W-6A, and W-7A to this subpart.
*	*	*	*	*
(i) The leak detection surveys selected for use in Equation W-30 must be conducted during the calendar year as indicated in paragraph (q)(1)(vi) and (vii) of this section, as applicable.
*	*	*	*	*
(iii) Onshore petroleum and natural gas production facilities must use the appropriate default whole gas leaker emission factors consistent with the well type, where components associated with gas wells are considered to be in gas service and components associated with oil wells are considered to be in oil service as listed in Table W-1E to this subpart.
*	*	*	*	*
(v) Onshore natural gas processing facilities must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non-compressor components in gas service listed in Table W-2A to this subpart.
*	*	*	*	*
(x) Natural gas distribution facilities must use Equation W-30 of this section and the default methane leaker emission factors for transmission-distribution transfer station components in gas service listed in Table W-7A to this subpart to calculate component emissions from annual equipment leak surveys conducted at above grade transmission-distribution transfer stations.
(A) Use Equation W-31 of this section to determine the meter/regulator run population emission factors for each GHGi. As additional survey data become available, you must recalculate the meter/regulator run population emission factors for each GHGi annually according to paragraph (q)(2)(x)(B) of this section.
		(Eq. W-31)
Where:
EFs,MR,i	=	Meter/regulator run population emission factor for GHGi based on all surveyed above grade transmission-distribution transfer stations over "n" years, in standard cubic feet of GHGi per operational hour of all meter/regulator runs.
Es,p,i,y	=	Annual total volumetric emissions at standard conditions of GHGi from component type "p" during year "y" in standard ("s") cubic feet, as calculated using Equation W-30 of this section.
p	=	Seven component types listed in Table W-7A to this subpart for transmission-distribution transfer stations.
Tw,y	=	The total time the surveyed meter/regulator run "w" was operational, in hours during survey year "y" using an engineering estimate based on best available data.
CountMR,y	=	Count of meter/regulator runs surveyed at above grade transmission-distribution transfer stations in year "y".
y	=	Year of data included in emission factor "EFs,MR,i" according to paragraph (q)(2)(x)(B) of this section.
n	=	Number of years of data, according to paragraph (q)(1)(vii) of this section, whose results are used to calculate emission factor "EFs,MR,i" according to paragraph (q)(2)(x)(B) of this section.
(B) The emission factor "EFs,MR,i," based on annual equipment leak surveys at above grade transmission-distribution transfer stations, must be calculated annually. If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, "n," according to paragraph (q)(1)(vii) of this section and you have submitted a smaller number of annual reports than the duration of the selected cycle period of 5 years or less, then all available data from the current year and previous years must be used in the calculation of the emission factor "EFs,MR,i" from Equation W-31 of this section. After the first survey cycle of "n" years is completed and beginning in calendar year (n+1), the survey will continue on a rolling basis by including the survey results from the current calendar year "y" and survey results from all previous (n−1) calendar years, such that each annual calculation of the emission factor "EFs,MR,i" from Equation W-31 is based on survey results from "n" years. Upon completion of a cycle, you may elect to change the number of years in the next cycle period (to be 5 years or less). If the number of years in the new cycle is greater than the number of years in the previous cycle, calculate "EFs,MR,i" from Equation W-31 in each year of the new cycle using the survey results from the current calendar year and the survey results from the preceding number years that is equal to the number of years in the previous cycle period. If the number of years, "nnew," in the new cycle is smaller than the number of years in the previous cycle, "n," calculate "EFs,MR,i" from Equation W-31 in each year of the new cycle using the survey results from the current calendar year and survey results from all previous (nnew−1) calendar years.
(xi) If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, "n," according to paragraph (q)(1)(vii) of this section, you must use the meter/regulator run population emission factors calculated using Equation W-31 of this section and the total count of all meter/regulator runs at above grade transmission-distribution transfer stations to calculate emissions from all above grade transmission-distribution transfer stations using Equation W-32B in paragraph (r) of this section.
(3) Calculation Method 2: Leaker measurement methodology. If you elect to use this method, you must use this method for all components included in a complete leak survey. For industry segments listed in § 98.230(a)(2) through (9), if equipment leaks are detected during surveys required or elected for components listed in paragraphs (q)(1)(i) through (v) of this section, you must determine the volumetric flow rate of each natural gas leak identified during the leak survey and aggregate the emissions by component type as specified in paragraphs (q)(3)(i) through (vii) of this section.
(i) Determine the volumetric flow rate of each natural gas leak identified during the leak survey following the methods § 98.234(b) through (d), as appropriate for each leak identified. You do not need to use the same measurement method for each leak measured.
(ii) For each leak, calculate the volume of natural gas emitted as the product of the natural gas flow rate measured in paragraph (q)(3)(i) of this section and the duration of the leak. If one leak detection survey is conducted in the calendar year, assume the component was leaking for the entire calendar year. If multiple leak detection surveys are conducted in the calendar year, assume a component found leaking in the first survey was leaking since the beginning of the year until the date of the survey; assume a component found leaking in the last survey of the year was leaking from the preceding survey through the end of the year; assume a component found leaking in a survey between the first and last surveys of the year was leaking since the preceding survey until the date of the survey. For each leaking component, account for time the component was not operational (i.e., not operating under pressure) using an engineering estimate based on best available data.
(iii) For each leak, convert the volumetric emissions of natural gas determined in paragraph (q)(3)(ii) of this section to standard conditions using the method specified in paragraph (t)(1) of this section.
(iv) For each leak, convert the volumetric emissions of natural gas at standard conditions determined in paragraph (q)(3)(iii) of this section to CO2 and CH4 volumetric emissions at standard conditions using the methods specified in paragraph (u) of this section.
(v) For each leak, convert the GHG volumetric emissions at standard conditions determined in paragraph (q)(3)(iv) of this section to GHG mass emissions using the methods specified in paragraph (v) of this section.
(vi) Sum the CO2 and CH4 mass emissions determined in paragraph (q)(3)(v) of this section separately for each type of component required to be surveyed for which a leak was detected.
(vii) For natural gas distribution facilities:
(A) Use Equation W-31 of this section to determine the meter/regulator run population emission factors for each GHGi using the methods as specified in paragraphs (q)(2)(x)(A) and (B) of this section, except use the GHG mass emissions calculated in paragraph (q)(3)(vi) rather than the emissions calculated using Equation W-30.
(B) If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, "n," according to paragraph (q)(1)(vii) of this section, you must use the meter/regulator run population emission factors calculated according to paragraph (q)(3)(vii)(A) of this section and the total count of all meter/regulator runs at above grade transmission-distribution transfer stations to calculate emissions from all above grade transmission-distribution transfer stations using Equation W-32B in paragraph (r) of this section.
(r) Equipment leaks by population count. This paragraph (r) applies to emissions sources listed in § 98.232(c)(21)(ii), (f)(7), (g)(5), (h)(6), and (j)(10)(ii) if you are not required to comply with paragraph (q) of this section and if you do not elect to comply with paragraph (q) of this section for these components in lieu of this paragraph (r). This paragraph (r) also applies to emission sources listed in § 98.232(i)(2), (i)(3), (i)(4), (i)(5), (i)(6), and (j)(11). To be subject to the requirements of this paragraph (r), the listed emissions sources also must contact streams with gas content greater than 10 percent CH4 plus CO2 by weight. Emissions sources that contact streams with gas content less than or equal to 10 percent CH4 plus CO2 by weight are exempt from the requirements of this paragraph (r) and do not need to be reported. Tubing systems equal to 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. You must calculate emissions from all emission sources listed in this paragraph (r) using Equation W-32A of this section, except for natural gas distribution facility emission sources listed in § 98.232(i)(3). Natural gas distribution facility emission sources listed in § 98.232(i)(3) must calculate emissions using Equation W-32B of this section and according to paragraph (r)(6)(ii) of this section.
*	*	*	*	*
Es,e,i	=	Annual volumetric emissions of GHGi from the emission source type in standard cubic feet. The emission source type may be a major equipment (e.g., wellhead, separator), component (e.g., connector, open-ended line), below grade metering-regulating station, below grade transmission-distribution transfer station, distribution main, distribution service, or gathering pipeline.
Es,MR,i	=	Annual volumetric emissions of GHGi from all meter/regulator runs at above grade metering regulating stations that are not above grade transmission-distribution transfer stations or, when used to calculate emissions according to paragraph (q)(2)(xi) or (q)(3)(vii)(B) of this section, the annual volumetric emissions of GHGi from all meter/regulator runs at above grade transmission-distribution transfer stations.
Counte	=	Total number of the emission source type at the facility. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must count each major equipment piece listed in Table W-1A to this subpart. Onshore petroleum and natural gas gathering and boosting facilities must also count the miles of gathering pipelines by material type (protected steel, unprotected steel, plastic, or cast iron). Underground natural gas storage facilities must count each component listed in Table W-4B to this subpart. LNG storage facilities must count the number of vapor recovery compressors. LNG import and export facilities must count the number of vapor recovery compressors. Natural gas distribution facilities must count the: (1) Number of distribution services by material type; (2) miles of distribution mains by material type; (3) number of below grade transmission-distribution transfer stations; and (4) number of below grade metering-regulating stations; as listed in Table W-7B to this subpart.
CountMR	=	Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations or, when used to calculate emissions according to paragraph (q)(2)(xi) or (q)(3)(vii)(B) of this section, the total number of meter/regulator runs at above grade transmission-distribution transfer stations.
EFs,e	=	Population emission factor for the specific emission source type, as listed in Tables W-1A, W-4B, W-5B, W-6B, and W-7B to this subpart.
*	*	*	*	*
(2) Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must use the appropriate default whole gas population emission factors listed in Table W-1A of this subpart. Major equipment associated with gas wells are considered gas service equipment in Table W-1A of this subpart. Onshore petroleum and natural gas gathering and boosting facilities shall use the gas service equipment emission factors in Table W-1A of this subpart. Major equipment associated with crude oil wells are considered crude service equipment in Table W-1A of this subpart. Where facilities conduct EOR operations the emission factor listed in Table W-1A of this subpart shall be used to estimate all streams of gases, including recycle CO2 stream. For meters/piping, use one meters/piping per well-pad for onshore petroleum and natural gas production operations and the number of meters in the facility for onshore petroleum and natural gas gathering and boosting operations.
*	*	*	*	*
(6) *	*	*
(i) Below grade transmission-distribution transfer stations, below grade metering-regulating stations, distribution mains, and distribution services must use the appropriate default methane population emission factors listed in Table W-7B of this subpart to estimate emissions from components listed in § 98.232(i)(2), (4), (5), and (6), respectively.
(ii) Above grade metering-regulating stations that are not above grade transmission-distribution transfer stations must use the meter/regulator run population emission factor calculated in Equation W-31 for the components listed in § 98.232(i)(3). Natural gas distribution facilities that do not have above grade transmission-distribution transfer stations are not required to calculate emissions for above grade metering-regulating stations and are not required to report GHG emissions in § 98.236(r)(2)(v).
(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 BOEM in compliance with 30 CFR 550.302 through 304.
(1) Offshore production facilities under BOEM jurisdiction shall report the same annual emissions as calculated and reported by BOEM in data collection and emissions estimation study published by BOEM referenced in 30 CFR 550.302 through 304 (GOADS).
(i) For any calendar year that does not overlap with the most recent BOEM emissions study publication year, report the most recent BOEM reported emissions data published by BOEM referenced in 30 CFR 550.302 through 304 (GOADS). Adjust emissions based on the operating time for the facility relative to the operating time in the most recent BOEM published study.
(ii) [Reserved]
(2) Offshore production facilities that are not under BOEM jurisdiction must use the most recent monitoring methods and calculation methods published by BOEM referenced in 30 CFR 550.302 through 304 to calculate and report annual emissions (GOADS).
(i) For any calendar year that does not overlap with the most recent BOEM emissions study publication, you may report the most recently reported emissions data submitted to demonstrate compliance with this subpart of part 98, with emissions adjusted based on the operating time for the facility relative to operating time in the previous reporting period.
(ii) [Reserved]
(3) If BOEM 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 BOEM data collection and emissions estimation methods to estimate emissions. These emission estimates would be used to report emissions from the facility sources as required in paragraph (s)(1)(i) of this section.
(4) For either first or subsequent year reporting, offshore facilities either within or outside of BOEM jurisdiction that were not covered in the previous BOEM data collection cycle must use the most recent BOEM data collection and emissions estimation methods published by BOEM referenced in 30 CFR 550.302 through 304 to calculate and report emissions.
(t) *	*	*
(2) *	*	*
*	*	*	*	*
Za	=	Compressibility factor at actual conditions for GHGi. You may use either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure conditions.
*	*	*	*	*
(u) *	*	*
(2) *	*	*
(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. For onshore natural gas processing plants that solely fractionate a liquid stream, use the GHG mole percent in feed natural gas liquid for all streams. 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).
*	*	*	*	*
(y) Other large release events. Calculate CO2 and CH4 emissions from other release events for each release that emits GHG in excess of 250 metric tons of CO2e as specified in paragraphs (y)(1) through (4) of this section.
(1) Estimate the total volume of gas released during the event in standard cubic feet using any combination of measurement data, engineering estimates, and best available data. Typically, total volume of gas released would be estimated as the product of the estimated flow or release rate and the estimated event duration.
(2) Determine the composition of the gas released to the atmosphere using measurement data, if available, or process knowledge, engineering estimates and best available data. In the event of an explosion or fire, where a portion of the natural gas may be combusted, estimate the composition of the gas released to the atmosphere considering the fraction of natural gas that was converted to CO2 during the release event.
(3) Calculate the GHG volumetric emissions using Equation W-35 in paragraph (u)(1) of this section.
(4) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.
(z) Onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, and natural gas distribution combustion emissions. Except as specified in paragraphs (z)(5) and (6) of this section, calculate CO2, CH4, and N2O combustion-related emissions from stationary or portable equipment using the applicable method in paragraphs (z)(1) through (3) of this section according to the fuel combusted as specified in those paragraphs:
(1) If a fuel combusted in the stationary or portable equipment meets the specifications of paragraph (z)(1)(i) of this section, then calculate emissions according to paragraph (z)(1)(ii) of this section.
(i) 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 in which all fuels are listed in Table C-1. If the fuel is natural gas or the blend contains natural gas, the natural gas must also meet the criteria of paragraphs (z)(1)(i)(A) and (B) of this section.
(A) The natural gas must be of pipeline quality specification.
(B) The natural gas must have a minimum higher heating value of 950 Btu per standard cubic foot.
(ii) For fuels listed in paragraph (z)(1)(i) of this section, calculate CO2, CH4, and N2O emissions according to any Tier listed in subpart C of this part, except that natural gas-fired compressor-drivers must use the appropriate emission factor in Table W-8 for quantifying CH4 emissions instead of the CH4 emission factor in Table C-2 of subpart C of this part. You must follow all applicable calculation requirements for that tier listed in § 98.33, any monitoring or QA/QC requirements listed for that tier in § 98.34, any missing data procedures specified in § 98.35, and any recordkeeping requirements specified in § 98.37. You must report emissions according to paragraph (z)(4) of this section.
(2) If a fuel combusted in the stationary or portable equipment meets the specifications of paragraph (z)(2)(i) of this section, then calculate emissions according to paragraph (z)(2)(ii) of this section.
(i) The fuel combusted in the stationary or portable equipment is natural gas that is not pipeline quality or it is a blend containing natural gas that is not pipeline quality and other gaseous fuels listed in Table C-1. The natural gas also must meet the criteria of paragraphs (z)(2)(i)(A) through (C) of this section.
(A) The natural gas must have a minimum higher heating value of 950 Btu per standard cubic foot.
(B) The natural gas must have a maximum CO2 content of 1 percent by volume.
(C) The natural gas must have a minimum CH4 content of 85 percent by volume.
(ii) For fuels listed in paragraph (z)(2)(i) of this section, calculate CO2, CH4, and N2O emissions according to Tier 2, Tier 3, or Tier 4 listed in subpart C of this part, except that natural gas-fired compressor-drivers must use the appropriate emissions factor in Table W-8 for quantifying CH4 emissions instead of the CH4 emission factor in Table C-2 of subpart C of this part. You must follow all applicable calculation requirements for that tier listed in § 98.33, any monitoring or QA/QC requirements listed for that tier in § 98.34, any missing data procedures specified in § 98.35, and any recordkeeping requirements specified in § 98.37. You must report emissions according to paragraph (z)(4) of this section.
(3) If a fuel combusted in the stationary or portable equipment meets the specifications of paragraph (z)(3)(i) of this section, then calculate emissions according to paragraph (z)(3)(ii) of this section.
(i) The fuel is not listed in Table C-1 of subpart C of this part, the fuel is a blend containing one or more fuels not listed in Table C-1, or the fuel is natural gas or contains natural gas that does not meet the criteria of either paragraph (z)(1)(i) or (z)(2)(i) of this section. This includes natural gas that has a higher heating value of less than 950 Btu per standard cubic feet and natural gas that is not pipeline quality and does not meet the composition criteria of either paragraphs (z)(2)(i)(B) or (C) of this section. This also includes field gas that does not meet the definition of natural gas in § 98.238, and blends containing field gas that does not meet the definition of natural gas in § 98.238.
(ii) For fuels listed in paragraph (z)(3)(i) of this section, calculate combustion emissions for each unit or group of units combusting the same fuel as follows:
(A) You may use company records to determine the volume of fuel combusted in the unit or group of units during the reporting year.
(B) If you have a continuous gas composition analyzer on fuel to the combustion unit(s), you must use these compositions for determining the concentration of each hydrocarbon constituent in the flow of gas to the unit or group of units. If you do not have a continuous gas composition analyzer on gas to the combustion unit(s), you may use engineering estimates based on best available data to determine the concentration of each hydrocarbon constituent in the flow of gas to the unit or group of units. Otherwise, you must use the appropriate gas compositions for each stream of hydrocarbons going to the combustion unit(s) as specified in the applicable paragraph in (u)(2) of this section.
(C) Calculate GHG volumetric emissions at actual conditions using Equations W-39A and W-39B of this section:
		(Eq. W-39A)
		(Eq. W-39B)
Where:
Ea,CO2	=	Contribution of annual CO2 emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions.
Va	=	Volume of gas sent to the combustion unit or group of units in actual cubic feet, during the year.
YCO2	=	Mole fraction of CO2 in gas sent to the combustion unit or group of units.
Ea,CH4	=	Contribution of annual CH4 emissions from portable or stationary fuel combustion sources in cubic feet, under actual conditions.
η	=	Fraction of gas combusted for portable and stationary equipment determined using engineering estimation. For internal combustion devices that are not compressor-drivers, a default of 0.995 can be used. For two-stroke lean-burn compressor-drivers, a default of 0.953 must be used; for four- stroke lean-burn compressor-drivers, a default of 0.962 must be used; and for four-stroke rich-burn compressor-drivers, a default of 0.997 must be used.
Yj	=	Mole fraction of hydrocarbon constituent j (such as methane, ethane, propane, butane, and pentanes plus) in gas sent to the combustion unit or group of units.
Rj	=	Number of carbon atoms in the hydrocarbon constituent j in gas sent to the combustion unit or group of units; 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus.
YCH4	=	Mole fraction of methane in gas sent to the combustion unit or group of units.
(D) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(E) Calculate both combustion-related CH4 and CO2 mass emissions from volumetric CH4 and CO2 emissions using calculation in paragraph (v) of this section.
(F) Calculate N2O mass emissions using Equation W-40 of this section.
		(Eq. W-40)
Where:
MassN2O	=	Annual N2O emissions from the combustion of a particular type of fuel (metric tons).
Fuel	=	Annual mass or volume of the fuel combusted (mass or volume per year, choose appropriately to be consistent with the units of HHV).
HHV	=	Higher heating value of fuel, mmBtu/unit of fuel (in units consistent with the fuel quantity combusted). For field gas or process vent gas, you may use either a default higher heating value of 1.235 x 10−3 mmBtu/scf or a site-specific higher heating value. For natural gas that is not of pipeline quality or that has a higher heating value less than 950 Btu per standard cubic foot, use a site-specific higher heating value.
EF	=	Use 1.0 x 10−4 kg N2O/mmBtu.
1 x 10−3	=	Conversion factor from kilograms to metric tons.
(4) Emissions from fuel combusted in stationary or portable equipment at onshore petroleum and natural gas production facilities, at onshore petroleum and natural gas gathering and boosting facilities, and at natural gas distribution facilities that are calculated according to the procedures in either paragraph (z)(1)(ii) or (z)(2)(ii) of this section must be reported according to the requirements specified in § 98.236(z) rather than the reporting requirements specified in subpart C of this part.
(5) 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.
(6) Internal fuel combustion sources, not compressor-drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr (or the equivalent of 130 horsepower), 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 internal fuel combustion unit.
 Amend § 98.234 by revising the introductory text and paragraphs (a) and (d)(3), and adding paragraphs (d)(5) and (i) to read as follows:
§ 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 550.
(a) You must use any of the applicable methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) or screening survey(s) as specified in § 98.233(k), (o), and (p) that occur during a calendar year. You must use any of the methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(i), (ii), or (v)(A) that occur during a calendar year. You must use one of the methods described in paragraph (a)(1)(ii), (iii), or (2)(ii) of this section, as applicable, to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(iii) or (v)(B). If electing to comply with § 98.233(q) as specified in § 98.233(q)(1)(iv), you must use any of the methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) of equipment leaks from component types as specified in § 98.233(q)(1)(iv) that occur during a calendar year. Inaccessible emissions sources, as defined in 40 CFR part 60, are not exempt from this subpart. If the primary leak detection method employed cannot be used to monitor inaccessible components without elevating the monitoring personnel more than 2 meters above a support surface, you must use alternative leak detection devices as described in paragraph (a)(1) or (3) of this section to monitor inaccessible equipment leaks or vented emissions at least once per calendar year.
(1) Optical gas imaging instrument. Use an optical gas imaging instrument for equipment leak detection as specified in either paragraph (a)(1)(i), (ii), or (iii) of this section. You may use any of the methods as specified in paragraphs (a)(1)(i) through (iii) of this section unless you are required to use a specific method to comply with the fugitive emission component requirements in part 60, subpart OOOOa of this chapter or with the fugitive emission component or equipment leak requirements in part 60, OOOOb of this chapter or with the fugitive emission component or equipment leak requirements in an applicable approved state plan or applicable Federal plan in part 62 of this chapter.
(i) Optical gas imaging instrument as specified in § 60.18 of this chapter. Use an optical gas imaging instrument for equipment leak detection in accordance with 40 CFR part 60, subpart A, § 60.18 of the Alternative work practice for monitoring equipment leaks, § 60.18(i)(1)(i); § 60.18(i)(2)(i) except that the minimum monitoring frequency shall be annual using the detection sensitivity level of 60 grams per hour as stated in 40 CFR Part 60, subpart A, Table 1: Detection Sensitivity Levels; § 60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, and § 60.18(i)(2)(iv) and (v); § 60.18(i)(3); § 60.18(i)(4)(i) and (v); including the requirements for daily instrument checks and distances, and excluding requirements for video records. Any emissions detected by the optical gas imaging instrument from an applicable component is 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.
(ii) Optical gas imaging instrument as specified in § 60.5397a of this chapter. Use an optical gas imaging instrument for equipment leak detection in accordance with § 60.5397a(b), (c)(3), (c)(7), and (e) of this chapter and paragraphs (a)(1)(ii)(A) through (C) of this section.
(A) For the purposes of this subpart, any visible emissions observed by the optical gas imaging instrument from a component required or elected to be monitored as specified in § 98.233(q)(1) is a leak.
(B) For the purposes of this subpart, the term "fugitive emissions component" in § 60.5397a of this chapter means "component."
(C) For the purpose of complying with § 98.233(q)(1)(iv), the phrase "the collection of fugitive emissions components at well sites and compressor stations" in § 60.5397a(b) of this chapter means "the collection of components for which you elect to comply with § 98.233(q)(1)(iv)."
(iii) Optical gas imaging instrument as specified in appendix K to part 60 of this chapter. Use an optical gas imaging instrument for equipment leak detection in accordance with appendix K to part 60, Determination of Volatile Organic Compound and Greenhouse Gas Leaks Using Optical Gas Imaging. Any emissions detected by the optical gas imaging instrument from an applicable component is a leak.
(2) Method 21. Use the equipment leak detection methods in Method 21 in appendix A-7 to part 60 of this chapter as specified in paragraph (a)(2)(i) or (ii) of this section. You may use either of the methods as specified in paragraphs (a)(2)(i) and (ii) of this section unless you are required to use a specific method to comply with the fugitive emission component requirements in part 60, subpart OOOOa of this chapter or with the fugitive emission component or equipment leak requirements in part 60, subpart OOOOb of this chapter or with the fugitive emission component or equipment leak requirements in an applicable approved state plan or applicable Federal plan in part 62 of this chapter. You must survey all applicable source types at the facility needed to conduct a complete equipment leak survey as defined in § 98.233(q)(1). For the purposes of this subpart, the term "fugitive emissions component" in § 60.5397a of this chapter means "component."
(i) Method 21 with a leak definition of 10,000 ppm. Use the equipment leak detection methods in Method 21 in appendix A-7 to part 60 of this chapter using methane as the reference compound. If an instrument reading of 10,000 ppm or greater is measured for any applicable component, a leak is detected.
(ii) Method 21 with a leak definition of 500 ppm. Use the equipment leak detection methods in Method 21 in appendix A-7 to part 60 of this chapter using methane as the reference compound. If an instrument reading of 500 ppm or greater is measured for any applicable component, a leak is detected.
(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. 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) [Reserved]
(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. Acoustic stethoscope type devices designed to detect through valve leakage when put in contact with the valve body and that provide an audible leak signal but do not calculate a leak rate can be used to identify through-valve leakage. For these acoustic stethoscope type devices, a leak is detected if an audible leak signal is observed or registered by the device. If the acoustic stethoscope type device is used as a screening to a measurement method and a leak is detected, the leak must be measured using any one of the methods specified in paragraphs (b) through (d) of this section.
*	*	*	*	*
(d) *	*	*
(3) For high volume samplers that output methane mass emissions, you must use the calculations in § 98.233(u) and (v) in reverse to determine the natural gas volumetric emissions at standard conditions. For high volume samplers that output methane volumetric flow in actual conditions, divide the volumetric methane flow rate by the mole fraction of methane in the natural gas according to the provisions in § 98.233(u) and estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t). Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in § 98.233(u) and (v).
*	*	*	*	*
(5) If the measured methane flow exceeds the manufacturer's reported quantitation limit or if the measured natural gas flow determined as specified in paragraph (d)(3) of this section exceeds 70 percent of the manufacturer's reported maximum sampling flow rate, then the flow exceeds the capacity of the instrument and you must either use a temporary or permanent flow meter according to paragraph (b) of this section or use calibrated bags according to paragraph (c) of this section to determine the leak or flow rate.
*	*	*	*	*
(i) Special reporting provisions for best available monitoring methods in reporting year 2023. (1) Best available monitoring methods. From January 1, 2023, to December 31, 2023, you must use the calculation methodologies and equations in § 98.233 but you may use the best available monitoring method as described in paragraph (i)(2) of this section for any parameter specified in paragraphs (i)(3) through (7) of this section for which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2023. Starting no later than January 1, 2024, you must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part.
(2) Best available monitoring methods means any of the following methods:
(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 facility records.
(3) Best available monitoring methods for measurement data for natural gas pneumatic devices. You may use best available monitoring methods for any measurement data, including activity data such as gas compositions and hours of operation, that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart for natural gas pneumatic devices as specified in § 98.233(a) at onshore natural gas processing plants and for natural gas intermittent bleed pneumatic devices that are monitored as specified in § 98.233(a)(6).
(4) Best available monitoring methods for measurement data for LNG import/export facilities. You may use best available monitoring methods for any measurement data, including activity data such as flow rates, gas compositions, and hours of operation, that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart for acid gas removal vents as specified in § 98.233(d) at LNG import/export facilities.
(5) Best available monitoring methods for measurement data for other large release events. You may use best available monitoring methods for any measurement data, including activity data such as flow rates, gas compositions, and hours of operation, that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart for other large release events as specified in § 98.233(y).
(6) Best available monitoring methods for measurement data for miscellaneous flared sources. You may use best available monitoring methods for any measurement data, including activity data such as flow rates and gas compositions, that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart for miscellaneous flared sources as specified in § 98.233(n)(1) and (2).
(7) Best available monitoring methods for measurement data for specific emission sources routed to vapor recovery. You may use best available monitoring methods for any measurement data, including activity data such as flow rates, gas compositions, and hours of operation, that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart for dehydrator vents and storage tank vents routed to vapor recovery as specified in § 98.233(e)(4) and (j)(4), respectively.
(8) Best available monitoring methods for measurement data for compressors. You may use best available monitoring methods for any measurement data that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart for dry seal vents on centrifugal compressors and all compressor sources for centrifugal compressors found in standby-pressurized-mode as specified in § 98.233(o). You may use best available monitoring methods for any measurement data that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart for rod packing on reciprocating compressors in standby-pressurized-mode as specified in § 98.233(p).
(9) Best available monitoring methods for measurement data for a facility that was part of a facility with respect to onshore petroleum and natural gas gathering and boosting prior to January 1, 2023, and meets the definition of onshore natural gas processing in § 98.230(a)(3) effective as of January 1, 2023. You may use best available monitoring methods for measurement data, including activity data, as listed in paragraphs (i)(9)(i) through (iv) of this section that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart.
(i) Temperature and pressure for emergency blowdowns in § 98.233(i).
(ii) Equipment leak surveys in § 98.233(q).
(iii) Centrifugal compressors in § 98.233(o).
(iv) Reciprocating compressors in § 98.233(p).
(10) Best available monitoring methods for measurement data for a facility that was an onshore natural gas processing facility prior to January 1, 2023, and became part of a facility with respect to onshore petroleum and natural gas gathering and boosting as defined in § 98.238 as of January 1, 2023, due to the change in definition of onshore natural gas processing in § 98.230(a)(3) effective as of January 1, 2023. You may use best available monitoring methods for measurement data, including activity data, as listed in paragraphs (i)(10)(i) through (iii) of this section that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart.
(i) Natural gas driven pneumatic pumps in § 98.233(c).
(ii) Storage tanks in § 98.233(j).
(iii) Equipment leak surveys in § 98.233(q) and/or equipment leaks by population count in § 98.233(r), as applicable, for equipment components not required for the onshore natural gas processing industry segment (i.e., pumps, flanges, other components, and gathering pipelines).
 Amend § 98.236 by:
a. Revising the introductory text and paragraphs (a)(1) introductory text and (a)(1)(xviii);
b. Adding paragraph (a)(1)(xix);
c. Revising paragraphs (a)(2) and (a)(3) introductory text;
d. Redesignating paragraphs (a)(3)(i) through (vii) as paragraphs (a)(3)(ii) through (viii), respectively;
e. Adding new paragraph (a)(3)(i) and paragraph (a)(3)(ix);
f. Revising paragraph (a)(4) introductory text;
g. Adding paragraph (a)(4)(viii);
h. Revising paragraph (a)(5) introductory text;
i. Adding paragraph (a)(5)(vii);
j. Revising paragraph (a)(6) introductory text;
k. Adding paragraph (a)(6)(vi);
l. Revising paragraph (a)(7) introductory text;
m. Redesignating paragraphs (a)(7)(i) through (vi) as paragraphs (a)(7)(ii) through (vii), respectively;
n. Adding new paragraph (a)(7)(i) and paragraph (a)(7)(viii);
o. Revising paragraph (a)(8) introductory text;
p. Adding paragraph (a)(8)(iv);
q. Revising paragraphs (a)(9) introductory text and (a)(9)(xii);
r. Adding paragraph (a)(9)(xiii);
s. Revising paragraphs (a)(10), (b), (c), (d)(1)(iii), and (d)(2)(iii)(L);
t. Adding paragraph (d)(2)(iv);
u. Revising paragraphs (e) introductory text, (e)(1) introductory text, and (e)(1)(viii), (xi), (xii), and (xv) through (xviii);
v. Adding paragraph (e)(1)(xix);
w. Revising paragraph (e)(2);
x. Removing and reserving paragraph (e)(3);
y. Revising paragraphs (f)(1) introductory text and (f)(1)(iii);
z. Adding paragraphs (f)(1)(xi)(F) and (f)(1)(xii)(F);
aa. Revising paragraphs (f)(2) introductory text and (f)(2)(iii), (ix) and (x);
bb. Adding paragraphs (f)(2)(xi) and (xii);
cc. Revising paragraphs (g)(10), (h)(2) introductory text, and (h)(2)(v) through (vii);
dd. Adding paragraphs (h)(2)(viii) through (xvi);
ee. Revising paragraphs (h)(4) introductory text and (h)(4)(iii) through (v);
ff. Adding paragraphs (h)(4)(vi) through (xiv);
gg. Revising paragraphs (i)(1) introductory text, (j) introductory text, (j)(1) and (2), (j)(3)(ii), (k)(1)(ii) through (iv), (k)(2) introductory text, (k)(3), (l)(1) introductory text, (l)(2) introductory text, and (l)(2)(vi) through (viii);
hh. Adding paragraphs (l)(2)(ix) through (xvii);
ii. Revising paragraphs (l)(3) introductory text, (l)(4) introductory text, and (l)(4)(v) through (vii);
jj. Adding paragraphs (l)(4)(viii) through (xvi);
kk. Revising paragraphs (m)(4) through (8), (n), (o)(1), (o)(2)(i)(B), (o)(2)(ii)(A), (o)(5)(i) through (iii), (p)(1), (p)(2)(ii)(A), (p)(3)(ii) introductory text, (p)(5)(i) through (iii), (q)(1) introductory text, and (q)(1)(iii);
ll. Adding paragraphs (q)(1)(vi) and (vii);
mm. Revising paragraphs (q)(2), (r)(1) introductory text, and (r)(1)(i);
nn. Removing and reserving paragraph (r)(3);
oo. Revising paragraphs (s) introductory text, (y), (z) introductory text, (z)(2)(i) and (iv) through (vi), (aa)(3) introductory text, and (aa)(3)(i);
pp. Adding paragraph (aa)(3)(viii);
qq. Removing and reserving paragraph (aa)(9);
rr. Revising paragraph (aa)(10) introductory text;
ss. Adding paragraphs (aa)(10)(v) and (vi); and
tt. Revising paragraphs (aa)(11)(ii) and (iii), (bb) introductory text, and (cc).
The revisions and additions read as follows:
§ 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. Reporters that use a flow or volume measurement system that corrects to standard conditions as provided in the introductory text in § 98.233 for data elements that are otherwise required to be determined at actual conditions, report gas volumes at standard conditions rather than the gas volumes at actual conditions and report the standard temperature and pressure used by the measurement system rather than the actual temperature and pressure.
(a) *	*	*
(1) Onshore petroleum and natural gas production. For the equipment/activities specified in paragraphs (a)(1)(i) through (xix) of this section, report the information specified in the applicable paragraphs of this section.
*	*	*	*	*
(xviii) Other large release events. Report the information specified in paragraph (y) of this section.
(xix) Combustion equipment. Report the information specified in paragraph (z) of this section.
(2) Offshore petroleum and natural gas production. Report the information specified in paragraphs (s) and (y) of this section.
(3) Onshore natural gas processing. For the equipment/activities specified in paragraphs (a)(3)(i) through (ix) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
*	*	*	*	*
(ix) Other large release events. Report the information specified in paragraph (y) of this section.
(4) Onshore natural gas transmission compression. For the equipment/activities specified in paragraphs (a)(4)(i) through (viii) of this section, report the information specified in the applicable paragraphs of this section.
*	*	*	*	*
(viii) Other large release events. Report the information specified in paragraph (y) of this section.
(5) Underground natural gas storage. For the equipment/activities specified in paragraphs (a)(5)(i) through (vii) of this section, report the information specified in the applicable paragraphs of this section.
*	*	*	*	*
(vii) Other large release events. Report the information specified in paragraph (y) of this section.
(6) LNG storage. For the equipment/activities specified in paragraphs (a)(6)(i) through (vi) of this section, report the information specified in the applicable paragraphs of this section.
*	*	*	*	*
(vi) Other large release events. Report the information specified in paragraph (y) of this section.
(7) LNG import and export equipment. For the equipment/activities specified in paragraphs (a)(7)(i) through (viii) of this section, report the information specified in the applicable paragraphs of this section.
(i) Acid gas removal units. Report the information specified in paragraph (d) of this section.
*	*	*	*	*
(viii) Other large release events. Report the information specified in paragraph (y) of this section.
(8) Natural gas distribution. For the equipment/activities specified in paragraphs (a)(8)(i) through (iv) of this section, report the information specified in the applicable paragraphs of this section.
*	*	*	*	*
(iv) Other large release events. Report the information specified in paragraph (y) of this section.
(9) Onshore petroleum and natural gas gathering and boosting. For the equipment/activities specified in paragraphs (a)(9)(i) through (xiii) of this section, report the information specified in the applicable paragraphs of this section.
*	*	*	*	*
(xii) Other large release events. Report the information specified in paragraph (y) of this section.
(xiii) Combustion equipment. Report the information specified in paragraph (z) of this section.
(10) Onshore natural gas transmission pipeline. For blowdown vent stacks, report the information specified in paragraphs (i) and (y) of this section.
(b) Natural gas pneumatic devices. You must indicate whether the facility contains the following types of equipment: Continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, and intermittent bleed natural gas pneumatic devices. If the facility contains any continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, or intermittent bleed natural gas pneumatic devices, then you must report the information specified in paragraphs (b)(1) through (4) of this section.
(1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) through (iii) of this section.
(i) For onshore natural gas processing, onshore natural gas transmission compression, and underground natural gas storage facilities, the total number of devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed), determined according to § 98.233(a)(2).
(ii) For onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities, the number of devices by each type as specified in paragraphs (b)(1)(ii)(A) through (E) of this section.
(A) Continuous low bleed devices.
(B) Continuous high bleed devices.
(C) Intermittent bleed devices subject to part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter (i.e., the number required to use Equation W-1B).
(D) Intermittent bleed devices not subject to part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter but routinely monitored (i.e., the number electing to use Equation W-1B).
(E) Intermittent bleed devices not subject to part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter and not routinely monitored (i.e., the number using Equation W-1A).
(iii) If the reported values in paragraphs (b)(1)(ii)(A), (B), and (E) of this section are estimated values determined according to § 98.233(a)(3), then you must report the information specified in paragraphs (b)(1)(iii)(A) through (C) of this section.
(A) The number of devices of each type reported in paragraphs (b)(1)(ii)(A), (B), and (E) of this section that are counted.
(B) The number of devices of each type reported in paragraphs (b)(1)(ii)(A), (B), and (E) of this section that are estimated (not counted).
(C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting.
(2) For each type of pneumatic device for which Equation W-1A of this subpart is used, report the information in paragraphs (b)(2)(i) through (iii) of this section.
(i) The estimated average number of hours in the calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) or paragraphs (b)(1)(ii)(A), (B), and (E) of this section, as applicable, were in service (i.e., supplied with natural gas) in the calendar year ("Tt" in Equation W-1A of this subpart).
(ii) Annual CO2 emissions, in metric tons CO2, for the natural gas pneumatic devices combined, calculated using Equation W-1A of this subpart and § 98.233(a)(5), and reported in paragraph (b)(1)(i) or paragraphs (b)(1)(ii)(A), (B), and (E) of this section, as applicable.
(iii) Annual CH4 emissions, in metric tons CH4, for the natural gas pneumatic devices combined, calculated using Equation W-1A of this subpart and § 98.233(a)(5), and reported in paragraph (b)(1)(i) or paragraphs (b)(1)(ii)(A), (B), and (E) of this section, as applicable.
(3) For intermittent bleed pneumatic devices for which Equation W-1B of this subpart is used, report the information in paragraphs (b)(3)(i) through (iii) of this section.
(i) The total number of intermittent devices detected as malfunctioning in any pneumatic device monitoring survey during the calendar year ("x" in Equation W-1B of this subpart).
(ii) Average time the intermittent devices were in service (i.e., supplied with natural gas) and assumed to be malfunctioning in the calendar year (average value of "Tz" in Equation W-1B of this subpart).
(iii) The total number of intermittent devices that were monitored but were not detected as malfunctioning in any pneumatic device monitoring survey during the calendar year ("Count" in Equation W-1B of this subpart).
(iv) Average time the intermittent devices that were monitored but were not detected as malfunctioning in any pneumatic device monitoring survey during the calendar year were in service (i.e., supplied with natural gas) during the calendar year ("Tavg" in Equation W-1B of this subpart).
(v) Annual CO2 emissions, in metric tons CO2, for the natural gas intermittent bleed pneumatic devices combined for which emissions were calculated using Equation W-1B of this subpart and § 98.233(a)(6).
(vi) Annual CH4 emissions, in metric tons CH4, for the natural gas pneumatic devices combined for which emissions were calculated using Equation W-1B of this subpart and § 98.233(a)(6).
(c) Natural gas driven pneumatic pumps. You must indicate whether the facility has any natural gas driven pneumatic pumps. If the facility contains any natural gas driven pneumatic pumps, then you must report the information specified in paragraphs (c)(1) through (6) of this section. If a pump was vented directly to the atmosphere for part of the year and routed to a flare, combustion, or vapor recovery system during another part of the year, then include the pump in each of the counts specified in paragraphs (c)(1) through (3) of this section.
(1) Count of natural gas driven pneumatic pumps vented directly to the atmosphere at any point during the year.
(2) Count of natural gas driven pneumatic pumps routed to a flare, combustion, or vapor recovery system at any point during the year.
(3) Total count of natural gas driven pneumatic pumps at the facility.
(4) Average estimated number of hours in the calendar year that natural gas driven pneumatic pumps that vented directly to atmosphere were in service (i.e., supplied with natural gas) ("T" in Equation W-2 of this subpart).
(5) Annual CO2 emissions, in metric tons CO2, for all natural gas driven pneumatic pumps vented directly to the atmosphere combined, calculated according to § 98.233(c)(1) and (2).
(6) Annual CH4 emissions, in metric tons CH4, for all natural gas driven pneumatic pumps vented directly to the atmosphere combined, calculated according to § 98.233(c)(1) and (2).
(d) *	*	*
(1) *	*	*
(iii) The calculation method used to calculate CO2 emissions from the acid gas removal unit, as specified in § 98.233(d). If the AGR vent was routed to a flare and comingled with emissions from other sources and you continuously monitor the flow rate and/or composition, select "Routed to a flare [§ 98.233(d)(12)(ii)]" as the calculation method.
*	*	*	*	*
(2) *	*	*
(iii) *	*	*
(L) Solvent type, from one of the following options: Selexol(TM), Rectisol(R), Purisol(TM), Fluor Solvent(SM), Benfield(TM), 20 wt% MEA, 30 wt% MEA, 40 wt% MDEA, 50 wt% MDEA, and other.
(iv) If the AGR vent was routed to a flare, then you must report the unique name or ID for the flare stack to which the AGR vent is routed.
(e) Dehydrators. You must indicate whether your facility contains any of the following equipment: Glycol dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 million standard cubic feet per day and glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day. If your facility contains any of the equipment listed in this paragraph (e), then you must report the applicable information in paragraphs (e)(1) through (3).
(1) For each glycol dehydrator that has an annual average daily natural gas throughput greater than or equal to 0.4 million standard cubic feet per day (as specified in § 98.233(e)(1)), you must report the information specified in paragraphs (e)(1)(i) through (xix) of this section for the dehydrator.
*	*	*	*	*
(viii) Whether stripping gas is used in dehydrator.
(A) If stripping gas is used in the dehydrator, type of stripping gas used (dry natural gas, flash gas, nitrogen/inert gas, other).
(B) If stripping gas is used in the dehydrator, average flow rate of stripping gas in standard cubic feet per minute.
*	*	*	*	*
(xi) Temperature of the wet natural gas at the absorber inlet, in degrees Fahrenheit.
(xii) Pressure of the wet natural gas at the absorber inlet, in pounds per square inch gauge.
*	*	*	*	*
(xv) Sub-basin ID that best represents the wells supplying gas to the dehydrator (for the onshore petroleum and natural gas production industry segment only) or name of the county that best represents the equipment supplying gas to the dehydrator (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(xvi) If a flash tank separator is used in the dehydrator, then you must report the information specified in paragraphs (e)(1)(xvi)(A) through (I) of this section for the emissions from the flash tank vent.
(A) Flash tank vent gas flow rate in standard cubic feet per hour.
(B) Flow-weighted average mole fraction of CO2 in flash tank vent gas ("XCO2" in Equation W-20 of this subpart if the flash tank vent gas is routed to a flare).
(C) Flow-weighted average mole fraction of CH4 in flash tank vent gas ("XCH4" in Equation W-19 of this subpart if the flash tank vent gas is routed to a flare).
(D) Whether any flash gas emissions are vented directly to the atmosphere, routed to a flare, routed to the regenerator firebox/fire tubes, routed to a vapor recovery system, used as stripping gas, or any combination.
(E) Annual CO2 emissions, in metric tons CO2, from the flash tank when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1)(iv), and, if applicable, (e)(1)(vi)(A).
(F) Annual CH4 emissions, in metric tons CH4, from the flash tank when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1)(iv) and, if applicable, (e)(1)(vi)(A).
(G) Annual CO2 emissions, in metric tons CO2, that resulted from routing flash gas to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1)(v) and, if applicable, (e)(1)(vi)(B).
(H) Annual CH4 emissions, in metric tons CH4, that resulted from routing flash gas to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1)(v) and, if applicable, (e)(1)(vi)(B).
(I) Annual N2O emissions, in metric tons N2O, that resulted from routing flash gas to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1)(v) and, if applicable, (e)(1)(vi)(B).
(xvii) If flash tank emissions were routed to a flare, then you must report the information specified in paragraphs (e)(1)(xvii)(A) through (G) of this section for the flared emissions from the flash tank vent.
(A) Indicate whether the flare was monitored with a CEMS in accordance with § 98.233(n)(8). If a CEMS was used, then paragraphs (e)(1)(xvi)(H) and (I) and (e)(1)(xvii)(B) through (G) of this section do not apply.
(B) Indicate whether all gas from the flash tank was measured using a continuous flow monitor.
(C) Indicate whether all gas from the flash tank was measured with a continuous gas composition analyzer.
(D) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(E) Total volume of gas from the flash tank to a flare, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(F) Fraction of total flared gas from the flash tank routed to an un-lit flare ("Zu" in Equation W-19 of this subpart).
(G) Average flare combustion efficiency, expressed as a fraction of gas from the flash tank combusted by a burning flare.
(xviii) Report the information specified in paragraphs (e)(1)(xviii)(A) through (I) of this section for the emissions from the dehydrator still vent.
(A) Still vent gas flow rate in standard cubic feet per hour.
(B) Flow-weighted average mole fraction of CO2 in still vent gas ("XCO2" in Equation W-20 of this subpart if the flash tank vent gas is routed to a flare).
(C) Flow-weighted average mole fraction of CH4 in still vent gas ("XCH4" in Equation W-19 of this subpart if the flash tank vent gas is routed to a flare).
(D) Whether any still vent emissions are vented directly to the atmosphere, routed to a flare, routed to the regenerator firebox/fire tubes, or routed to a vapor recovery system.
(E) Annual CO2 emissions, in metric tons CO2, from the still vent when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1)(iv), and, if applicable, (e)(1)(vi)(A).
(F) Annual CH4 emissions, in metric tons CH4, from the still vent when not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1)(iv) and, if applicable, (e)(1)(vi)(A).
(G) Annual CO2 emissions, in metric tons CO2, that resulted from routing still vent gas to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1)(v) and, if applicable, (e)(1)(vi)(B).
(H) Annual CH4 emissions, in metric tons CH4, that resulted from routing still vent gas to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1)(v) and, if applicable, (e)(1)(vi)(B).
(I) Annual N2O emissions, in metric tons N2O, that resulted from routing still vent gas to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1)(v) and, if applicable, (e)(1)(vi)(B).
(xix) If emissions from the still vent were routed to a flare, then you must report the information specified in paragraphs (e)(1)(xix)(A) through (G) of this section for the flared emissions from the still vent.
(A) Indicate whether the flare was monitored with a CEMS in accordance with § 98.233(n)(8). If a CEMS was used, then paragraphs (e)(1)(xviii)(H) and (I) and (e)(1)(xix)(B) through (G) of this section do not apply.
(B) Indicate whether all gas from the still vent was measured using a continuous flow monitor.
(C) Indicate whether all gas from the still vent was measured with a continuous gas composition analyzer.
(D) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(E) Total volume of gas from the still vent to a flare, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(F) Fraction of total flared gas from the still vent routed to an un-lit flare ("Zu" in Equation W-19 of this subpart).
(G) Average flare combustion efficiency, expressed as a fraction of gas from the still vent combusted by a burning flare.
(2) You must report the information specified in paragraphs (e)(2)(i) through (v) of this section for all glycol dehydrators with an annual average daily natural gas throughput greater than 0 million standard cubic feet per day and less than 0.4 million standard cubic feet per day (as specified in § 98.233(e)(2)) at the facility.
(i) The total number of dehydrators at the facility.
(ii) Whether any dehydrator emissions were routed to a vapor recovery system. If any dehydrator emissions were routed to a vapor recovery system, then you must report the total number of dehydrators at the facility that routed to a vapor recovery system.
(iii) Whether any dehydrator emissions were routed to a control device other than a vapor recovery system or a flare or regenerator firebox/fire tubes. If any dehydrator emissions were routed to a control device(s) other than a vapor recovery system or a flare or regenerator firebox/fire tubes, then you must specify the type of control device(s) and the total number of dehydrators at the facility that were routed to each type of control device.
(iv) Whether any dehydrator emissions were routed to a flare or regenerator firebox/fire tubes. If any dehydrator emissions were routed to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(2)(iv)(A) through (L) of this section.
(A) The total number of dehydrators routed to a flare or regenerator firebox/fire tubes.
(B) Indicate whether all gas from the dehydrators routed to flares was measured using a continuous flow monitor.
(C) Indicate whether all gas from the dehydrators routed to flares was measured with a continuous gas composition analyzer.
(D) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(E) Total volume of gas from dehydrators to a flare, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(F) Fraction of total flared gas from the dehydrators routed to un-lit flares ("Zu" in Equation W-19 of this subpart).
(G) Average flare combustion efficiency, expressed as a fraction of gas from the dehydrators combusted by a burning flare.
(H) Flow-weighted average mole fraction of CH4 in gas from the dehydrators routed to a flare ("XCH4" in Equation W-19 of this subpart).
(I) Flow-weighted average mole fraction of CO2 in gas from the dehydrators routed to a flare ("XCO2" in Equation W-20 of this subpart).
(J) Annual CO2 emissions, in metric tons CO2, for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(5) and, if applicable, (e)(4)(ii).
(K) Annual CH4 emissions, in metric tons CH4, for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(5) and, if applicable, (e)(4)(ii).
(L) Annual N2O emissions, in metric tons N2O, for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(5) and, if applicable, (e)(4)(ii).
(v) For dehydrator emissions that were not routed to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(2)(v)(A) and (B) of this section.
(A) Annual CO2 emissions, in metric tons CO2, for emissions from all dehydrators reported in paragraph (e)(2)(i) of this section that were not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(2) and, if applicable, (e)(4)(i), where emissions are added together for all such dehydrators.
(B) Annual CH4 emissions, in metric tons CH4, for emissions from all dehydrators reported in paragraph (e)(2)(i) of this section that were not routed to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(2) and, if applicable, (e)(4)(i), where emissions are added together for all such dehydrators.
*	*	*	*	*
(f) *	*	*
(1) For each sub-basin and well tubing diameter and pressure group for which you used Calculation Method 1 to calculate natural gas emissions from well venting for liquids unloading, report the information specified in paragraphs (f)(1)(i) through (xii) of this section. Report information separately for wells by unloading type combination.
*	*	*	*	*
(iii) Unloading type combination (with or without plunger lifts, automated or manual unloading).
*	*	*	*	*
(xi) *	*	*
(F) Unloading type (automated or manual).
(xii) *	*	*
(F) Unloading type (automated or manual).
(2) For each sub-basin for which you used Calculation Method 2 or 3 (as specified in § 93.233(f)) to calculate natural gas emissions from well venting for liquids unloading, you must report the information in paragraphs (f)(2)(i) through (xii) of this section. Report information separately for each calculation method and unloading type combination.
*	*	*	*	*
(iii) Unloading type combination (with or without plunger lifts, automated or manual unloadings).
*	*	*	*	*
(ix) Average flow-line rate of gas (average of "SFRp" from Equation W-8 or W-9 of this subpart, as applicable), at standard conditions in cubic feet per hour.
(x) Cumulative amount of time that wells were left open to the atmosphere during unloading events (sum of "HRp,q" from Equation W-8 or W-9 of this subpart, as applicable), in hours.
(xi) For wells without plunger lifts, the information in paragraphs (f)(2)(xi)(A) through (C) of this section.
(A) Average internal casing diameter (average of "CDp" from Equation W-8 of this subpart), in inches.
(B) Average well depth (average of "WDp" from Equation W-8 of this subpart), in feet.
(C) Average shut-in pressure, surface pressure, or casing pressure (average of "SPp" from Equation W-8 of this subpart), in pounds per square inch absolute.
(xii) For wells with plunger lifts, the information in paragraphs (f)(2)(xii)(A) through (C) of this section.
(A) Average internal tubing diameter (average of "TDp" from Equation W-9 of this subpart), in inches.
(B) Average tubing depth (average of "WDp" from Equation W-9 of this subpart), in feet.
(C) Average flow line pressure (average of "SPp" from Equation W-9 of this subpart), in pounds per square inch absolute.
(g) *	*	*
(10) If the well emissions were routed to a flare, then you must report the information specified in paragraphs (g)(10)(i) through (xi) of this section.
(i) Indicate whether the total emissions reported under paragraph (g)(8) and (9) of this section include vented emissions during the initial flowback period.
(ii) Indicate whether the flare was monitored with a CEMS in accordance with § 98.233(n)(8). If a CEMS was used, then paragraph (g)(9) and paragraphs (g)(10)(iii) through (xi) of this section do not apply.
(iii) Indicate whether all of the gas from completions and workovers was measured using continuous flow monitors.
(iv) Indicate whether all of the gas streams from completions and workovers were measured with continuous gas composition analyzers.
(v) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(vi) Total volume of gas from completions and workovers to all flares, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(vii) Fraction of total flared gas from completions and workovers routed to un-lit flares ("Zu" in Equation W-19 of this subpart).
(viii) Average flare combustion efficiency, expressed as a fraction of gas from completions and workovers combusted by a burning flare.
(ix) Flow-weighted average mole fraction of CH4 in gas from completions and workovers routed to flares ("XCH4" in Equation W-19 of this subpart).
(x) Flow-weighted average mole fraction of CO2 in gas from completions and workovers routed to flares ("XCO2" in Equation W-20 of this subpart).
(xi) Total N2O emissions, in metric tons N2O.
(h) *	*	*
(2) For each sub-basin with gas well completions without hydraulic fracturing and with flaring, report the information specified in paragraphs (h)(2)(i) through (xvi) of this section.
*	*	*	*	*
(v) Indicate whether the flare was monitored with a CEMS in accordance with § 98.233(n)(8). If a CEMS was used, then paragraphs (h)(2)(vi) through (xii), (xiv), and (xv) of this section do not apply.
(vi) Indicate whether all of the gas from completions was measured using continuous flow monitors.
(vii) Indicate whether all of the gas streams from completions were measured with continuous gas composition analyzers.
(viii) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(ix) Total volume of gas from completions to all flares, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(x) Fraction of total flared gas from completions routed to un-lit flares ("Zu" in Equation W-19 of this subpart).
(xi) Average flare combustion efficiency, expressed as a fraction of gas from completions combusted by a burning flare.
(xii) Flow-weighted average mole fraction of CH4 in gas from completions routed to flares ("XCH4" in Equation W-19 of this subpart).
(xiii) Flow-weighted average mole fraction of CO2 in gas from completions routed to flares ("XCO2" in Equation W-20 of this subpart).
(xiv) Annual CO2 emissions, in metric tons CO2, that resulted from completions that flared gas calculated according to § 98.233(h)(2).
(xv) Annual CH4 emissions, in metric tons CH4, that resulted from completions that flared gas calculated according to § 98.233(h)(2).
(xvi) Annual N2O emissions, in metric tons N2O, that resulted from completions that flared gas calculated according to § 98.233(h)(2).
*	*	*	*	*
(4) For each sub-basin with gas well workovers without hydraulic fracturing and with flaring, report the information specified in paragraphs (h)(4)(i) through (xiv) of this section.
*	*	*	*	*
(iii) Indicate whether the flare was monitored with a CEMS in accordance with § 98.233(n)(8). If a CEMS was used, then paragraphs (h)(4)(iv) through (x), (xii), and (xiii) of this section do not apply.
(iv) Indicate whether all of the gas from workovers was measured using continuous flow monitors.
(v) Indicate whether all of the gas streams from workovers were measured with continuous gas composition analyzers.
(vi) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(vii) Total volume of gas from workovers to all flares, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(viii) Fraction of total flared gas from workovers routed to un-lit flares ("Zu" in Equation W-19 of this subpart).
(ix) Average flare combustion efficiency, expressed as a fraction of gas from workovers combusted by a burning flare.
(x) Flow-weighted average mole fraction of CH4 in gas from workovers routed to flares ("XCH4" in Equation W-19 of this subpart).
(xi) Flow-weighted average mole fraction of CO2 in gas from workovers routed to flares ("XCO2" in Equation W-20 of this subpart).
(xii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from workovers that flared gas calculated as specified in § 98.233(h)(2).
(xiii) Annual CH4 emissions, in metric tons CH4 per year, that resulted from workovers that flared gas, calculated as specified in § 98.233(h)(2).
(xiv) Annual N2O emissions, in metric tons N2O per year, that resulted from workovers that flared gas calculated as specified in § 98.233(h)(2).
(i) *	*	*
(1) Report by equipment or event type. If you calculated emissions from blowdown vent stacks by the seven categories listed in § 98.233(i)(2)(iv) for onshore natural gas processing, onshore natural gas transmission compression, LNG import and export equipment, or onshore petroleum and natural gas gathering and boosting industry segments, then you must report the equipment or event types and the information specified in paragraphs (i)(1)(i) through (iii) of this section for each equipment or event type. If a blowdown event resulted in emissions from multiple equipment types, and the emissions cannot be apportioned to the different equipment types, then you may report the information in paragraphs (i)(1)(i) through (iii) of this section for the equipment type that represented the largest portion of the emissions for the blowdown event. If you calculated emissions from blowdown vent stacks by the eight categories listed in § 98.233(i)(2)(iv) for the onshore natural gas transmission pipeline segment, then you must report the pipeline segments or event types and the information specified in paragraphs (i)(1)(i) through (iii) of this section for each "equipment or event type" (i.e., category). If a blowdown event resulted in emissions from multiple categories, and the emissions cannot be apportioned to the different categories, then you may report the information in paragraphs (i)(1)(i) through (iii) of this section for the "equipment or event type" (i.e., category) that represented the largest portion of the emissions for the blowdown event.
*	*	*	*	*
(j) Onshore production and onshore petroleum and natural gas gathering and boosting storage tanks. You must indicate whether your facility sends hydrocarbon produced liquids to atmospheric tanks. If your facility sends hydrocarbon produced liquids to atmospheric tanks, then you must indicate which Calculation Method(s) you used to calculate GHG emissions, and you must report the information specified in paragraphs (j)(1) and (2) of this section as applicable. If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j), and any atmospheric tanks were observed to have malfunctioning dump valves during the calendar year, then you must indicate that dump valves were malfunctioning and must report the information specified in paragraph (j)(3) of this section.
(1) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j) to calculate GHG emissions, then you must report the information specified in paragraphs (j)(1)(i) through (xvi) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) and by calculation method. Onshore petroleum and natural gas gathering and boosting facilities do not report the information specified in paragraph (j)(1)(ix) of this section.
(i) Sub-basin ID (for onshore production) or county name (for onshore petroleum and natural gas gathering and boosting).
(ii) Calculation method used, and name of the software package used if using Calculation Method 1.
(iii) The total annual hydrocarbon liquids volume from gas-liquid separators and direct from wells or non-separator equipment that is sent to applicable onshore production and onshore petroleum and natural gas gathering and boosting storage tanks, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and delineation wells are the only wells in the sub-basin with hydrocarbon liquids production greater than or equal to 10 barrels per day and flowing to gas-liquid separators or direct to storage tanks. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the total volume of hydrocarbon liquids from all wells and the well ID number(s) for the well(s) included in this volume.
(iv) The average gas-liquid separator or non-separator equipment temperature, in degrees Fahrenheit.
(v) The average gas-liquid separator or non-separator equipment pressure, in pounds per square inch gauge.
(vi) The average sales oil or stabilized hydrocarbon liquids API gravity, in degrees.
(vii) The flow-weighted average concentration (mole fraction) of CO2 in flash gas from onshore production and onshore natural gas gathering and boosting storage tanks (calculated as the sum of all products of the concentration of CO2 in the flash gas for each storage tank times the throughput for that storage tank, divided by the sum of all throughputs from storage tanks) ("XCO2" in Equation W-20 of this subpart if the flash gas is routed to a flare).
(viii) The flow-weighted average concentration (mole fraction) of CH4 in flash gas from onshore production and onshore natural gas gathering and boosting storage tanks (calculated as the sum of all products of the concentration of CH4 in the flash gas for each storage tank times the throughput for that storage tank, divided by the sum of all throughputs from storage tanks) ("XCH4" in Equation W-19 of this subpart and "Y1" in Equation W-20 of this subpart if the flash gas is routed to a flare).
(ix) The number of wells sending hydrocarbon liquids to gas-liquid separators or directly to atmospheric tanks.
(x) Count of atmospheric tanks specified in paragraphs (j)(1)(x)(A) through (D) of this section.
(A) The number of atmospheric tanks.
(B) The number of atmospheric tanks that vented gas directly to the atmosphere and did not control emissions using a vapor recovery system or one or more flares at any point during the reporting year.
(C) The number of atmospheric tanks that routed emissions to vapor recovery and/or one or more flares at any point during the reporting year.
(D) The number of atmospheric tanks in paragraph (j)(1)(x)(C) of this section that had an open or unseated thief hatch at some point during the year while the tank was also routing emissions to a vapor recovery system and/or a flare.
(xi) For the atmospheric tanks at your facility identified in paragraph (j)(1)(x)(B) of this section, you must report the information specified in paragraphs (j)(1)(xi)(A) and (B) of this section.
(A) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(j)(1) and (2).
(B) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(j)(1) and (2).
(xii) For the atmospheric tanks at your facility identified in paragraph (j)(1)(x)(C) of this section, you must report the information specified in paragraphs (j)(1)(xii)(A) through (N) of this section.
(A) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(j)(1), (2), and (4).
(B) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(j)(1), (2), and (4).
(C) Indicate whether the flare was monitored with a CEMS in accordance with § 98.233(n)(8). If a CEMS was used, then paragraphs (j)(1)(xii)(D) through (K), (M), and (N) of this section do not apply.
(D) Indicate whether all of the gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(1)(xii) was measured using a continuous flow monitor.
(E) Indicate whether all of the gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(1)(xii) was measured with a continuous gas composition analyzer.
(F) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(G) Total volume of gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(1)(xii) that was routed to a flare, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(H) Fraction of total flared gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(1)(xii) that was routed to un-lit flares ("Zu" in Equation W-19 of this subpart).
(I) Average flare combustion efficiency, expressed as a fraction of gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(1)(xii) combusted by a burning flare.
(J) Annual CO2 emissions, in metric tons CO2, from flares used to control emissions, calculated according to § 98.233(j)(5).
(K) Annual CH4 emissions, in metric tons CH4, from flares used to control emissions, calculated according to § 98.233(j)(5).
(L) Annual N2O emissions, in metric tons N2O, from flares used to control emissions, calculated according to § 98.233(j)(5).
(M) Total CO2 mass, in metric tons CO2, that was recovered during the calendar year using a vapor recovery system.
(N) Total CH4 mass, in metric tons CH4, that was recovered during the calendar year using a vapor recovery system.
(xiii) For the atmospheric tanks at your facility identified in paragraph (j)(1)(x)(D) of this section, the total volume of gas vented through open or unseated thief hatches, in scf, during periods while the tanks were also routing emissions to vapor recovery systems and/or flares.
(2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the information specified in paragraphs (j)(2)(i) through (iii) of this section.
(i) Report the information specified in paragraphs (j)(2)(i)(A) through (E) of this section, at the basin level, for atmospheric tanks where emissions were calculated using Calculation Method 3 of § 98.233(j).
(A) The total annual hydrocarbon liquids throughput that is sent to all atmospheric tanks in the basin, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and delineation wells are the only wells in the sub-basin with hydrocarbon liquids production less than 10 barrels per day and that send hydrocarbon liquids to atmospheric tanks. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the total annual hydrocarbon liquids throughput from all wells and the well ID number(s) for the well(s) included in this volume.
(B) An estimate of the fraction of hydrocarbon liquids throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the basin that controlled emissions with flares.
(C) An estimate of the fraction of hydrocarbon liquids throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the basin that controlled emissions with vapor recovery systems.
(D) The number of atmospheric tanks in the basin.
(E) The total number of separators, wells, or non-separator equipment ("Count" from Equation W-15 of this subpart) in the basin.
(ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (D) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) with atmospheric tanks whose emissions were calculated using Calculation Method 3 of § 98.233(j) and that either did not control emissions with flares or that used flares to control emissions from less than half the annual hydrocarbon liquids received.
(A) Sub-basin ID (for onshore production) or county name (for onshore petroleum and natural gas gathering and boosting).
(B) The number of atmospheric tanks in the sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) that did not control emissions with flares and for which emissions were calculated using Calculation Method 3.
(C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks in the sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) that did not control emissions with flares, calculated using Equation W-15 of § 98.233(j) and adjusted using the requirements described in § 98.233(j)(4), if applicable.
(D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks in the sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) that did not control emissions with flares, calculated using Equation W-15 of § 98.233(j) and adjusted using the requirements described in § 98.233(j)(4), if applicable.
(iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (N) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) with atmospheric tanks whose emissions were calculated using Calculation Method 3 of § 98.233(j) and that used flares to control emissions from at least half the annual hydrocarbon liquids received.
(A) Sub-basin ID (for onshore production) or county name (for onshore petroleum and natural gas gathering and boosting).
(B) The number of atmospheric tanks in the sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) that controlled emissions with flares and for which emissions were calculated using Calculation Method 3.
(C) Indicate whether the flare was monitored with a CEMS in accordance with § 98.233(n)(8). If a CEMS was used, then paragraphs (j)(2)(iii)(D) through (K), (M), and (N) of this section do not apply.
(D) Indicate whether all of the gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(2)(iii) was measured using a continuous flow monitor.
(E) Indicate whether all of the gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(2)(iii) was measured with a continuous gas composition analyzer.
(F) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(G) Total volume of gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(2)(iii) that was routed to a flare, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(H) Fraction of total flared gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(2)(iii) that was routed to un-lit flares ("Zu" in Equation W-19 of this subpart).
(I) Average flare combustion efficiency, expressed as a fraction of gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(2)(iii) combusted by a burning flare.
(J) Flow-weighted average mole fraction of CH4 in gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(2)(iii) and routed to a flare ("XCH4" in Equation W-19 of this subpart).
(K) Flow-weighted average mole fraction of CO2 in gas from the atmospheric tanks in the applicable sub-basin or county and subject to this paragraph (j)(2)(iii) and routed to a flare ("XCO2" in Equation W-20 of this subpart).
(L) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled emissions with flares, calculated according to § 98.233(j)(5) and adjusted using the requirements described in § 98.233(j)(4), if applicable.
(M) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled emissions with flares, calculated according to § 98.233(j)(5) and adjusted using the requirements described in § 98.233(j)(4), if applicable.
(N) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled emissions with flares, calculated according to § 98.233(j)(5).
(3) *	*	*
(ii) The total time the dump valves on gas-liquid separators did not close properly in the calendar year, in hours (sum of the "Tdv" values used in Equation W-16 of this subpart).
*	*	*	*	*
(k) *	*	*
(1) *	*	*
(ii) Indicate if there is a flare attached to the transmission storage tank vent stack.
(iii) Method used to determine if dump valve leakage occurred.
(iv) Indicate whether scrubber dump valve leakage occurred for the transmission storage tank vent according to § 98.233(k)(2) or § 98.233(k)(5).
(2) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iv) of this section, and the vent stack vented directly to the atmosphere during the calendar year, then you must report the information specified in paragraphs (k)(2)(i) through (v) of this section for each transmission storage vent stack where scrubber dump valve leakage occurred.
*	*	*	*	*
(3) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iv) of this section, and the vent stack routed to a flare during the calendar year, then you must report the information specified in paragraphs (k)(3)(i) through (iii) of this section.
(i) Indicate whether leak rate was determined using a continuous flow measurement device for the duration of the time that flaring occurred or if an annual measurement was conducted in accordance with § 98.236(k)(1)(ii).
(ii) Measured leakage rate (average leak rate from a continuous flow measurement device) in standard cubic feet per hour.
(iii) Duration of time that flaring occurred in hours, as defined in § 98.233(k)(3) (may use best available data if a continuous flow measurement device was used).
(l) *	*	*
(1) If you used Equation W-17A of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are not routed to a flare, then you must report the information specified in paragraphs (l)(1)(i) through (vii) of this section.
*	*	*	*	*
(2) If you used Equation W-17A of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are routed to a flare, then you must report the information specified in paragraphs (l)(2)(i) through (xvii) of this section. All reported data elements should be specific to the wells for which Equation W-17A of § 98.233 was used and for which well testing emissions were routed to flares.
*	*	*	*	*
(vi) Indicate whether the flare was monitored with a CEMS in accordance with § 98.233(n)(8). If a CEMS was used, then paragraphs (l)(2)(vii) through (xiv), (xvi), and (xvii) of this section do not apply.
(vii) Indicate whether all of the gas from well testing routed to flares was measured using continuous flow monitors.
(viii) Indicate whether all of the gas streams from well testing routed to flares were measured with continuous gas composition analyzers.
(ix) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(x) Total volume of gas from well testing routed to all flares, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(xi) Fraction of total flared gas from well testing routed to un-lit flares ("Zu" in Equation W-19 of this subpart).
(xii) Average flare combustion efficiency, expressed as a fraction of gas from well testing combusted by a burning flare.
(xiii) Flow-weighted average mole fraction of CH4 in gas from well testing routed to flares ("XCH4" in Equation W-19 of this subpart).
(xiv) Flow-weighted average mole fraction of CO2 in gas from well testing routed to flares ("XCO2" in Equation W-20 of this subpart).
(xv) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l).
(xvi) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l).
(xvii) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(l).
(3) If you used Equation W-17B of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were not routed to a flare, then you must report the information specified in paragraphs (l)(3)(i) through (vi) of this section.
*	*	*	*	*
(4) If you used Equation W-17B of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were routed to a flare, then you must report the information specified in paragraphs (l)(4)(i) through (xvi) of this section. All reported data elements should be specific to the wells for which Equation W-17B of § 98.233 was used and for which well testing emissions were routed to flares.
*	*	*	*	*
(v) Indicate whether the flare was monitored with a CEMS in accordance with § 98.233(n)(8). If a CEMS was used, then paragraphs (l)(4)(vi) through (xiii), (xv), and (xvi) of this section do not apply.
(vi) Indicate whether all of the gas from well testing routed to flares was measured using continuous flow monitors.
(vii) Indicate whether all of the gas streams from well testing routed to flares were measured with continuous gas composition analyzers.
(viii) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(ix) Total volume of gas from well testing routed to all flares, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(x) Fraction of total flared gas from well testing routed to un-lit flares ("Zu" in Equation W-19 of this subpart).
(xi) Average flare combustion efficiency, expressed as a fraction of gas from well testing combusted by a burning flare.
(xii) Flow-weighted average mole fraction of CH4 in gas from well testing routed to flares ("XCH4" in Equation W-19 of this subpart).
(xiii) Flow-weighted average mole fraction of CO2 in gas from well testing routed to flares ("XCO2" in Equation W-20 of this subpart).
(xiv) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l).
(xv) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l).
(xvi) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(l).
(m) *	*	*
(4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil (average of the "GOR" values used in Equation W-18 of this subpart). Do not report the GOR if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare in the sub-basin (i.e., if you did not use Equation W-18 for any wells with associated gas venting or flaring emissions in the sub-basin).
(5) Volume of oil produced, in barrels, in the calendar year only during the time periods in which associated gas was vented or flared (the sum of "Vp,q" used in Equation W-18 of § 98.233). You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells from which associated gas was vented or flared. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the volume of oil produced for well(s) with associated gas venting and flaring and the well ID number(s) for the well(s) included in the measurement. Do not report the volume of oil produced if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare in the sub-basin (i.e., if you did not use Equation W-18 for any wells with associated gas venting or flaring emissions in the sub-basin).
(6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year only during time periods in which associated gas was vented or flared (the sum of "SG" values used in Equation W-18 of § 98.233(m)). You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells from which associated gas was vented or flared. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured total volume of associated gas sent to sales for well(s) with associated gas venting and flaring and the well ID number(s) for the well(s) included in the measurement. Do not report the volume of gas sent to sales if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare in the sub-basin (i.e., if you did not use Equation W-18 for any wells with associated gas venting or flaring emissions in the sub-basin).
(7) If you had associated gas emissions vented directly to the atmosphere without flaring, then you must report the information specified in paragraphs (m)(7)(i) through (viii) of this section for each sub-basin.
(i) Total number of wells for which associated gas was vented directly to the atmosphere without flaring and a list of their well ID numbers.
(ii) Indicate whether all of the associated gas volume vented in the sub-basin was measured using continuous flow monitors.
(iii) Indicate whether all associated gas streams vented in the sub-basin were measured with continuous gas composition analyzers.
(iv) Total volume of associated gas vented in the sub-basin, in standard cubic feet.
(v) Flow-weighted average mole fraction of CH4 in associated gas vented in the sub-basin.
(vi) Flow-weighted average mole fraction of CO2 in associated gas vented in the sub-basin.
(vii) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(m)(3) and (4).
(viii) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(m)(3) and (4).
(8) If you had associated gas emissions that were flared, then you must report the information specified in paragraphs (m)(8)(i) through (xiii) of this section for each sub-basin.
(i) Total number of wells for which associated gas was flared and a list of their well ID numbers.
(ii) Indicate whether the flare was monitored with a CEMS in accordance with § 98.233(n)(8). If a CEMS was used, then paragraphs (m)(8)(iii) through (x), (xii), and (xiii) of this section do not apply.
(iii) Indicate whether all of the associated gas volume routed to flares in the sub-basin was measured using continuous flow monitors.
(iv) Indicate whether all associated gas streams routed to flares in the sub-basin were measured with continuous gas composition analyzers.
(v) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(vi) Total volume of associated gas routed to all flares in the sub-basin, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(vii) Fraction of total flared associated gas in the sub-basin routed to un-lit flares ("Zu" in Equation W-19 of this subpart).
(viii) Average flare combustion efficiency, expressed as a fraction of associated gas combusted by a burning flare.
(ix) Flow-weighted average mole fraction of CH4 in associated gas routed to flares in the sub-basin ("XCH4" in Equation W-19 of this subpart).
(x) Flow-weighted average mole fraction of CO2 in associated gas routed to flares in the sub-basin ("XCO2" in Equation W-20 of this subpart).
(xi) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(m)(5).
(xii) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(m)(5).
(xiii) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(m)(5).
(n) Flare stacks. You must indicate if your facility has any flare stacks to which emissions are routed from miscellaneous flared sources (i.e., sources other than those subject to § 98.233(e), (g), (h), (j), (l), or (m), as applicable for the industry segment). If you have any miscellaneous flared sources, you must report the information specified in paragraph (n)(1) of this section for each flare used to control emissions from such sources. Additionally, for each flare at your facility, regardless of the source(s) controlled, you must report the information specified in paragraph (n)(2) of this section.
(1) For each flare stack used to control miscellaneous flared sources, you must report the information specified in paragraph (n)(1)(i) through (xiv) of this section.
(i) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single flare stack for each location where it operates at in a given calendar year.
(ii) Indicate whether the flare stack has a continuous flow measurement device.
(iii) Indicate whether the flare stack has a continuous gas composition analyzer on feed gas to the flare.
(iv) Indicate whether only the default HHV, only a site-specific HHV(s), or both the default and site-specific HHVs (depending on the stream to the flare) were used in Equation W-40 to calculate N2O emissions.
(v) Estimated fraction of total volume flared that was received from another facility solely for flaring (e.g., gas separated from liquid at a production facility that is routed to a flare that is assigned to an onshore petroleum and natural gas gathering and boosting facility).
(vi) Volume of gas from miscellaneous flared sources sent to the flare, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
(vii) Fraction of the feed gas sent to an un-lit flare ("Zu" in Equation W-19 of this subpart).
(viii) Flare combustion efficiency, expressed as the fraction of gas combusted by a burning flare.
(ix) Flow-weighted average mole fraction of CH4 in the feed gas from miscellaneous flared sources to the flare ("XCH4" in Equation W-19 of this subpart).
(x) Flow-weighted average mole fraction of CO2 in the feed gas from miscellaneous flared sources to the flare ("XCO2" in Equation W-20 of this subpart).
(xi) Annual CO2 emissions, in metric tons CO2 (refer to Equation W-20 of this subpart). If gas from an acid gas removal unit is routed to the flare, then the CO2 emissions to report should exclude the CO2 emissions reported under paragraph (d)(1)(v) of this section to prevent double counting of emissions.
(xii) Annual CH4 emissions, in metric tons CH4 (refer to Equation W-19 of this subpart).
(xiii) Annual N2O emissions, in metric tons N2O (refer to Equation W-40 of this subpart).
(xiv) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used to measure emissions from the flare, then the information specified in paragraphs (n)(1)(ii) through (x), (xii), and (xiii) of this section do not apply for that flare; report only the CO2 emissions as specified in paragraph (n)(1)(xi) of this section.
(2) For each flare stack at your facility, you must report the information specified in paragraphs (n)(2)(i) through (ix) of this section.
(i) Unique name or ID for the flare stack.
(ii) Indicate each emission source type that routed emissions to the flare stack during the reporting year (i.e., dehydrator vents, well venting during completions and workovers with hydraulic fracturing, gas well venting during completions and workovers without hydraulic fracturing, onshore production and onshore petroleum and natural gas gathering and boosting storage tanks, well testing venting and flaring, associated gas venting and flaring, miscellaneous flared sources).
(iii) Total volume of gas routed to the flare.
(iv) Indicate the type of flare (i.e., open ground-level flare, enclosed ground-level flare, open elevated flare, or enclosed elevated flare).
(v) Indicate the type of flare assist (i.e., unassisted, air-assisted with single speed fan/blower, air-assisted with dual speed fan/blower, air-assisted with variable speed fan/blower, steam-assisted, or pressure-assisted).
(vi) Indicate whether the flare has a continuous pilot or autoigniter.
(vii) If the flare has a continuous pilot, indicate whether the presence of flame is continuously monitored.
(viii) If the flare has a continuous pilot and the presence of a flame is not continuously monitored, indicate how periods when the pilot is not lit are identified (i.e., assumed pilot is always lit, assumed pilot was unlit for a fixed number of hours or fraction of operating hours, visual observations of flare flame, other (specify)).
(ix) Estimated fraction of the total volume routed to the flare when it was not lit.
(o) *	*	*
(1) Compressor activity data. Report the information specified in paragraphs (o)(1)(i) through (x) of this section, as applicable, for each centrifugal compressor located at your facility.
(i) Unique name or ID for the centrifugal compressor.
(ii) Hours in operating-mode.
(iii) Hours in standby-pressurized-mode.
(iv) Hours in not-operating-depressurized-mode.
(v) If you conducted volumetric emission measurements as specified in § 98.233(o)(1):
(A) Indicate whether the compressor was measured in operating-mode.
(B) Indicate whether the compressor was measured in standby-pressurized-mode.
(C) Indicate whether the compressor was measured in not-operating-depressurized-mode.
(vi) Indicate whether the compressor has blind flanges installed and associated dates.
(vii) Indicate whether the compressor has wet or dry seals.
(viii) If the compressor has wet seals, the number of wet seals.
(ix) If the compressor has dry seals, the number of dry seals.
(x) Power output of the compressor driver (hp).
(2) *	*	*
(i) *	*	*
(B) Centrifugal compressor source (wet seal, dry seal, isolation valve, or blowdown valve).
*	*	*	*	*
(ii) *	*	*
(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion, or vapor recovery.
*	*	*	*	*
(5) *	*	*
(i) Report the following activity data.
(A) Total number of centrifugal compressors at the facility.
(B) Number of centrifugal compressors that have wet seals.
(C) Number of centrifugal compressors that have atmospheric wet seal oil degassing vents (i.e., wet seal oil degassing vents where the emissions are released to the atmosphere rather than being routed to flares, combustion, or vapor recovery).
(ii) Annual CO2 emissions, in metric tons CO2, from centrifugal compressors with atmospheric wet seal oil degassing vents.
(iii) Annual CH4 emissions, in metric tons CH4, from centrifugal compressors with atmospheric wet seal oil degassing vents.
(p) *	*	*
(1) Compressor activity data. Report the information specified in paragraphs (p)(1)(i) through (vii) of this section, as applicable, for each reciprocating compressor located at your facility.
(i) Unique name or ID for the reciprocating compressor.
(ii) Hours in operating-mode.
(iii) Hours in standby-pressurized-mode.
(iv) Hours in not-operating-depressurized-mode.
(v) If you conducted volumetric emission measurements as specified in § 98.233(p)(1):
(A) Indicate whether the compressor was measured in operating-mode.
(B) Indicate whether the compressor was measured in standby-pressurized-mode.
(C) Indicate whether the compressor was measured in not-operating-depressurized-mode.
(vi) Indicate whether the compressor has blind flanges installed and associated dates.
(vii) Power output of the compressor driver (hp).
(2) *	*	*
(ii) *	*	*
(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion, or vapor recovery.
*	*	*	*	*
(3) *	*	*
(ii) For each compressor mode-source combination where a reporter emission factor as calculated in Equation W-28 was used to calculate emissions in Equation W-27, report the information specified in paragraphs (p)(3)(ii)(A) through (D) of this section.
*	*	*	*	*
(5) *	*	*
(i) Report the following activity data.
(A) Total number of reciprocating compressors at the facility.
(B) Number of reciprocating compressors that have rod packing emissions vented to the atmosphere (i.e., rod packing vents where the emissions are released to the atmosphere rather than being routed to flares, combustion, or vapor recovery).
(ii) Annual CO2 emissions, in metric tons CO2, from reciprocating compressors with rod packing emissions vented to the atmosphere.
(iii) Annual CH4 emissions, in metric tons CH4, from reciprocating compressors with rod packing emissions vented to the atmosphere.
(q) *	*	*
(1) You must report the information specified in paragraphs (q)(1)(i) through (vii) of this section.
*	*	*	*	*
(iii) Except for natural gas distribution facilities, indicate whether any of the leak detection surveys used in calculating emissions per § 98.233(q)(2) were conducted for compliance with any of the standards in paragraphs (q)(1)(iii)(A) through (E) of this section. Report the indication per facility, not per component type, and indicate all that apply for the facility.
(A) The well site or compressor station fugitive emissions standards in § 60.5397a of this chapter.
(B) The well site or compressor station fugitive emissions standards in [applicable section in 40 CFR part 60, subpart OOOOb].
(C) The well site or compressor station fugitive emissions standards in an applicable approved state plan or applicable Federal plan in part 62 of this chapter.
(D) The standards for equipment leaks at onshore natural gas plants in [applicable section in 40 CFR part 60, subpart OOOOb].
(E) The standards for equipment leaks at onshore natural gas plants in an applicable approved state plan or applicable Federal plan in part 62 of this chapter.
*	*	*	*	*
(vi) Report whether emissions were calculated using Calculation Method 1 (leaker factor emission calculation methodology) and/or using Calculation Method 2 (leaker measurement methodology).
(vii) For facilities in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting, report the number of major equipment (as listed in Table W-1A) by service type for which leak detection surveys were conducted and emissions calculated according to § 98.233(q).
(2) You must indicate whether your facility contains any of the component types subject to or complying with § 98.233(q) that are listed in § 98.232(c)(21), (d)(7), (e)(7), (e)(8), (f)(5), (f)(6), (f)(7), (f)(8), (g)(4), (g)(6), (g)(7), (h)(5), (h)(7), (h)(8), (i)(1), or (j)(10) for your facility's industry segment. For each component type that is located at your facility, you must report the information specified in paragraphs (q)(2)(i) through (v) of this section. If a component type is located at your facility and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (v) of this section but report a zero ("0") for the information required according to paragraphs (q)(2)(ii) through (v) of this section. If you used Calculation Method 1 (leaker factor emission calculation methodology) for some complete leak surveys and used Calculation Method 2 (leaker measurement methodology) for some complete leak surveys, you must report the information specified in paragraphs (q)(2)(i) through (v) of this section separately for component surveys using Calculation Method 1 and Calculation Method 2.
(i) Component type.
(ii) Total number of the surveyed component type that were identified as leaking in the calendar year ("xp" in Equation W-30 of this subpart for the component type or the number of leaks measured for the specified component type according to the provisions in § 98.233(q)(3)(i)).
(iii) Average time the surveyed components are assumed to be leaking and operational, in hours (average of "Tp,z" from Equation W-30 of this subpart for the component type or average duration of leaks for the specified component type determined according to the provisions in § 98.233(q)(3)(ii)).
(iv) Annual CO2 emissions, in metric tons CO2, for the component type as calculated using Equation W-30 or § 98.233(q)(3)(vi) (for surveyed components only).
(v) Annual CH4 emissions, in metric tons CH4, for the component type as calculated using Equation W-30 or § 98.233(q)(3)(vi) (for surveyed components only).
*	*	*	*	*
(r) *	*	*
(1) You must indicate whether your facility contains any of the emission source types required to use Equation W-32A of § 98.233. You must report the information specified in paragraphs (r)(1)(i) through (v) of this section separately for each emission source type required to use Equation W-32A that is located at your facility. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the information specified in paragraphs (r)(1)(i) through (v) separately by equipment type and service type.
(i) Emission source type. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the equipment type and service type.
*	*	*	*	*
(s) Offshore petroleum and natural gas production. You must report the information specified in paragraphs (s)(1) through (3) of this section for each emission source type listed in the most recent BOEM study.
*	*	*	*	*
(y) Other large release events. You must indicate whether there were any other large release events from your facility during the reporting year. If there were any other large release events, you must report the total number of other large release events from your facility that occurred during the reporting year and, for each other large release event, report the information specified in paragraphs (y)(1) through (8) of this section.
(1) Unique release event identification number (e.g., Event 1, Event 2).
(2) The approximate start date, start time, and duration (in hours) of the release event.
(3) A general description of the event. Include:
(A) Identification of the equipment involved in the release.
(B) A description of how the release occurred, from one of the following categories: fire/explosion, gas well blowout, oil well blowout, gas well release, oil well release, pressure relief, large leak, and other (specify).
(C) A description of the technology or method used to identify the release.
(D) An indication of whether the release was identified under the provisions of [reference to applicable standards in 40 CFR part 60, subpart OOOOb] or an applicable approved state plan or applicable Federal plan in part 62 of this chapter.
(E) An indication of whether a portion of the natural gas released was combusted during the release, and if so, the fraction of the natural gas released that was estimated to be combusted.
(4) The total volume of gas released during the event in standard cubic feet.
(5) The volume fraction of CO2 in the gas released during the event.
(6) The volume fraction of CH4 in the gas released during the event.
(7) Annual CO2 emissions, in metric tons CO2, from the release event.
(8) Annual CH4 emissions, in metric tons CH4, from the release event.
(z) Combustion equipment at onshore petroleum and natural gas production facilities, onshore petroleum and natural gas gathering and boosting facilities, and natural gas distribution facilities. If your facility is required by § 98.232(c)(22), (i)(7), or (j)(12) to report emissions from combustion equipment, then you must indicate whether your facility has any combustion units subject to reporting according to paragraph (a)(1)(xix), (a)(8)(i), or (a)(9)(xiii) of this section. If your facility contains any combustion units subject to reporting according to paragraph (a)(1)(xix), (a)(8)(i), or (a)(9)(xiii) of this section, then you must report the information specified in paragraphs (z)(1) and (2) of this section, as applicable.
*	*	*	*	*
(2) *	*	*
(i) The type of combustion unit. For internal fuel combustion units of any heat capacity that are compressor-drivers, you must also specify the design class as: 2-stroke lean-burn, 4-stroke lean-burn, 4-stroke rich-burn, or other.
*	*	*	*	*
(iv) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(z)(1) through (3).
(v) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(z)(1) through (3).
(vi) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(z)(1) through (3).
(aa) *	*	*
(3) For natural gas processing, if your facility fractionates NGLs and also reports as a supplier to subpart NN of this part, you must report the information specified in paragraphs (aa)(3)(ii) and (aa)(3)(v) through (viii) of this section. Otherwise, report the information specified in paragraphs (aa)(3)(i) through (viii) of this section.
(i) The quantity of natural gas received at the gas processing plant for processing in the calendar year, in thousand standard cubic feet.
*	*	*	*	*
(viii) Indicate whether the facility reports as a supplier to subpart NN of this part.
*	*	*	*	*
(10) For onshore petroleum and natural gas gathering and boosting facilities, report the quantities specified in paragraphs (aa)(10)(i) through (vi) of this section.
*	*	*	*	*
(v) The number of compressor stations in the facility.
(vi) The number of centralized oil production sites in the facility.
(11) *	*	*
(ii) The quantity of natural gas withdrawn from underground natural gas storage and LNG storage (regasification) facilities owned and operated by the onshore natural gas transmission pipeline owner or operator that are not subject to this subpart in the calendar year, in thousand standard cubic feet.
(iii) The quantity of natural gas added to underground natural gas storage and LNG storage (liquefied) facilities owned and operated by the onshore natural gas transmission pipeline owner or operator that are not subject to this subpart in the calendar year, in thousand standard cubic feet.
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(bb) For any missing data procedures used, report the information in § 98.3(c)(8) and the procedures used to substitute an unavailable value of a parameter, except as provided in paragraphs (bb)(1) and (2) of this section.
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