Subpart W—Petroleum and Natural Gas Systems 

This redline/strikeout document represents the changes to subpart W regulatory text in the 

proposed action: 

Greenhouse Gas Reporting Rule: Leak Detection Methodology Revisions and 

Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule 

Signed by the EPA Administrator Gina McCarthy on January 21, 2016 

§ 98.230 Definition of the source category. 

(a) This source category consists of the following industry segments: 

(1) Offshore petroleum and natural gas production. Offshore petroleum and natural gas 

production is any platform structure, affixed temporarily or permanently to offshore submerged 

lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that 

processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore. In 

addition, offshore production includes secondary platform structures connected to the platform 

structure via walkways, storage tanks associated with the platform structure and floating 

production and storage offloading equipment (FPSO). This source category does not include 

reporting of emissions from offshore drilling and exploration that is not conducted on production 

platforms. 

(2) Onshore petroleum and natural gas production. Onshore petroleum and natural gas 

production means all equipment on a single well-pad or associated with a single well-pad 

(including but not limited to compressors, generators, dehydrators, storage vessels, engines, 

boilers, heaters, flares, separation and processing equipment, and portable non-self-propelled 

equipment, which includes well drilling and completion equipment, workover equipment, and 

leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, 

stabilization, separation or treating of petroleum and/or natural gas (including condensate). This 
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equipment also includes associated storage or measurement vessels, all petroleum and natural 

gas production equipment located on islands, artificial islands, or structures connected by a 

causeway to land, an island, or an artificial island. Onshore petroleum and natural gas production 

also means all equipment on or associated with a single enhanced oil recovery (EOR) well pad 

using CO2 or natural gas injection. 

(3) Onshore natural gas processing. Natural gas processing means the separation of 

natural gas liquids (NGLs) or non-methane gases from produced natural gas, or the separation of 

NGLs into one or more component mixtures. Separation includes one or more of the following: 

forced extraction of natural gas liquids, sulfur and carbon dioxide removal, fractionation of 

NGLs, or the capture of CO2 separated from natural gas streams. This segment also includes all 

residue gas compression equipment owned or operated by the natural gas processing plant. This 

industry segment includes processing plants that fractionate gas liquids, and processing plants 

that do not fractionate gas liquids but have an annual average throughput of 25 MMscf per day or 

greater. 

(4) Onshore natural gas transmission compression. Onshore natural gas transmission 

compression means any stationary combination of compressors that move natural gas from 

production fields, natural gas processing plants, or other transmission compressors through 

transmission pipelines to natural gas distribution pipelines, LNG storage facilities, or into 

underground storage. In addition, a transmission compressor station includes equipment for 

liquids separation, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) 

gas compression that is part of onshore natural gas processing plants are included in the onshore 

natural gas processing segment and are excluded from this segment. 
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(5) Underground natural gas storage. Underground natural gas storage means subsurface 

storage, including depleted gas or oil reservoirs and salt dome caverns that store natural gas that 

has been transferred from its original location for the primary purpose of load balancing (the 

process of equalizing the receipt and delivery of natural gas); natural gas underground storage 

processes and operations (including compression, dehydration and flow measurement, and 

excluding transmission pipelines); and all the wellheads connected to the compression units 

located at the facility that inject and recover natural gas into and from the underground 

reservoirs. 

(6) Liquefied natural gas (LNG) storage. LNG storage means onshore LNG storage 

vessels located above ground, equipment for liquefying natural gas, compressors to capture and 

re-liquefy boil-off-gas, re-condensers, and vaporization units for re-gasification of the liquefied 

natural gas. 

(7) LNG import and export equipment. LNG import equipment means all onshore or 

offshore equipment that receives imported LNG via ocean transport, stores LNG, re-gasifies 

LNG, and delivers re-gasified natural gas to a natural gas transmission or distribution system. 

LNG export equipment means all onshore or offshore equipment that receives natural gas, 

liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to any location, 

including locations in the United States. 

(8) Natural gas distribution. Natural gas distribution means the distribution pipelines and 

metering and regulating equipment at metering-regulating stations that are operated by a Local 

Distribution Company (LDC) within a single state that is regulated as a separate operating 

company by a public utility commission or that is operated as an independent municipally-owned 

distribution system. This segment also excludes customer meters and regulators, infrastructure, 
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and pipelines (both interstate and intrastate) delivering natural gas directly to major industrial 

users and farm taps upstream of the local distribution company inlet. 

(9) Onshore petroleum and natural gas gathering and boosting. Onshore petroleum and 

natural gas gathering and boosting means gathering pipelines and other equipment used to collect 

petroleum and/or natural gas from onshore production gas or oil wells and used to compress, 

dehydrate, sweeten, or transport the petroleum and/or natural gas to a natural gas processing 

facility, a natural gas transmission pipeline or to a natural gas distribution pipeline. Gathering 

and boosting equipment includes, but is not limited to gathering pipelines, separators, 

compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, storage vessels, 

engines, boilers, heaters, and flares. Gathering and boosting equipment does not include 

equipment reported under any other industry segment defined in this section. Gathering pipelines 

operating on a vacuum and gathering pipelines with a GOR) less than 300 standard cubic feet per 

stock tank barrel (scf/STB) are not included in this industry segment (oil here refers to 

hydrocarbon liquids of all API gravities). 

(10) Onshore natural gas transmission pipeline. Onshore natural gas transmission 

pipeline means all natural gas transmission pipelines as defined in § 98.238. 

(b) [Reserved] 

§ 98.231 Reporting threshold. 

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

and natural gas systems and the facility meets the requirements of § 98.2(a)(2), except for the 

industry segments in paragraphs (a)(1) through (4) of this section. 
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(1) Facilities must report emissions from the onshore petroleum and natural gas 

production industry segment only if emission sources specified in § 98.232(c) emit 25,000 metric 

tons of CO2 equivalent or more per year. 

(2) Facilities must report emissions from the natural gas distribution industry segment 

only if emission sources specified in § 98.232(i) emit 25,000 metric tons of CO2 equivalent or 

more per year. 

(3) Facilities must report emissions from the onshore petroleum and natural gas gathering 

and boosting industry segment only if emission sources specified in § 98.232(j) emit 25,000 

metric tons of CO2 equivalent or more per year. 

(4) Facilities must report emissions from the onshore natural gas transmission pipeline 

industry segment only if emission sources specified in § 98.232(m) emit 25,000 metric tons of 

CO2 equivalent or more per year. 

(b) For applying the threshold defined in § 98.2(a)(2), natural gas processing facilities 

must also include owned or operated residue gas compression equipment. 

§ 98.232 GHGs to report. 

(a) You must report CO2, CH4, and N2O emissions from each industry segment specified 

in paragraphs (b) through (j) and (m) of this section, CO2, CH4, and N2O emissions from each 

flare as specified in paragraphs (b) through (j) of this section, and stationary and portable 

combustion emissions as applicable as specified in paragraph (k) of this section. 

(b) For offshore petroleum and natural gas production, report CO2, CH4, and N2O 

emissions from equipment leaks, vented emission, and flare emission source types as identified 

in the data collection and emissions estimation study conducted by BOEMRE in compliance 

with 30 CFR 250.302 through 304. Offshore platforms do not need to report portable emissions. 
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(c) For an onshore petroleum and natural gas production facility, report CO2, CH4, and 

N2O emissions from only the following source types on a single well-pad or associated with a 

single well-pad: 

(1) Natural gas pneumatic device venting. 

(2) [Reserved] 

(3) Natural gas driven pneumatic pump venting. 

(4) Well venting for liquids unloading. 

(5) Gas well venting during well completions without hydraulic fracturing. 

(6) Well venting during well completions with hydraulic fracturing that have a GOR of 

300 scf/STB or greater (oil here refers to hydrocarbon liquids produced of all API gravities). 

(7) Gas well venting during well workovers without hydraulic fracturing. 

(8) Well venting during well workovers with hydraulic fracturing that have a GOR of 300 

scf/STB or greater (oil here refers to hydrocarbon liquids produced of all API gravities). 

(9) Flare stack emissions. 

(10) Storage tanks vented emissions from produced hydrocarbons. 

(11) Reciprocating compressor venting. 

(12) Well testing venting and flaring. 

(13) Associated gas venting and flaring from produced hydrocarbons. 

(14) Dehydrator vents. 

(15) [Reserved] 

(16) EOR injection pump blowdown. 

(17) Acid gas removal vents. 

(18) EOR hydrocarbon liquids dissolved CO2. 
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(19) Centrifugal compressor venting. 

(20) [Reserved] 

(21) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, 

pumps, flanges, and other equipment leak sources (such as instruments, loading arms, stuffing 

boxes, compressor seals, dump lever arms, and breather caps). 

(22) You must use the methods in § 98.233(z) and report under this subpart the emissions 

of CO2, CH4, and N2O from stationary or portable fuel combustion equipment that cannot move 

on roadways under its own power and drive train, and that is located at an onshore petroleum and 

natural gas production facility as defined in § 98.238. Stationary or portable equipment are the 

following equipment, which are integral to the extraction, processing, or movement of oil or 

natural gas: well drilling and completion equipment, workover equipment, natural gas 

dehydrators, natural gas compressors, electrical generators, steam boilers, and process heaters. 

(d) For onshore natural gas processing, report CO2, CH4, and N2O emissions from the 

following sources: 

(1) Reciprocating compressor venting. 

(2) Centrifugal compressor venting. 

(3) Blowdown vent stacks. 

(4) Dehydrator vents. 

(5) Acid gas removal vents. 

(6) Flare stack emissions. 

(7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, 

and meters.
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(8) Equipment leaks from pumps that are subject to 40 CFR part 60, subpart OOOOa. 

You may also elect to report emissions from pumps if you survey them using a leak detection 

method described in § 98.234(a) and are not subject to 40 CFR part 60, subpart OOOOa.

(e) For onshore natural gas transmission compression, report CO2, CH4, and N2O 

emissions from the following sources: 

(1) Reciprocating compressor venting. 

(2) Centrifugal compressor venting. 

(3) Transmission storage tanks. 

(4) Blowdown vent stacks. 

(5) Natural gas pneumatic device venting. 

(6) Flare stack emissions. 

(7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, 

and meters.

(8) Equipment leaks from all equipment leak component types, except those listed in 

paragraph (e)(7) of this section, that are subject to 40 CFR part 60, subpart OOOOa. You may 

also elect to report emissions from these equipment leak component types if you survey them 

using a leak detection method described in § 98.234(a) and are not subject to 40 CFR part 60, 

subpart OOOOa.

(f) For underground natural gas storage, report CO2, CH4, and N2O emissions from the 

following sources: 

(1) Reciprocating compressor venting. 

(2) Centrifugal compressor venting. 

(3) Natural gas pneumatic device venting. 
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(4) Flare stack emissions. 

(5) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, 

and meters associated with storage stations.

(6) Equipment leaks from all equipment leak component types associated with storage 

stations, except those listed in paragraph (f)(5) of this section, that are subject to 40 CFR part 60, 

subpart OOOOa. You may also elect to report emissions from these equipment leak component 

types if you survey them using a leak detection method described in § 98.234(a) and are not 

subject to 40 CFR part 60, subpart OOOOa. 

(7) Equipment leaks from valves, connectors, open-ended lines, and pressure relief valves 

associated with storage wellheads. 

(8) Equipment leaks from all equipment leak component types associated with storage 

wellheads, except those listed in paragraph (f)(7) of this section, that are subject to 40 CFR part 

60, subpart OOOOa. You may also elect to report emissions from these equipment leak 

component types if you survey them using a leak detection method described in § 98.234(a) and 

are not subject to 40 CFR part 60, subpart OOOOa.

(g) For LNG storage, report CO2, CH4, and N2O emissions from the following sources: 

(1) Reciprocating compressor venting. 

(2) Centrifugal compressor venting. 

(3) Flare stack emissions.

(4) Equipment leaks from valves, pump seals, connectors, and other equipment leak 

sources in LNG service. 

(5) Equipment leaks from vapor recovery compressors that are not subject to 40 CFR part 

60, subpart OOOOa. 

Deleted: Equipment leaks from valves; pump seals; 

connectors; vapor recovery compressors, and other 

equipment leak sources.¶

(4) 
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(6) Equipment leaks from all equipment leak component types in gas service that are 

subject to 40 CFR part 60, subpart OOOOa. You may also elect to report emissions from these 

equipment leak component types if you survey them using a leak detection method described in 

§ 98.234(a) and are not subject to 40 CFR part 60, subpart OOOOa.

(h) LNG import and export equipment, report CO2, CH4, and N2O emissions from the 

following sources: 

(1) Reciprocating compressor venting. 

(2) Centrifugal compressor venting. 

(3) Blowdown vent stacks. 

(4) Flare stack emissions.

(5) Equipment leaks from valves, pump seals, connectors, and other equipment leak 

sources in LNG service. 

(6) Equipment leaks from vapor recovery compressors that are not subject to 40 CFR part 

60, subpart OOOOa. 

(7) Equipment leaks from all equipment leak component types in gas service that are 

subject to 40 CFR part 60, subpart OOOOa. You may also elect to report emissions from these 

equipment leak component types if you survey them using a leak detection method described in 

§ 98.234(a) and are not subject to 40 CFR part 60, subpart OOOOa.

(i) For natural gas distribution, report CO2, CH4, and N2O emissions from the following 

sources: 

(1) Equipment leaks from connectors, block valves, control valves, pressure relief valves, 

orifice meters, regulators, and open-ended lines at above grade transmission-distribution transfer 

stations. 

Deleted: Equipment leaks from valves, pump seals, 

connectors, vapor recovery compressors, and other 

equipment leak sources.¶

(5) 
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(2) Equipment leaks at below grade transmission-distribution transfer stations. 

(3) Equipment leaks at above grade metering-regulating stations that are not above grade 

transmission-distribution transfer stations. 

(4) Equipment leaks at below grade metering-regulating stations. 

(5) Distribution main equipment leaks. 

(6) Distribution services equipment leaks. 

(7) Report under subpart W of this part the emissions of CO2, CH4, and N2O emissions 

from stationary fuel combustion sources following the methods in § 98.233(z). 

(j) For an onshore petroleum and natural gas gathering and boosting facility, report CO2, 

CH4, and N2O emissions from the following source types: 

(1) Natural gas pneumatic device venting. 

(2) Natural gas driven pneumatic pump venting. 

(3) Acid gas removal vents. 

(4) Dehydrator vents. 

(5) Blowdown vent stacks. 

(6) Storage tank vented emissions. 

(7) Flare stack emissions. 

(8) Centrifugal compressor venting. 

(9) Reciprocating compressor venting. 

(10) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, 

pumps, flanges, and other equipment leak sources (such as instruments, loading arms, stuffing 

boxes, compressor seals, dump lever arms, and breather caps). 

(11) Gathering pipeline equipment leaks. 
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(12) You must use the methods in § 98.233(z) and report under this subpart the emissions 

of CO2, CH4, and N2O from stationary or portable fuel combustion equipment that cannot move 

on roadways under its own power and drive train, and that is located at an onshore petroleum and 

natural gas gathering and boosting facility as defined in § 98.238. Stationary or portable 

equipment includes the following equipment, which are integral to the movement of natural gas: 

Natural gas dehydrators, natural gas compressors, electrical generators, steam boilers, and 

process heaters. 

(k) Report under subpart C of this part (General Stationary Fuel Combustion Sources) the 

emissions of CO2, CH4, and N2O from each stationary fuel combustion unit by following the 

requirements of subpart C except for facilities under onshore petroleum and natural gas 

production, onshore petroleum and natural gas gathering and boosting, and natural gas 

distribution. Onshore petroleum and natural gas production facilities must report stationary and 

portable combustion emissions as specified in paragraph (c) of this section. Natural gas 

distribution facilities must report stationary combustion emissions as specified in paragraph (i) of 

this section. Onshore petroleum and natural gas gathering and boosting facilities must report 

stationary and portable combustion emissions as specified in paragraph (j) of this section. 

(l) You must report under subpart PP of this part (Suppliers of Carbon Dioxide), CO2

emissions captured and transferred off site by following the requirements of subpart PP. 

(m) For onshore natural gas transmission pipeline, report pipeline blowdown CO2 and 

CH4 emissions from blowdown vent stacks. 

§ 98.233 Calculating GHG emissions. 

You must calculate and report the annual GHG emissions as prescribed in this section. 

For calculations that specify measurements in actual conditions, reporters may use a flow or 
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volume measurement system that corrects to standard conditions and determine the flow or 

volume at standard conditions; otherwise, reporters must use average atmospheric conditions or 

typical operating conditions as applicable to the respective monitoring methods in this section. 

(a) Natural gas pneumatic device venting. Calculate CH4 and CO2 volumetric emissions 

from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic 

devices using Equation W-1 of this section. 





3

1

, * * * t

Es i Countt EFt GHGi Tt (Eq. W-1) 

Where: 

Es,i = Annual total volumetric GHG emissions at standard conditions in standard 

cubic feet per year from natural gas pneumatic device vents, of types “t” 

(continuous high bleed, continuous low bleed, intermittent bleed), for GHGi. 

Countt = Total number of natural gas pneumatic devices of type “t” (continuous high 

bleed, continuous low bleed, intermittent bleed) as determined in paragraph 

(a)(1) or (a)(2) of this section. 

EFt = Population emission factors for natural gas pneumatic device vents (in 

standard cubic feet per hour per device) of each type “t” listed in Tables W1A, W-3, and W-4 of this subpart for onshore petroleum and natural gas 

production, onshore natural gas transmission compression, and underground 

natural gas storage facilities, respectively. Onshore petroleum and natural gas 

gathering and boosting facilities must use the population emission factors 

listed in Table W-1A of this subpart. 

GHGi = For onshore petroleum and natural gas production facilities, onshore 

petroleum and natural gas gathering and boosting facilities, onshore natural 

gas transmission compression facilities, and underground natural gas storage 

facilities, concentration of GHGi, CH4 or CO2, in produced natural gas or 

processed natural gas for each facility as specified in paragraphs (u)(2)(i), 

(iii), and (iv) of this section. 

Tt = Average estimated number of hours in the operating year the devices, of each 

type “t”, were operational using engineering estimates based on best available 

data. Default is 8,760 hours. 
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(1) For all industry segments, determine “Countt” for Equation W-1 of this subpart for 

each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and 

intermittent bleed) by counting the devices, except as specified in paragraph (a)(2) of this 

section. The reported number of devices must represent the total number of devices for the 

reporting year. 

(2) For the onshore petroleum and natural gas production industry segment, you have the 

option in the first two consecutive calendar years to determine “Countt” for Equation W-1 of this 

section for each type of natural gas pneumatic device (continuous high bleed, continuous low 

bleed, and intermittent bleed) using engineering estimates based on best available data. For the 

onshore petroleum and natural gas gathering and boosting industry segment, you have the option 

in the first two consecutive calendar years to determine “Countt” for Equation W-1 for each type 

of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent 

bleed) using engineering estimates based on best available data. 

(3) For all industry segments, determine the type of pneumatic device using engineering 

estimates based on best available information. 

(4) Calculate both CH4 and CO2 mass emissions from volumetric emissions using 

calculations in paragraph (v) of this section. 

(b) [Reserved] 

(c) Natural gas driven pneumatic pump venting. (1) Calculate CH4 and CO2 volumetric 

emissions from natural gas driven pneumatic pump venting using Equation W-2 of this section. 

Natural gas driven pneumatic pumps covered in paragraph (e) of this section do not have to 

report emissions under this paragraph (c). 

Es,i  Count* EF * GHGi * T (Eq. W-2) 
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Where: 

Es,i = Annual total volumetric GHG emissions at standard conditions in standard 

cubic feet per year from all natural gas driven pneumatic pump venting, for 

GHGi. 

Count = Total number of natural gas driven pneumatic pumps. 

EF = Population emissions factors for natural gas driven pneumatic pumps (in 

standard cubic feet per hour per pump) listed in Table W-1A of this subpart 

for onshore petroleum and natural gas production and onshore petroleum and 

natural gas gathering and boosting facilities. 

GHGi = Concentration of GHGi, CH4, or CO2, in produced natural gas as defined in 

paragraph (u)(2)(i) of this section. 

T = Average estimated number of hours in the operating year the pumps were 

operational using engineering estimates based on best available data. Default 

is 8,760 hours. 

(2) Calculate both CH4 and CO2 mass emissions from volumetric emissions using 

calculations in paragraph (v) of this section. 

(d) Acid gas removal (AGR) vents. For AGR vents (including processes such as amine, 

membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for CO2

only (not CH4) vented directly to the atmosphere or emitted through a flare, engine (e.g., 

permeate from a membrane or de-adsorbed gas from a pressure swing adsorber used as fuel 

supplement), or sulfur recovery plant, using any of the calculation methods described in this 

paragraph (d), as applicable. 

(1) Calculation Method 1. If you operate and maintain a continuous emissions monitoring 

system (CEMS) that has both a CO2 concentration monitor and volumetric flow rate monitor, 

you must calculate CO2 emissions under this subpart by following the Tier 4 Calculation Method 

and all associated calculation, quality assurance, reporting, and recordkeeping requirements for 

Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you 

may follow the manufacturer’s instructions or industry standard practice. If a CO2 concentration 
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monitor and volumetric flow rate monitor are not available, you may elect to install a CO2

concentration monitor and a volumetric flow rate monitor that comply with all of the 

requirements specified for the Tier 4 Calculation Method in subpart C of this part (General 

Stationary Fuel Combustion Sources). The calculation and reporting of CH4 and N2O emissions 

is not required as part of the Tier 4 requirements for AGR units. 

(2) Calculation Method 2. If a CEMS is not available but a vent meter is installed, use the 

CO2 composition and annual volume of vent gas to calculate emissions using Equation W-3 of 

this section. 

2 CO2 Ea,CO Vs *Vol (Eq. W-3) 

Where: 

Ea,CO2 = Annual volumetric CO2 emissions at actual conditions, in cubic feet per year. 

VS = Total annual volume of vent gas flowing out of the AGR unit in cubic feet 

per year at actual conditions as determined by flow meter using methods set 

forth in § 98.234(b). Alternatively, you may follow the manufacturer’s 

instructions or industry standard practice for calibration of the vent meter. 

VolCO2 = Annual average volumetric fraction of CO2 content in vent gas flowing out of 

the AGR unit as determined in paragraph (d)(6) of this section. 

(3) Calculation Method 3. If a CEMS or a vent meter is not installed, you may use the 

inlet or outlet gas flow rate of the acid gas removal unit to calculate emissions for CO2 using 

Equations W-4A or W-4B of this section. If inlet gas flow rate is known, use Equation W-4A. If 

outlet gas flow rate is known, use Equation W-4B. 





 







  

O

I O

a,CO in Vol

Vol Vol E V 2 1 (Eq. W-4A) 





 







  

I

I O

a,CO out Vol

Vol Vol E V 2 1 (Eq. W-4B) 
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Where: 

Ea,CO2 = Annual volumetric CO2 emissions at actual conditions, in cubic feet per year. 

Vin = Total annual volume of natural gas flow into the AGR unit in cubic feet per 

year at actual conditions as determined using methods specified in paragraph 

(d)(5) of this section. 

Vout = Total annual volume of natural gas flow out of the AGR unit in cubic feet per 

year at actual conditions as determined using methods specified in paragraph 

(d)(5) of this section. 

VolI = Annual average volumetric fraction of CO2 content in natural gas flowing 

into the AGR unit as determined in paragraph (d)(7) of this section. 

Volo = Annual average volumetric fraction of CO2 content in natural gas flowing out 

of the AGR unit as determined in paragraph (d)(8) of this section. 

(4) Calculation Method 4. If CEMS or a vent meter is not installed, you may calculate 

emissions using any standard simulation software package, such as AspenTech HYSYS®, or API 

4679 AMINECalc, that uses the Peng-Robinson equation of state and speciates CO2 emissions. 

A minimum of the following, determined for typical operating conditions over the calendar year 

by engineering estimate and process knowledge based on best available data, must be used to 

characterize emissions: 

(i) Natural gas feed temperature, pressure, and flow rate. 

(ii) Acid gas content of feed natural gas. 

(iii) Acid gas content of outlet natural gas. 

(iv) Unit operating hours, excluding downtime for maintenance or standby. 

(v) Exit temperature of natural gas. 

(vi) Solvent pressure, temperature, circulation rate, and weight. 

(5) For Calculation Method 3, determine the gas flow rate of the inlet when using 

Equation W-4A of this section or the gas flow rate of the outlet when using Equation W-4B of 

this section for the natural gas stream of an AGR unit using a meter according to methods set 
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forth in § 98.234(b). If you do not have a continuous flow meter, either install a continuous flow 

meter or use an engineering calculation to determine the flow rate. 

(6) For Calculation Method 2, if a continuous gas analyzer is not available on the vent 

stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas 

stream for each quarter that the AGR unit is operating to determine VolCO2 in Equation W-3 of 

this section, according to the methods set forth in § 98.234(b). 

(7) For Calculation Method 3, if a continuous gas analyzer is installed on the inlet gas 

stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not 

available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas 

stream for each quarter that the AGR unit is operating to determine VolI in Equation W-4A or 

W-4B of this section, according to the methods set forth in § 98.234(b). 

(8) For Calculation Method 3, determine annual average volumetric fraction of CO2

content in natural gas flowing out of the AGR unit using one of the methods specified in 

paragraphs (d)(8)(i) through (d)(8)(iii) of this section. 

(i) If a continuous gas analyzer is installed on the outlet gas stream, then the continuous 

gas analyzer results must be used. If a continuous gas analyzer is not available, you may install a 

continuous gas analyzer. 

(ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may 

be taken from the outlet gas stream for each quarter that the AGR unit is operating to determine 

VolO in Equation W-4A or W-4B of this section, according to the methods set forth in § 

98.234(b). 

(iii) If a continuous gas analyzer is not available or installed, you may use the outlet 

pipeline quality specification for CO2 in natural gas. 
Page 19 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

(9) Calculate annual volumetric CO2 emissions at standard conditions using calculations 

in paragraph (t) of this section. 

(10) Calculate annual mass CO2 emissions using calculations in paragraph (v) of this 

section. 

(11) Determine if CO2 emissions from the AGR unit are recovered and transferred 

outside the facility. Adjust the CO2 emissions estimated in paragraphs (d)(1) through (d)(10) of 

this section downward by the magnitude of CO2 emissions recovered and transferred outside the 

facility. 

(e) Dehydrator vents. For dehydrator vents, calculate annual CH4 and CO2 emissions 

using the applicable calculation methods described in paragraphs (e)(1) through (e)(4) of this 

section. If emissions from dehydrator vents are routed to a vapor recovery system, you must 

adjust the emissions downward according to paragraph (e)(5) of this section. If emissions from 

dehydrator vents are routed to a flare or regenerator fire-box/fire tubes, you must calculate CH4, 

CO2, and N2O annual emissions as specified in paragraph (e)(6) of this section. 

(1) Calculation Method 1. Calculate annual mass emissions from glycol dehydrators that 

have an annual average of daily natural gas throughput that is greater than or equal to 0.4 million 

standard cubic feet per day by using a software program, such as AspenTech HYSYS® or GRIGLYCalcTM, that uses the Peng-Robinson equation of state to calculate the equilibrium 

coefficient, speciates CH4 and CO2 emissions from dehydrators, and has provisions to include 

regenerator control devices, a separator flash tank, stripping gas and a gas injection pump or gas 

assist pump. The following parameters must be determined by engineering estimate based on 

best available data and must be used at a minimum to characterize emissions from dehydrators: 

(i) Feed natural gas flow rate. 
Page 20 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

(ii) Feed natural gas water content. 

(iii) Outlet natural gas water content. 

(iv) Absorbent circulation pump type (e.g., natural gas pneumatic/air pneumatic/electric). 

(v) Absorbent circulation rate. 

(vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene glycol (DEG) or ethylene 

glycol (EG)). 

(vii) Use of stripping gas. 

(viii) Use of flash tank separator (and disposition of recovered gas). 

(ix) Hours operated. 

(x) Wet natural gas temperature and pressure. 

(xi) Wet natural gas composition. Determine this parameter using one of the methods 

described in paragraphs (e)(1)(xi)(A) through (D) of this section. 

(A) Use the GHG mole fraction as defined in paragraph (u)(2)(i) or (ii) of this section. 

(B) If the GHG mole fraction cannot be determined using paragraph (u)(2)(i) or (ii) of 

this section, select a representative analysis. 

(C) You may use an appropriate standard method published by a consensus-based 

standards organization if such a method exists or you may use an industry standard practice as 

specified in § 98.234(b) to sample and analyze wet natural gas composition. 

(D) If only composition data for dry natural gas is available, assume the wet natural gas is 

saturated. 

(2) Calculation Method 2. Calculate annual volumetric emissions from glycol 

dehydrators that have an annual average of daily natural gas throughput that is less than 0.4 

million standard cubic feet per day using Equation W-5 of this section: 
Page 21 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

* *1000 E , EF Count s i i (Eq. W-5) 

Where: 

Es,i = Annual total volumetric GHG emissions (either CO2 or CH4) at standard 

conditions in cubic feet. 

EFi = Population emission factors for glycol dehydrators in thousand standard cubic 

feet per dehydrator per year. Use 73.4 for CH4 and 3.21 for CO2 at 60 °F and 

14.7 psia. 

Count = Total number of glycol dehydrators that have an annual average of daily 

natural gas throughput that is less than 0.4 million standard cubic feet per 

day. 

1000 = Conversion of EFi in thousand standard cubic feet to standard cubic feet. 

(3) Calculation Method 3. For dehydrators of any size that use desiccant, you must 

calculate emissions from the amount of gas vented from the vessel when it is depressurized for 

the desiccant refilling process using Equation W-6 of this section. Desiccant dehydrator 

emissions covered in this paragraph do not have to be calculated separately using the method 

specified in paragraph (i) of this section for blowdown vent stacks. 

 

(4 * *100)

* * * *% *

1

2

2

, P

H D P G N Es n

  (Eq. W-6) 

Where: 

Es,n = Annual natural gas emissions at standard conditions in cubic feet. 

H = Height of the dehydrator vessel (ft). 

D = Inside diameter of the vessel (ft). 

P1 = Atmospheric pressure (psia). 

P2 = Pressure of the gas (psia). 

π = pi (3.14). 

%G = Percent of packed vessel volume that is gas. 

N = Number of dehydrator openings in the calendar year. 
Page 22 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

100 = Conversion of %G to fraction. 

(4) For glycol dehydrators that use the calculation method in paragraph (e)(2) of this 

section, calculate both CH4 and CO2 mass emissions from volumetric GHGi emissions using 

calculations in paragraph (v) of this section. For desiccant dehydrators that use the calculation 

method in paragraph (e)(3) of this section, calculate both CH4 and CO2 volumetric and mass 

emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of 

this section. 

(5) Determine if the dehydrator unit has vapor recovery. Adjust the emissions estimated 

in paragraphs (e)(1), (2), and (3) of this section downward by the magnitude of emissions 

recovered using a vapor recovery system as determined by engineering estimate based on best 

available data. 

(6) Calculate annual emissions from dehydrator vents to flares or regenerator fire-box/fire 

tubes as follows: 

(i) Use the dehydrator vent volume and gas composition as determined in paragraphs 

(e)(1) through (5) of this section, as applicable. 

(ii) Use the calculation method of flare stacks in paragraph (n) of this section to 

determine dehydrator vent emissions from the flare or regenerator combustion gas vent. 

(f) Well venting for liquids unloadings. Calculate annual volumetric natural gas emissions 

from well venting for liquids unloading using one of the calculation methods described in 

paragraphs (f)(1), (2), or (3) of this section. Calculate annual CH4 and CO2 volumetric and mass 

emissions using the method described in paragraph (f)(4) of this section. 

(1) Calculation Method 1. Calculate emissions from wells with plunger lifts and wells 

without plunger lifts separately. For at least one well of each unique well tubing diameter group 
Page 23 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

and pressure group combination in each sub-basin category (see § 98.238 for the definitions of 

tubing diameter group, pressure group, and sub-basin category), where gas wells are vented to 

the atmosphere to expel liquids accumulated in the tubing, install a recording flow meter on the 

vent line used to vent gas from the well (e.g., on the vent line off the wellhead separator or 

atmospheric storage tank) according to methods set forth in § 98.234(b). Calculate the total 

emissions from well venting to the atmosphere for liquids unloading using Equation W-7A of 

this section. For any tubing diameter group and pressure group combination in a sub-basin where 

liquids unloading occurs both with and without plunger lifts, Equation W-7A will be used twice, 

once for wells with plunger lifts and once for wells without plunger lifts. 





h

p

Ea FR Tp

1

 (Eq. W-7A) 

Where: 

Ea = Annual natural gas emissions for all wells of the same tubing diameter group 

and pressure group combination in a sub-basin at actual conditions, a, in 

cubic feet. Calculate emission from wells with plunger lifts and wells without 

plunger lifts separately. 

h = Total number of wells of the same tubing diameter group and pressure group 

combination in a sub-basin either with or without plunger lifts. 

p = Wells 1 through h of the same tubing diameter group and pressure group 

combination in a sub-basin. 

Tp = Cumulative amount of time in hours of venting for each well, p, of the same 

tubing diameter group and pressure group combination in a sub-basin during 

the year. If the available venting data do not contain a record of the date of 

the venting events and data are not available to provide the venting hours for 

the specific time period of January 1 to December 31, you may calculate an 

annualized vent time, Tp, using Equation W-7B of this section. 

FR = Average flow rate in cubic feet per hour for all measured wells of the same 

tubing diameter group and pressure group combination in a sub-basin, over 

the duration of the liquids unloading, under actual conditions as determined 

in paragraph (f)(1)(i) of this section. 
Page 24 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

p

p

p

p D

MP

HR

T   (Eq. W-7B) 

Where: 

HRp = Cumulative amount of time in hours of venting for each well, p, during the 

monitoring period. 

MPp = Time period, in days, of the monitoring period for each well, p. A minimum 

of 300 days in a calendar year are required. The next period of data collection 

must start immediately following the end of data collection for the previous 

reporting year. 

Dp = Time period, in days during which the well, p, was in production (365 if the 

well was in production for the entire year). 

(i) Determine the well vent average flow rate (“FR” in Equation W-7A of this section) as 

specified in paragraphs (f)(1)(i)(A) through (C) of this section for at least one well in a unique 

well tubing diameter group and pressure group combination in each sub-basin category. 

Calculate emissions from wells with plunger lifts and wells without plunger lifts separately. 

(A) Calculate the average flow rate per hour of venting for each unique tubing diameter 

group and pressure group combination in each sub-basin category by dividing the recorded total 

annual flow by the recorded time (in hours) for all measured liquid unloading events with 

venting to the atmosphere. 

(B) Apply the average hourly flow rate calculated under paragraph (f)(1)(i)(A) of this 

section to all wells in the same pressure group that have the same tubing diameter group, for the 

number of hours of venting these wells. 

(C) Calculate a new average flow rate every other calendar year starting with the first 

calendar year of data collection. For a new producing sub-basin category, calculate an average 

flow rate beginning in the first year of production. 
Page 25 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

(ii) Calculate natural gas volumetric emissions at standard conditions using calculations 

in paragraph (t) of this section. 

(2) Calculation Method 2. Calculate the total emissions for each sub-basin from well 

venting to the atmosphere for liquids unloading without plunger lift assist using Equation W-8 of 

this section. 

           







 



          

W

p

V

q

s p p p p p p q p q

p

E V CD WD SP SFR HR Z 1 1

, ,

3 2 0.37 10 1.0 (Eq. W-8) 

Where: 

Es = Annual natural gas emissions for each sub-basin at standard conditions, s, in 

cubic feet per year. 

W = Total number of wells with well venting for liquids unloading for each subbasin. 

p = Wells 1 through W with well venting for liquids unloading for each subbasin. 

Vp = Total number of unloading events in the monitoring period per well, p. 

0.37×10−3

 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). 

CDp = Casing internal diameter for each well, p, in inches. 

WDp = Well depth from either the top of the well or the lowest packer to the bottom 

of the well, for each well, p, in feet. 

SPp = For each well, p, shut-in pressure or surface pressure for wells with tubing 

production, or casing pressure for each well with no packers, in pounds per 

square inch absolute (psia). If casing pressure is not available for each well, 

you may determine the casing pressure by multiplying the tubing pressure of 

each well with a ratio of casing pressure to tubing pressure from a well in the 

same sub-basin for which the casing pressure is known. The tubing pressure 

must be measured during gas flow to a flow-line. The shut-in pressure, 

surface pressure, or casing pressure must be determined just prior to liquids 

unloading when the well production is impeded by liquids loading or closed 

to the flow-line by surface valves. 

SFRp = Average flow-line rate of gas for well, p, at standard conditions in cubic feet 

per hour. Use Equation W-33 of this section to calculate the average flowline rate at standard conditions. 
Page 26 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

HRp,q = Hours that each well, p, was left open to the atmosphere during each 

unloading event, q. 

1.0 = Hours for average well to blowdown casing volume at shut-in pressure. 

q = Unloading event. 

Zp,q = If HRp,q is less than 1.0 then Zp,q is equal to 0. If HRp,q is greater than or equal 

to 1.0 then Zp,q is equal to 1. 

(3) Calculation Method 3. Calculate the total emissions for each sub-basin from well 

venting to the atmosphere for liquids unloading with plunger lift assist using Equation W-9 of 

this section. 

           







 



          

W

p

V

q

s p p p p p p q p q

p

E V TD WD SP SFR HR Z 1 1

, ,

3 2 0.37 10 0.5 (Eq. W-9) 

Where: 

Es = Annual natural gas emissions for each sub-basin at standard conditions, s, in 

cubic feet per year. 

W = Total number of wells with plunger lift assist and well venting for liquids 

unloading for each sub-basin. 

p = Wells 1 through W with well venting for liquids unloading for each subbasin. 

Vp = Total number of unloading events in the monitoring period for each well, p. 

0.37×10−3

 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). 

TDp = Tubing internal diameter for each well, p, in inches. 

WDp = Tubing depth to plunger bumper for each well, p, in feet. 

SPp = Flow-line pressure for each well, p, in pounds per square inch absolute (psia), 

using engineering estimate based on best available data. 

SFRp = Average flow-line rate of gas for well, p, at standard conditions in cubic feet 

per hour. Use Equation W-33 of this section to calculate the average flowline rate at standard conditions. 

HRp,q = Hours that each well, p, was left open to the atmosphere during each 

unloading event, q. 

0.5 = Hours for average well to blowdown tubing volume at flow-line pressure. 
Page 27 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

q = Unloading event. 

Zp,q = If HRp,q is less than 0.5 then Zp,q is equal to 0. If HRp,q is greater than or equal 

to 0.5 then Zp,q is equal to 1. 

(4) Calculate CH4 and CO2 volumetric and mass emissions from volumetric natural gas 

emissions using calculations in paragraphs (u) and (v) of this section. 

(g) Well venting during completions and workovers with hydraulic fracturing. Calculate 

annual volumetric natural gas emissions from gas well and oil well venting during completions 

and workovers involving hydraulic fracturing using Equation W-10A or Equation W-10B of this 

section. Equation W-10A applies to well venting when the gas flowback rate is measured from a 

specified number of example completions or workovers and Equation W-10B applies when the 

gas flowback vent or flare volume is measured for each completion or workover. Completion 

and workover activities are separated into two periods, an initial period when flowback is routed 

to open pits or tanks and a subsequent period when gas content is sufficient to route the flowback 

to a separator or when the gas content is sufficient to allow measurement by the devices specified 

in paragraph (g)(1) of this section, regardless of whether a separator is actually utilized. If you 

elect to use Equation W-10A, you must follow the procedures specified in paragraph (g)(1). If 

you elect to use Equation W-10B, you must use a recording flow meter installed on the vent line, 

downstream of a separator and ahead of a flare or vent, to measure the gas flowback. For either 

equation, emissions must be calculated separately for completions and workovers, for each subbasin, and for each well type combination identified in paragraph (g)(2) of this section. You must 

calculate CH4 and CO2 volumetric and mass emissions as specified in paragraph (g)(3) of this 

section. If emissions from well venting during completions and workovers with hydraulic 

fracturing are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as 

specified in paragraph (g)(4) of this section. 
Page 28 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

    

       

W

p

Es n Tp s FRMs PRs p EnFs p Tp i FRMi PRs p

1

, , , , , 2 , (Eq. W-10A) 

    

    

W

p

Es n FVs p EnFs p Tp i FRp i

1

, , , , , 2 (Eq. W-10B) 

Where: 

Es,n = Annual volumetric natural gas emissions in standard cubic feet from gas 

venting during well completions or workovers following hydraulic fracturing 

for each sub-basin and well type combination. 

W = Total number of wells completed or worked over using hydraulic fracturing 

in a sub-basin and well type combination. 

Tp,s = Cumulative amount of time of flowback, after sufficient quantities of gas are 

present to enable separation, where gas vented or flared for the completion or 

workover, in hours, for each well, p, in a sub-basin and well type 

combination during the reporting year. This may include non-contiguous 

periods of venting or flaring. 

Tp,i = Cumulative amount of time of flowback to open tanks/pits, from when gas is 

first detected until sufficient quantities of gas are present to enable 

separation, for the completion or workover, in hours, for each well, p, in a 

sub-basin and well type combination during the reporting year. This may 

include non-contiguous periods of routing to open tanks/pits but does not 

include periods when the oil well ceases to produce fluids to the surface. 

FRMs = Ratio of average gas flowback, during the period when sufficient quantities 

of gas are present to enable separation, of well completions and workovers 

from hydraulic fracturing to 30-day production rate for the sub-basin and well 

type combination, calculated using procedures specified in paragraph 

(g)(1)(iii) of this section. 

FRMi = Ratio of initial gas flowback rate during well completions and workovers 

from hydraulic fracturing to 30-day gas production rate for the sub-basin and 

well type combination, calculated using procedures specified in paragraph 

(g)(1)(iv) of this section, for the period of flow to open tanks/pits. 

PRs,p = Average gas production flow rate during the first 30 days of production after 

completions of newly drilled wells or well workovers using hydraulic 

fracturing in standard cubic feet per hour of each well p, that was measured in 

the sub-basin and well type combination. If applicable, PRs,p may be 

calculated for oil wells using procedures specified in paragraph (g)(1)(vii) of 

this section. 
Page 29 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

EnFs,p = Volume of N2 injected gas in cubic feet at standard conditions that was 

injected into the reservoir during an energized fracture job or during 

flowback for each well, p, as determined by using an appropriate meter 

according to methods described in § 98.234(b), or by using receipts of gas 

purchases that are used for the energized fracture job or injection during 

flowback. Convert to standard conditions using paragraph (t) of this section. 

If the fracture process did not inject gas into the reservoir or if the injected 

gas is CO2 then EnFs,p is 0. 

FVs,p = Flow volume of vented or flared gas for each well, p, in standard cubic feet 

measured using a recording flow meter (digital or analog) on the vent line to 

measure gas flowback during the separation period of the completion or 

workover according to methods set forth in § 98.234(b). 

FRp,i = Flow rate vented or flared of each well, p, in standard cubic feet per hour 

measured using a recording flow meter (digital or analog) on the vent line to 

measure the flowback, at the beginning of the period of time when sufficient 

quantities of gas are present to enable separation, of the completion or 

workover according to methods set forth in § 98.234(b). 

(1) If you elect to use Equation W-10A of this section on gas wells, you must use 

Calculation Method 1 as specified in paragraph (g)(1)(i) of this section, or Calculation Method 2 

as specified in paragraph (g)(1)(ii) of this section, to determine the value of FRMs and FRMi. If 

you elect to use Equation W-10A of this section on oil wells, you must use Calculation Method 1 

as specified in paragraph (g)(1)(i) to determine the value of FRMs and FRMi. These values must 

be based on the flow rate for flowback gases, once sufficient gas is present to enable separation. 

The number of measurements or calculations required to estimate FRMs and FRMi must be 

determined individually for completions and workovers per sub-basin and well type combination 

as follows: Complete measurements or calculations for at least one completion or workover for 

less than or equal to 25 completions or workovers for each well type combination within a subbasin; complete measurements or calculations for at least two completions or workovers for 26 to 

50 completions or workovers for each sub-basin and well type combination; complete 

measurements or calculations for at least three completions or workovers for 51 to 100 

completions or workovers for each sub-basin and well type combination; complete 
Page 30 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

measurements or calculations for at least four completions or workovers for 101 to 250 

completions or workovers for each sub-basin and well type combination; and complete 

measurements or calculations for at least five completions or workovers for greater than 250 

completions or workovers for each sub-basin and well type combination. 

(i) Calculation Method 1. You must use Equation W-12A of this section as specified in 

paragraph (g)(1)(iii) of this section to determine the value of FRMs. You must use Equation W12B of this section as specified in paragraph (g)(1)(iv) of this section to determine the value of 

FRMi. The procedures specified in paragraphs (g)(1)(v) and (vi) of this section also apply. When 

making gas flowback measurements for use in Equations W-12A and W-12B of this section, you 

must use a recording flow meter (digital or analog) installed on the vent line, downstream of a 

separator and ahead of a flare or vent, to measure the gas flowback rates in units of standard 

cubic feet per hour according to methods set forth in § 98.234(b). 

(ii) Calculation Method 2 (for gas wells). You must use Equation W-12A as specified in 

paragraph (g)(1)(iii) of this section to determine the value of FRMs. You must use Equation W12B as specified in paragraph (g)(1)(iv) of this section to determine the value of FRMi. The 

procedures specified in paragraphs (g)(1)(v) and (vi) also apply. When calculating the flowback 

rates for use in Equations W-12A and W-12B of this section based on well parameters, you must 

record the well flowing pressure immediately upstream (and immediately downstream in 

subsonic flow) of a well choke according to methods set forth in § 98.234(b) to calculate the well 

flowback. The upstream pressure must be surface pressure and reservoir pressure cannot be 

assumed. The downstream pressure must be measured after the choke and atmospheric pressure 

cannot be assumed. Calculate flowback rate using Equation W-11A of this section for subsonic 

flow or Equation W-11B of this section for sonic flow. You must use best engineering estimates 
Page 31 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

based on best available data along with Equation W-11C of this section to determine whether the 

predominant flow is sonic or subsonic. If the value of R in Equation W-11C of this section is 

greater than or equal to 2, then flow is sonic; otherwise, flow is subsonic. Convert calculated FRa

values from actual conditions upstream of the restriction orifice to standard conditions (FRs,p and 

FRi,p) for use in Equations W-12A and W-12B of this section using Equation W-33 in paragraph 

(t) of this section. 

































 













  

1.758

1

2

1.515

1

5 2 1.27 10 * * 3430* * P

P

P

P FRa A Tu (Eq. W-11A) 

Where: 

FRa = Flowback rate in actual cubic feet per hour, under actual subsonic flow 

conditions. 

A = Cross sectional open area of the restriction orifice (m2

). 

P1 = Pressure immediately upstream of the choke (psia). 

Tu = Temperature immediately upstream of the choke (degrees Kelvin). 

P2 = Pressure immediately downstream of the choke (psia). 

3430 = Constant with units of m2

/(sec2 * K). 

1.27*105

 = Conversion from m3/second to ft3/hour. 

FRa A 08*Tu 1.27 10 * * 187. 5   (Eq. W-11B) 

Where: 

FRa = Flowback rate in actual cubic feet per hour, under actual sonic flow 

conditions. 

A = Cross sectional open area of the restriction orifice (m2

). 

Tu = Temperature immediately upstream of the choke (degrees Kelvin). 

187.08 = Constant with units of m2

/(sec2 * K). 

1.27*105

 = Conversion from m3/second to ft3/hour. 
Page 32 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

2

1

P R  P

 (Eq. W-11C) 

Where: 

R = Pressure ratio. 

P1 = Pressure immediately upstream of the choke (psia). 

P2 = Pressure immediately downstream of the choke (psia). 

(iii) For Equation W-10A of this section, calculate FRMs using Equation W-12A of this 

section. 







  N

p

s p

N

p

s p

s

PR

FR

FRM

1

,

1

,

 (Eq. W-12A) 

Where: 

FRMs = Ratio of average gas flowback rate, during the period of time when sufficient 

quantities of gas are present to enable separation, of well completions and 

workovers from hydraulic fracturing to 30-day gas production rate for each 

sub-basin and well type combination. 

FRs,p = Measured average gas flowback rate from Calculation Method 1 described in 

paragraph (g)(1)(i) of this section or calculated average flowback rate from 

Calculation Method 2 described in paragraph (g)(1)(ii) of this section, during 

the separation period in standard cubic feet per hour for well(s) p for each 

sub-basin and well type combination. Convert measured and calculated FRa

values from actual conditions upstream of the restriction orifice (FRa) to 

standard conditions (FRs,p) for each well p using Equation W-33 in paragraph 

(t) of this section. You may not use flow volume as used in Equation W-10B 

of this section converted to a flow rate for this parameter. 

PRs,p = Average gas production flow rate during the first 30 days of production after 

completions of newly drilled wells or well workovers using hydraulic 

fracturing, in standard cubic feet per hour for each well, p, that was measured 

in the sub-basin and well type combination. For oil wells for which 

production is not measured continuously during the first 30 days of 

production, the average flow rate may be based on individual well production 

tests conducted within the first 30 days of production. Alternatively, if 

applicable, PRs,p may be calculated for oil wells using procedures specified in 

paragraph (g)(1)(vii) of this section. 
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N = Number of measured or calculated well completions or workovers using 

hydraulic fracturing in a sub-basin and well type combination. 

(iv) For Equation W-10A of this section, calculate FRMi using Equation W-12B of this 

section. 







  N

p

s p

N

p

i p

i

PR

FR

FRM

1

,

1

,

 (Eq. W-12B) 

Where: 

FRMi = Ratio of initial gas flowback rate during well completions and workovers 

from hydraulic fracturing to 30-day gas production rate for the sub-basin and 

well type combination, for the period of flow to open tanks/pits. 

FRi,p = Initial measured gas flowback rate from Calculation Method 1 described in 

paragraph (g)(1)(i) of this section or initial calculated flow rate from 

Calculation Method 2 described in paragraph (g)(1)(ii) of this section in 

standard cubic feet per hour for well(s), p, for each sub-basin and well type 

combination. Measured and calculated FRi,p values must be based on flow 

conditions at the beginning of the separation period and must be expressed at 

standard conditions. 

PRs,p = Average gas production flow rate during the first 30-days of production after 

completions of newly drilled wells or well workovers using hydraulic 

fracturing, in standard cubic feet per hour of each well, p, that was measured 

in the sub-basin and well type combination. For oil wells for which 

production is not measured continuously during the first 30 days of 

production, the average flow rate may be based on individual well production 

tests conducted within the first 30 days of production. Alternatively, if 

applicable, PRs,p may be calculated for oil wells using procedures specified in 

paragraph (g)(1)(vii) of this section. 

N = Number of measured or calculated well completions or workovers using 

hydraulic fracturing in a sub-basin and well type combination. 

(v) For Equation W-10A of this section, the ratio of gas flowback rate during well 

completions and workovers from hydraulic fracturing to 30-day gas production rate are applied 

to all well completions and well workovers, respectively, in the sub-basin and well type 
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combination for the total number of hours of flowback and for the first 30 day average gas 

production rate for each of these wells. 

(vi) For Equations W-12A and W-12B of this section, calculate new flowback rates for 

well completions and well workovers in each sub-basin and well type combination once every 

two years starting in the first calendar year of data collection. 

(vii) For oil wells where the gas production rate is not metered and you elect to use 

Equation W-10A of this section, calculate the average gas production rate (PRs,p) using Equation 

W-12C of this section. If GOR cannot be determined from your available data, then you must use 

one of the procedures specified in paragraph (g)(1)(vii)(A) or (B) of this section to determine 

GOR. If GOR from each well is not available, use the GOR from a cluster of wells in the same 

sub-basin category. 

720 , * p

s p p

V

PR  GOR (Eq. W-12C) 

Where: 

PRs,p = Average gas production flow rate during the first 30 days of production after 

completions of newly drilled wells or well workovers using hydraulic 

fracturing in standard cubic feet per hour of well p, in the sub-basin and well 

type combination. 

GORp = Average gas to oil ratio during the first 30 days of production after 

completions of newly drilled wells or workovers using hydraulic fracturing in 

standard cubic feet of gas per barrel of oil for each well p, that was measured 

in the sub-basin and well type combination; oil here refers to hydrocarbon 

liquids produced of all API gravities. 

Vp = Volume of oil produced during the first 30 days of production after 

completions of newly drilled wells or well workovers using hydraulic 

fracturing in barrels of each well p, that was measured in the sub-basin and 

well type combination. 

720 = Conversion from 30 days of production to hourly production rate. 
Page 35 of 200 

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(A) You may use an appropriate standard method published by a consensus-based 

standards organization if such a method exists. 

(B) You may use an industry standard practice as described in § 98.234(b). 

(2) For paragraphs (g) introductory text and (g)(1) of this section, measurements and 

calculations are completed separately for workovers and completions per sub-basin and well type 

combination. A well type combination is a unique combination of the parameters listed in 

paragraphs (g)(2)(i) through (iv) of this section. 

(i) Vertical or horizontal (directional drilling). 

(ii) With flaring or without flaring. 

(iii) Reduced emission completion/workover or not reduced emission 

completion/workover. 

(iv) Oil well or gas well. 

(3) Calculate both CH4 and CO2 volumetric and mass emissions from total natural gas 

volumetric emissions using calculations in paragraphs (u) and (v) of this section. 

(4) Calculate annual emissions from well venting during well completions and workovers 

from hydraulic fracturing where all or a portion of the gas is flared as specified in paragraphs 

(g)(4)(i) and (ii) of this section. 

(i) Use the volumetric total natural gas emissions vented to the atmosphere during well 

completions and workovers as determined in paragraph (g) of this section to calculate volumetric 

and mass emissions using paragraphs (u) and (v) of this section. 

(ii) Use the calculation method of flare stacks in paragraph (n) of this section to adjust 

emissions for the portion of gas flared during well completions and workovers using hydraulic 

fracturing. This adjustment to emissions from completions using flaring, versus completions 
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without flaring, accounts for the conversion of CH4 to CO2 in the flare and for the formation on 

N2O during flaring. 

(h) Gas well venting during completions and workovers without hydraulic fracturing. 

Calculate annual volumetric natural gas emissions from each gas well venting during workovers 

without hydraulic fracturing using Equation W-13A of this section. Calculate annual volumetric 

natural gas emissions from each gas well venting during completions without hydraulic 

fracturing using Equation W-13B of this section. You must convert annual volumetric natural 

gas emissions to CH4 and CO2 volumetric and mass emissions as specified in paragraph (h)(1) of 

this section. If emissions from gas well venting during completions and workovers without 

hydraulic fracturing are routed to a flare, you must calculate CH4, CO2, and N2O annual 

emissions as specified in paragraph (h)(2) of this section. 

Es wo Nwo EFwo * ,  (Eq. W-13A) 

p

f

p

Es p Vp * T 1

, 

 (Eq. W-13B) 

Where: 

Es,wo = Annual volumetric natural gas emissions in standard cubic feet from gas well 

venting during well workovers without hydraulic fracturing. 

Nwo = Number of workovers per sub-basin category that do not involve hydraulic 

fracturing in the reporting year. 

EFwo = Emission factor for non-hydraulic fracture well workover venting in standard 

cubic feet per workover. Use 3,114 standard cubic feet natural gas per well 

workover without hydraulic fracturing. 

Es,p = Annual volumetric natural gas emissions in standard cubic feet from gas well 

venting during well completions without hydraulic fracturing. 

p = Well completions 1 through f in a sub-basin. 

f = Total number of well completions without hydraulic fracturing in a sub-basin 

category. 
Page 37 of 200 

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Vp = Average daily gas production rate in standard cubic feet per hour for each 

well, p, undergoing completion without hydraulic fracturing. This is the total 

annual gas production volume divided by total number of hours the wells 

produced to the flow-line. For completed wells that have not established a 

production rate, you may use the average flow rate from the first 30 days of 

production. In the event that the well is completed less than 30 days from the 

end of the calendar year, the first 30 days of the production straddling the 

current and following calendar years shall be used. 

Tp = Time that gas is vented to either the atmosphere or a flare for each well, p, 

undergoing completion without hydraulic fracturing, in hours during the year. 

(1) Calculate both CH4 and CO2 volumetric emissions from natural gas volumetric 

emissions using calculations in paragraph (u) of this section. Calculate both CH4 and CO2 mass 

emissions from volumetric emissions vented to atmosphere using calculations in paragraph (v) of 

this section. 

(2) Calculate annual emissions of CH4, CO2, and N2O from gas well venting to flares 

during well completions and workovers not involving hydraulic fracturing as specified in 

paragraphs (h)(2)(i) and (ii) of this section. 

(i) Use the gas well venting volume and gas composition during well completions and 

workovers that are flared as determined using the methods specified in paragraphs (h) and (h)(1) 

of this section. 

(ii) Use the calculation method of flare stacks in paragraph (n) of this section to 

determine emissions from the flare for gas well venting to a flare during completions and 

workovers without hydraulic fracturing. 

(i) Blowdown vent stacks. Calculate CO2 and CH4 blowdown vent stack emissions from 

the depressurization of equipment to reduce system pressure for planned or emergency 

shutdowns resulting from human intervention or to take equipment out of service for 

maintenance as specified in either paragraph (i)(2) or (3) of this section. You may use the 

method in paragraph (i)(2) of this section for some blowdown vent stacks at your facility and the 
Page 38 of 200 

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method in paragraph (i)(3) of this section for other blowdown vent stacks at your facility. 

Equipment with a unique physical volume of less than 50 cubic feet as determined in paragraph 

(i)(1) of this section are not subject to the requirements in paragraphs (i)(2) through (4) of this 

section. The requirements in this paragraph (i) do not apply to blowdown vent stack emissions 

from depressurizing to a flare, over-pressure relief, operating pressure control venting, 

blowdown of non-GHG gases, and desiccant dehydrator blowdown venting before reloading. 

(1) Method for calculating unique physical volumes. You must calculate each unique 

physical volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, 

discharge bottles, and vessels) between isolation valves, in cubic feet, by using engineering 

estimates based on best available data. 

(2) Method for determining emissions from blowdown vent stacks according to equipment 

or event type. If you elect to determine emissions according to each equipment or event type, 

using unique physical volumes as calculated in paragraph (i)(1) of this section, you must 

calculate emissions as specified in paragraph (i)(2)(i) of this section and either paragraph 

(i)(2)(ii) or, if applicable, paragraph (i)(2)(iii) of this section for each equipment or event type. 

For industry segments other than onshore natural gas transmission pipeline, equipment or event 

types must be grouped into the following seven categories: Facility piping (i.e., piping within the 

facility boundary other than physical volumes associated with distribution pipelines), pipeline 

venting (i.e., physical volumes associated with distribution pipelines vented within the facility 

boundary), compressors, scrubbers/strainers, pig launchers and receivers, emergency shutdowns 

(this category includes emergency shutdown blowdown emissions regardless of equipment type), 

and all other equipment with a physical volume greater than or equal to 50 cubic feet. If a 

blowdown event resulted in emissions from multiple equipment types and the emissions cannot 
Page 39 of 200 

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be apportioned to the different equipment types, then categorize the blowdown event as the 

equipment type that represented the largest portion of the emissions for the blowdown event. For 

the onshore natural gas transmission pipeline segment, pipeline segments or event types must be 

grouped into the following eight categories: Pipeline integrity work (e.g., the preparation work of 

modifying facilities, ongoing assessments, maintenance or mitigation), traditional operations or 

pipeline maintenance, equipment replacement or repair (e.g., valves), pipe abandonment, new 

construction or modification of pipelines including commissioning and change of service, 

operational precaution during activities (e.g. excavation near pipelines), emergency shutdowns 

including pipeline incidents as defined in 49 CFR 191.3, and all other pipeline segments with a 

physical volume greater than or equal to 50 cubic feet. If a blowdown event resulted in emissions 

from multiple categories and the emissions cannot be apportioned to the different categories, 

then categorize the blowdown event in the category that represented the largest portion of the 

emissions for the blowdown event. 

(i) Calculate the total annual natural gas emissions from each unique physical volume 

that is blown down using either Equation W-14A or W-14B of this section. 

 

  













 

















  V C

T P Z

T P

E N V

a s a

s a

s n * 459.67

459.67 , * (Eq. W-14A) 

Where: 

Es,n = Annual natural gas emissions at standard conditions from each unique 

physical volume that is blown down, in cubic feet. 

N = Number of occurrences of blowdowns for each unique physical volume in the 

calendar year. 

V = Unique physical volume between isolation valves, in cubic feet, as calculated 

in paragraph (i)(1) of this section. 
Page 40 of 200 

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C = Purge factor is 1 if the unique physical volume is not purged, or 0 if the 

unique physical volume is purged using non-GHG gases. 

Ts = Temperature at standard conditions (60 °F). 

Ta = Temperature at actual conditions in the unique physical volume (°F). For 

emergency blowdowns at onshore petroleum and natural gas gathering and 

boosting facilities, engineering estimates based on best available information 

may be used to determine the temperature. 

Ps = Absolute pressure at standard conditions (14.7 psia). 

Pa = Absolute pressure at actual conditions in the unique physical volume (psia). 

For emergency blowdowns at onshore petroleum and natural gas gathering 

and boosting facilities, engineering estimates based on best available 

information may be used to determine the pressure. 

Za = Compressibility factor at actual conditions for natural gas. You may use 

either a default compressibility factor of 1, or a site-specific compressibility 

factor based on actual temperature and pressure conditions. 

      

































  

N

p a p s a

s a b p a e p

s n p T P Z

T P P

E V

1 ,

, , , ,

, 459.67

459.67

 (Eq. W-14B) 

Where: 

Es,n = Annual natural gas emissions at standard conditions from each unique 

physical volume that is blown down, in cubic feet. 

p = Individual occurrence of blowdown for the same unique physical volume. 

N = Number of occurrences of blowdowns for each unique physical volume in the 

calendar year. 

Vp = Unique physical volume between isolation valves, in cubic feet, for each 

blowdown “p.” 

Ts = Temperature at standard conditions (60 °F). 

Ta,p = Temperature at actual conditions in the unique physical volume (°F) for each 

blowdown “p”. 

Ps = Absolute pressure at standard conditions (14.7 psia). 

Pa,b,p = Absolute pressure at actual conditions in the unique physical volume (psia) at 

the beginning of the blowdown “p”. 

Pa,e,p = Absolute pressure at actual conditions in the unique physical volume (psia) at 

the end of the blowdown “p”; 0 if blowdown volume is purged using nonGHG gases. 
Page 41 of 200 

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Za = Compressibility factor at actual conditions for natural gas. You may use 

either a default compressibility factor of 1, or a site-specific compressibility 

factor based on actual temperature and pressure conditions. 

(ii) Except as allowed in paragraph (i)(2)(iii) of this section, calculate annual CH4 and 

CO2 volumetric and mass emissions from each unique physical volume that is blown down by 

using the annual natural gas emission value as calculated in either Equation W-14A or Equation 

W-14B of paragraph (i)(2)(i) of this section and the calculation method specified in paragraph 

(i)(4) of this section. Calculate the total annual CH4 and CO2 emissions for each equipment or 

event type by summing the annual CH4 and CO2 mass emissions for all unique physical volumes 

associated with the equipment or event type. 

(iii) For onshore natural gas transmission compression facilities and LNG import and 

export equipment, as an alternative to using the procedures in paragraph (i)(2)(ii) of this section, 

you may elect to sum the annual natural gas emissions as calculated using either Equation W14A or Equation W-14B of paragraph (i)(2)(i) of this section for all unique physical volumes 

associated with the equipment type or event type. Calculate the total annual CH4 and CO2

volumetric and mass emissions for each equipment type or event type using the sums of the total 

annual natural gas emissions for each equipment type and the calculation method specified in 

paragraph (i)(4) of this section. 

(3) Method for determining emissions from blowdown vent stacks using a flow meter. In 

lieu of determining emissions from blowdown vent stacks as specified in paragraph (i)(2) of this 

section, you may use a flow meter and measure blowdown vent stack emissions for any unique 

physical volumes determined according to paragraph (i)(1) of this section to be greater than or 

equal to 50 cubic feet. If you choose to use this method, you must measure the natural gas 

emissions from the blowdown(s) through the monitored stack(s) using a flow meter according to 
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methods in § 98.234(b), and calculate annual CH4 and CO2 volumetric and mass emissions 

measured by the meters according to paragraph (i)(4) of this section. 

(4) Method for converting from natural gas emissions to GHG volumetric and mass 

emissions. Calculate both CH4 and CO2 volumetric and mass emissions using the methods 

specified in paragraphs (u) and (v) of this section. 

(j) Onshore production and onshore petroleum and natural gas gathering and boosting 

storage tanks. Calculate CH4, CO2, and N2O (when flared) emissions from atmospheric pressure 

fixed roof storage tanks receiving hydrocarbon produced liquids from onshore petroleum and 

natural gas production facilities and onshore petroleum and natural gas gathering and boosting 

facilities (including stationary liquid storage not owned or operated by the reporter), as specified 

in this paragraph (j). For gas-liquid separators or onshore petroleum and natural gas gathering 

and boosting non-separator equipment (e.g., stabilizers, slug catchers) with annual average daily 

throughput of oil greater than or equal to 10 barrels per day, calculate annual CH4 and CO2 using 

Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (2) of this section. For wells 

flowing directly to atmospheric storage tanks without passing through a separator with 

throughput greater than or equal to 10 barrels per day, calculate annual CH4 and CO2 emissions 

using Calculation Method 2 as specified in paragraph (j)(2) of this section. For hydrocarbon 

liquids flowing to gas-liquid separators or non-separator equipment or directly to atmospheric 

storage tanks with throughput less than 10 barrels per day, use Calculation Method 3 as specified 

in paragraph (j)(3) of this section. If you use Calculation Method 1 or Calculation Method 2 for 

separators, you must also calculate emissions that may have occurred due to dump valves not 

closing properly using the method specified in paragraph (j)(6) of this section. If emissions from 

atmospheric pressure fixed roof storage tanks are routed to a vapor recovery system, you must 
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adjust the emissions downward according to paragraph (j)(4) of this section. If emissions from 

atmospheric pressure fixed roof storage tanks are routed to a flare, you must calculate CH4, CO2, 

and N2O annual emissions as specified in paragraph (j)(5) of this section. 

(1) Calculation Method 1. Calculate annual CH4 and CO2 emissions from onshore 

production storage tanks and onshore petroleum and natural gas gathering and boosting storage 

tanks using operating conditions in the last gas-liquid separator or non-separator equipment 

before liquid transfer to storage tanks. Calculate flashing emissions with a software program, 

such as AspenTech HYSYS® or API 4697 E&P Tank, that uses the Peng-Robinson equation of 

state, models flashing emissions, and speciates CH4 and CO2 emissions that will result when the 

oil from the separator or non-separator equipment enters an atmospheric pressure storage tank. 

The following parameters must be determined for typical operating conditions over the year by 

engineering estimate and process knowledge based on best available data, and must be used at a 

minimum to characterize emissions from liquid transferred to tanks: 

(i) Separator or non-separator equipment temperature. 

(ii) Separator or non-separator equipment pressure. 

(iii) Sales oil or stabilized oil API gravity. 

(iv) Sales oil or stabilized oil production rate. 

(v) Ambient air temperature. 

(vi) Ambient air pressure. 

(vii) Separator or non-separator equipment oil composition and Reid vapor pressure. If 

this data is not available, determine these parameters by using one of the methods described in 

paragraphs (j)(1)(vii)(A) through (C) of this section. 
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(A) If separator or non-separator equipment oil composition and Reid vapor pressure 

default data are provided with the software program, select the default values that most closely 

match your separator or non-separator equipment pressure first, and API gravity secondarily. 

(B) If separator or non-separator equipment oil composition and Reid vapor pressure data 

are available through your previous analysis, select the latest available analysis that is 

representative of produced crude oil or condensate from the sub-basin category for onshore 

petroleum and natural gas production or from the county for onshore petroleum and natural gas 

gathering and boosting. 

(C) Analyze a representative sample of separator or non-separator equipment oil in each 

sub-basin category for onshore petroleum and natural gas production or each county for onshore 

petroleum and natural gas gathering and boosting for oil composition and Reid vapor pressure 

using an appropriate standard method published by a consensus-based standards organization. 

(2) Calculation Method 2. Calculate annual CH4 and CO2 emissions using the methods in 

paragraph (j)(2)(i) of this section for gas-liquid separators with annual average daily throughput 

of oil greater than or equal to 10 barrels per day. Calculate annual CH4 and CO2 emissions using 

the methods in paragraph (j)(2)(ii) of this section for wells with annual average daily oil 

production greater than or equal to 10 barrels per day that flow directly to atmospheric storage 

tanks in onshore petroleum and natural gas production and onshore petroleum and natural gas 

gathering and boosting (if applicable). Calculate annual CH4 and CO2 emissions using the 

methods in paragraph (j)(2)(iii) of this section for non-separator equipment with annual average 

daily hydrocarbon liquids throughput greater than or equal to 10 barrels per day that flow 

directly to atmospheric storage tanks in onshore petroleum and natural gas gathering and 

boosting. 
Page 45 of 200 

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(i) Flow to storage tank after passing through a separator. Assume that all of the CH4

and CO2 in solution at separator temperature and pressure is emitted from oil sent to storage 

tanks. You may use an appropriate standard method published by a consensus-based standards 

organization if such a method exists or you may use an industry standard practice as described in 

§ 98.234(b) to sample and analyze separator oil composition at separator pressure and 

temperature. 

(ii) Flow to storage tank direct from wells. Calculate CH4 and CO2 emissions using either 

of the methods in paragraph (j)(2)(ii)(A) or (B) of this section. 

(A) If well production oil and gas compositions are available through a previous analysis, 

select the latest available analysis that is representative of produced oil and gas from the subbasin category and assume all of the CH4 and CO2 in both oil and gas are emitted from the tank. 

(B) If well production oil and gas compositions are not available, use default oil and gas 

compositions in software programs, such as API 4697 E&P Tank, that most closely match the 

well production gas/oil ratio and API gravity and assume all of the CH4 and CO2 in both oil and 

gas are emitted from the tank. 

(iii) Flow to storage tank direct from non-separator equipment. Calculate CH4 and CO2

emissions using either of the methods in paragraph (j)(2)(iii)(A) or (B) of this section. 

(A) If other non-separator equipment liquid and gas compositions are available through a 

previous analysis, select the latest available analysis that is representative of liquid and gas from 

non-separator equipment in the same county and assume all of the CH4 and CO2 in both 

hydrocarbon liquids and gas are emitted from the tank. 

(B) If non-separator equipment liquid and gas compositions are not available, use default 

liquid and gas compositions in software programs, such as API 4697 E&P Tank, that most 
Page 46 of 200 

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closely match the non-separator equipment gas/liquid ratio and API gravity and assume all of the 

CH4 and CO2 in both hydrocarbon liquids and gas are emitted from the tank. 

(3) Calculation Method 3. Calculate CH4 and CO2 emissions using Equation W-15 of this 

section: 

* *1000 E , EF Count s i i (Eq. W-15) 

Where: 

Es,i = Annual total volumetric GHG emissions (either CO2 or CH4) at standard 

conditions in cubic feet. 

EFi = Population emission factor for separators, wells, or non-separator equipment 

in thousand standard cubic feet per separator, well, or non-separator 

equipment per year, for crude oil use 4.2 for CH4 and 2.8 for CO2 at 60 °F 

and 14.7 psia, and for gas condensate use 17.6 for CH4 and 2.8 for CO2 at 60 

°F and 14.7 psia. 

Count = Total number of separators, wells, or non-separator equipment with annual 

average daily throughput less than 10 barrels per day. Count only separators, 

wells, or non-separator equipment that feed oil directly to the storage tank. 

1,000 = Conversion from thousand standard cubic feet to standard cubic feet. 

(4) Determine if the storage tank receiving your separator oil has a vapor recovery 

system. 

(i) Adjust the emissions estimated in paragraphs (j)(1) through (3) of this section 

downward by the magnitude of emissions recovered using a vapor recovery system as 

determined by engineering estimate based on best available data. 

(ii) [Reserved] 

(5) Determine if the storage tank receiving your separator oil is sent to flare(s). 

(i) Use your separator flash gas volume and gas composition as determined in this 

section. 
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(ii) Use the calculation method of flare stacks in paragraph (n) of this section to 

determine storage tank emissions from the flare. 

(6) If you use Calculation Method 1 or Calculation Method 2 in paragraph (j)(1) or (2) of 

this section, calculate emissions from occurrences of gas-liquid separator liquid dump valves not 

closing during the calendar year by using Equation W-16 of this section. 





 



  n

n

s i o n T

E

E CF * 8760 , , * (Eq. W-16) 

Where: 

Es,i,o = Annual volumetric GHG emissions at standard conditions from each storage 

tank in cubic feet that resulted from the dump valve on the gas-liquid 

separator not closing properly. 

En = Storage tank emissions as determined in paragraphs (j)(1), (j)(2) and, if 

applicable, (j)(4) of this section in standard cubic feet per year. 

Tn = Total time a dump valve is not closing properly in the calendar year in hours. 

Estimate Tn based on maintenance, operations, or routine separator 

inspections that indicate the period of time when the valve was 

malfunctioning in open or partially open position. 

CFn = Correction factor for tank emissions for time period Tn is 2.87 for crude oil 

production. Correction factor for tank emissions for time period Tn is 4.37 for 

gas condensate production. 

8,760 = Conversion to hourly emissions. 

(7) Calculate both CH4 and CO2 mass emissions from natural gas volumetric emissions 

using calculations in paragraph (v) of this section. 

(k) Transmission storage tanks. For vent stacks connected to one or more transmission 

condensate storage tanks, either water or hydrocarbon, without vapor recovery, in onshore 

natural gas transmission compression, calculate CH4 and CO2 annual emissions from compressor 

scrubber dump valve leakage as specified in paragraphs (k)(1) through (k)(4) of this section. If 
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emissions from compressor scrubber dump valve leakage are routed to a flare, you must 

calculate CH4, CO2, and N2O annual emissions as specified in paragraph (k)(5) of this section. 

(1) Except as specified in paragraph (k)(1)(iv) of this section, you must monitor the tank 

vapor vent stack annually for emissions using one of the methods specified in paragraphs 

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

(i) Use an optical gas imaging instrument according to methods set forth in § 

98.234(a)(1). 

(ii) Measure the tank vent directly using a flow meter or high volume sampler according 

to methods in § 98.234(b) or (d) for a duration of 5 minutes. 

(iii) Measure the tank vent using a calibrated bag according to methods in § 98.234(c) for 

a duration of 5 minutes or until the bag is full, whichever is shorter. 

(iv) You may annually monitor leakage through compressor scrubber dump valve(s) into 

the tank using an acoustic leak detection device according to methods set forth in § 98.234(a)(5). 

(2) If the tank vapors from the vent stack are continuous for 5 minutes, or the optical gas 

imaging instrument or acoustic leak detection device detects a leak, then you must use one of the 

methods in either paragraph (k)(2)(i) or (ii) of this section. 

(i) Use a flow meter, such as a turbine meter, calibrated bag, or high volume sampler to 

estimate tank vapor volumes from the vent stack according to methods set forth in § 98.234(b) 

through (d). If you do not have a continuous flow measurement device, you may install a flow 

measuring device on the tank vapor vent stack. If the vent is directly measured for five minutes 

under paragraph (k)(1)(ii) or (iii) of this section to detect continuous leakage, this serves as the 

measurement. 
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(ii) Use an acoustic leak detection device on each scrubber dump valve connected to the 

tank according to the method set forth in § 98.234(a)(5). 

(3) If a leaking dump valve is identified, the leak must be counted as having occurred 

since the beginning of the calendar year, or from the previous test that did not detect leaking in 

the same calendar year. If the leaking dump valve is fixed following leak detection, the leak 

duration will end upon being repaired. If a leaking dump valve is identified and not repaired, the 

leak must be counted as having occurred through the rest of the calendar year. 

(4) Use the requirements specified in paragraphs (k)(4)(i) and (ii) of this section to 

quantify annual emissions. 

(i) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section. 

(ii) Calculate CH4 and CO2 volumetric and mass emissions at standard conditions using 

calculations in paragraphs (t), (u), and (v) of this section, as applicable to the monitoring 

equipment used. 

(5) Calculate annual emissions from storage tanks to flares as specified in paragraphs 

(k)(5)(i) and (ii) of this section. 

(i) Use the storage tank emissions volume and gas composition as determined in 

paragraphs (k)(1) through (4) of this section. 

(ii) Use the calculation method of flare stacks in paragraph (n) of this section to 

determine storage tank emissions sent to a flare. 

(l) Well testing venting and flaring. Calculate CH4 and CO2 annual emissions from well 

testing venting as specified in paragraphs (l)(1) through (5) of this section. If emissions from 

well testing venting are routed to a flare, you must calculate CH4, CO2, and N2O annual 

emissions as specified in paragraph (l)(6) of this section. 
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(1) Determine the gas to oil ratio (GOR) of the hydrocarbon production from oil well(s) 

tested. Determine the production rate from gas well(s) tested. 

(2) If GOR cannot be determined from your available data, then you must measure 

quantities reported in this section according to one of the procedures specified in paragraph 

(l)(2)(i) or (ii) of this section to determine GOR. 

(i) You may use an appropriate standard method published by a consensus-based 

standards organization if such a method exists. 

(ii) You may use an industry standard practice as described in § 98.234(b). 

(3) Estimate venting emissions using Equation W-17A (for oil wells) or Equation W-17B 

(for gas wells) of this section. 

Ea,n  GOR*FR*D (Eq. W-17A) 

Ea,n  PR*D (Eq. W-17B) 

Where: 

Ea,n = Annual volumetric natural gas emissions from well(s) testing in cubic feet 

under actual conditions. 

GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to 

hydrocarbon liquids produced of all API gravities. 

FR = Average annual flow rate in barrels of oil per day for the oil well(s) being 

tested. 

PR = Average annual production rate in actual cubic feet per day for the gas well(s) 

being tested. 

D = Number of days during the calendar year that the well(s) is tested. 

(4) Calculate natural gas volumetric emissions at standard conditions using calculations 

in paragraph (t) of this section. 
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(5) Calculate both CH4 and CO2 volumetric and mass emissions from natural gas 

volumetric emissions using calculations in paragraphs (u) and (v) of this section. 

(6) Calculate emissions from well testing if emissions are routed to a flare as specified in 

paragraphs (l)(6)(i) and (ii) of this section. 

(i) Use the well testing emissions volume and gas composition as determined in 

paragraphs (l)(1) through (4) of this section. 

(ii) Use the calculation method of flare stacks in paragraph (n) of this section to 

determine well testing emissions from the flare. 

(m) Associated gas venting and flaring. Calculate CH4 and CO2 annual emissions from 

associated gas venting not in conjunction with well testing (refer to paragraph (l): Well testing 

venting and flaring of this section) as specified in paragraphs (m)(1) through (4) of this section. 

If emissions from associated gas venting are routed to a flare, you must calculate CH4, CO2, and 

N2O annual emissions as specified in paragraph (m)(5) of this section. 

(1) Determine the GOR of the hydrocarbon production from each well whose associated 

natural gas is vented or flared. If GOR from each well is not available, use the GOR from a 

cluster of wells in the same sub-basin category. 

(2) If GOR cannot be determined from your available data, then you must use one of the 

procedures specified in paragraphs (m)(2)(i) or (ii) of this section to determine GOR. 

(i) You may use an appropriate standard method published by a consensus-based 

standards organization if such a method exists. 

(ii) You may use an industry standard practice as described in § 98.234(b). 

(3) Estimate venting emissions using Equation W-18 of this section. 

     

 

y

q

x

p

Es n GORp q Vp q SGp q

1 1

, , * , , (Eq. W-18) 
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Where: 

Es,n = Annual volumetric natural gas emissions, at the facility level, from associated 

gas venting at standard conditions, in cubic feet. 

GORp,q = Gas to oil ratio, for well p in sub-basin q, in standard cubic feet of gas per 

barrel of oil; oil here refers to hydrocarbon liquids produced of all API 

gravities. 

Vp,q = Volume of oil produced, for well p in sub-basin q, in barrels in the calendar 

year during time periods in which associated gas was vented or flared. 

SGp,q = Volume of associated gas sent to sales, for well p in sub-basin q, in standard 

cubic feet of gas in the calendar year during time periods in which associated 

gas was vented or flared. 

x = Total number of wells in sub-basin that vent or flare associated gas. 

y = Total number of sub-basins in a basin that contain wells that vent or flare 

associated gas. 

(4) Calculate both CH4 and CO2 volumetric and mass emissions from volumetric natural 

gas emissions using calculations in paragraphs (u) and (v) of this section. 

(5) Calculate emissions from associated natural gas if emissions are routed to a flare as 

specified in paragraphs (m)(5)(i) and (ii) of this section. 

(i) Use the associated natural gas volume and gas composition as determined in 

paragraph (m)(1) through (4) of this section. 

(ii) Use the calculation method of flare stacks in paragraph (n) of this section to 

determine associated gas emissions from the flare. 

(n) Flare stack emissions. Calculate CO2, CH4, and N2O emissions from a flare stack as 

specified in paragraphs (n)(1) through (9) of this section. 

(1) If you have a continuous flow measurement device on the flare, you must use the 

measured flow volumes to calculate the flare gas emissions. If all of the flare gas is not measured 

by the existing flow measurement device, then the flow not measured can be estimated using 

engineering calculations based on best available data or company records. If you do not have a 
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continuous flow measurement device on the flare, you can use engineering calculations based on 

process knowledge, company records, and best available data. 

(2) If you have a continuous gas composition analyzer on gas to the flare, you must use 

these compositions in calculating emissions. If you do not have a continuous gas composition 

analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of 

hydrocarbons going to the flare as specified in paragraphs (n)(2)(i) through (iii) of this section. 

(i) For onshore natural gas production and onshore petroleum and natural gas gathering 

and boosting, determine the GHG mole fraction using paragraph (u)(2)(i) of this section. 

(ii) For onshore natural gas processing, when the stream going to flare is natural gas, use 

the GHG mole fraction in feed natural gas for all streams 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 fraction in feed natural gas liquid for 

all streams. 

(iii) For any industry segment required to report to flare stack emissions under § 98.232, 

when the stream going to the flare is a hydrocarbon product stream, such as methane, ethane, 

propane, butane, pentane-plus and mixed light hydrocarbons, then you may use a representative 

composition from the source for the stream determined by engineering calculation based on 

process knowledge and best available data. 

(3) Determine flare combustion efficiency from manufacturer. If not available, assume 

that flare combustion efficiency is 98 percent. 
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(4) Convert GHG volumetric emissions to standard conditions using calculations in 

paragraph (t) of this section. 

(5) Calculate GHG volumetric emissions from flaring at standard conditions using 

Equations W-19 and W-20 of this section. 

    Es,CH4 Vs XCH4  ZL  ZU * * 1  * (Eq. W-19) 

  

 

5

1

* * * * * jEs,CO2 Vs X CO2  Vs Yj Rj ZL (Eq. W-20) 

Where: 

Es,CH4 = Annual CH4 emissions from flare stack in cubic feet, at standard conditions. 

Es,CO2 = Annual CO2 emissions from flare stack in cubic feet, at standard conditions. 

Vs = Volume of gas sent to flare in standard cubic feet, during the year as 

determined in paragraph (n)(1) of this section. 

η = Flare combustion efficiency, expressed as fraction of gas combusted by a 

burning flare (default is 0.98). 

XCH4 = Mole fraction of CH4 in the feed gas to the flare as determined in paragraph 

(n)(2) of this section. 

XCO2 = Mole fraction of CO2 in the feed gas to the flare as determined in paragraph 

(n)(2) of this section. 

ZU = Fraction of the feed gas sent to an un-lit flare determined by engineering 

estimate and process knowledge based on best available data and operating 

records. 

ZL = Fraction of the feed gas sent to a burning flare (equal to 1 − ZU). 

Yj = Mole fraction of hydrocarbon constituents j (such as methane, ethane, 

propane, butane, and pentanes-plus) in the feed gas to the flare as determined 

in paragraph (n)(1) of this section. 

Rj = Number of carbon atoms in the hydrocarbon constituent j in the feed gas to 

the flare: 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for 

pentanes-plus). 

(6) Calculate both CH4 and CO2 mass emissions from volumetric emissions using 

calculation in paragraph (v) of this section. 
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(7) Calculate N2O emissions from flare stacks using Equation W-40 in paragraph (z) of 

this section. 

(8) If you operate and maintain a CEMS that has both a CO2 concentration monitor and 

volumetric flow rate monitor for the combustion gases from the flare, you must calculate only 

CO2 emissions for the flare. You must follow the Tier 4 Calculation Method and all associated 

calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C 

of this part (General Stationary Fuel Combustion Sources). If a CEMS is used to calculate flare 

stack emissions, the requirements specified in paragraphs (n)(1) through (7) of this section are 

not required. 

(9) The flare emissions determined under this paragraph (n) must be corrected for flare 

emissions calculated and reported under other paragraphs of this section to avoid double 

counting of these emissions. 

(o) Centrifugal compressor venting. If you are required to report emissions from 

centrifugal compressor venting as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), 

you must conduct volumetric emission measurements specified in paragraph (o)(1) of this 

section using methods specified in paragraphs (o)(2) through (5) of this section; perform 

calculations specified in paragraphs (o)(6) through (9) of this section; and calculate CH4 and CO2

mass emissions as specified in paragraph (o)(11) of this section. If emissions from a compressor 

source are routed to a flare, paragraphs (o)(1) through (11) do not apply and instead you must 

calculate CH4, CO2, and N2O emissions as specified in paragraph (o)(12) of this section. If 

emissions from a compressor source are captured for fuel use or are routed to a thermal oxidizer, 

paragraphs (o)(1) through (12) do not apply and instead you must calculate and report emissions 

as specified in subpart C of this part. If emissions from a compressor source are routed to vapor 
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recovery, paragraphs (o)(1) through (12) do not apply. If you are required to report emissions 

from centrifugal compressor venting at an onshore petroleum and natural gas production facility 

as specified in § 98.232(c)(19) or an onshore petroleum and natural gas gathering and boosting 

facility as specified in § 98.232(j)(8), you must calculate volumetric emissions as specified in 

paragraph (o)(10); and calculate CH4 and CO2 mass emissions as specified in paragraph (o)(11). 

(1) General requirements for conducting volumetric emission measurements. You must 

conduct volumetric emission measurements on each centrifugal compressor as specified in this 

paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a 

measurement method specified in paragraph (o)(1)(i) or (ii) of this section. Manifolded 

compressor sources (as defined in § 98.238) must use a measurement method specified in 

paragraph (o)(1)(i), (ii), (iii), or (iv) of this section. 

(i) Centrifugal compressor source as found measurements. Measure venting from each 

compressor according to either paragraph (o)(1)(i)(A) or (B) of this section at least once 

annually, based on the compressor mode (as defined in § 98.238) in which the compressor was 

found at the time of measurement, except as specified in paragraphs (o)(1)(i)(C) and (D) of this 

section. If additional measurements beyond the required annual testing are performed (including 

duplicate measurements or measurement of additional operating modes), then all measurements 

satisfying the applicable monitoring and QA/QC that is required by this paragraph (o) must be 

used in the calculations specified in this section. 

(A) For a compressor measured in operating-mode, you must measure volumetric 

emissions from blowdown valve leakage through the blowdown vent as specified in either 

paragraph (o)(2)(i)(A) or (B) of this section and, if the compressor has wet seal oil degassing 
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vents, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph 

(o)(2)(ii) of this section. 

(B) For a compressor measured in not-operating-depressurized-mode, you must measure 

volumetric emissions from isolation valve leakage as specified in either paragraph (o)(2)(i)(A), 

(B), or (C) of this section. If a compressor is not operated and has blind flanges in place 

throughout the reporting period, measurement is not required in this compressor mode. 

(C) You must measure the compressor as specified in paragraph (o)(1)(i)(B) of this 

section at least once in any three consecutive calendar years, provided the measurement can be 

taken during a scheduled shutdown. If three consecutive calendar years occur without measuring 

the compressor in not-operating-depressurized-mode, you must measure the compressor as 

specified in paragraph (o)(1)(i)(B) of this section at the next scheduled depressurized shutdown. 

The requirement specified in this paragraph does not apply if the compressor has blind flanges in 

place throughout the reporting year. For purposes of this paragraph, a scheduled shutdown means 

a shutdown that requires a compressor to be taken off-line for planned or scheduled maintenance. 

A scheduled shutdown does not include instances when a compressor is taken offline due to a 

decrease in demand but must remain available. 

(D) An annual as found measurement is not required in the first year of operation for any 

new compressor that begins operation after as found measurements have been conducted for all 

existing compressors. For only the first year of operation of new compressors, calculate 

emissions according to paragraph (o)(6)(ii) of this section. 

(ii) Centrifugal compressor source continuous monitoring. Instead of measuring the 

compressor source according to paragraph (o)(1)(i) of this section for a given compressor, you 
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may elect to continuously measure volumetric emissions from a compressor source as specified 

in paragraph (o)(3) of this section. 

(iii) Manifolded centrifugal compressor source as found measurements. For a compressor 

source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead 

of measuring the compressor source according to paragraph (o)(1)(i), (ii), or (iv) of this section, 

you may elect to measure combined volumetric emissions from the manifolded group of 

compressor sources by conducting measurements at the common vent stack as specified in 

paragraph (o)(4) of this section. The measurements must be conducted at the frequency specified 

in paragraphs (o)(1)(iii)(A) and (B) of this section. 

(A) A minimum of one measurement must be taken for each manifolded group of 

compressor sources in a calendar year. 

(B) The measurement may be performed while the compressors are in any compressor 

mode. 

(iv) Manifolded centrifugal compressor source continuous monitoring. For a compressor 

source that is part of a manifolded group of compressor sources, instead of measuring the 

compressor source according to paragraph (o)(1)(i), (ii), or (iii) of this section, you may elect to 

continuously measure combined volumetric emissions from the manifolded group of compressor 

sources as specified in paragraph (o)(5) of this section. 

(2) Methods for performing as found measurements from individual centrifugal 

compressor sources. If conducting measurements for each compressor source, you must 

determine the volumetric emissions from blowdown valves and isolation valves as specified in 

paragraph (o)(2)(i) of this section, and the volumetric emissions from wet seal oil degassing 

vents as specified in paragraph (o)(2)(ii) of this section. 
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(i) For blowdown valves on compressors in operating-mode and for isolation valves on 

compressors in not-operating-depressurized-mode, determine the volumetric emissions using one 

of the methods specified in paragraphs (o)(2)(i)(A) through (D) of this section. 

(A) Determine the volumetric flow at standard conditions from the blowdown vent using 

calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 

98.234(d), respectively. 

(B) Determine the volumetric flow at standard conditions from the blowdown vent using 

a temporary meter such as a vane anemometer according to methods set forth in § 98.234(b). 

(C) Use an acoustic leak detection device according to methods set forth in § 

98.234(a)(5). 

(D) You may choose to use any of the methods set forth in § 98.234(a) to screen for 

emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must 

use one of the methods specified in paragraph (o)(2)(i)(A) through (C) of this section. If 

emissions are not detected using the methods in § 98.234(a), then you may assume that the 

volumetric emissions are zero. For the purposes of this paragraph, when using any of the 

methods in § 98.234(a), emissions are detected whenever a leak is detected according to the 

methods. 

(ii) For wet seal oil degassing vents in operating-mode, determine vapor volumes at 

standard conditions, using a temporary meter such as a vane anemometer or permanent flow 

meter according to methods set forth in § 98.234(b). 

(3) Methods for continuous measurement from individual centrifugal compressor 

sources. If you elect to conduct continuous volumetric emission measurements for an individual 
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compressor source as specified in paragraph (o)(1)(ii) of this section, you must measure 

volumetric emissions as specified in paragraphs (o)(3)(i) and (ii) of this section. 

(i) Continuously measure the volumetric flow for the individual compressor source at 

standard conditions using a permanent meter according to methods set forth in § 98.234(b). 

(ii) If compressor blowdown emissions are included in the metered emissions specified in 

paragraph (o)(3)(i) of this section, the compressor blowdown emissions may be included with the 

reported emissions for the compressor source and do not need to be calculated separately using 

the method specified in paragraph (i) of this section for blowdown vent stacks. 

(4) Methods for performing as found measurements from manifolded groups of 

centrifugal compressor sources. If conducting measurements for a manifolded group of 

compressor sources, you must measure volumetric emissions as specified in paragraphs (o)(4)(i) 

and (ii) of this section. 

(i) Measure at a single point in the manifold downstream of all compressor inputs and, if 

practical, prior to comingling with other non-compressor emission sources. 

(ii) Determine the volumetric flow at standard conditions from the common stack using 

one of the methods specified in paragraphs (o)(4)(ii)(A) through (E) of this section. 

(A) A temporary meter such as a vane anemometer according the methods set forth in § 

98.234(b). 

(B) Calibrated bagging according to methods set forth in § 98.234(c). 

(C) A high volume sampler according to methods set forth § 98.234(d). 

(D) An acoustic leak detection device according to methods set forth in § 98.234(a)(5). 

(E) You may choose to use any of the methods set forth in § 98.234(a) to screen for 

emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must 
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use one of the methods specified in paragraph (o)(4)(ii)(A) through (o)(4)(ii)(D) of this section. 

If emissions are not detected using the methods in § 98.234(a), then you may assume that the 

volumetric emissions are zero. For the purposes of this paragraph, when using any of the 

methods in § 98.234(a), emissions are detected whenever a leak is detected according to the 

method. 

(5) Methods for continuous measurement from manifolded groups of centrifugal 

compressor sources. If you elect to conduct continuous volumetric emission measurements for a 

manifolded group of compressor sources as specified in paragraph (o)(1)(iv) of this section, you 

must measure volumetric emissions as specified in paragraphs (o)(5)(i) through (iii) of this 

section. 

(i) Measure at a single point in the manifold downstream of all compressor inputs and, if 

practical, prior to comingling with other non-compressor emission sources. 

(ii) Continuously measure the volumetric flow for the manifolded group of compressor 

sources at standard conditions using a permanent meter according to methods set forth in § 

98.234(b). 

(iii) If compressor blowdown emissions are included in the metered emissions specified 

in paragraph (o)(5)(ii) of this section, the compressor blowdown emissions may be included with 

the reported emissions for the manifolded group of compressor sources and do not need to be 

calculated separately using the method specified in paragraph (i) of this section for blowdown 

vent stacks. 

(6) Method for calculating volumetric GHG emissions from as found measurements for 

individual centrifugal compressor sources. For compressor sources measured according to 
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paragraph (o)(1)(i) of this section, you must calculate annual GHG emissions from the 

compressor sources as specified in paragraphs (o)(6)(i) through (iv) of this section. 

(i) Using Equation W-21 of this section, calculate the annual volumetric GHG emissions 

for each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) 

and (B) of this section that was measured during the reporting year. 

Es,i,m MTs,m Tm GHGi,m  * * (Eq. W-21) 

Where: 

Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for measured 

compressor mode-source combination m, at standard conditions, in cubic 

feet. 

MTs,m = Volumetric gas emissions for measured compressor mode-source 

combination m, in standard cubic feet per hour, measured according to 

paragraph (o)(2) of this section. If multiple measurements are performed for a 

given mode-source combination m, use the average of all measurements. 

Tm = Total time the compressor is in the mode-source combination for which Es,i,m

is being calculated in the reporting year, in hours. 

GHGi,m = Mole fraction of GHGi in the vent gas for measured compressor mode-source 

combination m; use the appropriate gas compositions in paragraph (u)(2) of 

this section. 

m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or 

(o)(1)(i)(B) of this section that was measured for the reporting year. 

(ii) Using Equation W-22 of this section, calculate the annual volumetric GHG emissions 

from each centrifugal compressor mode-source combination specified in paragraph (o)(1)(i)(A) 

and (B) of this section that was not measured during the reporting year. 

Es,i,m EFs,m Tm GHGi,m  * * (Eq. W-22) 

Where: 
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Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for unmeasured 

compressor mode-source combination m, at standard conditions, in cubic 

feet. 

EFs,m = Reporter emission factor for compressor mode-source combination m, in 

standard cubic feet per hour, as calculated in paragraph (o)(6)(iii) of this 

section. 

Tm = Total time the compressor was in the unmeasured mode-source combination 

m, for which Es,i,m is being calculated in the reporting year, in hours. 

GHGi,m = Mole fraction of GHGi in the vent gas for unmeasured compressor modesource combination m; use the appropriate gas compositions in paragraph 

(u)(2) of this section. 

m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or 

(o)(1)(i)(B) of this section that was not measured in the reporting year. 

(iii) Using Equation W-23 of this section, develop an emission factor for each compressor 

mode-source combination specified in paragraph (o)(1)(i)(A) and (B) of this section. These 

emission factors must be calculated annually and used in Equation W-22 of this section to 

determine volumetric emissions from a centrifugal compressor in the mode-source combinations 

that were not measured in the reporting year. 

m

Count

p

s m p

s m Count

MT

EF

m

  1

, ,

, (Eq. W-23) 

Where: 

EFs,m = Reporter emission factor to be used in Equation W-22 of this section for 

compressor mode-source combination m, in standard cubic feet per hour. The 

reporter emission factor must be based on all compressors measured in 

compressor mode-source combination m in the current reporting year and the 

preceding two reporting years. 

MTs,m,p = Average volumetric gas emission measurement for compressor mode-source 

combination m, for compressor p, in standard cubic feet per hour, calculated 

using all volumetric gas emission measurements (MTs,m in Equation W-21 of 

this section) for compressor mode-source combination m for compressor p in 

the current reporting year and the preceding two reporting years. 
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Countm = Total number of compressors measured in compressor mode-source 

combination m in the current reporting year and the preceding two reporting 

years. 

m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or 

(o)(1)(i)(B) of this section. 

(iv) The reporter emission factor in Equation W-23 of this section may be calculated by 

using all measurements from a single owner or operator instead of only using measurements 

from a single facility. If you elect to use this option, the reporter emission factor must be applied 

to all reporting facilities for the owner or operator. 

(7) Method for calculating volumetric GHG emissions from continuous monitoring of 

individual centrifugal compressor sources. For compressor sources measured according to 

paragraph (o)(1)(ii) of this section, you must use the continuous volumetric emission 

measurements taken as specified in paragraph (o)(3) of this section and calculate annual 

volumetric GHG emissions associated with the compressor source using Equation W-24A of this 

section. 

Es,i,v Qs,v GHGi,v  * (Eq. W-24A) 

Where: 

Es,i,v = Annual volumetric GHGi (either CH4 or CO2) emissions from compressor 

source v, at standard conditions, in cubic feet. 

Qs,v = Volumetric gas emissions from compressor source v, for reporting year, in 

standard cubic feet. 

GHGi,v = Mole fraction of GHGi in the vent gas for compressor source v; use the 

appropriate gas compositions in paragraph (u)(2) of this section. 

(8) Method for calculating volumetric GHG emissions from as found measurements of 

manifolded groups of centrifugal compressor sources. For manifolded groups of compressor 

sources measured according to paragraph (o)(1)(iii) of this section, you must calculate annual 
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volumetric GHG emissions using Equation W-24B of this section. If the centrifugal compressors 

included in the manifolded group of compressor sources share the manifold with reciprocating 

compressors, you must follow the procedures in either this paragraph (o)(8) or paragraph (p)(8) 

of this section to calculate emissions from the manifolded group of compressor sources. 

Es,i,g Tg MTs,g,avg GHGi,g  * * (Eq. W-24B) 

Where: 

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions for manifolded 

group of compressor sources g, at standard conditions, in cubic feet. 

Tg = Total time the manifolded group of compressor sources g had potential for 

emissions in the reporting year, in hours. Include all time during which at 

least one compressor source in the manifolded group of compressor sources g 

was in a mode-source combination specified in either paragraph (o)(1)(i)(A), 

(o)(1)(i)(B), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. Default 

of 8760 hours may be used. 

MTs,g,avg = Average volumetric gas emissions of all measurements performed in the 

reporting year according to paragraph (o)(4) of this section for the 

manifolded group of compressor sources g, in standard cubic feet per hour. 

GHGi,g = Mole fraction of GHGi in the vent gas for manifolded group of compressor 

sources g; use the appropriate gas compositions in paragraph (u)(2) of this 

section. 

(9) Method for calculating volumetric GHG emissions from continuous monitoring of 

manifolded group of centrifugal compressor sources. For a manifolded group of compressor 

sources measured according to paragraph (o)(1)(iv) of this section, you must use the continuous 

volumetric emission measurements taken as specified in paragraph (o)(5) of this section and 

calculate annual volumetric GHG emissions associated with each manifolded group of 

compressor sources using Equation W-24C of this section. If the centrifugal compressors 

included in the manifolded group of compressor sources share the manifold with reciprocating 
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compressors, you must follow the procedures in either this paragraph (o)(9) or paragraph (p)(9) 

of this section to calculate emissions from the manifolded group of compressor sources. 

Es,i,g Qs,g GHGi,g  * (Eq. W-24C) 

Where: 

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions from manifolded 

group of compressor sources g, at standard conditions, in cubic feet. 

Qs,g = Volumetric gas emissions from manifolded group of compressor sources g, 

for reporting year, in standard cubic feet. 

GHGi,g = Mole fraction of GHGi in the vent gas for measured manifolded group of 

compressor sources g; use the appropriate gas compositions in paragraph 

(u)(2) of this section. 

(10) Method for calculating volumetric GHG emissions from wet seal oil degassing vents 

at an onshore petroleum and natural gas production facility or an onshore petroleum and natural 

gas gathering and boosting facility. You must calculate emissions from centrifugal compressor 

wet seal oil degassing vents at an onshore petroleum and natural gas production facility or an 

onshore petroleum and natural gas gathering and boosting facility using Equation W-25 of this 

section. 

Es,iCount*EFi,s (Eq. W-25) 

Where: 

Es,i = Annual volumetric GHGi (either CH4 or CO2) emissions from centrifugal 

compressor wet seals, at standard conditions, in cubic feet. 

Count = Total number of centrifugal compressors that have wet seal oil degassing 

vents. 

EFi,s = Emission factor for GHGi. Use 1.2 × 107

 standard cubic feet per year per 

compressor for CH4 and 5.30 × 105

 standard cubic feet per year per 

compressor for CO2 at 60 °F and 14.7 psia. 
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(11) Method for converting from volumetric to mass emissions. You must calculate both 

CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of 

this section. 

(12) General requirements for calculating volumetric GHG emissions from centrifugal 

compressors routed to flares. You must calculate and report emissions from all centrifugal 

compressor sources that are routed to a flare as specified in paragraphs (o)(12)(i) through (iii) of 

this section. 

(i) Paragraphs (o)(1) through (11) of this section are not required for compressor sources 

that are routed to a flare. 

(ii) If any compressor sources are routed to a flare, calculate the emissions for the flare 

stack as specified in paragraph (n) of this section and report emissions from the flare as specified 

in § 98.236(n), without subtracting emissions attributable to compressor sources from the flare. 

(iii) Report all applicable activity data for compressors with compressor sources routed to 

flares as specified in § 98.236(o). 

(p) Reciprocating compressor venting. If you are required to report emissions from 

reciprocating compressor venting as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), 

you must conduct volumetric emission measurements specified in paragraph (p)(1) of this 

section using methods specified in paragraphs (p)(2) through (5) of this section; perform 

calculations specified in paragraphs (p)(6) through (9) of this section; and calculate CH4 and CO2

mass emissions as specified in paragraph (p)(11) of this section. If emissions from a compressor 

source are routed to a flare, paragraphs (p)(1) through (11) do not apply and instead you must 

calculate CH4, CO2, and N2O emissions as specified in paragraph (p)(12) of this section. If 

emissions from a compressor source are captured for fuel use or are routed to a thermal oxidizer, 
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paragraphs (p)(1) through (12) do not apply and instead you must calculate and report emissions 

as specified in subpart C of this part. If emissions from a compressor source are routed to vapor 

recovery, paragraphs (p)(1) through (12) do not apply. If you are required to report emissions 

from reciprocating compressor venting at an onshore petroleum and natural gas production 

facility as specified in § 98.232(c)(11) or an onshore petroleum and natural gas gathering and 

boosting facility as specified in § 98.232(j)(5), you must calculate volumetric emissions as 

specified in paragraph (p)(10); and calculate CH4 and CO2 mass emissions as specified in 

paragraph (p)(11). 

(1) General requirements for conducting volumetric emission measurements. You must 

conduct volumetric emission measurements on each reciprocating compressor as specified in this 

paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a 

measurement method specified in paragraph (p)(1)(i) or (ii) of this section. Manifolded 

compressor sources (as defined in § 98.238) must use a measurement method specified in 

paragraph (p)(1)(i), (ii), (iii), or (iv) of this section. 

(i) Reciprocating compressor source as found measurements. Measure venting from each 

compressor according to either paragraph (p)(1)(i)(A), (B), or (C) of this section at least once 

annually, based on the compressor mode (as defined in § 98.238) in which the compressor was 

found at the time of measurement, except as specified in paragraphs (p)(1)(i)(D) and (E) of this 

section. If additional measurements beyond the required annual testing are performed (including 

duplicate measurements or measurement of additional operating modes), then all measurements 

satisfying the applicable monitoring and QA/QC that is required by this paragraph (o) must be 

used in the calculations specified in this section. 
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(A) For a compressor measured in operating-mode, you must measure volumetric 

emissions from blowdown valve leakage through the blowdown vent as specified in either 

paragraph (p)(2)(i)(A) or (B) of this section, and measure volumetric emissions from 

reciprocating rod packing as specified in paragraph (p)(2)(ii) of this section. 

(B) For a compressor measured in standby-pressurized-mode, you must measure 

volumetric emissions from blowdown valve leakage through the blowdown vent as specified in 

either paragraph (p)(2)(i)(A) or (B) of this section. 

(C) For a compressor measured in not-operating-depressurized-mode, you must measure 

volumetric emissions from isolation valve leakage as specified in either paragraph (p)(2)(i)(A), 

(B), or (C) of this section. If a compressor is not operated and has blind flanges in place 

throughout the reporting period, measurement is not required in this compressor mode. 

(D) You must measure the compressor as specified in paragraph (p)(1)(i)(C) of this 

section at least once in any three consecutive calendar years, provided the measurement can be 

taken during a scheduled shutdown. If there is no scheduled shutdown within three consecutive 

calendar years, you must measure the compressor as specified in paragraph (p)(1)(i)(C) of this 

section at the next scheduled depressurized shutdown. For purposes of this paragraph, a 

scheduled shutdown means a shutdown that requires a compressor to be taken off-line for 

planned or scheduled maintenance. A scheduled shutdown does not include instances when a 

compressor is taken offline due to a decrease in demand but must remain available. 

(E) An annual as found measurement is not required in the first year of operation for any 

new compressor that begins operation after as found measurements have been conducted for all 

existing compressors. For only the first year of operation of new compressors, calculate 

emissions according to paragraph (p)(6)(ii) of this section. 
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(ii) Reciprocating compressor source continuous monitoring. Instead of measuring the 

compressor source according to paragraph (p)(1)(i) of this section for a given compressor, you 

may elect to continuously measure volumetric emissions from a compressor source as specified 

in paragraph (p)(3) of this section. 

(iii) Manifolded reciprocating compressor source as found measurements. For a 

compressor source that is part of a manifolded group of compressor sources (as defined in § 

98.238), instead of measuring the compressor source according to paragraph (p)(1)(i), (ii), or (iv) 

of this section, you may elect to measure combined volumetric emissions from the manifolded 

group of compressor sources by conducting measurements at the common vent stack as specified 

in paragraph (p)(4) of this section. The measurements must be conducted at the frequency 

specified in paragraphs (p)(1)(iii)(A) and (B) of this section. 

(A) A minimum of one measurement must be taken for each manifolded group of 

compressor sources in a calendar year. 

(B) The measurement may be performed while the compressors are in any compressor 

mode. 

(iv) Manifolded reciprocating compressor source continuous monitoring. For a 

compressor source that is part of a manifolded group of compressor sources, instead of 

measuring the compressor source according to paragraph (p)(1)(i), (ii), or (iii) of this section, 

you may elect to continuously measure combined volumetric emissions from the manifolded 

group of compressors sources as specified in paragraph (p)(5) of this section. 

(2) Methods for performing as found measurements from individual reciprocating 

compressor sources. If conducting measurements for each compressor source, you must 

determine the volumetric emissions from blowdown valves and isolation valves as specified in 
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paragraph (p)(2)(i) of this section. You must determine the volumetric emissions from 

reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section. 

(i) For blowdown valves on compressors in operating-mode or standby-pressurizedmode, and for isolation valves on compressors in not-operating-depressurized-mode, determine 

the volumetric emissions using one of the methods specified in paragraphs (p)(2)(i)(A) through 

(D) of this section. 

(A) Determine the volumetric flow at standard conditions from the blowdown vent using 

calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and (d), 

respectively. 

(B) Determine the volumetric flow at standard conditions from the blowdown vent using 

a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b). 

(C) Use an acoustic leak detection device according to methods set forth in § 

98.234(a)(5). 

(D) You may choose to use any of the methods set forth in § 98.234(a) to screen for 

emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must 

use one of the methods specified in paragraphs (p)(2)(i)(A) through (C) of this section. If 

emissions are not detected using the methods in § 98.234(a), then you may assume that the 

volumetric emissions are zero. For the purposes of this paragraph, when using any of the 

methods in § 98.234(a), emissions are detected whenever a leak is detected according to the 

method. 

(ii) For reciprocating rod packing equipped with an open-ended vent line on compressors 

in operating-mode, determine the volumetric emissions using one of the methods specified in 

paragraphs (p)(2)(ii)(A) through (C) of this section. 
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(A) Determine the volumetric flow at standard conditions from the open-ended vent line 

using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) 

and (d), respectively. 

(B) Determine the volumetric flow at standard conditions from the open-ended vent line 

using a temporary meter such as a vane anemometer, according to methods set forth in § 

98.234(b). 

(C) You may choose to use any of the methods set forth in § 98.234(a) to screen for 

emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must 

use one of the methods specified in paragraph (p)(2)(ii)(A) and (p)(4)(ii)(B) of this section. If 

emissions are not detected using the methods in § 98.234(a), then you may assume that the 

volumetric emissions are zero. For the purposes of this paragraph, when using any of the 

methods in § 98.234(a), emissions are detected whenever a leak is detected according to the 

method. 

(iii) For reciprocating rod packing not equipped with an open-ended vent line on 

compressors in operating-mode, you must determine the volumetric emissions using the method 

specified in paragraphs (p)(2)(iii)(A) and (B) of this section. 

(A) You must use the methods described in § 98.234(a) to conduct annual leak detection 

of equipment leaks from the packing case into an open distance piece, or for compressors with a 

closed distance piece, conduct annual detection of gas emissions from the rod packing vent, 

distance piece vent, compressor crank case breather cap, or other vent emitting gas from the rod 

packing. 
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(B) You must measure emissions found in paragraph (p)(2)(iii)(A) of this section using 

an appropriate meter, calibrated bag, or high volume sampler according to methods set forth in § 

98.234(b), (c), and (d), respectively. 

(3) Methods for continuous measurement from individual reciprocating compressor 

sources. If you elect to conduct continuous volumetric emission measurements for an individual 

compressor source as specified in paragraph (p)(1)(ii) of this section, you must measure 

volumetric emissions as specified in paragraphs (p)(3)(i) and (p)(3)(ii) of this section. 

(i) Continuously measure the volumetric flow for the individual compressor sources at 

standard conditions using a permanent meter according to methods set forth in § 98.234(b). 

(ii) If compressor blowdown emissions are included in the metered emissions specified in 

paragraph (p)(3)(i) of this section, the compressor blowdown emissions may be included with the 

reported emissions for the compressor source and do not need to be calculated separately using 

the method specified in paragraph (i) of this section for blowdown vent stacks. 

(4) Methods for performing as found measurements from manifolded groups of 

reciprocating compressor sources. If conducting measurements for a manifolded group of 

compressor sources, you must measure volumetric emissions as specified in paragraphs (p)(4)(i) 

and (ii) of this section. 

(i) Measure at a single point in the manifold downstream of all compressor inputs and, if 

practical, prior to comingling with other non-compressor emission sources. 

(ii) Determine the volumetric flow at standard conditions from the common stack using 

one of the methods specified in paragraph (p)(4)(ii)(A) through (E) of this section. 

(A) A temporary meter such as a vane anemometer according the methods set forth in § 

98.234(b). 
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(B) Calibrated bagging according to methods set forth in § 98.234(c). 

(C) A high volume sampler according to methods set forth § 98.234(d). 

(D) An acoustic leak detection device according to methods set forth in § 98.234(a)(5). 

(E) You may choose to use any of the methods set forth in § 98.234(a) to screen for 

emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must 

use one of the methods specified in paragraph (p)(4)(ii)(A) through (D) of this section. If 

emissions are not detected using the methods in § 98.234(a), then you may assume that the 

volumetric emissions are zero. For the purposes of this paragraph, when using any of the 

methods in § 98.234(a), emissions are detected whenever a leak is detected according to the 

method. 

(5) Methods for continuous measurement from manifolded groups of reciprocating 

compressor sources. If you elect to conduct continuous volumetric emission measurements for a 

manifolded group of compressor sources as specified in paragraph (p)(1)(iv) of this section, you 

must measure volumetric emissions as specified in paragraphs (p)(5)(i) through (iii) of this 

section. 

(i) Measure at a single point in the manifold downstream of all compressor inputs and, if 

practical, prior to comingling with other non-compressor emission sources. 

(ii) Continuously measure the volumetric flow for the manifolded group of compressor 

sources at standard conditions using a permanent meter according to methods set forth in § 

98.234(b). 

(iii) If compressor blowdown emissions are included in the metered emissions specified 

in paragraph (p)(5)(ii) of this section, the compressor blowdown emissions may be included with 

the reported emissions for the manifolded group of compressor sources and do not need to be 
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calculated separately using the method specified in paragraph (i) of this section for blowdown 

vent stacks. 

(6) Method for calculating volumetric GHG emissions from as found measurements for 

individual reciprocating compressor sources. For compressor sources measured according to 

paragraph (p)(1)(i) of this section, you must calculate GHG emissions from the compressor 

sources as specified in paragraphs (p)(6)(i) through (iv) of this section. 

(i) Using Equation W-26 of this section, calculate the annual volumetric GHG emissions 

for each reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) 

through (C) of this section that was measured during the reporting year. 

Es,i,m MTs,m Tm GHGi,m  * * (Eq. W-26) 

Where: 

Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for measured 

compressor mode-source combination m, at standard conditions, in cubic 

feet. 

MTs,m = Volumetric gas emissions for measured compressor mode-source 

combination m, in standard cubic feet per hour, measured according to 

paragraph (p)(2) of this section. If multiple measurements are performed for a 

given mode-source combination m, use the average of all measurements. 

Tm = Total time the compressor is in the mode-source combination m, for which 

Es,i,m is being calculated in the reporting year, in hours. 

GHGi,m = Mole fraction of GHGi in the vent gas for measured compressor mode-source 

combination m; use the appropriate gas compositions in paragraph (u)(2) of 

this section. 

m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), 

(B), or (C) of this section that was measured for the reporting year. 

(ii) Using Equation W-27 of this section, calculate the annual volumetric GHG emissions 

from each reciprocating compressor mode-source combination specified in paragraph 

(p)(1)(i)(A), (B), and (C) of this section that was not measured during the reporting year. 
Page 76 of 200 

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Es,i,mEFs,m *Tm *GHGi,m (Eq. W-27) 

Where: 

Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for unmeasured 

compressor mode-source combination m, at standard conditions, in cubic 

feet. 

EFs,m = Reporter emission factor for compressor mode-source combination m, in 

standard cubic feet per hour, as calculated in paragraph (p)(6)(iii) of this 

section. 

Tm = Total time the compressor was in the unmeasured mode-source combination 

m, for which Es,i,m is being calculated in the reporting year, in hours. 

GHGi,m = Mole fraction of GHGi in the vent gas for unmeasured compressor modesource combination m; use the appropriate gas compositions in paragraph 

(u)(2) of this section. 

m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), 

(p)(1)(i)(B), or (p)(1)(i)(C) of this section that was not measured for the 

reporting year. 

(iii) Using Equation W-28 of this section, develop an emission factor for each compressor 

mode-source combination specified in paragraph (p)(1)(i)(A), (B), and (C) of this section. These 

emission factors must be calculated annually and used in Equation W-27 of this section to 

determine volumetric emissions from a reciprocating compressor in the mode-source 

combinations that were not measured in the reporting year. 

m

Count

p

s m p

s m Count

MT

EF

m

  1

, ,

, (Eq. W-28) 

Where: 

EFs,m = Reporter emission factor to be used in Equation W-27 of this section for 

compressor mode-source combination m, in standard cubic feet per hour. The 

reporter emission factor must be based on all compressors measured in 

compressor mode-source combination m in the current reporting year and the 

preceding two reporting years. 
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MTs,m,p = Average volumetric gas emission measurement for compressor mode-source 

combination m, for compressor p, in standard cubic feet per hour, calculated 

using all volumetric gas emission measurements (MTs,m in Equation W-26 of 

this section) for compressor mode-source combination m for compressor p in 

the current reporting year and the preceding two reporting years. 

Countm = Total number of compressors measured in compressor mode-source 

combination m in the current reporting year and the preceding two reporting 

years. 

m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), 

(B), or (C) of this section. 

(iv) The reporter emission factor in Equation W-28 of this section may be calculated by 

using all measurements from a single owner or operator instead of only using measurements 

from a single facility. If you elect to use this option, the reporter emission factor must be applied 

to all reporting facilities for the owner or operator. 

(7) Method for calculating volumetric GHG emissions from continuous monitoring of 

individual reciprocating compressor sources. For compressor sources measured according to 

paragraph (p)(1)(ii) of this section, you must use the continuous volumetric emission 

measurements taken as specified in paragraph (p)(3) of this section and calculate annual 

volumetric GHG emissions associated with the compressor source using Equation W-29A of this 

section. 

Es,i,v Qs,v GHGi,v  * (Eq. W-29A) 

Where: 

Es,i,v = Annual volumetric GHGi (either CH4 or CO2) emissions from compressor 

source v, at standard conditions, in cubic feet. 

Qs,v = Volumetric gas emissions from compressor source v, for reporting year, in 

standard cubic feet. 

GHGi,v = Mole fraction of GHGi in the vent gas for compressor source v; use the 

appropriate gas compositions in paragraph (u)(2) of this section. 
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(8) Method for calculating volumetric GHG emissions from as found measurements of 

manifolded groups of reciprocating compressor sources. For manifolded groups of compressor 

sources measured according to paragraph (p)(1)(iii) of this section, you must calculate annual 

GHG emissions using Equation W-29B of this section. If the reciprocating compressors included 

in the manifolded group of compressor sources share the manifold with centrifugal compressors, 

you must follow the procedures in either this paragraph (p)(8) or paragraph (o)(8) of this section 

to calculate emissions from the manifolded group of compressor sources. 

Es,i,g Tg MTs,g,avg GHGi,g  * * (Eq. W-29B) 

Where: 

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions for manifolded 

group of compressor sources g, at standard conditions, in cubic feet. 

Tg = Total time the manifolded group of compressor sources g had potential for 

emissions in the reporting year, in hours. Include all time during which at 

least one compressor source in the manifolded group of compressor sources g 

was in a mode-source combination specified in either paragraph (o)(1)(i)(A), 

(o)(1)(i)(B), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. Default 

of 8760 hours may be used. 

MTs,g,avg = Average volumetric gas emissions of all measurements performed in the 

reporting year according to paragraph (p)(4) of this section for the 

manifolded group of compressor sources g, in standard cubic feet per hour. 

GHGi,g = Mole fraction of GHGi in the vent gas for manifolded group of compressor 

sources g; use the appropriate gas compositions in paragraph (u)(2) of this 

section. 

(9) Method for calculating volumetric GHG emissions from continuous monitoring of 

manifolded group of reciprocating compressor sources. For a manifolded group of compressor 

sources measured according to paragraph (p)(1)(iv) of this section, you must use the continuous 

volumetric emission measurements taken as specified in paragraph (p)(5) of this section and 

calculate annual volumetric GHG emissions associated with each manifolded group of 
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compressor sources using Equation W-29C of this section. If the reciprocating compressors 

included in the manifolded group of compressor sources share the manifold with centrifugal 

compressors, you must follow the procedures in either this paragraph (p)(9) or paragraph (o)(9) 

of this section to calculate emissions from the manifolded group of compressor sources. 

Es,i,g Qs,g GHGi,g  * (Eq. W-29C) 

Where: 

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions from manifolded 

group of compressor sources g, at standard conditions, in cubic feet. 

Qs,g = Volumetric gas emissions from manifolded group of compressor sources g, 

for reporting year, in standard cubic feet. 

GHGi,g = Mole fraction of GHGi in the vent gas for measured manifolded group of 

compressor sources g; use the appropriate gas compositions in paragraph 

(u)(2) of this section. 

(10) Method for calculating volumetric GHG emissions from reciprocating compressor 

venting at an onshore petroleum and natural gas production facility or an onshore petroleum and 

natural gas gathering and boosting facility. You must calculate emissions from reciprocating 

compressor venting at an onshore petroleum and natural gas production facility or an onshore 

petroleum and natural gas gathering and boosting facility using Equation W-29D of this section. 

Es,i Count EFi,s  * (Eq. W-29D) 

Where: 

Es,i = Annual volumetric GHGi (either CH4 or CO2) emissions from reciprocating 

compressors, at standard conditions, in cubic feet. 

Count = Total number of reciprocating compressors. 

EFi,s = Emission factor for GHGi. Use 9.48 × 103

 standard cubic feet per year per 

compressor for CH4 and 5.27 × 102

 standard cubic feet per year per 

compressor for CO2 at 60 °F and 14.7 psia. 
Page 80 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

(11) Method for converting from volumetric to mass emissions. You must calculate both 

CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of 

this section. 

(12) General requirements for calculating volumetric GHG emissions from reciprocating 

compressors routed to flares. You must calculate and report emissions from all reciprocating 

compressor sources that are routed to a flare as specified in paragraphs (p)(12)(i) through (iii) of 

this section. 

(i) Paragraphs (p)(1) through (11) of this section are not required for compressor sources 

that are routed to a flare. 

(ii) If any compressor sources are routed to a flare, calculate the emissions for the flare 

stack as specified in paragraph (n) of this section and report emissions from the flare as specified 

in § 98.236(n), without subtracting emissions attributable to compressor sources from the flare. 

(iii) Report all applicable activity data for compressors with compressor sources routed to 

flares as specified in § 98.236(p). 

(q) Equipment leak surveys. (1) Applicability. (i) Except as specified in paragraph 

(q)(1)(iv) of this section, you must use any of the methods described in § 98.234(a) to conduct 

leak detection(s) of equipment leaks from all equipment leak component types listed in § 

98.232(d)(7), (e)(7), (f)(5), (g)(4), (h)(5), and (i)(1), and you must calculate equipment leak 

emissions for these equipment leak component types using the procedures specified in paragraph 

(q)(2) of this section.

(ii) Except as specified in paragraph (q)(1)(iv) of this section, equipment component 

types in § 98.232(c)(21), (d)(8), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (h)(7), and (j)(10) that are 

Deleted: Y

Deleted: 3

Deleted: 4
Page 81 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

subject to 40 CFR part 60, subpart OOOOa are subject to the equipment leak emissions 

calculation procedures in paragraph (q)(2) of this section. 

(iii) Except as specified in paragraph (q)(1)(iv) of this section, you may elect to comply 

with this paragraph (q) (i.e., use any of the methods described in § 98.234(a) to conduct leak 

detections, and use the procedures specified in paragraph (q)(2) of this section to calculate 

emissions) for any equipment leak component types in § 98.232(c)(21), (d)(8), (e)(8), (f)(6), 

(f)(7), (f)(8), (g)(6), (h)(7), and (j)(10) that are not subject to paragraph (q)(1)(ii) of this section. 

(iv) This paragraph (q) applies to component types in streams with gas content greater 

than 10 percent CH4 plus CO2 by weight. Component types in streams with gas content less than 

or equal to 10 percent CH4 plus CO2 by weight are exempt from the requirements of this 

paragraph (q) and do not need to be reported. Tubing systems equal to or less than one half inch 

diameter are exempt from the requirements of this paragraph (q) and do not need to be reported.

(2) Emission calculation methodology. For industry segments listed in § 98.230(a)(2) 

through (9), if equipment leaks are detected for component types listed in paragraphs (q)(1)(i) 

through (iii) 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 (xi) of this 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)(2)(x)(A) 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. 

Deleted: 3

Deleted: 8

Deleted: this 

Deleted: 8

Deleted: i

Deleted: 9
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This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.





p x

z

Es p i GHGi EFs p Tp z

1

, , * (Eq. W-30) , * ,

Where: 

Es,p,i = Annual total volumetric emissions of GHGi from specific component type 

“p” (in accordance with paragraphs (q)(1)(i) through (iii) of this section) in 

standard (“s”) cubic feet, as specified in paragraphs (q)(2)(ii) through (x) of 

this section. 

xp = Total number of specific component type “p” detected as leaking in any leak 

survey during the year. A component found leaking in two or more surveys 

during the year is counted as one leaking component.

EFs,p = Leaker emission factor for specific component types listed in Table 1E and 

Table W-2 through Table W-7 of this subpart. 

GHGi = For onshore petroleum and natural gas production facilities and onshore 

petroleum and natural gas gathering and boosting facilities, concentration of 

GHGi, CH4, or CO2, in produced natural gas as defined in paragraph (u)(2) of 

this section; for onshore natural gas processing facilities, concentration of 

GHGi, CH4 or CO2, in the total hydrocarbon of the feed natural gas; for 

onshore natural gas transmission compression and underground natural gas 

storage, GHGi equals 0.975 for CH4 and 1.1 × 10−2

 for CO2 ; for LNG storage 

and LNG import and export equipment, GHGi equals 1 for CH4 and 0 for 

CO2 ; and for natural gas distribution, GHGi equals 1 for CH4 and 1.1 × 10−2

CO2. 

Tp,z = The total time the surveyed component “z”, component type “p”, was 

assumed to be leaking and operational, in hours. 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; 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; and 

sum times for all leaking periods. 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. 

(i) You must conduct either one leak detection survey in a calendar year or multiple 

complete leak detection surveys in a calendar year. The leak detection surveys selected must be 

conducted during the calendar year. 

Deleted: listed 

Deleted: § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), 

and (i)(1)

Deleted: 1

Deleted: q

Deleted: (8)

Deleted: during annual

Deleted: s

Deleted: , accounting for time the component was 

not operational (i.e., not operating under pressure) 

using engineering estimate based on best available 

data

Deleted: that the

Deleted: to be 

Deleted: has been

Deleted: previous survey (if not found leaking in the 

previous survey) or the 

Deleted: calendar 

Deleted: (if it was found leaking in the previous 

survey), accounting for time the component was not 

operational using engineering estimate based on best 

available data. For the last leak detection survey in the 

calendar year, assume that all leaking components 

continue to leak until the end of the calendar year

Deleted: ing

Deleted: 1
Page 83 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

(ii) Calculate both CO2 and CH4 mass emissions using calculations in paragraph (v) of 

this section.

(iii) Onshore petroleum and natural gas production facilities must use the appropriate 

default whole gas leaker emission factors for components in gas service, light crude service, and 

heavy crude service listed in Table W-1E of this subpart. 

(iv) Onshore petroleum and natural gas gathering and boosting facilities must use the 

appropriate default whole gas leaker factors for components in gas service listed in Table W-1E 

of 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 noncompressor components in gas service listed in Table W-2 of this subpart. 

(vi) Onshore natural gas transmission compression 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-3 of this subpart. 

(vii) Underground natural gas storage facilities must use the appropriate default total 

hydrocarbon leaker emission factors for storage stations in gas service listed in Table W-4 of this 

subpart. 

(viii) LNG storage facilities must use the appropriate default methane leaker emission 

factors for LNG storage components in gas service listed in Table W-5 of this subpart. 

(ix) LNG import and export facilities must use the appropriate default methane leaker 

emission factors for LNG terminals components in LNG service listed in Table W-6 of this 

subpart. 

Deleted: 2

Deleted: 3

Deleted: 4

Deleted: 5

Deleted: 6

Deleted: 7
Page 84 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

(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-7 of this subpart to calculate component emissions from annual 

equipment leak surveys conducted at above grade transmission-distribution transfer stations. 

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. 

(A) 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. 

(B) 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)(C) of this section. 

 



 

   n

y

Count

w

w y

n

y p

s p i y

s MR i MR y

T

E

EF

1 1

,

1

7

1

, , ,

, , ,

 (Eq. W-31) 

Where: 

Deleted: 8

Deleted: i

Deleted: ii

Deleted: 8

Deleted: iii
Page 85 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

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-7 of this subpart for transmissiondistribution 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 transmissiondistribution transfer stations in year “y”. 

y = Year of data included in emission factor “EFs,MR,i” according to paragraph 

(q)(2)(x)(C) of this section. 

n = Number of years of data, according to paragraph (q)(8)(i) of this section, 

whose results are used to calculate emission factor “EFs,MR,i” according to 

paragraph (q)(2)(x)(C) of this section. 

(C) 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)(2)(x)(A) 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 

Deleted: 8

Deleted: iii

Deleted: 8

Deleted: iii

Deleted: iii

Deleted: 8

Deleted: i

Deleted: 

Deleted: 

Deleted: of this section 
Page 86 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

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 transmissiondistribution transfer stations over multiple years, “n,” according to paragraph (q)(2)(x)(A) 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. 

(r) Equipment leaks by population count. This paragraph (r) applies to emissions sources 

listed in § 98.232(c)(21), (f)(7), (g)(5), (h)(6), and (j)(10) that are not subject to the requirements 

in paragraph (q) of this section, and it 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 using Equation W-32A of 

Deleted: of this section 

Deleted: of this section 

Deleted: 9

Deleted: 8

Deleted: i

Deleted: 

Deleted: 5

Deleted: 3

Deleted: 4

Deleted: (j)(10), 

Deleted: on

Deleted: in
Page 87 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

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 Counte EFs e GHGi Te * * * , ,  , (Eq. W-32A) 

Es,MR,i CountMR EFs,MR,i Tw,avg  * * (Eq. W-32B) 

Where: 

Es,e,i = Annual volumetric emissions of GHGi from the emission source type in 

standard cubic feet. The emission source type may be a component (e.g.

connector, open-ended line, etc.), 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 transmissiondistribution transfer stations or, when used to calculate emissions according 

to paragraph (q)(9) of this section, the annual volumetric emissions of GHGi

from all meter/regulator runs at above grade transmission-distribution 

transfer stations, in standard cubic feet. 

Counte = Total number of the emission source type at the facility. For onshore 

petroleum and natural gas production facilities and onshore petroleum and 

natural gas gathering and boosting facilities, average component counts are 

provided by major equipment piece in Tables W-1B and Table W-1C of this 

subpart. Use average component counts as appropriate for operations in 

Eastern and Western U.S., according to Table W-1D of this subpart. 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-4 of 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: (1) The number of distribution 

services by material type; (2) miles of distribution mains by material type; 

and (3) number of below grade metering-regulating stations, by pressure 

type; as listed in Table W-7 of this subpart. 
Page 88 of 200 

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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)(9) of this 

section, the total number of meter/regulator runs at above grade transmissiondistribution transfer stations. 

EFs,e = Population emission factor for the specific emission source type, as listed in 

Tables W-1A and W-4 through W-7 of this subpart. Use appropriate 

population emission factor for operations in Eastern and Western U.S., 

according to Table W-1D of this subpart. 

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, as determined in Equation W-31 of this section. 

GHGi = For onshore petroleum and natural gas production facilities and onshore 

petroleum and natural gas gathering and boosting facilities, concentration of 

GHGi, CH4, or CO2, in produced natural gas as defined in paragraph (u)(2) of 

this section; for onshore natural gas transmission compression and 

underground natural gas storage, GHGi equals 0.975 for CH4 and 1.1 × 10−2

for CO2; for LNG storage and LNG import and export equipment, GHGi

equals 1 for CH4 and 0 for CO2; and for natural gas distribution, GHGi equals 

1 for CH4 and 1.1 × 10−2

 CO2. 

Te = Average estimated time that each emission source type associated with the 

equipment leak emission was operational in the calendar year, in hours, using 

engineering estimate based on best available data. 

Tw,avg = Average estimated time that each meter/regulator run was operational in the 

calendar year, in hours per meter/regulator run, using engineering estimate 

based on best available data. 

(1) Calculate both CH4 and CO2 mass emissions from volumetric emissions using 

calculations in paragraph (v) of this section. 

(2) Onshore petroleum and natural gas production facilities 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 and 

components associated with gas wells and onshore petroleum and natural gas gathering and 

boosting systems are considered gas service components in reference to Table W-1A of this 

subpart and major natural gas equipment in reference to Table W-1B of this subpart. Major 
Page 89 of 200 

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equipment and components associated with crude oil wells are considered crude service 

components in reference to Table W-1A of this subpart and major crude oil equipment in 

reference to Table W-1C of this subpart. Where facilities conduct EOR operations the emissions 

factor listed in Table W-1A of this subpart shall be used to estimate all streams of gases, 

including recycle CO2 stream. The component count can be determined using either of the 

calculation methods described in this paragraph (r)(2), except for miles of gathering pipelines by 

material type, which must be determined using Component Count Method 2 in paragraph 

(r)(2)(ii) of this section. The same calculation method must be used for the entire calendar year. 

(i) Component Count Method 1. For all onshore petroleum and natural gas production 

operations and onshore petroleum and natural gas gathering and boosting operations in the 

facility perform the following activities: 

(A) Count all major equipment listed in Table W-1B and Table W-1C of this subpart. 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. 

(B) Multiply major equipment counts by the average component counts listed in Table 

W-1B of this subpart for onshore natural gas production and onshore petroleum and natural gas 

gathering and boosting; and Table W-1C of this subpart for onshore oil production. Use the 

appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. 

according to the mapping in Table W-1D of this subpart. 

(ii) Component Count Method 2. Count each component individually for the facility. Use 

the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. 

according to the mapping in Table W-1D of this subpart. 
Page 90 of 200 

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(3) Underground natural gas storage facilities must use the appropriate default total 

hydrocarbon population emission factors for storage wellheads in gas service listed in Table W-4 

of this subpart. 

(4) LNG storage facilities must use the appropriate default methane population emission 

factor for LNG storage compressors in gas service listed in Table W-5 of this subpart. 

(5) LNG import and export facilities must use the appropriate default methane population 

emission factor for LNG terminal compressors in gas service listed in Table W-6 of this subpart. 

(6) Natural gas distribution facilities must use the appropriate methane emission factors 

as described in paragraphs (r)(6)(i) and (ii) of this section. 

(i) Below grade metering-regulating stations, distribution mains, and distribution services 

must use the appropriate default methane population emission factors listed in Table W-7 of this 

subpart. Below grade transmission-distribution transfer stations must use the emission factor for 

below grade metering-regulating stations. 

(ii) Above grade metering-regulating stations that are not above grade transmissiondistribution transfer stations must use the meter/regulator run population emission factor 

calculated in Equation W-31. 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 BOEMRE in compliance with 30 CFR 250.302 through 304. 
Page 91 of 200 

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(1) Offshore production facilities under BOEMRE jurisdiction shall report the same 

annual emissions as calculated and reported by BOEMRE in data collection and emissions 

estimation study published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). 

(i) For any calendar year that does not overlap with the most recent BOEMRE emissions 

study publication year, report the most recent BOEMRE reported emissions data published by 

BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). Adjust emissions based on the 

operating time for the facility relative to the operating time in the most recent BOEMRE 

published study. 

(ii) [Reserved] 

(2) Offshore production facilities that are not under BOEMRE jurisdiction must use the 

most recent monitoring methods and calculation methods published by BOEMRE referenced in 

30 CFR 250.302 through 250.304 to calculate and report annual emissions (GOADS). 

(i) For any calendar year that does not overlap with the most recent BOEMRE 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 BOEMRE discontinues or delays their data collection effort by more than 4 years, 

then offshore reporters shall once in every 4 years use the most recent BOEMRE data collection 

and emissions estimation methods to 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. 
Page 92 of 200 

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(4) For either first or subsequent year reporting, offshore facilities either within or outside 

of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle 

must use the most recent BOEMRE data collection and emissions estimation methods published 

by BOEMRE referenced in 30 CFR 250.302 through 250.304 to calculate and report emissions. 

(t) GHG volumetric emissions using actual conditions. If equation parameters in § 98.233 

are already determined at standard conditions as provided in the introductory text in § 98.233, 

which results in volumetric emissions at standard conditions, then this paragraph does not apply. 

Calculate volumetric emissions at standard conditions as specified in paragraphs (t)(1) or (2) of 

this section, with actual pressure and temperature determined by engineering estimates based on 

best available data unless otherwise specified. 

(1) Calculate natural gas volumetric emissions at standard conditions using actual natural 

gas emission temperature and pressure, and Equation W-33 of this section for conversions of Ea,n

or conversions of FRa (whether sub-sonic or sonic). 

 

  a s a

a n s a

s n T P Z

E T P

E

459.67 * *

, * 459.67 * , 

  (Eq. W-33) 

Where: 

Es,n = Natural gas volumetric emissions at standard temperature and pressure (STP) 

conditions in cubic feet, except Es,n equals FRs,p for each well p when 

calculating either subsonic or sonic flowrates under § 98.233(g). 

Ea,n = Natural gas volumetric emissions at actual conditions in cubic feet, except 

Ea,n equals FRa,p for each well p when calculating either subsonic or sonic 

flowrates under § 98.233(g). 

Ts = Temperature at standard conditions (60 °F). 

Ta = Temperature at actual emission conditions (°F). 

Ps = Absolute pressure at standard conditions (14.7 psia). 

Pa = Absolute pressure at actual conditions (psia). 
Page 93 of 200 

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Za = Compressibility factor at actual conditions for natural gas. You may use 

either a default compressibility factor of 1, or a site-specific compressibility 

factor based on actual temperature and pressure conditions. 

(2) Calculate GHG volumetric emissions at standard conditions using actual GHG 

emissions temperature and pressure, and Equation W-34 of this section. 

 

  a s a

a i s a

s i T P Z

E T P

E

459.67 * *

, * 459.67 * , 

  (Eq. W-34) 

Where: 

Es,i = GHG i volumetric emissions at standard temperature and pressure (STP) 

conditions in cubic feet. 

Ea,i = GHG i volumetric emissions at actual conditions in cubic feet. 

Ts = Temperature at standard conditions (60 °F). 

Ta = Temperature at actual emission conditions (°F). 

Ps = Absolute pressure at standard conditions (14.7 psia). 

Pa = Absolute pressure at actual conditions (psia). 

Za = Compressibility factor at actual conditions for GHG i. 

You may use either a default compressibility factor of 1, or a site-specific compressibility factor 

based on actual temperature and pressure conditions. 

(3) Reporters using 68 °F for standard temperature may use the ratio 519.67/527.67 to 

convert volumetric emissions from 68 °F to 60 °F. 

(u) GHG volumetric emissions at standard conditions. Calculate GHG volumetric 

emissions at standard conditions as specified in paragraphs (u)(1) and (2) of this section. 

(1) Estimate CH4 and CO2 emissions from natural gas emissions using Equation W-35 of 

this section. 

Es i Es n Mi * ,  , (Eq. W-35) 

where: 
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Es,i = GHG i (either CH4 or CO2) volumetric emissions at standard conditions in 

cubic feet. 

Es,n = Natural gas volumetric emissions at standard conditions in cubic feet. 

Mi = Mole fraction of GHG i in the natural gas. 

(2) For Equation W-35 of this section, the mole fraction, Mi, shall be the annual average 

mole fraction for each sub-basin category or facility, as specified in paragraphs (u)(2)(i) through 

(vii) of this section. 

(i) GHG mole fraction in produced natural gas for onshore petroleum and natural gas 

production facilities and onshore petroleum and natural gas gathering and boosting facilities. If 

you have a continuous gas composition analyzer for produced natural gas, you must use an 

annual average of these values for determining the mole fraction. If you do not have a continuous 

gas composition analyzer, then you must use an annual average gas composition based on your 

most recent available analysis of the sub-basin category or facility, as applicable to the emission 

source. 

(ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the demethanizer 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). 
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(iii) GHG mole fraction in transmission pipeline natural gas that passes through the 

facility for the onshore natural gas transmission compression industry segment and the onshore 

natural gas transmission pipeline industry segment. You may use either a default 95 percent 

methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site 

specific engineering estimates based on best available data. 

(iv) GHG mole fraction in natural gas stored in the underground natural gas storage 

industry segment. You may use either a default 95 percent methane and 1 percent carbon dioxide 

fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best 

available data. 

(v) GHG mole fraction in natural gas stored in the LNG storage industry segment. You 

may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole 

fraction in natural gas or site specific engineering estimates based on best available data. 

(vi) GHG mole fraction in natural gas stored in the LNG import and export industry 

segment. For export facilities that receive gas from transmission pipelines, you may use either a 

default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in 

natural gas or site specific engineering estimates based on best available data. 

(vii) GHG mole fraction in local distribution pipeline natural gas that passes through the 

facility for natural gas distribution facilities. You may use either a default 95 percent methane 

and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific 

engineering estimates based on best available data. 

(v) GHG mass emissions. Calculate GHG mass emissions in metric tons by converting 

the GHG volumetric emissions at standard conditions into mass emissions using Equation W-36 

of this section. 
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3

, * *10 Massi Es i  i (Eq. W-36) 

Where: 

Massi = GHGi (either CH4, CO2, or N2O) mass emissions in metric tons. 

Es,i = GHGi (either CH4, CO2, or N2O) volumetric emissions at standard conditions, 

in cubic feet. 

ρi = Density of GHGi. Use 0.0526 kg/ft3

 for CO2 and N2O, and 0.0192 kg/ft3 for 

CH4 at 60 °F and 14.7 psia. 

(w) EOR injection pump blowdown. Calculate CO2 pump blowdown emissions from each 

EOR injection pump system as follows: 

(1) Calculate the total injection pump system volume in cubic feet (including pipelines, 

manifolds and vessels) between isolation valves. 

(2) Retain logs of the number of blowdowns per calendar year. 

(3) Calculate the total annual CO2 emissions from each EOR injection pump system 

using Equation W-37 of this section: 

3 * * * *10 2 CO2 MassCO N Vv Rc GHG (Eq. W-37) 

Where: 

MassCO2 = Annual EOR injection pump system emissions in metric tons from 

blowdowns. 

N = Number of blowdowns for the EOR injection pump system in the calendar 

year. 

Vv = Total volume in cubic feet of EOR injection pump system chambers 

(including pipelines, manifolds and vessels) between isolation valves. 

Rc = Density of critical phase EOR injection gas in kg/ft3

. You may use an 

appropriate standard method published by a consensus-based standards 

organization if such a method exists or you may use an industry standard 

practice to determine density of super critical EOR injection gas. 

GHGCO2 = Mass fraction of CO2 in critical phase injection gas. 
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1 × 10−3 = Conversion factor from kilograms to metric tons. 

(x) EOR hydrocarbon liquids dissolved CO2. Calculate CO2 emissions downstream of the 

storage tank from dissolved CO2 in hydrocarbon liquids produced through EOR operations as 

follows: 

(1) Determine the amount of CO2 retained in hydrocarbon liquids after flashing in 

tankage at STP conditions. Annual samples of hydrocarbon liquids downstream of the storage 

tank must be taken according to methods set forth in § 98.234(b) to determine retention of CO2

in hydrocarbon liquids immediately downstream of the storage tank. Use the annual analysis for 

the calendar year. 

(2) Estimate emissions using Equation W-38 of this section. 

CO hl Vhl Mass S 2  * (Eq. W-38) 

Where: 

MassCO2 = Annual CO2 emissions from CO2 retained in hydrocarbon liquids produced 

through EOR operations beyond tankage, in metric tons. 

Shl = Amount of CO2 retained in hydrocarbon liquids downstream of the storage 

tank, in metric tons per barrel, under standard conditions. 

Vhl = Total volume of hydrocarbon liquids produced at the EOR operations in 

barrels in the calendar year. 

(y) [Reserved] 

(z) Onshore petroleum and natural gas production, onshore petroleum and natural gas 

gathering and boosting, and natural gas distribution combustion emissions. Calculate CO2, CH4, 

and N2O combustion-related emissions from stationary or portable equipment, except as 

specified in paragraphs (z)(3) and (4) of this section, as follows: 

(1) If a fuel combusted in the stationary or portable equipment is listed in Table C-1 of 

subpart C of this part, or is a blend containing one or more fuels listed in Table C-1, calculate 
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emissions according to paragraph (z)(1)(i) of this section. If the fuel combusted is natural gas and 

is of pipeline quality specification and has a minimum high heat value of 950 Btu per standard 

cubic foot, use the calculation method described in paragraph (z)(1)(i) of this section and you 

may use the emission factor provided for natural gas as listed in Table C-1. If the fuel is natural 

gas, and is not pipeline quality or has a high heat value of less than 950 Btu per standard cubic 

feet, calculate emissions according to paragraph (z)(2) of this section. If the fuel is field gas, 

process vent gas, or a blend containing field gas or process vent gas, calculate emissions 

according to paragraph (z)(2) of this section. 

(i) For fuels listed in Table C-1 or a blend containing one or more fuels listed in Table C1, calculate CO2, CH4, and N2O emissions according to any Tier listed in 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. 

(ii) 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 will be reported according to the 

requirements specified in § 98.236(z) and not according to the reporting requirements specified 

in subpart C of this part. 

(2) For fuel combustion units that combust field gas, process vent gas, a blend containing 

field gas or process vent gas, or natural gas that is not of pipeline quality or that has a high heat 

value of less than 950 Btu per standard cubic feet, calculate combustion emissions as follows: 

(i) You may use company records to determine the volume of fuel combusted in the unit 

during the reporting year. 
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(ii) If you have a continuous gas composition analyzer on fuel to the combustion unit, 

you must use these compositions for determining the concentration of gas hydrocarbon 

constituent in the flow of gas to the unit. If you do not have a continuous gas composition 

analyzer on gas to the combustion unit, you must use the appropriate gas compositions for each 

stream of hydrocarbons going to the combustion unit as specified in the applicable paragraph in 

(u)(2) of this section. 

(iii) Calculate GHG volumetric emissions at actual conditions using Equations W-39A 

and W-39B of this section: 



 

5

1

( * ) * * * jEa,CO Va YCO Va Yj Rj 2 2  (Eq. W-39A) 

  4 CH 4 Ea,CH  Va * 1  *Y (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 combustion unit in actual cubic feet, during the year. 

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

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, a default of 

0.995 can be used. 

Yj = Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, 

propane, butane, and pentanes plus) in gas sent to combustion unit. 

Rj = Number of carbon atoms in the gas hydrocarbon constituent j; 1 for methane, 

2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus, in gas sent 

to combustion unit. 

YCH4 = Mole fraction of methane constituent in gas sent to combustion unit. 
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(iv) Calculate GHG volumetric emissions at standard conditions using calculations in 

paragraph (t) of this section. 

(v) Calculate both combustion-related CH4 and CO2 mass emissions from volumetric 

CH4 and CO2 emissions using calculation in paragraph (v) of this section. 

(vi) Calculate N2O mass emissions using Equation W-40 of this section. 

MassN O   Fuel HHV EF 2      3 1 10 (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 × 10−3

 mmBtu/scf or a sitespecific higher heating value. For natural gas that is not of pipeline quality or 

that has a high heat value less than 950 Btu per standard cubic foot, use a 

site-specific higher heating value. 

EF = Use 1.0 × 10−4

 kg N2O/mmBtu. 

1 × 10−3

 = Conversion factor from kilograms to metric tons. 

(3) External fuel combustion sources with a rated heat capacity equal to or less than 5 

mmBtu/hr do not need to report combustion emissions or include these emissions for threshold 

determination in § 98.231(a). You must report the type and number of each external fuel 

combustion unit. 

(4) 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. 
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§ 98.234 Monitoring and QA/QC requirements. 

The GHG emissions data for petroleum and natural gas emissions sources must be quality 

assured as applicable as specified in this section. Offshore petroleum and natural gas production 

facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 250. 

(a) You must use any of the methods described in paragraphs (a)(1) through (5) of this 

section to conduct leak detection(s) of through-valve leakage from all source types listed 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 (6) of this section to conduct leak detection(s) of 

equipment leaks from component types listed in § 98.233(q)(1)(i) and (iii) that occur during a 

calendar year. To conduct leak detection(s) of equipment leaks from component types listed in § 

98.233(q)(1)(ii), you must use the method described in paragraph (a)(6) of this section.

(1) Optical gas imaging instrument as specified in 40 CFR 60.18. 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 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 is a leak unless screened with Method 21 (40 CFR part 60, 

appendix A-7) monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, 

you must operate the optical gas imaging instrument to image the source types required by this 

subpart in accordance with the instrument manufacturer’s operating parameters. Unless using 

Deleted: as follows 

Deleted: this 

Deleted: equipment leaks and 

Deleted: and (q)
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methods in paragraph (a)(2) of this section, an optical gas imaging instrument must be used for 

all source types that are inaccessible and cannot be monitored without elevating the monitoring 

personnel more than 2 meters above a support surface. 

(2) Method 21. Use the equipment leak detection methods in 40 CFR part 60, appendix 

A-7, Method 21. If using Method 21 monitoring, if an instrument reading of 10,000 ppm or 

greater is measured, a leak is detected. Inaccessible emissions sources, as defined in 40 CFR part 

60, are not exempt from this subpart. Owners or operators must use alternative leak detection 

devices as described in paragraph (a)(1) or (a)(2) of this section to monitor inaccessible 

equipment leaks or vented emissions. 

(3) Infrared laser beam illuminated instrument. Use an infrared laser beam illuminated 

instrument for equipment leak detection. Any emissions detected by the infrared laser beam 

illuminated instrument is a leak unless screened with Method 21 monitoring, in which case 

10,000 ppm or greater is designated a leak. In addition, you must operate the infrared laser beam 

illuminated instrument to detect the source types required by this subpart in accordance with the 

instrument manufacturer’s operating parameters. 

(4) [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 throughvalve 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 
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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 non-leakers with subsequent 

measurement required to calculate the rate if through-valve leakage is identified. Leaks are 

reported if a leak rate of 3.1 scf per hour or greater is measured.

(6) Optical gas imaging instrument as specified in 40 CFR 60.5397a. Use an optical gas 

imaging instrument for equipment leak detection in accordance with § 60.5397a(b) through (e) 

and (g) through (i) of this chapter and paragraphs (a)(6)(i) through (v) of this section. 

(i) For the purposes of this subpart, any fugitive emission from a fugitive emissions 

component, as defined in 40 CFR part 60, subpart OOOOa, that is detected by the optical gas 

imaging instrument is a leak. 

(ii) For the purposes of this subpart, the term “fugitive emissions component” in § 

60.5397a(b) through (i) of this chapter means “equipment leak component.” 

(iii) For the purpose of complying with § 98.233(q)(1)(iii), the phrases “the collection of 

fugitive emissions components at well sites and compressor stations” and “each collection of 

fugitive emissions components at a well site and each collection of fugitive emissions 

components at a compressor station” in § 60.5397a(b) and (g) of this chapter mean “the 

collection of equipment leak components for which you elect to comply with § 

98.233(q)(1)(iii).” 

(iv) The requirements in § 60.5397a(c)(4) and (5) of this chapter to include procedures 

and timelines for repair in your monitoring plan do not apply to equipment leak components for 

which you elect to comply with § 98.233(q)(1)(iii). 

(v) For the purpose of complying with § 98.233(q)(1)(iii), the reference in § 60.5397a(g) 

to “the initial survey” does not apply.
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(b) You must operate and calibrate all flow meters, composition analyzers and pressure 

gauges used to measure quantities reported in § 98.233 according to the procedures in § 98.3(i) 

and the procedures in paragraph (b) of this section. You may use an appropriate standard method 

published by a consensus-based standards organization if such a method exists or you may use 

an industry standard practice. Consensus-based standards organizations include, but are not 

limited to, the following: ASTM International, the American National Standards Institute 

(ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers 

(ASME), the American Petroleum Institute (API), and the North American Energy Standards 

Board (NAESB). 

(c) Use calibrated bags (also known as vent bags) only where the emissions are at nearatmospheric pressures and below the maximum temperature specified by the vent bag 

manufacturer such that the bag is safe to handle. The bag opening must be of sufficient size that 

the entire emission can be tightly encompassed for measurement till the bag is completely filled. 

(1) Hold the bag in place enclosing the emissions source to capture the entire emissions 

and record the time required for completely filling the bag. If the bag inflates in less than one 

second, assume one second inflation time. 

(2) Perform three measurements of the time required to fill the bag, report the emissions 

as the average of the three readings. 

(3) Estimate natural gas volumetric emissions at standard conditions using calculations in 

§ 98.233(t). 

(4) Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas 

emissions using the calculations in § 98.233(u) and (v). 
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(d) Use a high volume sampler to measure emissions within the capacity of the 

instrument. 

(1) A technician following manufacturer instructions shall conduct measurements, 

including equipment manufacturer operating procedures and measurement methods relevant to 

using a high volume sampler, including positioning the instrument for complete capture of the 

equipment leak without creating backpressure on the source. 

(2) If the high volume sampler, along with all attachments available from the 

manufacturer, is not able to capture all the emissions from the source then use anti-static wraps 

or other aids to capture all emissions without violating operating requirements as provided in the 

instrument manufacturer’s manual. 

(3) Estimate 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). 

(4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent 

CH4 by using calibrated gas samples and by following manufacturer’s instructions for 

calibration. 

(e) Peng Robinson Equation of State means the equation of state defined by Equation W41 of this section: 

2 2 V 2bV b

a

V b

RT

p

m m  m     

 (Eq. W-41) 

Where: 

p = Absolute pressure. 

R = Universal gas constant. 

T = Absolute temperature. 
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Vm = Molar volume. 

a = 

c

c

p

R T

2 2 0.45724

b = 

c

c

p

0.7780RT

α =   2

2 1 0.37464 1.54226 0.26992 1 































    Tc

T  

Where: 

ω = Acentric factor of the species. 

Tc = Critical temperature. 

Pc = Critical pressure. 

(f) Special reporting provisions for best available monitoring methods in reporting year 

2015—(1) Best available monitoring methods. From January 1, 2015 to March 31, 2015, for a 

facility subject to this subpart, you must use the calculation methodologies and equations in § 

98.233 “Calculating GHG Emissions”, but you may use the best available monitoring method for 

any parameter for which it is not reasonably feasible to acquire, install, and operate a required 

piece of monitoring equipment by January 1, 2015 as specified in paragraphs (f)(2) and (3) of 

this section. Starting no later than April 1, 2015, you must discontinue using best available 

methods and begin following all applicable monitoring and QA/QC requirements of this part, 

except as provided in paragraph (f)(4) of this section. 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. 
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(iv) Other company records. 

(2) Best available monitoring methods for well-related measurement data. You may use 

best available monitoring methods for well-related measurement data identified in paragraphs 

(f)(2)(i) and (ii) of this section that cannot reasonably be measured according to the monitoring 

and QA/QC requirements of this subpart. 

(i) If Calculation Method 1 for liquids unloading in § 98.233(f)(1) was used in calendar 

year 2014 and will be used again in calendar year 2015, the vented natural gas flow rate for any 

well in a unique tubing diameter group and pressure group combination that has not been 

previously measured. 

(ii) If using Equation W-10A of this subpart to determine natural gas emissions from 

completions and workovers for representative wells, the initial and average flowback rates (when 

using Calculation Method 1 in § 98.233(g)(1)(i)) or pressures upstream and downstream of the 

choke (when using Calculation Method 2 in § 98.233(g)(1)(ii)) for any well in a well type 

combination that has not been previously measured. 

(3) Best available monitoring methods for emissions measurement. You may use best 

available monitoring methods for sources listed in paragraphs (f)(3)(i) and (ii) of this section if 

the required measurement data cannot reasonably be obtained according to the monitoring and 

QA/QC requirements of this part. 

(i) Centrifugal compressor as found measurements of manifolded emissions from groups 

of centrifugal compressor sources according to § 98.233(o)(4) and (5), in onshore natural gas 

processing, onshore natural gas transmission compression, underground natural gas storage, 

LNG storage, and LNG import and export equipment as specified in § 98.232(d)(2), (e)(2), 

(f)(2), (g)(2), and (h)(2). 
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(ii) Reciprocating compressor as found measurements of manifolded emissions from 

groups of reciprocating compressor sources according to § 98.233(p)(4) and (5), in onshore 

natural gas processing, onshore natural gas transmission compression, underground natural gas 

storage, LNG storage, and LNG import and export equipment as specified in § 98.232(d)(1), 

(e)(1), (f)(1), (g)(1), and (h)(1). 

(4) Requests for extension of the use of best available monitoring methods beyond March 

31, 2015. You may submit a request to the Administrator to use one or more best available 

monitoring methods for sources listed in paragraphs (f)(2) and (3) of this section beyond March 

31, 2015. 

(i) Timing of request. The extension request must be submitted to EPA no later than 

January 31, 2015. 

(ii) Content of request. Requests must contain the following information: 

(A) A list of specific source types and parameters for which you are seeking use of best 

available monitoring methods. 

(B) For each specific source type for which you are requesting use of best available 

monitoring methods, a description of the reasons that the needed equipment could not be 

obtained and installed before April 1, 2015. 

(C) A description of the specific actions you will take to obtain and install the equipment 

as soon as reasonably feasible and the expected date by which the equipment will be installed 

and operating. 

(iii) Approval criteria. To obtain approval to use best available monitoring methods after 

March 31, 2015, you must submit a request demonstrating to the Administrator’s satisfaction that 

it is not reasonably feasible to acquire, install, and operate a required piece of monitoring 
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equipment by April 1, 2015. The use of best available methods under paragraph (f) of this 

section will not be approved beyond December 31, 2015. 

(g) Special reporting provisions for best available monitoring methods in reporting year 

2016—(1) Best available monitoring methods. From January 1, 2016, to December 31, 2016, 

you must use the calculation methodologies and equations in § 98.233 but you may use the best 

available monitoring method as described in paragraph (g)(2) of this section for any parameter 

specified in paragraphs (g)(3) through (6) of this section for which it is not reasonably feasible to 

acquire, install, and operate a required piece of monitoring equipment by January 1, 2016. 

Starting no later than January 1, 2017, you must discontinue using best available methods and 

begin following all applicable monitoring and QA/QC requirements of this part. For onshore 

petroleum and natural gas production, this paragraph (g)(1) only applies if emissions from well 

completions and workovers of oil wells with hydraulic fracturing cause your facility to exceed 

the reporting threshold in § 98.231(a)(1). 

(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 company records. 

(3) Best available monitoring methods for well-related measurement data for oil wells 

with hydraulic fracturing. You may use best available monitoring methods for any well-related 

measurement data that cannot reasonably be measured according to the monitoring and QA/QC 
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requirements of this subpart for venting during well completions and workovers of oil wells with 

hydraulic fracturing. 

(4) Best available monitoring methods for measurement data for onshore petroleum and 

natural gas gathering and boosting facilities. You may use best available monitoring methods 

for any leak detection and/or measurement data 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). 

(5) Best available monitoring methods for measurement data for natural gas 

transmission pipelines. You may use best available monitoring methods for any measurement 

data for natural gas transmission pipelines that cannot reasonably be obtained according to the 

monitoring and QA/QC requirements of this subpart for blowdown vent stacks. 

(6) Best available monitoring methods for specified activity data. You may use best 

available monitoring methods for activity data as listed in paragraphs (g)(6)(i) through (iii) of 

this section that cannot reasonably be obtained according to the monitoring and QA/QC 

requirements of this subpart for well completions and workovers of oil wells with hydraulic 

fracturing, onshore petroleum and natural gas gathering and boosting facilities, or natural gas 

transmission pipelines. 

(i) Cumulative hours of venting, days, or times of operation in § 98.233(e), (g), (o), (p), 

and (r). 

(ii) Number of blowdowns, completions, workovers, or other events in § 98.233(g) and 

(i). 

(iii) Cumulative volume produced, volume input or output, or volume of fuel used in 

paragraphs § 98.233(d), (e), (j), (n), and (z). 
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(h) For well venting for liquids unloading, if a monitoring period other than the full 

calendar year is used to determine the cumulative amount of time in hours of venting for each 

well (the term “Tp” in Equation W-7A and W-7B of § 98.233) or the number of unloading events 

per well (the term “Vp” in Equations W-8 and W-9 of § 98.233), then the monitoring period must 

begin before February 1 of the reporting year and must not end before December 1 of the 

reporting year. The end of one monitoring period must immediately precede the start of the next 

monitoring period for the next reporting year. All production days must be monitored and all 

venting accounted for. 

§ 98.235 Procedures for estimating missing data. 

Except as specified in § 98.233, whenever a value of a parameter is unavailable for a 

GHG emission calculation required by this subpart (including, but not limited to, if a measuring 

device malfunctions during unit operation or activity data are not collected), you must follow the 

procedures specified in paragraphs (a) through (i) of this section, as applicable. 

(a) For stationary and portable combustion sources that use the calculation methods of 

subpart C of this part, you must use the missing data procedures in subpart C of this part. 

(b) For each missing value of a parameter that should have been measured quarterly or 

more frequently using equipment including, but not limited to, a continuous flow meter, 

composition analyzer, thermocouple, or pressure gauge, you must substitute the arithmetic 

average of the quality-assured values of that parameter immediately preceding and immediately 

following the missing data incident. If the “after” value is not obtained by the end of the 

reporting year, you may use the “before” value for the missing data substitution. If, for a 

particular parameter, no quality-assured data are available prior to the missing data incident, you 
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must use the first quality-assured value obtained after the missing data period as the substitute 

data value. A value is quality-assured according to the procedures specified in § 98.234. 

(c) For each missing value of a parameter that should have been measured annually, you 

must repeat the estimation or measurement activity for those sources as soon as possible, 

including in the subsequent calendar year if missing data are not discovered until after December 

31 of the year in which data are collected, until valid data for reporting are obtained. Data 

developed and/or collected in a subsequent calendar year to substitute for missing data cannot be 

used for that subsequent year’s emissions estimation. Where missing data procedures are used 

for the previous year, at least 30 days must separate emissions estimation or measurements for 

the previous year and emissions estimation or measurements for the current year of data 

collection. 

(d) For each missing value of a parameter that should have been measured biannually 

(every two years), you must conduct the estimation or measurement activity for those sources as 

soon as possible in the subsequent calendar year if the estimation or measurement was not made 

in the appropriate year (first year of data collection and every two years thereafter), until valid 

data for reporting are obtained. Data developed and/or collected in a subsequent calendar year to 

substitute for missing data cannot be used to alternate or postpone subsequent biannual emissions 

estimations or measurements. 

(e) For the first 6 months of required data collection, facilities that become newly subject 

to this subpart W may use best engineering estimates for any data that cannot reasonably be 

measured or obtained according to the requirements of this subpart. 

(f) For the first 6 months of required data collection, facilities that are currently subject to 

this subpart W and that acquire new sources from another facility that were not previously 
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subject to this subpart W may use best engineering estimates for any data related to those newly 

acquired sources that cannot reasonably be measured or obtained according to the requirements 

of this subpart. 

(g) Unless addressed in another paragraph of this section, for each missing value of any 

activity data, you must substitute data value(s) using the best available estimate(s) of the 

parameter(s), based on all applicable and available process or other data (including, but not 

limited to, processing rates, operating hours). 

(h) You must report information for all measured and substitute values of a parameter, 

and the procedures used to substitute an unavailable value of a parameter per the requirements in 

§ 98.236(bb). 

(i) You must follow recordkeeping requirements listed in § 98.237(f). 

§ 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 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) The annual report must include the information specified in paragraphs (a)(1) through 

(10) of this section for each applicable industry segment. The annual report must also include 

annual emissions totals, in metric tons of each GHG, for each applicable industry segment listed 
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in paragraphs (a)(1) through (10), and each applicable emission source listed in paragraphs (b) 

through (z) of this section. 

(1) Onshore petroleum and natural gas production. For the equipment/activities specified 

in paragraphs (a)(1)(i) through (xvii) 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. 

(ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph 

(c) of this section. 

(iii) Acid gas removal units. Report the information specified in paragraph (d) of this 

section. 

(iv) Dehydrators. Report the information specified in paragraph (e) of this section. 

(v) Liquids unloading. Report the information specified in paragraph (f) of this section. 

(vi) Completions and workovers with hydraulic fracturing. Report the information 

specified in paragraph (g) of this section. 

(vii) Completions and workovers without hydraulic fracturing. Report the information 

specified in paragraph (h) of this section. 

(viii) Onshore production storage tanks. Report the information specified in paragraph (j) 

of this section. 

(ix) Well testing. Report the information specified in paragraph (l) of this section. 

(x) Associated natural gas. Report the information specified in paragraph (m) of this 

section. 

(xi) Flare stacks. Report the information specified in paragraph (n) of this section. 
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(xii) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section. 

(xiii) Reciprocating compressors. Report the information specified in paragraph (p) of 

this section. 

(xiv) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(xv) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section. 

(xvi) EOR injection pumps. Report the information specified in paragraph (w) of this 

section. 

(xvii) EOR hydrocarbon liquids. Report the information specified in paragraph (x) of this 

section. 

(xviii) Combustion equipment. Report the information specified in paragraph (z) of this 

section. 

(2) Offshore petroleum and natural gas production. Report the information specified in 

paragraph (s) of this section. 

(3) Onshore natural gas processing. For the equipment/activities specified in paragraphs 

(a)(3)(i) through (vii) 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. 

(ii) Dehydrators. Report the information specified in paragraph (e) of this section. 
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(iii) Blowdown vent stacks. Report the information specified in paragraph (i) of this 

section. 

(iv) Flare stacks. Report the information specified in paragraph (n) of this section. 

(v) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section. 

(vi) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section. 

(vii) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(4) Onshore natural gas transmission compression. For the equipment/activities specified 

in paragraphs (a)(4)(i) through (vii) 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. 

(ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this 

section. 

(iii) Transmission storage tanks. Report the information specified in paragraph (k) of this 

section. 

(iv) Flare stacks. Report the information specified in paragraph (n) of this section. 

(v) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section. 

(vi) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section. 
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(vii) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(5) Underground natural gas storage. For the equipment/activities specified in 

paragraphs (a)(5)(i) through (vi) 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. 

(ii) Flare stacks. Report the information specified in paragraph (n) of this section. 

(iii) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section. 

(iv) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section. 

(v) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(vi) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section. 

(6) LNG storage. For the equipment/activities specified in paragraphs (a)(6)(i) through 

(v) of this section, report the information specified in the applicable paragraphs of this section. 

(i) Flare stacks. Report the information specified in paragraph (n) of this section. 

(ii) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section. 

(iii) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section. 
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(iv) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(v) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section. 

(7) LNG import and export equipment. For the equipment/activities specified in 

paragraphs (a)(7)(i) through (vi) of this section, report the information specified in the applicable 

paragraphs of this section. 

(i) Blowdown vent stacks. Report the information specified in paragraph (i) of this 

section. 

(ii) Flare stacks. Report the information specified in paragraph (n) of this section. 

(iii) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section. 

(iv) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section. 

(v) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(vi) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section. 

(8) Natural gas distribution. For the equipment/activities specified in paragraphs (a)(8)(i) 

through (iii) of this section, report the information specified in the applicable paragraphs of this 

section. 

(i) Combustion equipment. Report the information specified in paragraph (z) of this 

section. 
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(ii) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(iii) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section. 

(9) Onshore petroleum and natural gas gathering and boosting. For the 

equipment/activities specified in paragraphs (a)(9)(i) through (xi) 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. 

(ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph 

(c) of this section. 

(iii) Acid gas removal units. Report the information specified in paragraph (d) of this 

section. 

(iv) Dehydrators. Report the information specified in paragraph (e) of this section. 

(v) Blowdown vent stacks. Report the information specified in paragraph (i) of this 

section. 

(vi) Storage tanks. Report the information specified in paragraph (j) of this section. 

(vii) Flare stacks. Report the information specified in paragraph (n) of this section. 

(viii) Centrifugal compressors. Report the information specified in paragraph (o) of this 

section. 

(ix) Reciprocating compressors. Report the information specified in paragraph (p) of this 

section. 
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(x) Equipment leak surveys. Report the information specified in paragraph (q) of this 

section. 

(xi) Equipment leaks by population count. Report the information specified in paragraph 

(r) of this section. 

(xii) 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 paragraph (i) 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 (b)(4) of this section. 

(1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) and 

(ii) of this section. 

(i) The total number of devices of each type, determined according to § 98.233(a)(1) and 

(2). 

(ii) If the reported value in paragraph (b)(1)(i) of this section is an estimated value 

determined according to § 98.233(a)(2), then you must report the information specified in 

paragraphs (b)(1)(ii)(A) through (C) of this section. 

(A) The number of devices of each type reported in paragraph (b)(1)(i) of this section that 

are counted. 
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(B) The number of devices of each type reported in paragraph (b)(1)(i) 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, the estimated average number of hours in the 

calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) of this 

section were operating in the calendar year (“Tt” in Equation W-1 of this subpart). 

(3) Annual CO2 emissions, in metric tons CO2, for the natural gas pneumatic devices 

combined, calculated using Equation W-1 of this subpart and § 98.233(a)(4), and reported in 

paragraph (b)(1)(i) of this section. 

(4) Annual CH4 emissions, in metric tons CH4, for the natural gas pneumatic devices 

combined, calculated using Equation W-1 of this subpart and § 98.233(a)(4), and reported in 

paragraph (b)(1)(i) of this section. 

(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 (4) of this 

section. 

(1) Count of natural gas driven pneumatic pumps. 

(2) Average estimated number of hours in the calendar year the pumps were operational 

(“T” in Equation W-2 of this subpart). 

(3) Annual CO2 emissions, in metric tons CO2, for all natural gas driven pneumatic 

pumps combined, calculated according to § 98.233(c)(1) and (2). 
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(4) Annual CH4 emissions, in metric tons CH4, for all natural gas driven pneumatic 

pumps combined, calculated according to § 98.233(c)(1) and (2). 

(d) Acid gas removal units. You must indicate whether your facility has any acid gas 

removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery 

plant. If your facility contains any acid gas removal units that vent directly to the atmosphere, to 

a flare or engine, or to a sulfur recovery plant, then you must report the information specified in 

paragraphs (d)(1) and (2) of this section. 

(1) You must report the information specified in paragraphs (d)(1)(i) through (vi) of this 

section for each acid gas removal unit. 

(i) A unique name or ID number for the acid gas removal unit. For the onshore petroleum 

and natural gas production and the onshore petroleum and natural gas gathering and boosting 

industry segments, a different name or ID may be used for a single acid gas removal unit for 

each location it operates at in a given year. 

(ii) Total feed rate entering the acid gas removal unit, using a meter or engineering 

estimate based on process knowledge or best available data, in million cubic feet per year. 

(iii) The calculation method used to calculate CO2 emissions from the acid gas removal 

unit, as specified in § 98.233(d). 

(iv) Whether any CO2 emissions from the acid gas removal unit are recovered and 

transferred outside the facility, as specified in § 98.233(d)(11). If any CO2 emissions from the 

acid gas removal unit were recovered and transferred outside the facility, then you must report 

the annual quantity of CO2, in metric tons CO2, that was recovered and transferred outside the 

facility under subpart PP of this part. 
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(v) Annual CO2 emissions, in metric tons CO2, from the acid gas removal unit, calculated 

using any one of the calculation methods specified in § 98.233(d) and as specified in § 

98.233(d)(10) and (11). 

(vi) Sub-basin ID that best represents the wells supplying gas to the unit (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 unit (for the onshore petroleum and natural gas 

gathering and boosting industry segment only). 

(2) You must report information specified in paragraphs (d)(2)(i) through (iii) of this 

section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, for 

each acid gas removal unit. 

(i) If you used Calculation Method 1 or Calculation Method 2 as specified in § 98.233(d) 

to calculate CO2 emissions from the acid gas removal unit, then you must report the information 

specified in paragraphs (d)(2)(i)(A) and (B) of this section. 

(A) Annual average volumetric fraction of CO2 in the vent gas exiting the acid gas 

removal unit. 

(B) Annual volume of gas vented from the acid gas removal unit, in cubic feet. 

(ii) If you used Calculation Method 3 as specified in § 98.233(d) to calculate CO2

emissions from the acid gas removal unit, then you must report the information specified in 

paragraphs (d)(2)(ii)(A) through (D) of this section. 

(A) Indicate which equation was used (Equation W-4A or W-4B). 

(B) Annual average volumetric fraction of CO2 in the natural gas flowing out of the acid 

gas removal unit, as specified in Equation W-4A or Equation W-4B of this subpart. 
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(C) Annual average volumetric fraction of CO2 content in natural gas flowing into the 

acid gas removal unit, as specified in Equation W-4A or Equation W-4B of this subpart. 

(D) The natural gas flow rate used, as specified in Equation W-4A of this subpart, 

reported as either total annual volume of natural gas flow into the acid gas removal unit in cubic 

feet at actual conditions; or total annual volume of natural gas flow out of the acid gas removal 

unit, as specified in Equation W-4B of this subpart, in cubic feet at actual conditions. 

(iii) If you used Calculation Method 4 as specified in § 98.233(d) to calculate CO2

emissions from the acid gas removal unit, then you must report the information specified in 

paragraphs (d)(2)(iii)(A) through (L) of this section, as applicable to the simulation software 

package used. 

(A) The name of the simulation software package used. 

(B) Natural gas feed temperature, in degrees Fahrenheit. 

(C) Natural gas feed pressure, in pounds per square inch. 

(D) Natural gas flow rate, in standard cubic feet per minute. 

(E) Acid gas content of the feed natural gas, in mole percent. 

(F) Acid gas content of the outlet natural gas, in mole percent. 

(G) Unit operating hours, excluding downtime for maintenance or standby, in hours per 

year. 

(H) Exit temperature of the natural gas, in degrees Fahrenheit. 

(I) Solvent pressure, in pounds per square inch. 

(J) Solvent temperature, in degrees Fahrenheit. 

(K) Solvent circulation rate, in gallons per minute. 

(L) Solvent weight, in pounds per gallon. 
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(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, glycol dehydrators with an annual average 

daily natural gas throughput less than 0.4 million standard cubic feet per day, and dehydrators 

that use desiccant. 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 (xviii) of this section 

for the dehydrator. 

(i) A unique name or ID number for the dehydrator. For the onshore petroleum and 

natural gas production and the onshore petroleum and natural gas gathering and boosting 

industry segments, a different name or ID may be used for a single dehydrator for each location 

it operates at in a given year. 

(ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, 

determined by engineering estimate based on best available data. 

(iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet. 

(iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic 

feet. 

(v) Dehydrator absorbent circulation pump type (e.g., natural gas pneumatic, air 

pneumatic, or electric). 

(vi) Dehydrator absorbent circulation rate, in gallons per minute. 
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(vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene glycol (DEG), or 

ethylene glycol (EG)). 

(viii) Whether stripper gas is used in dehydrator. 

(ix) Whether a flash tank separator is used in dehydrator. 

(x) Total time the dehydrator is operating, in hours. 

(xi) Temperature of the wet natural gas, in degrees Fahrenheit. 

(xii) Pressure of the wet natural gas, in pounds per square inch gauge. 

(xiii) Mole fraction of CH4 in wet natural gas. 

(xiv) Mole fraction of CO2 in wet natural gas. 

(xv) Whether any dehydrator emissions are vented to a vapor recovery device. 

(xvi) Whether any dehydrator emissions are vented to a flare or regenerator firebox/fire 

tubes. If any emissions are vented to a flare or regenerator firebox/fire tubes, report the 

information specified in paragraphs (e)(1)(xvi)(A) through (C) of this section for these emissions 

from the dehydrator. 

(A) Annual CO2 emissions, in metric tons CO2, for the dehydrator, calculated according 

to § 98.233(e)(6). 

(B) Annual CH4 emissions, in metric tons CH4, for the dehydrator, calculated according 

to § 98.233(e)(6). 

(C) Annual N2O emissions, in metric tons N2O, for the dehydrator, calculated according 

to § 98.233(e)(6). 

(xvii) Whether any dehydrator emissions are vented to the atmosphere without being 

routed to a flare or regenerator firebox/fire tubes. If any emissions are not routed to a flare or 
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regenerator firebox/fire tubes, then you must report the information specified in paragraphs 

(e)(1)(xvii)(A) and (B) of this section for those emissions from the dehydrator. 

(A) Annual CO2 emissions, in metric tons CO2, for the dehydrator when not venting to a 

flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1), and, if applicable, 

(e)(5). 

(B) Annual CH4 emissions, in metric tons CH4, for the dehydrator when not venting to a 

flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(1) and, if applicable, 

(e)(5). 

(xviii) 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). 

(2) For glycol dehydrators with an annual average daily natural gas throughput less than 

0.4 million standard cubic feet per day (as specified in § 98.233(e)(2)), you must report the 

information specified in paragraphs (e)(2)(i) through (v) of this section for the entire facility. 

(i) The total number of dehydrators at the facility. 

(ii) Whether any dehydrator emissions were vented to a vapor recovery device. If any 

dehydrator emissions were vented to a vapor recovery device, then you must report the total 

number of dehydrators at the facility that vented to a vapor recovery device. 

(iii) Whether any dehydrator emissions were vented to a control device other than a vapor 

recovery device or a flare or regenerator firebox/fire tubes. If any dehydrator emissions were 

vented to a control device(s) other than a vapor recovery device or a flare or regenerator 
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firebox/fire tubes, then you must specify the type of control device(s) and the total number of 

dehydrators at the facility that were vented to each type of control device. 

(iv) Whether any dehydrator emissions were vented to a flare or regenerator firebox/fire 

tubes. If any dehydrator emissions were vented to a flare or regenerator firebox/fire tubes, then 

you must report the information specified in paragraphs (e)(2)(iv)(A) through (D) of this section. 

(A) The total number of dehydrators venting to a flare or regenerator firebox/fire tubes. 

(B) 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)(6). 

(C) 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)(6). 

(D) 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)(6). 

(v) For dehydrator emissions that were not vented 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 vented to a flare or regenerator 

firebox/fire tubes, calculated according to § 98.233(e)(2), (e)(4), and, if applicable, (e)(5), 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 vented to a flare or regenerator 

firebox/fire tubes, calculated according to § 98.233(e)(2), (e)(4), and, if applicable, (e)(5), where 

emissions are added together for all such dehydrators. 
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(3) For dehydrators that use desiccant (as specified in § 98.233(e)(3)), you must report 

the information specified in paragraphs (e)(3)(i) through (iii) of this section for the entire facility. 

(i) The same information specified in paragraphs (e)(2)(i) through (iv) of this section for 

glycol dehydrators, and report the information under this paragraph for dehydrators that use 

desiccant. 

(ii) Annual CO2 emissions, in metric tons CO2, for emissions from all desiccant 

dehydrators reported under paragraph (e)(3)(i) of this section that are not venting to a flare or 

regenerator firebox/fire tubes, calculated according to § 98.233(e)(3), (e)(4), and, if applicable, 

(e)(5), and summing for all such dehydrators. 

(iii) Annual CH4 emissions, in metric tons CH4, for emissions from all desiccant 

dehydrators reported in paragraph (e)(3)(i) of this section that are not venting to a flare or 

regenerator firebox/fire tubes, calculated according to § 98.233(e)(3), (e)(4), and, if applicable, 

(e)(5), and summing for all such dehydrators. 

(f) Liquids unloading. You must indicate whether well venting for liquids unloading 

occurs at your facility, and if so, which methods (as specified in § 98.233(f)) were used to 

calculate emissions. If your facility performs well venting for liquids unloading and uses 

Calculation Method 1, then you must report the information specified in paragraph (f)(1) of this 

section. If the facility performs liquids unloading and uses Calculation Method 2 or 3, then you 

must report the information specified in paragraph (f)(2) of this section. 

(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 with plunger lifts and wells without plunger lifts. 
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(i) Sub-basin ID. 

(ii) Well tubing diameter and pressure group ID and a list of the well ID numbers 

associated with each sub-basin and well tubing diameter and pressure group ID. 

(iii) Plunger lift indicator. 

(iv) Count of wells vented to the atmosphere for the sub-basin/well tubing diameter and 

pressure group. 

(v) Percentage of wells for which the monitoring period used to determine the cumulative 

amount of time venting was not the full calendar year. 

(vi) Cumulative amount of time wells were vented (sum of “Tp” from Equation W-7A or 

W-7B of this subpart), in hours. 

(vii) Cumulative number of unloadings vented to the atmosphere for each well, 

aggregated across all wells in the sub-basin/well tubing diameter and pressure group. 

(viii) Annual natural gas emissions, in standard cubic feet, from well venting for liquids 

unloading, calculated according to § 98.233(f)(1). 

(ix) Annual CO2 emissions, in metric tons CO2, from well venting for liquids unloading, 

calculated according to § 98.233(f)(1) and (4). 

(x) Annual CH4 emissions, in metric tons CH4, from well venting for liquids unloading, 

calculated according to § 98.233(f)(1) and (4). 

(xi) For each well tubing diameter group and pressure group combination, you must 

report the information specified in paragraphs (f)(1)(xi)(A) through (E) of this section for each 

individual well not using a plunger lift that was tested during the year. 

(A) Well ID number of tested well. 

(B) Casing pressure, in pounds per square inch absolute. 
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(C) Internal casing diameter, in inches. 

(D) Measured depth of the well, in feet. 

(E) Average flow rate of the well venting over the duration of the liquids unloading, in 

standard cubic feet per hour. 

(xii) For each well tubing diameter group and pressure group combination, you must 

report the information specified in paragraphs (f)(1)(xii)(A) through (E) of this section for each 

individual well using a plunger lift that was tested during the year. 

(A) Well ID number. 

(B) The tubing pressure, in pounds per square inch absolute. 

(C) The internal tubing diameter, in inches. 

(D) Measured depth of the well, in feet. 

(E) Average flow rate of the well venting over the duration of the liquids unloading, in 

standard cubic feet per hour. 

(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 (f)(2)(i) through (x) of this section. Report information separately for 

each calculation method. 

(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin. 

(ii) Calculation method. 

(iii) Plunger lift indicator. 

(iv) Number of wells vented to the atmosphere. 

(v) Cumulative number of unloadings vented to the atmosphere for each well, aggregated 

across all wells. 
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(vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids 

unloading, calculated according to § 98.233(f)(2) or (3), as applicable. 

(vii) Annual CO2 emissions, in metric tons CO2, from well venting for liquids unloading, 

calculated according to § 98.233(f)(2) or (3), as applicable, and § 98.233(f)(4). 

(viii) Annual CH4 emissions, in metric tons CH4, from well venting for liquids unloading, 

calculated according to § 98.233(f)(2) or (3), as applicable, and § 98.233(f)(4). 

(ix) For wells without plunger lifts, the average internal casing diameter, in inches. 

(x) For wells with plunger lifts, the average internal tubing diameter, in inches. 

(g) Completions and workovers with hydraulic fracturing. You must indicate whether 

your facility had any well completions or workovers with hydraulic fracturing during the 

calendar year. If your facility had well completions or workovers with hydraulic fracturing 

during the calendar year, then you must report information specified in paragraphs (g)(1) through 

(10) of this section, for each sub-basin and well type combination. Report information separately 

for completions and workovers. 

(1) Sub-basin ID and a list of the well ID numbers associated with each sub-basin that 

had completions or workovers with hydraulic fracturing during the calendar year. 

(2) Well type combination (horizontal or vertical, gas well or oil well). 

(3) Number of completions or workovers in the sub-basin and well type combination 

category. 

(4) Calculation method used. 

(5) If you used Equation W-10A of § 98.233 to calculate annual volumetric total gas 

emissions, then you must report the information specified in paragraphs (g)(5)(i) through (iii) of 

this section. 
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(i) Cumulative gas flowback time, in hours, from when gas is first detected until 

sufficient quantities are present to enable separation, and the cumulative flowback time, in hours, 

after sufficient quantities of gas are present to enable separation (sum of “Tp,i” and sum of “Tp,s” 

values used in Equation W-10A of § 98.233). You may delay the reporting of this data element if 

you indicate in the annual report that wildcat wells and/or delineation wells are the only wells 

included in this number. If you elect to delay reporting of this data element, you must report by 

the date specified in § 98.236(cc) the total number of hours of flowback from all wells during 

completions or workovers and the well ID number(s) for the well(s) included in the number. 

(ii) For the measured well(s), the flowback rate, in standard cubic feet per hour (average 

of “FRs,p” values used in Equation W-12A of § 98.233), and the well ID numbers of the wells for 

which it is measured. You may delay the reporting of this data element if you indicate in the 

annual report that wildcat wells and/or delineation wells are the only wells that can be used for 

the measurement. If you elect to delay reporting of this data element, you must report by the date 

specified in § 98.236(cc) the measured flowback rate during well completion or workover and 

the well ID number(s) for the well(s) included in the measurement. 

(iii) If you used Equation W-12C of § 98.233 to calculate the average gas production rate 

for an oil well, then you must report the information specified in paragraphs (g)(5)(iii)(A) and 

(B) of this section. 

(A) Gas to oil ratio for the well in standard cubic feet of gas per barrel of oil (“GORp” in 

Equation W-12C of § 98.233). You may delay the reporting of this data element if you indicate 

in the annual report that wildcat wells and/or delineation wells are the only wells that can be used 

for the measurement. If you elect to delay reporting of this data element, you must report by the 
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date specified in § 98.236(cc) the gas to oil ratio for the well and the well ID number for the 

well. 

(B) Volume of oil produced during the first 30 days of production after completions of 

each newly drilled well or well workover using hydraulic fracturing, in barrels (“Vp” in Equation 

W-12C of § 98.233). You may delay the reporting of this data element if you indicate in the 

annual report that wildcat wells and/or delineation wells are the only wells that can be used for 

the measurement. 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 during the first 30 days of production after 

well completion or workover and the well ID number for the well. 

(6) If you used Equation W-10B of § 98.233 to calculate annual volumetric total gas 

emissions, then you must report the information specified in paragraphs (g)(6)(i) through (iii) of 

this section. 

(i) Vented natural gas volume, in standard cubic feet, for each well in the sub-basin 

(“FVs,p” in Equation W-10B of § 98.233). 

(ii) Flow rate at the beginning of the period of time when sufficient quantities of gas are 

present to enable separation, in standard cubic feet per hour, for each well in the sub-basin 

(“FRp,i” in Equation W-10B of § 98.233). 

(iii) The well ID number for which vented natural gas volume was measured. 

(7) Annual gas emissions, in standard cubic feet (“Es,n” in Equation W-10A or W-10B). 

(8) Annual CO2 emissions, in metric tons CO2. 

(9) Annual CH4 emissions, in metric tons CH4. 

(10) If the well emissions were vented to a flare, then you must report the total N2O 

emissions, in metric tons N2O. 
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(h) Completions and workovers without hydraulic fracturing. You must indicate whether 

the facility had any gas well completions without hydraulic fracturing or any gas well workovers 

without hydraulic fracturing, and if the activities occurred with or without flaring. If the facility 

had gas well completions or workovers without hydraulic fracturing, then you must report the 

information specified in paragraphs (h)(1) through (4) of this section, as applicable. 

(1) For each sub-basin with gas well completions without hydraulic fracturing and 

without flaring, report the information specified in paragraphs (h)(1)(i) through (vi) of this 

section. 

(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin for gas 

well completions without hydraulic fracturing and without flaring. 

(ii) Number of well completions that vented gas directly to the atmosphere without 

flaring. 

(iii) Total number of hours that gas vented directly to the atmosphere during venting for 

all completions in the sub-basin category (the sum of all “Tp” for completions that vented to the 

atmosphere as used in Equation W-13B). 

(iv) Average daily gas production rate for all completions without hydraulic fracturing in 

the sub-basin without flaring, in standard cubic feet per hour (average of all “Vp” used in 

Equation W-13B 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 that can be used 

for the measurement. If you elect to delay reporting of this data element, you must report by the 

date specified in § 98.236(cc) the measured average daily gas production rate for all wells during 

completions and the well ID number(s) for the well(s) included in the measurement. 
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(v) Annual CO2 emissions, in metric tons CO2, that resulted from completions venting 

gas directly to the atmosphere (“Es,p” from Equation W-13B for completions that vented directly 

to the atmosphere, converted to mass emissions according to § 98.233(h)(1)). 

(vi) Annual CH4 emissions, in metric tons CH4, that resulted from completions venting 

gas directly to the atmosphere (“Es,p” from Equation W-13B for completions that vented directly 

to the atmosphere, converted to mass emissions according to § 98.233(h)(1)). 

(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 (vii) of this section. 

(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin for gas 

well completions without hydraulic fracturing and with flaring. 

(ii) Number of well completions that flared gas. 

(iii) Total number of hours that gas vented to a flare during venting for all completions in 

the sub-basin category (the sum of all “Tp” for completions that vented to a flare from Equation 

W-13B). 

(iv) Average daily gas production rate for all completions without hydraulic fracturing in 

the sub-basin with flaring, in standard cubic feet per hour (the average of all “Vp” from Equation 

W-13B 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 that can be used for the 

measurement. If you elect to delay reporting of this data element, you must report by the date 

specified in § 98.236(cc) the measured average daily gas production rate for all wells during 

completions and the well ID number(s) for the well(s) included in the measurement. 

(v) Annual CO2 emissions, in metric tons CO2, that resulted from completions that flared 

gas calculated according to § 98.233(h)(2). 
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(vi) Annual CH4 emissions, in metric tons CH4, that resulted from completions that flared 

gas calculated according to § 98.233(h)(2). 

(vii) Annual N2O emissions, in metric tons N2O, that resulted from completions that 

flared gas calculated according to § 98.233(h)(2). 

(3) For each sub-basin with gas well workovers without hydraulic fracturing and without 

flaring, report the information specified in paragraphs (h)(3)(i) through (iv) of this section. 

(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin for gas 

well workovers without hydraulic fracturing and without flaring. 

(ii) Number of workovers that vented gas to the atmosphere without flaring. 

(iii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from workovers 

venting gas directly to the atmosphere (“Es,wo” in Equation W-13A for workovers that vented 

directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)). 

(iv) Annual CH4 emissions, in metric tons CH4 per year, that resulted from workovers 

venting gas directly to the atmosphere (“Es,wo” in Equation W-13A for workovers that vented 

directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)). 

(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 (v) of this section. 

(i) Sub-basin ID and a list of well ID numbers associated with each sub-basin for gas well 

workovers without hydraulic fracturing and with flaring. 

(ii) Number of workovers that flared gas. 

(iii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from workovers 

that flared gas calculated as specified in § 98.233(h)(2). 
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(iv) Annual CH4 emissions, in metric tons CH4 per year, that resulted from workovers 

that flared gas, calculated as specified in § 98.233(h)(2). 

(v) 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) Blowdown vent stacks. You must indicate whether your facility has blowdown vent 

stacks. If your facility has blowdown vent stacks, then you must report whether emissions were 

calculated by equipment or event type or by using flow meters or a combination of both. If you 

calculated emissions by equipment or event type for any blowdown vent stacks, then you must 

report the information specified in paragraph (i)(1) of this section considering, in aggregate, all 

blowdown vent stacks for which emissions were calculated by equipment or event type. If you 

calculated emissions using flow meters for any blowdown vent stacks, then you must report the 

information specified in paragraph (i)(2) of this section considering, in aggregate, all blowdown 

vent stacks for which emissions were calculated using flow meters. For the onshore natural gas 

transmission pipeline segment, you must also report the information in paragraph (i)(3) of this 

section. 

(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) for industry segments other than the 

onshore natural gas transmission pipeline segment, 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 
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emissions from blowdown vent stacks by the eight categories listed in § 98.233(i)(2) 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. 

(i) Total number of blowdowns in the calendar year for the equipment or event type (the 

sum of equation variable “N” from Equation W-14A or Equation W-14B of this subpart, for all 

unique physical volumes for the equipment or event type). 

(ii) Annual CO2 emissions for the equipment or event type, in metric tons CO2, calculated 

according to § 98.233(i)(2)(iii). 

(iii) Annual CH4 emissions for the equipment or event type, in metric tons CH4, 

calculated according to § 98.233(i)(2)(iii). 

(2) Report by flow meter. If you elect to calculate emissions from blowdown vent stacks 

by using a flow meter according to § 98.233(i)(3), then you must report the information specified 

in paragraphs (i)(2)(i) and (ii) of this section for the facility. 

(i) Annual CO2 emissions from all blowdown vent stacks at the facility for which 

emissions were calculated using flow meters, in metric tons CO2 (the sum of all CO2 mass 

emission values calculated according to § 98.233(i)(3), for all flow meters). 
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(ii) Annual CH4 emissions from all blowdown vent stacks at the facility for which 

emissions were calculated using flow meters, in metric tons CH4, (the sum of all CH4 mass 

emission values calculated according to § 98.233(i)(3), for all flow meters). 

(3) Onshore natural gas transmission pipeline segment. Report the information in 

paragraphs (i)(3)(i) through (iii) of this section for each state. 

(i) Annual CO2 emissions in metric tons CO2. 

(ii) Annual CH4 emissions in metric tons CH4. 

(iii) Annual number of blowdown events. 

(j) Onshore production and onshore petroleum and natural gas gathering and boosting 

storage tanks. You must indicate whether your facility sends produced oil to atmospheric tanks. 

If your facility sends produced oil 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 you 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 paragraphs 

(j)(1)(ix) and (xi) of this section. 
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(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 oil volume from gas-liquid separators and direct from wells or nonseparator 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 oil 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 oil 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 oil API gravity, in degrees. 

(vii) The minimum and maximum concentration (mole fraction) of CO2 in flash gas from 

onshore production and onshore natural gas gathering and boosting storage tanks. 

(viii) The minimum and maximum concentration (mole fraction) of CH4 in flash gas from 

onshore production and onshore natural gas gathering and boosting storage tanks. 
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(ix) The number of wells sending oil to gas-liquid separators or directly to atmospheric 

tanks. 

(x) The number of atmospheric tanks. 

(xi) An estimate of the number of atmospheric tanks, not on well-pads, receiving your oil. 

(xii) If any emissions from the atmospheric tanks at your facility were controlled with 

vapor recovery systems, then you must report the information specified in paragraphs 

(j)(1)(xii)(A) through (E) of this section. 

(A) The number of atmospheric tanks that control emissions with vapor recovery 

systems. 

(B) Total CO2 mass, in metric tons CO2, that was recovered during the calendar year 

using a vapor recovery system. 

(C) Total CH4 mass, in metric tons CH4, that was recovered during the calendar year 

using a vapor recovery system. 

(D) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks equipped with 

vapor recovery systems. 

(E) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks equipped with 

vapor recovery systems. 

(xiii) If any atmospheric tanks at your facility vented gas directly to the atmosphere 

without using a vapor recovery system or without flaring, then you must report the information 

specified in paragraphs (j)(1)(xiii)(A) through (C) of this section. 

(A) The number of atmospheric tanks that vented gas directly to the atmosphere without 

using a vapor recovery system or without flaring. 
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(B) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to 

the atmosphere. 

(C) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to 

the atmosphere. 

(xiv) If you controlled emissions from any atmospheric tanks at your facility with one or 

more flares, then you must report the information specified in paragraphs (j)(1)(xiv)(A) through 

(D) of this section. 

(A) The number of atmospheric tanks that controlled emissions with flares. 

(B) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled 

emissions with one or more flares. 

(C) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled 

emissions with one or more flares. 

(D) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled 

emissions with one or more 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 (F) of this section, 

at the basin level, for atmospheric tanks where emissions were calculated using Calculation 

Method 3 of § 98.233(j). Onshore gathering and boosting facilities do not report the information 

specified in paragraphs (j)(2)(i)(E) and (F) of this section. 

(A) The total annual oil/condensate 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 
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sub-basin with oil/condensate production less than 10 barrels per day and that send 

oil/condensate 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 oil/condensate 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 oil/condensate 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 oil/condensate 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 number of wells with gas-liquid separators (“Count” from Equation W-15 of this 

subpart) in the basin. 

(F) The number of wells without gas-liquid separators (“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 did not control emissions with flares. 

(A) Sub-basin ID (for onshore production) or county name (for onshore petroleum and 

natural gas gathering and boosting). 
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(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. 

(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 for vapor recovery, 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 for vapor recovery, if applicable. 

(iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (E) 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 controlled emissions with flares. 

(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. 

(C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled 

emissions with flares. 
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(D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled 

emissions with flares. 

(E) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled 

emissions with flares. 

(3) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j), and any 

gas-liquid separator liquid dump values did not close properly during the calendar year, then you 

must report the information specified in paragraphs (j)(3)(i) through (iv) of this section for each 

sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering 

and boosting). 

(i) The total number of gas-liquid separators whose liquid dump valves did not close 

properly during the calendar year. 

(ii) The total time the dump valves on gas-liquid separators did not close properly in the 

calendar year, in hours (sum of the “Tn” values used in Equation W-16 of this subpart). 

(iii) Annual CO2 emissions, in metric tons CO2, that resulted from dump valves on gasliquid separators not closing properly during the calendar year, calculated using Equation W-16 

of this subpart. 

(iv) Annual CH4 emissions, in metric tons CH4, that resulted from the dump valves on 

gas-liquid separators not closing properly during the calendar year, calculated using Equation W16 of this subpart. 

(k) Transmission storage tanks. You must indicate whether your facility contains any 

transmission storage tanks. If your facility contains at least one transmission storage tank, then 

you must report the information specified in paragraphs (k)(1) through (3) of this section for 

each transmission storage tank vent stack. 
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(1) For each transmission storage tank vent stack, report the information specified in 

(k)(1)(i) through (iv) of this section. 

(i) The unique name or ID number for the transmission storage tank vent stack. 

(ii) Method used to determine if dump valve leakage occurred. 

(iii) Indicate whether scrubber dump valve leakage occurred for the transmission storage 

tank vent according to § 98.233(k)(2). 

(iv) Indicate if there is a flare attached to the transmission storage tank vent stack. 

(2) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as 

reported in paragraph (k)(1)(iii) 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. 

(i) Method used to measure the leak rate. 

(ii) Measured leak rate (average leak rate from a continuous flow measurement device), 

in standard cubic feet per hour. 

(iii) Duration of time that the leak is counted as having occurred, in hours, as determined 

in § 98.233(k)(3) (may use best available data if a continuous flow measurement device was 

used). 

(iv) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to 

the atmosphere, calculated according to § 98.233(k)(1) through (4). 

(v) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to 

the atmosphere, calculated according to § 98.233(k)(1) through (4). 
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(3) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as 

reported in paragraph (k)(1)(iii), and the vent stack vented to a flare during the calendar year, 

then you must report the information specified in paragraphs (k)(3)(i) through (vi) of this section. 

(i) Method used to measure the leak rate. 

(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). 

(iv) Annual CO2 emissions, in metric tons CO2, that resulted from flaring gas, calculated 

according to § 98.233(k)(5). 

(v) Annual CH4 emissions, in metric tons CH4, that resulted from flaring gas, calculated 

according to § 98.233(k)(5). 

(vi) Annual N2O emissions, in metric tons N2O, that resulted from flaring gas, calculated 

according to § 98.233(k)(5). 

(l) Well testing. You must indicate whether you performed gas well or oil well testing, 

and if the testing of gas wells or oil wells resulted in vented or flared emissions during the 

calendar year. If you performed well testing that resulted in vented or flared emissions during the 

calendar year, then you must report the information specified in paragraphs (l)(1) through (4) of 

this section, as applicable. 

(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 vented to a flare, then you 

must report the information specified in paragraphs (l)(1)(i) through (vii) of this section. 

(i) Number of wells tested in the calendar year. 
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(ii) Well ID numbers for the wells tested in the calendar year. 

(iii) Average number of well testing days per well for well(s) tested in the calendar year. 

(iv) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil. 

(v) Average flow rate for well(s) tested, in barrels of oil per day. 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 that are tested. If you elect to delay reporting of this data 

element, you must report by the date specified in § 98.236(cc) the measured average flow rate for 

well(s) tested and the well ID number(s) for the well(s) included in the measurement. 

(vi) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l). 

(vii) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l). 

(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 vented to a flare, then you 

must report the information specified in paragraphs (l)(2)(i) through (viii) of this section. 

(i) Number of wells tested in the calendar year. 

(ii) Well ID numbers for the wells tested in the calendar year. 

(iii) Average number of well testing days per well for well(s) tested in the calendar year. 

(iv) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil. 

(v) Average flow rate for well(s) tested, in barrels of oil per day. 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 that are tested. If you elect to delay reporting of this data 

element, you must report by the date specified in § 98.236(cc) the measured average flow rate for 

well(s) tested and the well ID number(s) for the well(s) included in the measurement. 

(vi) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l). 
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(vii) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l). 

(viii) 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 vented to a flare, then 

you must report the information specified in paragraphs (l)(3)(i) through (vi) of this section. 

(i) Number of wells tested in the calendar year. 

(ii) Well ID numbers for the wells tested in the calendar year. 

(iii) Average number of well testing days per well for well(s) tested in the calendar year. 

(iv) Average annual production rate for well(s) tested, in actual cubic feet per day. 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 that are tested. If you elect to delay reporting of this 

data element, you must report by the date specified in § 98.236(cc) the measured average annual 

production rate for well(s) tested and the well ID number(s) for the well(s) included in the 

measurement. 

(v) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l). 

(vi) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l). 

(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 vented to a flare, then you 

must report the information specified in paragraphs (l)(4)(i) through (vii) of this section. 

(i) Number of wells tested in calendar year. 

(ii) Well ID numbers for the wells tested in the calendar year. 

(iii) Average number of well testing days per well for well(s) tested in the calendar year. 
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(iv) Average annual production rate for well(s) tested, in actual cubic feet per day. 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 that are tested. If you elect to delay reporting of this 

data element, you must report by the date specified in § 98.236(cc) the measured average annual 

production rate for well(s) tested and the well ID number(s) for the well(s) included in the 

measurement. 

(v) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l). 

(vi) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l). 

(vii) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(l). 

(m) Associated natural gas. You must indicate whether any associated gas was vented or 

flared during the calendar year. If associated gas was vented or flared during the calendar year, 

then you must report the information specified in paragraphs (m)(1) through (8) of this section 

for each sub-basin. 

(1) Sub-basin ID and a list of well ID numbers for wells for which associated gas was 

vented or flared. 

(2) Indicate whether any associated gas was vented directly to the atmosphere without 

flaring. 

(3) Indicate whether any associated gas was flared. 

(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). 

(5) Volume of oil produced, in barrels, in the calendar year 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 
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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. 

(6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar 

year 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 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. 

(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 (iii) 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) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(m)(3) 

and (4). 

(iii) 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 (iv) of this section for each sub-basin. 
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(i) Total number of wells for which associated gas was flared and a list of their well ID 

numbers. 

(ii) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(m)(5). 

(iii) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(m)(5). 

(iv) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(m)(5). 

(n) Flare stacks. You must indicate if your facility contains any flare stacks. You must 

report the information specified in paragraphs (n)(1) through (12) of this section for each flare 

stack at your facility, and for each industry segment applicable to your facility. 

(1) 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. 

(2) Indicate whether the flare stack has a continuous flow measurement device. 

(3) Indicate whether the flare stack has a continuous gas composition analyzer on feed 

gas to the flare. 

(4) Volume of gas sent to the flare, in standard cubic feet (“Vs” in Equations W-19 and 

W-20 of this subpart). 

(5) Fraction of the feed gas sent to an un-lit flare (“Zu” in Equation W-19 of this subpart). 

(6) Flare combustion efficiency, expressed as the fraction of gas combusted by a burning 

flare. 

(7) Mole fraction of CH4 in the feed gas to the flare (“XCH4” in Equation W-19 of this 

subpart). 
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(8) Mole fraction of CO2 in the feed gas to the flare (“XCO2” in Equation W-20 of this 

subpart). 

(9) Annual CO2 emissions, in metric tons CO2 (refer to Equation W-20 of this subpart). 

(10) Annual CH4 emissions, in metric tons CH4 (refer to Equation W-19 of this subpart). 

(11) Annual N2O emissions, in metric tons N2O (refer to Equation W-40 of this subpart). 

(12) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS 

was used to measure emissions from the flare, then you are not required to report N2O and CH4

emissions for the flare stack. 

(o) Centrifugal compressors. You must indicate whether your facility has centrifugal 

compressors. You must report the information specified in paragraphs (o)(1) and (2) of this 

section for all centrifugal compressors at your facility. For each compressor source or 

manifolded group of compressor sources that you conduct as found leak measurements as 

specified in § 98.233(o)(2) or (4), you must report the information specified in paragraph (o)(3) 

of this section. For each compressor source or manifolded group of compressor sources that you 

conduct continuous monitoring as specified in § 98.233(o)(3) or (5), you must report the 

information specified in paragraph (o)(4) of this section. Centrifugal compressors in onshore 

petroleum and natural gas production and onshore petroleum and natural gas gathering and 

boosting are not required to report information in paragraphs (o)(1) through (4) of this section 

and instead must report the information specified in paragraph (o)(5) of this section. 

(1) Compressor activity data. Report the information specified in paragraphs (o)(1)(i) 

through (xiv) of this section for each centrifugal compressor located at your facility. 

(i) Unique name or ID for the centrifugal compressor. 

(ii) Hours in operating-mode. 
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(iii) Hours in not-operating-depressurized-mode. 

(iv) Indicate whether the compressor was measured in operating-mode. 

(v) Indicate whether the compressor was measured in not-operating-depressurized-mode. 

(vi) Indicate which, if any, compressor sources are part of a manifolded group of 

compressor sources. 

(vii) Indicate which, if any, compressor sources are routed to a flare. 

(viii) Indicate which, if any, compressor sources have vapor recovery. 

(ix) Indicate which, if any, compressor source emissions are captured for fuel use or are 

routed to a thermal oxidizer. 

(x) Indicate whether the compressor has blind flanges installed and associated dates. 

(xi) Indicate whether the compressor has wet or dry seals. 

(xii) If the compressor has wet seals, the number of wet seals. 

(xiii) Power output of the compressor driver (hp). 

(xiv) Indicate whether the compressor had a scheduled depressurized shutdown during 

the reporting year. 

(2) Compressor source. (i) For each compressor source at each compressor, report the 

information specified in paragraphs (o)(2)(i)(A) through (C) of this section. 

(A) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(i) of this 

section. 

(B) Centrifugal compressor source (wet seal, isolation valve, or blowdown valve). 

(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a 

manifolded group of compressor sources, use the same leak or vent ID for each compressor 

source in the manifolded group. If multiple compressor sources are released through a single 
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vent for which continuous measurements are used, use the same leak or vent ID for each 

compressor source released via the measured vent. For a single compressor using as found 

measurements, you must provide a different leak or vent ID for each compressor source. 

(ii) For each leak or vent, report the information specified in paragraphs (o)(2)(ii)(A) 

through (E) of this section. 

(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 (fuel or thermal oxidizer), or vapor recovery. 

(B) Indicate whether an as found measurement(s) as identified in § 98.233(o)(2) or (4) 

was conducted on the leak or vent. 

(C) Indicate whether continuous measurements as identified in § 98.233(o)(3) or (5) were 

conducted on the leak or vent. 

(D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(1) and (2) of this section for 

the leak or vent. If the leak or vent is routed to a flare, combustion, or vapor recovery, you are 

not required to report emissions under this paragraph. 

(1) Annual CO2 emissions, in metric tons CO2.

(2) Annual CH4 emissions, in metric tons CH4.

(E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the 

percentage of time that the respective device was operational when the compressor source 

emissions were routed to the device. 

(3) As found measurement sample data. If the measurement methods specified in § 

98.233(o)(2) or (4) are conducted, report the information specified in paragraph (o)(3)(i) of this 
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section. If the calculation specified in § 98.233(o)(6)(ii) is performed, report the information 

specified in paragraph (o)(3)(ii) of this section. 

(i) For each as found measurement performed on a leak or vent, report the information 

specified in paragraphs (o)(3)(i)(A) through (F) of this section. 

(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of 

this section. 

(B) Measurement date. 

(C) Measurement method. If emissions were not detected when using a screening 

method, report the screening method. If emissions were detected using a screening method, 

report only the method subsequently used to measure the volumetric emissions. 

(D) Measured flow rate, in standard cubic feet per hour. 

(E) For each compressor attached to the leak or vent, report the compressor mode during 

which the measurement was taken. 

(F) If the measurement is for a manifolded group of compressor sources, indicate whether 

the measurement location is prior to or after comingling with non-compressor emission sources. 

(ii) For each compressor mode-source combination where a reporter emission factor as 

calculated in Equation W-23 was used to calculate emissions in Equation W-22, report the 

information specified in paragraphs (o)(3)(ii)(A) through (D) of this section. 

(A) The compressor mode-source combination. 

(B) The compressor mode-source combination reporter emission factor, in standard cubic 

feet per hour (EFs,m in Equation W-23). 
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(C) The total number of compressors measured in the compressor mode-source 

combination in the current reporting year and the preceding two reporting years (Countm in 

Equation W-23). 

(D) Indicate whether the compressor mode-source combination reporter emission factor 

is facility-specific or based on all of the reporter’s applicable facilities. 

(4) Continuous measurement data. If the measurement methods specified in § 

98.233(o)(3) or (5) are conducted, report the information specified in paragraphs (o)(4)(i) 

through (iv) of this section for each continuous measurement conducted on each leak or vent 

associated with each compressor source or manifolded group of compressor sources. 

(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of 

this section. 

(ii) Measured volume of flow during the reporting year, in million standard cubic feet. 

(iii) Indicate whether the measured volume of flow during the reporting year includes 

compressor blowdown emissions as allowed for in § 98.233(o)(3)(ii) and (o)(5)(iii). 

(iv) If the measurement is for a manifolded group of compressor sources, indicate 

whether the measurement location is prior to or after comingling with non-compressor emission 

sources. 

(5) Onshore petroleum and natural gas production and onshore petroleum and natural 

gas gathering and boosting. Centrifugal compressors with wet seal degassing vents in onshore 

petroleum and natural gas production and onshore petroleum and natural gas gathering and 

boosting must report the information specified in paragraphs (o)(5)(i) through (iii) of this section. 

(i) Number of centrifugal compressors that have wet seal oil degassing vents. 
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(ii) Annual CO2 emissions, in metric tons CO2, from centrifugal compressors with wet 

seal oil degassing vents. 

(iii) Annual CH4 emissions, in metric tons CH4, from centrifugal compressors with wet 

seal oil degassing vents. 

(p) Reciprocating compressors. You must indicate whether your facility has reciprocating 

compressors. You must report the information specified in paragraphs (p)(1) and (2) of this 

section for all reciprocating compressors at your facility. For each compressor source or 

manifolded group of compressor sources that you conduct as found leak measurements as 

specified in § 98.233(p)(2) or (4), you must report the information specified in paragraph (p)(3) 

of this section. For each compressor source or manifolded group of compressor sources that you 

conduct continuous monitoring as specified in § 98.233(p)(3) or (5), you must report the 

information specified in paragraph (p)(4) of this section. Reciprocating compressors in onshore 

petroleum and natural gas production and onshore petroleum and natural gas gathering and 

boosting are not required to report information in paragraphs (p)(1) through (4) of this section 

and instead must report the information specified in paragraph (p)(5) of this section. 

(1) Compressor activity data. Report the information specified in paragraphs (p)(1)(i) 

through (xiv) of this section 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) Indicate whether the compressor was measured in operating-mode. 

(vi) Indicate whether the compressor was measured in standby-pressurized-mode. 
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(vii) Indicate whether the compressor was measured in not-operating-depressurizedmode. 

(viii) Indicate which, if any, compressor sources are part of a manifolded group of 

compressor sources. 

(ix) Indicate which, if any, compressor sources are routed to a flare. 

(x) Indicate which, if any, compressor sources have vapor recovery. 

(xi) Indicate which, if any, compressor source emissions are captured for fuel use or are 

routed to a thermal oxidizer. 

(xii) Indicate whether the compressor has blind flanges installed and associated dates. 

(xiii) Power output of the compressor driver (hp). 

(xiv) Indicate whether the compressor had a scheduled depressurized shutdown during 

the reporting year. 

(2) Compressor source. (i) For each compressor source at each compressor, report the 

information specified in paragraphs (p)(2)(i)(A) through (C) of this section. 

(A) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of 

this section. 

(B) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing). 

(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a 

manifolded group of compressor sources, use the same leak or vent ID for each compressor 

source in the manifolded group. If multiple compressor sources are released through a single 

vent for which continuous measurements are used, use the same leak or vent ID for each 

compressor source released via the measured vent. For a single compressor using as found 

measurements, you must provide a different leak or vent ID for each compressor source. 
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(ii) For each leak or vent, report the information specified in paragraphs (p)(2)(ii)(A) 

through (E) of this section. 

(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 (fuel or thermal oxidizer), or vapor recovery. 

(B) Indicate whether an as found measurement(s) as identified in § 98.233(p)(2) or (4) 

was conducted on the leak or vent. 

(C) Indicate whether continuous measurements as identified in § 98.233(p)(3) or (5) were 

conducted on the leak or vent. 

(D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(1) and (2) of this section for 

the leak or vent. If the leak or vent is routed to flare, combustion, or vapor recovery, you are not 

required to report emissions under this paragraph. 

(1) Annual CO2 emissions, in metric tons CO2. 

(2) Annual CH4 emissions, in metric tons CH4. 

(E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the 

percentage of time that the respective device was operational when the compressor source 

emissions were routed to the device. 

(3) As found measurement sample data. If the measurement methods specified in § 

98.233(p)(2) or (4) are conducted, report the information specified in paragraph (p)(3)(i) of this 

section. If the calculation specified in § 98.233(p)(6)(ii) is performed, report the information 

specified in paragraph (p)(3)(ii) of this section. 

(i) For each as found measurement performed on a leak or vent, report the information 

specified in paragraphs (p)(3)(i)(A) through (F) of this section. 
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(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of 

this section. 

(B) Measurement date. 

(C) Measurement method. If emissions were not detected when using a screening 

method, report the screening method. If emissions were detected using a screening method, 

report only the method subsequently used to measure the volumetric emissions. 

(D) Measured flow rate, in standard cubic feet per hour. 

(E) For each compressor attached to the leak or vent, report the compressor mode during 

which the measurement was taken. 

(F) If the measurement is for a manifolded group of compressor sources, indicate whether 

the measurement location is prior to or after comingling with non-compressor emission sources. 

(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 

(A) The compressor mode-source combination. 

(B) The compressor mode-source combination reporter emission factor, in standard cubic 

feet per hour (EFs,m in Equation W-28). 

(C) The total number of compressors measured in the compressor mode-source 

combination in the current reporting year and the preceding two reporting years (Countm in 

Equation W-28). 

(D) Indicate whether the compressor mode-source combination reporter emission factor 

is facility-specific or based on all of the reporter’s applicable facilities. 
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(4) Continuous measurement data. If the measurement methods specified in § 

98.233(p)(3) or (5) are conducted, report the information specified in paragraphs (p)(4)(i) 

through (iv) of this section for each continuous measurement conducted on each leak or vent 

associated with each compressor source or manifolded group of compressor sources. 

(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of 

this section. 

(ii) Measured volume of flow during the reporting year, in million standard cubic feet. 

(iii) Indicate whether the measured volume of flow during the reporting year includes 

compressor blowdown emissions as allowed for in § 98.233(p)(3)(ii) and (p)(5)(iii). 

(iv) If the measurement is for a manifolded group of compressor sources, indicate 

whether the measurement location is prior to or after comingling with non-compressor emission 

sources. 

(5) Onshore petroleum and natural gas production and onshore petroleum and natural 

gas gathering and boosting. Reciprocating compressors in onshore petroleum and natural gas 

production and onshore petroleum and natural gas gathering and boosting must report the 

information specified in paragraphs (p)(5)(i) through (iii) of this section. 

(i) Number of reciprocating compressors. 

(ii) Annual CO2 emissions, in metric tons CO2, from reciprocating compressors. 

(iii) Annual CH4 emissions, in metric tons CH4, from reciprocating compressors. 

(q) Equipment leak surveys. If your facility is subject to the requirements of § 98.233(q), 

then you must report the information specified in paragraphs (q)(1) and (2) of this section. 

Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must also report 

the information specified in paragraph (q)(3) of this section. 
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(1) You must report the information specified in paragraphs (q)(1)(i) through (v) of this 

section. 

(i) Except as specified in paragraph (q)(1)(ii) of this section, the number of complete 

equipment leak surveys performed during the calendar year. 

(ii) Natural gas distribution facilities performing equipment leak surveys across a 

multiple year leak survey cycle must report the number of years in the leak survey cycle.

(iii) Indicate whether any equipment leak component types were subject to 40 CFR part 

60, subpart OOOOa. 

(iv) Indicate whether you elected to comply with § 98.233(q)(1)(iii). 

(v) Report each type of method described in § 98.234(a) that was used to conduct leak 

surveys.

(2) You must indicate whether your facility contains any of the component types subject 

to § 98.233(q) that are listed in § 98.232(c)(21), (d)(7), (d)(8), (e)(7), (e)(8), (f)(5), (f)(6), (f)(7), 

(f)(8), (g)(4), (g)(5), (g)(6), (h)(5), (h)(6), (h)(7), (j)(10), or (i)(1), 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)(iii), (iv), and (v) of this section. 

(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). 

Deleted: and

Deleted: ii

Deleted: 3

Deleted: 4
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(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). 

(iv) Annual CO2 emissions, in metric tons CO2, for the component type as calculated 

using Equation W-30 (for surveyed components only). 

(v) Annual CH4 emissions, in metric tons CH4, for the component type as calculated 

using Equation W-30 (for surveyed components only). 

(3) Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must 

also report the information specified in paragraphs (q)(3)(i) through (viii) and, if applicable, 

(q)(3)(ix) of this section. 

(i) Number of above grade transmission-distribution transfer stations surveyed in the 

calendar year. 

(ii) Number of meter/regulator runs at above grade transmission-distribution transfer 

stations surveyed in the calendar year (“CountMR,y” from Equation W-31 of this subpart, for the 

current calendar year). 

(iii) Average time that meter/regulator runs surveyed in the calendar year were 

operational, in hours (average of “Tw,y” from Equation W-31 of this subpart, for the current 

calendar year). 

(iv) Number of above grade transmission-distribution transfer stations surveyed in the 

current leak survey cycle. 

(v) Number of meter/regulator runs at above grade transmission-distribution transfer 

stations surveyed in current leak survey cycle (sum of “CountMR,y” from Equation W-31 of this 

subpart, for all calendar years in the current leak survey cycle). 
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(vi) Average time that meter/regulator runs surveyed in the current leak survey cycle 

were operational, in hours (average of “Tw,y” from Equation W-31 of this subpart, for all years 

included in the leak survey cycle). 

(vii) Meter/regulator run CO2 emission factor based on all surveyed transmissiondistribution transfer stations in the current leak survey cycle, in standard cubic feet of CO2 per 

operational hour of all meter/regulator runs (“EFs,MR,i” for CO2 calculated using Equation W-31 

of this subpart). 

(viii) Meter/regulator run CH4 emission factor based on all surveyed transmissiondistribution transfer stations in the current leak survey cycle, in standard cubic feet of CH4 per 

operational hour of all meter/regulator runs (“EFs,MR,i” for CH4 calculated using Equation W-31 

of this subpart). 

(ix) If your natural gas distribution facility performs equipment leak surveys across a 

multiple year leak survey cycle, you must also report: 

(A) The total number of meter/regulator runs at above grade transmission-distribution 

transfer stations at your facility (“CountMR” in Equation W-32B of this subpart). 

(B) Average estimated time that each meter/regulator run at above grade transmissiondistribution transfer stations was operational in the calendar year, in hours per meter/regulator 

run (“Tw,avg” in Equation W-32B of this subpart). 

(C) Annual CO2 emissions, in metric tons CO2, for all above grade transmissiondistribution transfer stations at your facility. 

(D) Annual CH4 emissions, in metric tons CH4, for all above grade transmissiondistribution transfer stations at your facility. 
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(r) Equipment leaks by population count. If your facility is subject to the requirements of 

§ 98.233(r), then you must report the information specified in paragraphs (r)(1) through (3) of 

this section, as applicable. 

(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 component 

type, service type, and geographic location (i.e., Eastern U.S. or Western U.S.). 

(i) Emission source type. Onshore petroleum and natural gas production facilities and 

onshore petroleum and natural gas gathering and boosting facilities must report the component 

type, service type and geographic location. 

(ii) Total number of the emission source type at the facility (“Counte” in Equation W-32A 

of this subpart). 

(iii) Average estimated time that the emission source type was operational in the calendar 

year, in hours (“Te” in Equation W-32A of this subpart). 

(iv) Annual CO2 emissions, in metric tons CO2, for the emission source type. 

(v) Annual CH4 emissions, in metric tons CH4, for the emission source type. 

(2) Natural gas distribution facilities must also report the information specified in 

paragraphs (r)(2)(i) through (v) of this section. 

(i) Number of above grade transmission-distribution transfer stations at the facility. 
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(ii) Number of above grade metering-regulating stations that are not transmissiondistribution transfer stations at the facility. 

(iii) Total number of meter/regulator runs at above grade metering-regulating stations that 

are not above grade transmission-distribution transfer stations (“CountMR” in Equation W-32B of 

this subpart). 

(iv) Average estimated time that each meter/regulator run at above grade meteringregulating stations that are not above grade transmission-distribution transfer stations was 

operational in the calendar year, in hours per meter/regulator run (“Tw,avg” in Equation W-32B of 

this subpart). 

(v) If your facility has above grade metering-regulating stations that are not above grade 

transmission-distribution transfer stations and your facility also has above grade transmissiondistribution transfer stations, you must also report: 

(A) Annual CO2 emissions, in metric tons CO2, from above grade metering-regulating 

stations that are not above grade transmission-distribution transfer stations. 

(B) Annual CH4 emissions, in metric tons CH4, from above grade metering regulating 

stations that are not above grade transmission-distribution transfer stations. 

(3) Onshore petroleum and natural gas production facilities and onshore petroleum and 

natural gas gathering and boosting facilities must also report the information specified in 

paragraphs (r)(3)(i) and (ii) of this section. 

(i) Calculation method used. 

(ii) 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)(3)(ii)(A) and (B) of this section, for each major equipment type, production type (i.e., natural 
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gas or crude oil), and geographic location combination in Tables W-1B and W-1C of this 

subpart. 

(A) An indication of whether the facility contains the major equipment type. 

(B) If the facility does contain the equipment type, the count of the major equipment 

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 BOEMRE study. 

(1) Annual CO2 emissions, in metric tons CO2. 

(2) Annual CH4 emissions, in metric tons CH4. 

(3) Annual N2O emissions, in metric tons N2O. 

(t) [Reserved] 

(u) [Reserved] 

(v) [Reserved] 

(w) EOR injection pumps. You must indicate whether CO2 EOR injection was used at 

your facility during the calendar year and if any EOR injection pump blowdowns occurred 

during the year. If any EOR injection pump blowdowns occurred during the calendar year, then 

you must report the information specified in paragraphs (w)(1) through (8) of this section for 

each EOR injection pump system. 

(1) Sub-basin ID. 

(2) EOR injection pump system identifier. 

(3) Pump capacity, in barrels per day. 
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(4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“Vv” 

in Equation W-37 of this subpart). 

(5) Number of blowdowns for the EOR injection pump system in the calendar year. 

(6) Density of critical phase EOR injection gas, in kilograms per cubic foot (“Rc” in 

Equation W-37 of this subpart). 

(7) Mass fraction of CO2 in critical phase EOR injection gas (“GHGCO2” in Equation W37 of this subpart). 

(8) Annual CO2 emissions, in metric tons CO2, from EOR injection pump system 

blowdowns. 

(x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon liquids were 

produced through EOR operations. If hydrocarbon liquids were produced through EOR 

operations, you must report the information specified in paragraphs (x)(1) through (4) of this 

section for each sub-basin category with EOR operations. 

(1) Sub-basin ID. 

(2) Total volume of hydrocarbon liquids produced through EOR operations in the 

calendar year, in barrels (“Vhl” in Equation W-38 of this subpart). 

(3) Average CO2 retained in hydrocarbon liquids downstream of the storage tank, in 

metric tons per barrel under standard conditions (“Shl” in Equation W-38 of this subpart). 

(4) Annual CO2 emissions, in metric tons CO2, from CO2 retained in hydrocarbon liquids 

produced through EOR operations downstream of the storage tank (“MassCO2” in Equation W-38 

of this subpart). 

(y) [Reserved] 
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(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)(xvii), (a)(8)(i), or (a)(9)(xi) 

of this section. If your facility contains any combustion units subject to reporting according to 

paragraph (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) of this section, then you must report the information 

specified in paragraphs (z)(1) and (2) of this section, as applicable. 

(1) Indicate whether the combustion units include: External fuel combustion units with a 

rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units 

that are not compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or 

the equivalent of 130 horsepower). If the facility contains external fuel combustion units with a 

rated heat capacity less than or equal to 5 million Btu per hour or internal fuel combustion units 

that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btu per 

hour (or the equivalent of 130 horsepower), then you must report the information specified in 

paragraphs (z)(1)(i) and (ii) of this section for each unit type. 

(i) The type of combustion unit. 

(ii) The total number of combustion units. 

(2) Indicate whether the combustion units include: External fuel combustion units with a 

rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not 

compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the 

equivalent of 130 horsepower); or, internal fuel combustion units of any heat capacity that are 

compressor-drivers. If your facility contains: External fuel combustion units with a rated heat 
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capacity greater than 5 mmBtu/hr; internal fuel combustion units that are not compressor-drivers, 

with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 

horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers, 

then you must report the information specified in paragraphs (z)(2)(i) through (vi) of this section 

for each combustion unit type and fuel type combination. 

(i) The type of combustion unit. 

(ii) The type of fuel combusted. 

(iii) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, 

gallons, or tons. 

(iv) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(z)(1) 

and (2). 

(v) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(z)(1) and 

(2). 

(vi) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(z)(1) 

and (2). 

(aa) Each facility must report the information specified in paragraphs (aa)(1) through (11) 

of this section, for each applicable industry segment, by using best available data. If a quantity 

required to be reported is zero, you must report zero as the value. 

(1) For onshore petroleum and natural gas production, report the data specified in 

paragraphs (aa)(1)(i) and (ii) of this section. 

(i) Report the information specified in paragraphs (aa)(1)(i)(A) through (C) of this section 

for the basin as a whole. 
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(A) The quantity of gas produced in the calendar year from wells, in thousand standard 

cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field 

operations. This does not include gas injected back into reservoirs or shrinkage resulting from 

lease condensate production. 

(B) The quantity of gas produced in the calendar year for sales, in thousand standard 

cubic feet. 

(C) The quantity of crude oil and condensate produced in the calendar year for sales, in 

barrels. 

(ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (M) of this 

section for each unique sub-basin category. 

(A) State. 

(B) County. 

(C) Formation type. 

(D) The number of producing wells at the end of the calendar year and a list of the well 

ID numbers (exclude only those wells permanently taken out of production, i.e., plugged and 

abandoned). 

(E) The number of producing wells acquired during the calendar year and a list of the 

well ID numbers. 

(F) The number of producing wells divested during the calendar year and a list of the well 

ID numbers. 

(G) The number of wells completed during the calendar year and a list of the well ID 

numbers. 
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(H) The number of wells permanently taken out of production (i.e., plugged and 

abandoned) during the calendar year and a list of the well ID numbers. 

(I) Average mole fraction of CH4 in produced gas. 

(J) Average mole fraction of CO2 in produced gas. 

(K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic 

feet per barrel. 

(L) If an oil sub-basin, report the average API gravity of all wells. 

(M) If an oil sub-basin, report average low pressure separator pressure, in pounds per 

square inch gauge. 

(2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) and 

(ii) of this section. 

(i) The total quantity of gas handled at the offshore platform in the calendar year, in 

thousand standard cubic feet, including production volumes and volumes transferred via pipeline 

from another location. 

(ii) The total quantity of oil and condensate handled at the offshore platform in the 

calendar year, in barrels, including production volumes and volumes transferred via pipeline 

from another location. 

(3) For natural gas processing, report the information specified in paragraphs (aa)(3)(i) 

through (vii) of this section. 

(i) The quantity of natural gas received at the gas processing plant in the calendar year, in 

thousand standard cubic feet. 

(ii) The quantity of processed (residue) gas leaving the gas processing plant in the 

calendar year, in thousand standard cubic feet. 
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(iii) The cumulative quantity of all NGLs (bulk and fractionated) received at the gas 

processing plant in the calendar year, in barrels. 

(iv) The cumulative quantity of all NGLs (bulk and fractionated) leaving the gas 

processing plant in the calendar year, in barrels. 

(v) Average mole fraction of CH4 in natural gas received. 

(vi) Average mole fraction of CO2 in natural gas received. 

(vii) Indicate whether the facility fractionates NGLs. 

(4) For natural gas transmission compression, report the quantity specified in paragraphs 

(aa)(4)(i) through (v) of this section. 

(i) The quantity of gas transported through the compressor station in the calendar year, in 

thousand standard cubic feet. 

(ii) Number of compressors. 

(iii) Total compressor power rating of all compressors combined, in horsepower. 

(iv) Average upstream pipeline pressure, in pounds per square inch gauge. 

(v) Average downstream pipeline pressure, in pounds per square inch gauge. 

(5) For underground natural gas storage, report the quantities specified in paragraphs 

(aa)(5)(i) through (iii) of this section. 

(i) The quantity of gas injected into storage in the calendar year, in thousand standard 

cubic feet. 

(ii) The quantity of gas withdrawn from storage in the calendar year, in thousand standard 

cubic feet. 

(iii) Total storage capacity, in thousand standard cubic feet. 
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(6) For LNG import equipment, report the quantity of LNG imported in the calendar year, 

in thousand standard cubic feet. 

(7) For LNG export equipment, report the quantity of LNG exported in the calendar year, 

in thousand standard cubic feet. 

(8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (iii) 

of this section. 

(i) The quantity of LNG added into storage in the calendar year, in thousand standard 

cubic feet. 

(ii) The quantity of LNG withdrawn from storage in the calendar year, in thousand 

standard cubic feet. 

(iii) Total storage capacity, in thousand standard cubic feet. 

(9) For natural gas distribution, report the quantities specified in paragraphs (aa)(9)(i) 

through (vii) of this section. 

(i) The quantity of natural gas received at all custody transfer stations in the calendar 

year, in thousand standard cubic feet. This value may include meter corrections, but only for the 

calendar year covered by the annual report. 

(ii) The quantity of natural gas withdrawn from in-system storage in the calendar year, in 

thousand standard cubic feet. 

(iii) The quantity of natural gas added to in-system storage in the calendar year, in 

thousand standard cubic feet. 

(iv) The quantity of natural gas delivered to end users, in thousand standard cubic feet. 

This value does not include stolen gas, or gas that is otherwise unaccounted for. 
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(v) The quantity of natural gas transferred to third parties such as other LDCs or 

pipelines, in thousand standard cubic feet. This value does not include stolen gas, or gas that is 

otherwise unaccounted for. 

(vi) The quantity of natural gas consumed by the LDC for operational purposes, in 

thousand standard cubic feet. 

(vii) The estimated quantity of gas stolen in the calendar year, in thousand standard cubic 

feet. 

(10) For onshore petroleum and natural gas gathering and boosting facilities, report the 

quantities specified in paragraphs (aa)(10)(i) through (iv) of this section. 

(i) The quantity of gas received by the gathering and boosting facility in the calendar 

year, in thousand standard cubic feet. 

(ii) The quantity of gas transported to a natural gas processing facility, a natural gas 

transmission pipeline, a natural gas distribution pipeline, or another gathering and boosting 

facility in the calendar year, in thousand standard cubic feet. 

(iii) The quantity of all hydrocarbon liquids received by the gathering and boosting 

facility in the calendar year, in barrels. 

(iv) The quantity of all hydrocarbon liquids transported to a natural gas processing 

facility, a natural gas transmission pipeline, a natural gas distribution pipeline, or another 

gathering and boosting facility in the calendar year, in barrels. 

(11) For onshore natural gas transmission pipeline facilities, report the quantities 

specified in paragraphs (aa)(11)(i) through (vi) of this section. 
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(i) The quantity of natural gas received at all custody transfer stations in the calendar 

year, in thousand standard cubic feet. This value may include meter corrections, but only for the 

calendar year covered by the annual report. 

(ii) The quantity of natural gas withdrawn from in-system storage in the calendar year, in 

thousand standard cubic feet. 

(iii) The quantity of natural gas added to in-system storage in the calendar year, in 

thousand standard cubic feet. 

(iv) The quantity of natural gas transferred to third parties such as LDCs or other 

transmission pipelines, in thousand standard cubic feet. 

(v) The quantity of natural gas consumed by the transmission pipeline facility for 

operational purposes, in thousand standard cubic feet. 

(vi) The miles of transmission pipeline for each state in the facility. 

(bb) For any missing data procedures used, report the information in § 98.3(c)(8) except 

as provided in paragraphs (bb)(1) and (2) of this section. 

(1) For quarterly measurements, report the total number of quarters that a missing data 

procedure was used for each data element rather than the total number of hours. 

(2) For annual or biannual (once every two years) measurements, you do not need to 

report the number of hours that a missing data procedure was used for each data element. 

(cc) If you elect to delay reporting the information in paragraph (g)(5)(i), (g)(5)(ii), (g)(5)(iii)(A), 

(g)(5)(iii)(B), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), 

(l)(4)(iii), (m)(5), or (m)(6) of this section, you must report the information required in that 

paragraph no later than the date 2 years following the date specified in § 98.3(b) introductory 

text. 
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§ 98.237 Records that must be retained. 

Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. In 

addition to the information required by § 98.3(g), you must retain the following records: 

(a) Dates on which measurements were conducted. 

(b) Results of all emissions detected and measurements. 

(c) Calibration reports for detection and measurement instruments used. 

(d) Inputs and outputs of calculations or emissions computer model runs used for 

engineering estimation of emissions. 

(e) The records required under § 98.3(g)(2)(i) shall include an explanation of how 

company records, engineering estimation, or best available information are used to calculate each 

applicable parameter under this subpart. 

(f) For each time a missing data procedure was used, keep a record listing the emission 

source type, a description of the circumstance that resulted in the need to use missing data 

procedures, the missing data provisions in § 98.235 that apply, the calculation or analysis used to 

develop the substitute value, and the substitute value. 

§ 98.238 Definitions. 

Except as provided in this section, all terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part. 

Acid gas means hydrogen sulfide (H2S) and/or carbon dioxide (CO2) contaminants that 

are separated from sour natural gas by an acid gas removal unit. 

Acid gas removal unit (AGR) means a process unit that separates hydrogen sulfide and/or 

carbon dioxide from sour natural gas using liquid or solid absorbents or membrane separators. 
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Acid gas removal vent emissions mean the acid gas separated from the acid gas absorbing 

medium (e.g., an amine solution) and released with methane and other light hydrocarbons to the 

atmosphere or a flare. 

Associated gas venting or flaring means the venting or flaring of natural gas which 

originates at wellheads that also produce hydrocarbon liquids and occurs either in a discrete 

gaseous phase at the wellhead or is released from the liquid hydrocarbon phase by separation. 

This does not include venting or flaring resulting from activities that are reported elsewhere, 

including tank venting, well completions, and well workovers. 

Associated with a single well-pad means associated with the hydrocarbon stream as 

produced from one or more wells located on that single well-pad. The association ends where the 

stream from a single well-pad is combined with streams from one or more additional single wellpads, where the point of combination is located off that single well-pad. Onshore production 

storage tanks on or associated with a single well-pad are considered a part of the onshore 

production facility. 

Basin means geologic provinces as defined by the American Association of Petroleum 

Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG 

Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, 

Number 10 (October 1991) (incorporated by reference, see § 98.7) and the Alaska Geological 

Province Boundary Map, Compiled by the American Association of Petroleum Geologists 

Committee on Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by 

reference, see § 98.7). 
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Compressor means any machine for raising the pressure of a natural gas or CO2 by 

drawing in low pressure natural gas or CO2 and discharging significantly higher pressure natural 

gas or CO2. 

Compressor mode means the operational and pressurized status of a compressor. For a 

centrifugal compressor, “mode” refers to either operating-mode or not-operating-depressurizedmode. For a reciprocating compressor, “mode” refers to either: Operating-mode, standbypressurized-mode, or not-operating-depressurized-mode. 

Compressor source means the source of certain venting or leaking emissions from a 

centrifugal or reciprocating compressor. For centrifugal compressors, “source” refers to 

blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an 

open blowdown vent without blind flanges, and wet seal oil degassing vents. For reciprocating 

compressors, “source” refers to blowdown valve leakage through the blowdown vent, unit 

isolation valve leakage through an open blowdown vent without blind flanges, and rod packing 

emissions. 

Condensate means hydrocarbon and other liquid, including both water and hydrocarbon 

liquids, separated from natural gas that condenses due to changes in the temperature, pressure, or 

both, and remains liquid at storage conditions. 

Delineation well means a well drilled in order to determine the boundary of a field or 

producing reservoir. 

Distribution pipeline means a pipeline that is designated as such by the Pipeline and 

Hazardous Material Safety Administration (PHMSA) 49 CFR 192.3. 
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Engineering estimation, for purposes of subpart W, means an estimate of emissions based 

on engineering principles applied to measured and/or approximated physical parameters such as 

dimensions of containment, actual pressures, actual temperatures, and compositions. 

Enhanced oil recovery (EOR) means the use of certain methods such as water flooding or 

gas injection into existing wells to increase the recovery of crude oil from a reservoir. In the 

context of this subpart, EOR applies to injection of critical phase or immiscible carbon dioxide 

into a crude oil reservoir to enhance the recovery of oil. 

External combustion means fired combustion in which the flame and products of 

combustion are separated from contact with the process fluid to which the energy is delivered. 

Process fluids may be air, hot water, or hydrocarbons. External combustion equipment may 

include fired heaters, industrial boilers, and commercial and domestic combustion units. 

Facility with respect to natural gas distribution for purposes of reporting under this 

subpart and for the corresponding subpart A requirements means the collection of all 

distribution pipelines and metering-regulating stations that are operated by a Local Distribution 

Company (LDC) within a single state that is regulated as a separate operating company by a 

public utility commission or that are operated as an independent municipally-owned distribution 

system. 

Facility with respect to natural gas distribution for purposes of reporting under this 

subpart and for the corresponding subpart A requirements means the collection of all 

distribution pipelines and metering-regulating stations that are operated by a Local Distribution 

Company (LDC) within a single state that is regulated as a separate operating company by a 

public utility commission or that are operated as an independent municipally-owned distribution 

system. 
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Facility with respect to onshore petroleum and natural gas gathering and boosting for 

purposes of reporting under this subpart and for the corresponding subpart A requirements

means all gathering pipelines and other equipment located along those pipelines that are under 

common ownership or common control by a gathering and boosting system owner or operator 

and that are located in a single hydrocarbon basin as defined in this section. Where a person 

owns or operates more than one gathering and boosting system in a basin (for example, separate 

gathering lines that are not connected), then all gathering and boosting equipment that the person 

owns or operates in the basin would be considered one facility. Any gathering and boosting 

equipment that is associated with a single gathering and boosting system, including leased, 

rented, or contracted activities, is considered to be under common control of the owner or 

operator of the gathering and boosting system that contains the pipeline. The facility does not 

include equipment and pipelines that are part of any other industry segment defined in this 

subpart. 

Facility with respect to onshore petroleum and natural gas production for purposes of 

reporting under this subpart and for the corresponding subpart A requirements means all 

petroleum or natural gas equipment on a single well-pad or associated with a single well-pad and 

CO2 EOR operations that are under common ownership or common control including leased, 

rented, or contracted activities by an onshore petroleum and natural gas production owner or 

operator and that are located in a single hydrocarbon basin as defined in § 98.238. Where a 

person or entity owns or operates more than one well in a basin, then all onshore petroleum and 

natural gas production equipment associated with all wells that the person or entity owns or 

operates in the basin would be considered one facility. 
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Facility with respect to the onshore natural gas transmission pipeline segment means the 

total U.S. mileage of natural gas transmission pipelines, as defined in this section, owned and 

operated by an onshore natural gas transmission pipeline owner or operator as defined in this 

section. The facility does not include pipelines that are part of any other industry segment 

defined in this subpart. 

Farm Taps are pressure regulation stations that deliver gas directly from transmission 

pipelines to generally rural customers. In some cases a nearby LDC may handle the billing of the 

gas to the customer(s). 

Field means oil and gas fields identified in the United States as defined by the Energy 

Information Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08) 

(incorporated by reference, see § 98.7). 

Flare, for the purposes of subpart W, means a combustion device, whether at ground 

level or elevated, that uses an open or closed flame to combust waste gases without energy 

recovery. 

Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole 

basis, that is combusted at the flare burner tip. 

Flare stack emissions means CO2 and N2O from partial combustion of hydrocarbon gas 

sent to a flare plus CH4 emissions resulting from the incomplete combustion of hydrocarbon gas 

in flares. 

Forced extraction of natural gas liquids means removal of ethane or higher carbon 

number hydrocarbons existing in the vapor phase in natural gas, by removing ethane or heavier 

hydrocarbons derived from natural gas into natural gas liquids by means of a forced extraction 

process. Forced extraction processes include but are not limited to refrigeration, absorption (lean 
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oil), cryogenic expander, and combinations of these processes. Forced extraction does not 

include in and of itself; natural gas dehydration, or the collection or gravity separation of water 

or hydrocarbon liquids from natural gas at ambient temperature or heated above ambient 

temperatures, or the condensation of water or hydrocarbon liquids through passive reduction in 

pressure or temperature, or portable dewpoint suppression skids. 

Gathering and boosting system means a single network of pipelines, compressors and 

process equipment, including equipment to perform natural gas compression, dehydration, and 

acid gas removal, that has one or more connection points to gas and oil production and a 

downstream endpoint, typically a gas processing plant, transmission pipeline, LDC pipeline, or 

other gathering and boosting system. 

Gathering and boosting system owner or operator means any person that holds a contract 

in which they agree to transport petroleum or natural gas from one or more onshore petroleum 

and natural gas production wells to a natural gas processing facility, another gathering and 

boosting system, a natural gas transmission pipeline, or a distribution pipeline, or any person 

responsible for custody of the petroleum or natural gas transported. 

Horizontal well means a well bore that has a planned deviation from primarily vertical to 

a primarily horizontal inclination or declination tracking in parallel with and through the target 

formation. 

Internal combustion means the combustion of a fuel that occurs with an oxidizer (usually 

air) in a combustion chamber. In an internal combustion engine the expansion of the hightemperature and -pressure gases produced by combustion applies direct force to a component of 

the engine, such as pistons, turbine blades, or a nozzle. This force moves the component over a 
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distance, generating useful mechanical energy. Internal combustion equipment may include 

gasoline and diesel industrial engines, natural gas-fired reciprocating engines, and gas turbines. 

Liquefied natural gas (LNG) means natural gas (primarily methane) that has been 

liquefied by reducing its temperature to −260 degrees Fahrenheit at atmospheric pressure.

LNG boil-off gas means natural gas in the gaseous phase that vents from LNG storage 

tanks due to ambient heat leakage through the tank insulation and heat energy dissipated in the 

LNG by internal pumps. 

Manifolded compressor source means a compressor source (as defined in this section) 

that is manifolded to a common vent that routes gas from multiple compressors. 

Manifolded group of compressor sources means a collection of any combination of 

manifolded compressor sources (as defined in this section) that are manifolded to a common 

vent. 

Meter/regulator run means a series of components used in regulating pressure or 

metering natural gas flow, or both, in the natural gas distribution industry segment. At least one 

meter, at least one regulator, or any combination of both on a single run of piping is considered 

one meter/regulator run. 

Metering-regulating station means a station that meters the flowrate, regulates the 

pressure, or both, of natural gas in a natural gas distribution facility. This does not include 

customer meters, customer regulators, or farm taps. 

Natural gas means a naturally occurring mixture or process derivative of hydrocarbon 

and non-hydrocarbon gases found in geologic formations beneath the earth’s surface, of which 

its constituents include, but are not limited to, methane, heavier hydrocarbons and carbon 

dioxide. Natural gas may be field quality, pipeline quality, or process gas. 
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Offshore means seaward of the terrestrial borders of the United States, including waters 

subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing 

waters, and extending to the outer boundaries of the jurisdiction and control of the United States 

under the Outer Continental Shelf Lands Act. 

Onshore natural gas transmission pipeline owner or operator means, for interstate 

pipelines, the person identified as the transmission pipeline owner or operator on the Certificate 

of Public Convenience and Necessity issued under 15 U.S.C. 717f, or, for intrastate pipelines, the 

person identified as the owner or operator on the transmission pipeline’s Statement of Operating 

Conditions under section 311 of the Natural Gas Policy Act, or for pipelines that fall under the 

“Hinshaw Exemption” as referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 

(w)(1994), the person identified as the owner or operator on blanket certificates issued under 18 

CFR 284.224. If an intrastate pipeline is not subject to section 311 of the Natural Gas Policy Act 

(NGPA), the onshore natural gas transmission pipeline owner or operator is the person identified 

as the owner or operator on reports to the state regulatory body regulating rates and charges for 

the sale of natural gas to consumers. 

Onshore petroleum and natural gas production owner or operator means the person or 

entity who holds the permit to operate petroleum and natural gas wells on the drilling permit or 

an operating permit where no drilling permit is issued, which operates an onshore petroleum 

and/or natural gas production facility (as described in § 98.230(a)(2). Where petroleum and 

natural gas wells operate without a drilling or operating permit, the person or entity that pays the 

State or Federal business income taxes is considered the owner or operator. 

Operating pressure means the containment pressure that characterizes the normal state of 

gas or liquid inside a particular process, pipeline, vessel or tank. 
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Pressure groups as applicable to each sub-basin are defined as follows: Less than or 

equal to 25 psig; greater than 25 psig and less than or equal to 60 psig; greater than 60 psig and 

less than or equal to 110 psig; greater than 110 psig and less than or equal to 200 psig; and 

greater than 200 psig. The pressure in the context of pressure groups is either the well shut-in 

pressure; well casing pressure; or you may use the casing-to-tubing pressure of one well from the 

same sub-basin multiplied by the tubing pressure for each well in the sub-basin. 

Pump means a device used to raise pressure, drive, or increase flow of liquid streams in 

closed or open conduits. 

Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon 

dioxide containing light liquids from escaping the inside of a pump case to the atmosphere. 

Pump seal emissions means hydrocarbon gas released from the seal face between the 

pump internal chamber and the atmosphere. 

Reduced emissions completion means a well completion following hydraulic fracturing 

where gas flowback emissions from the gas outlet of the separator that are otherwise vented are 

captured, cleaned, and routed to the flow line or collection system, re-injected into the well or 

another well, used as an on-site fuel source, or used for other useful purpose that a purchased 

fuel or raw material would serve, with de minimis direct venting to the atmosphere. Short 

periods of flaring during a reduced emissions completion may occur. 

Reduced emissions workover means a well workover with hydraulic fracturing (i.e., 

refracturing) where gas flowback emissions from the gas outlet of the separator that are 

otherwise vented are captured, cleaned, and routed to the flow line or collection system, reinjected into the well or another well, used as an on-site fuel source, or used for other useful 
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purpose that a purchased fuel or raw material would serve, with de minimis direct venting to the 

atmosphere. Short periods of flaring during a reduced emissions workover may occur. 

Reservoir means a porous and permeable underground natural formation containing 

significant quantities of hydrocarbon liquids and/or gases. 

Residue Gas and Residue Gas Compression mean, respectively, production lease natural 

gas from which gas liquid products and, in some cases, non-hydrocarbon components have been 

extracted such that it meets the specifications set by a pipeline transmission company, and/or a 

distribution company; and the compressors operated by the processing facility, whether inside 

the processing facility boundary fence or outside the fence-line, that deliver the residue gas from 

the processing facility to a transmission pipeline. 

Separator means a vessel in which streams of multiple phases are gravity separated into 

individual streams of single phase. 

Sub-basin category, for onshore natural gas production, means a subdivision of a basin 

into the unique combination of wells with the surface coordinates within the boundaries of an 

individual county and subsurface completion in one or more of each of the following five 

formation types: Oil, high permeability gas, shale gas, coal seam, or other tight gas reservoir 

rock. The distinction between high permeability gas and tight gas reservoirs shall be designated 

as follows: High permeability gas reservoirs with >0.1 millidarcy permeability, and tight gas 

reservoirs with ≤0.1 millidarcy permeability. Permeability for a reservoir type shall be 

determined by engineering estimate. Wells that produce only from high permeability gas, shale 

gas, coal seam, or other tight gas reservoir rock are considered gas wells; gas wells producing 

from more than one of these formation types shall be classified into only one type based on the 

formation with the most contribution to production as determined by engineering knowledge. All 
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wells that produce hydrocarbon liquids (with or without gas) and do not meet the definition of a 

gas well in this sub-basin category definition are considered to be in the oil formation. All 

emission sources that handle condensate from gas wells in high permeability gas, shale gas, or 

tight gas reservoir rock formations are considered to be in the formation that the gas well belongs 

to and not in the oil formation. 

Transmission-distribution (T-D) transfer station means a metering-regulating station 

where a local distribution company takes part or all of the natural gas from a transmission 

pipeline and puts it into a distribution pipeline. 

Transmission pipeline means a Federal Energy Regulatory Commission rate-regulated 

Interstate pipeline, a state rate-regulated Intrastate pipeline, or a pipeline that falls under the 

“Hinshaw Exemption” as referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 

(w)(1994). 

Tubing diameter groups are defined as follows: Outer diameter less than or equal to 1 

inch; outer diameter greater than 1 inch and less than 2.375 inch; and outer diameter greater than 

or equal to 2.375 inch. 

Tubing systems means piping equal to or less than one half inch diameter as per nominal 

pipe size. 

Turbine meter means a flow meter in which a gas or liquid flow rate through the 

calibrated tube spins a turbine from which the spin rate is detected and calibrated to measure the 

fluid flow rate. 

Vented emissions means intentional or designed releases of CH4 or CO2 containing 

natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process 
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designed flow to the atmosphere through seals or vent pipes, equipment blowdown for 

maintenance, and direct venting of gas used to power equipment (such as pneumatic devices). 

Vertical well means a well bore that is primarily vertical but has some unintentional 

deviation or one or more intentional deviations to enter one or more subsurface targets that are 

off-set horizontally from the surface location, intercepting the targets either vertically or at an 

angle. 

Well identification (ID) number means the unique and permanent identification number 

assigned to a petroleum or natural gas well. If the well has been assigned a US Well Number, the 

well ID number required in this subpart is the US Well Number. If a US Well Number has not 

been assigned to the well, the well ID number is the identifier established by the well’s 

permitting authority. 

Well testing venting and flaring means venting and/or flaring of natural gas at the time 

the production rate of a well is determined for regulatory, commercial, or technical purposes. If 

well testing is conducted immediately after well completion or workover, then it is considered 

part of well completion or workover. 

Wildcat well means a well outside known fields or the first well drilled in an oil or gas 

field where no other oil and gas production exists. 

Table W-1A to Subpart W of Part 98—Default Whole Gas Emission Factors for Onshore 

Petroleum and Natural Gas Production Facilities and Onshore Petroleum and Natural Gas 

Gathering and Boosting Facilities 

Onshore petroleum and natural gas production and Onshore petroleum 

and natural gas gathering and boosting 

Emission factor (scf/hour/ 

component) 

Eastern U.S. 

Population Emission Factors—All Components, Gas Service1

Valve 0.027

Connector 0.003
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Onshore petroleum and natural gas production and Onshore petroleum 

and natural gas gathering and boosting 

Emission factor (scf/hour/ 

component) 

Open-ended Line 0.061

Pressure Relief Valve 0.040

Low Continuous Bleed Pneumatic Device Vents2 1.39

High Continuous Bleed Pneumatic Device Vents2 37.3

Intermittent Bleed Pneumatic Device Vents2 13.5

Pneumatic Pumps3 13.3

Population Emission Factors—All Components, Light Crude Service4 

Valve 0.05

Flange 0.003

Connector 0.007

Open-ended Line 0.05

Pump 0.01

Other5 0.30

Population Emission Factors—All Components, Heavy Crude Service6 

Valve 0.0005

Flange 0.0009

Connector (other) 0.0003

Open-ended Line 0.006

Other5 0.003

Population Emission Factors—Gathering Pipelines, by Material Type7

Protected Steel 0.47

Unprotected Steel 16.59

Plastic/Composite 2.50

Cast Iron 27.60

Western U.S. 

Population Emission Factors—All Components, Gas Service1

Valve 0.121

Connector 0.017

Open-ended Line 0.031

Pressure Relief Valve 0.193

Low Continuous Bleed Pneumatic Device Vents2 1.39

High Continuous Bleed Pneumatic Device Vents2 37.3

Intermittent Bleed Pneumatic Device Vents2 13.5

Pneumatic Pumps3 13.3

Population Emission Factors—All Components, Light Crude Service4

Valve 0.05
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Onshore petroleum and natural gas production and Onshore petroleum 

and natural gas gathering and boosting 

Emission factor (scf/hour/ 

component) 

Flange 0.003

Connector (other) 0.007

Open-ended Line 0.05

Pump 0.01

Other5 0.30

Population Emission Factors—All Components, Heavy Crude Service6

Valve 0.0005

Flange 0.0009

Connector (other) 0.0003

Open-ended Line 0.006

Other5 0.003

Population Emission Factors—Gathering Pipelines by Material Type7

Protected Steel 0.47

Unprotected Steel 16.59

Plastic/Composite 2.50

Cast Iron 27.60

1

 For multi-phase flow that includes gas, use the gas service emissions factors. 

2

 Emission Factor is in units of “scf/hour/device.” 

3

 Emission Factor is in units of “scf/hour/pump.” 

4

 Hydrocarbon liquids greater than or equal to 20°API are considered “light crude.” 

5

 “Others” category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, 

dump lever arms, and vents. 

6

 Hydrocarbon liquids less than 20°API are considered “heavy crude.” 

7

 Emission factors are in units of “scf/hour/mile of pipeline.” 

Table W-1B to Subpart W of Part 98—Default Average Component Counts for Major 

Onshore Natural Gas Production Equipment and Onshore Petroleum and Natural Gas 

Gathering and Boosting Equipment 

Major equipment Valves Connectors Open-ended lines Pressure relief valves 

Eastern U.S. 

Wellheads 8 38 0.5 0 

Separators 1 6 0 0 

Meters/piping 12 45 0 0 

Compressors 12 57 0 0 

In-line heaters 14 65 2 1 

Dehydrators 24 90 2 2 
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Western U.S. 

Wellheads 11 36 1 0 

Separators 34 106 6 2 

Meters/piping 14 51 1 1 

Compressors 73 179 3 4 

In-line heaters 14 65 2 1 

Dehydrators 24 90 2 2

Table W-1C to Subpart W of Part 98—Default Average Component Counts For Major 

Crude Oil Production Equipment 

Major equipment Valves Flanges Connectors Open-ended lines Other components 

Eastern U.S. 

Wellhead 5 10 4 0 1

Separator 6 12 10 0 0

Heater-treater 8 12 20 0 0

Header 5 10 4 0 0

Western U.S. 

Wellhead 5 10 4 0 1

Separator 6 12 10 0 0

Heater-treater 8 12 20 0 0

Header 5 10 4 0 0

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

Eastern U.S. Western U.S. 

Connecticut Alabama 

Delaware Alaska 

Florida Arizona 

Georgia Arkansas 

Illinois California 

Indiana Colorado 

Kentucky Hawaii 

Maine Idaho 

Maryland Iowa 

Massachusetts Kansas 

Michigan Louisiana 

New Hampshire Minnesota 
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New Jersey Mississippi 

New York Missouri 

North Carolina Montana 

Ohio Nebraska 

Pennsylvania Nevada 

Rhode Island New Mexico 

South Carolina North Dakota 

Tennessee Oklahoma 

Vermont Oregon 

Virginia South Dakota 

West Virginia Texas 

Wisconsin Utah 

 Washington 

 Wyoming 

Table W-1E of Subpart W of Part 98—Default Whole Gas Leaker Emission Factors for 

Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas 

Gathering and Boosting 

Equipment components 

Emission factor 

(scf/hour/component) 

Leaker Emission Factors—All Components, Gas Service1

Valve 4.9

Flange 4.1

Connector (other) 1.3

Open-Ended Line2 2.8

Pressure Relief Valve 4.5

Pump Seal 3.7

Other3 4.5

Leaker Emission Factors—All Components, Light Crude Service4

Valve 3.2

Flange 2.7

Connector (other) 1.0

Open-Ended Line 1.6

Pump 3.7

Agitator Seal 3.7

Other3 3.1
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Leaker Emission Factors—All Components, Heavy Crude Service5

Valve 3.2

Flange 2.7

Connector (other) 1.0

Open-Ended Line 1.6

Pump 3.7

Agitator Seal 3.7

Other3 3.1

1

 For multi-phase flow that includes gas, use the gas service emission factors. 

2

 The open-ended lines component type includes blowdown valve and isolation valve leaks emitted through the 

blowdown vent stack for centrifugal and reciprocating compressors. 

3

 “Others” category includes any equipment leak emission point not specifically listed in this table, except for the 

following: it excludes thief hatches and all other potential emission points in gas service on atmospheric storage 

tanks, all potential emission points in gas service on gas-liquid separators, wet seal oil degassing vents from 

centrifugal compressors, and rod packing vents from reciprocating compressors. 

4

 Hydrocarbon liquids greater than or equal to 20°API are considered “light crude.” 

5

 Hydrocarbon liquids less than 20°API are considered “heavy crude.” 

Table W-2 to Subpart W of Part 98—Default Total Hydrocarbon Emission Factors for 

Onshore Natural Gas Processing 

Onshore natural gas processing plants 

Emission factor (scf/hour/ 

component) 

Leaker Emission Factors—Compressor Components, Gas Service 

Valve1 14.84

Connector 5.59

Open-Ended Line 17.27

Pressure Relief Valve 39.66

Meter 19.33

Leaker Emission Factors—Non-Compressor Components, Gas Service 

Valve1 6.42

Connector 5.71

Open-Ended Line 11.27

Pressure Relief Valve 2.01

Meter 2.93

Pump 3.4

1

 Valves include control valves, block valves and regulator valves. 
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Table W-3 to Subpart W of Part 98—Default Total Hydrocarbon Emission Factors for 

Onshore Natural Gas Transmission Compression 

Onshore natural gas transmission compression 

Emission factor (scf/hour/ 

component) 

Leaker Emission Factors—Compressor Components, Gas Service 

Valve1 14.84

Connector 5.59

Flange 5.59

Open-Ended Line 17.27

Pressure Relief Valve 39.66

Meter or Instrument 19.33

Other2 4.1

Leaker Emission Factors—Non-Compressor Components, Gas Service 

Valve1 6.42

Connector 5.71

Flange 5.71

Open-Ended Line 11.27

Pressure Relief Valve 2.01

Meter or Instrument 2.93

Other2 4.1

Population Emission Factors—Gas Service 

Low Continuous Bleed Pneumatic Device Vents3 1.37

High Continuous Bleed Pneumatic Device Vents3 18.20

Intermittent Bleed Pneumatic Device Vents3 2.35

1

 Valves include control valves, block valves and regulator valves. 

2 Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table, 

except it excludes thief hatches and all other potential emission points in gas service on transmission storage 

tanks, and it excludes compressor emission points that are subject to § 98.233(o) or (p). 

3 Emission Factor is in units of “scf/hour/device.” 

Table W-4 to Subpart W of Part 98—Default Total Hydrocarbon Emission Factors for 

Underground Natural Gas Storage 

Underground natural gas storage 

Emission factor (scf/hour/ 

component) 

Leaker Emission Factors—Storage Station, Gas Service 

Valve1 14.84

Connector 5.59

Flange 5.59

Open-Ended Line 17.27

Deleted: 2

Deleted: 2

Deleted: 2
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Pressure Relief Valve 39.66

Meter and Instrument 19.33

Other2 4.1

Population Emission Factors—Storage Wellheads, Gas Service 

Connector 0.01

Valve 0.1

Pressure Relief Valve 0.17

Open-Ended Line 0.03

Leaker Emission Factors—Storage Wellheads, Gas Service 

Valve1 4.5

Connector 1.2

Flange 3.8

Open-Ended Line 2.5

Pressure Relief Valve 4.1

Other2 4.1

Population Emission Factors—Other Components, Gas Service 

Low Continuous Bleed Pneumatic Device Vents3 1.37

High Continuous Bleed Pneumatic Device Vents3 18.20

Intermittent Bleed Pneumatic Device Vents3 2.35

1

 Valves include control valves, block valves and regulator valves. 

2 Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table 

except that it does not include compressor emission points that are subject to § 98.233(o) or (p). 

3 Emission Factor is in units of “scf/hour/device.” 

Table W-5 to Subpart W of Part 98—Default Methane Emission Factors for Liquefied 

Natural Gas (LNG) Storage 

LNG storage 

Emission factor (scf/hour/ 

component) 

Leaker Emission Factors—LNG Storage Components, LNG Service 

Valve 1.19

Pump Seal 4.00

Connector 0.34

Other1 1.77

Leaker Emission Factors—LNG Storage Components, Gas Service 

Valve2 14.84

Connector 5.59

Flange 5.59

Open-Ended Line 17.27

Deleted: 

Deleted: 2

Deleted: 2

Deleted: 2
Page 199 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

Pressure Relief Valve 39.66

Meter and Instrument 19.33

Other3 4.1

Population Emission Factors—LNG Storage Compressor, Gas Service 

Vapor Recovery Compressor4 4.17

1

 “Other” equipment type for components in LNG service should be applied for any equipment type other than 

connectors, pumps, or valves. 

2 Valves include control valves, block valves and regulator valves. 

3

 “Other” equipment type for components in gas service should be applied for any equipment type other than valves, 

connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, except that it does not 

include compressor emission points that are subject to § 98.233(o) or (p). 

4 Emission Factor is in units of “scf/hour/device.” 

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

and Export Equipment 

LNG import and export equipment 

Emission factor (scf/hour/ 

component) 

Leaker Emission Factors—LNG Terminals Components, LNG Service 

Valve 1.19

Pump Seal 4.00

Connector 0.34

Other1 1.77

Leaker Emission Factors—LNG Terminals Components, Gas Service 

Valve2 14.84

Connector 5.59

Flange 5.59

Open-Ended Line 17.27

Pressure Relief Valve 39.66

Meter and Instrument 19.33

Other3 4.1

Population Emission Factors—LNG Terminals Compressor, Gas Service 

Vapor Recovery Compressor4 4.17

1

 “Other” equipment type for components in LNG service should be applied for any equipment type other than 

connectors, pumps, or valves. 

2 Valves include control valves, block valves and regulator valves. 

3

 “Other” equipment type for components in gas service should be applied for any equipment type other than valves, 

connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, except that it does not 

include compressor emission points that are subject to § 98.233(o) or (p). 

4 Emission Factor is in units of “scf/hour/compressor.” 

Deleted: 2

Deleted: 2

Deleted: s
Page 200 of 200 

This document showing the proposed amendments to subpart W is provided for informational purposes only. We 

have taken steps to ensure the accuracy of this version, but it is not the official version.

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

Distribution 

Natural gas distribution 

Emission factor (scf/hour/ 

component) 

Leaker Emission Factors—Transmission-Distribution Transfer Station1 Components, Gas Service 

Connector 1.69

Block Valve 0.557

Control Valve 9.34

Pressure Relief Valve 0.27

Orifice Meter 0.212

Regulator 0.772

Open-ended Line 26.131

Population Emission Factors—Below Grade Metering-Regulating station1 Components, Gas Service2

Below Grade M&R Station, Inlet Pressure > 300 psig 1.30

Below Grade M&R Station, Inlet Pressure 100 to 300 psig 0.20

Below Grade M&R Station, Inlet Pressure < 100 psig 0.10

Population Emission Factors—Distribution Mains, Gas Service3

Unprotected Steel 12.58

Protected Steel 0.35

Plastic 1.13

Cast Iron 27.25

Population Emission Factors—Distribution Services, Gas Service4

Unprotected Steel 0.19

Protected Steel 0.02

Plastic 0.001

Copper 0.03

1

 Excluding customer meters. 

2

 Emission Factor is in units of “scf/hour/station.” 

3

 Emission Factor is in units of “scf/hour/mile.” 

4

 Emission Factor is in units of “scf/hour/number of services.”