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For the reasons stated in the preamble, title 40, chapter 

I, of the Code of Federal Regulations is amended as follows: 

PART 98–[AMENDED]

1. The authority citation for part 98 continues to read as 

follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart W—[Amended] --Petroleum and Natural Gas Systems

Contents

§98.230 Definition of the source category.

§98.231 Reporting threshold.

§98.232 GHGs to report.

§98.233 Calculating GHG emissions.

§98.234 Monitoring and QA/QC requirements.

§98.235 Procedures for estimating missing data.

§98.236 Data reporting requirements.

§98.237 Records that must be retained.

§98.238 Definitions.

Table W-1A of Subpart W of Part 98—Default Whole Gas Emission 

Factors for Onshore Petroleum and Natural Gas Production

Table W-1B to Subpart W of Part 98—Default Average Component 

Counts for Major Onshore Natural Gas Production Equipment

Table W-1C to Subpart W of Part 98—Default Average Component 

Counts For Major Crude Oil Production Equipment

Table W-1D of Subpart W of Part 98—Designation Of Eastern And 

Western U.S.

Table W-2 of Subpart W of Part 98—Default Total Hydrocarbon 

Emission Factors for Onshore Natural Gas Processing

Table W-3 of Subpart W of Part 98—Default Total Hydrocarbon 

Emission Factors for Onshore Natural Gas Transmission 

Compression

Table W-4 of Subpart W of Part 98—Default Total Hydrocarbon 

Emission Factors for Underground Natural Gas Storage

Table W-5 of Subpart W of Part 98—Default Methane Emission 

Factors for Liquefied Natural Gas (LNG) Storage

Table W-6 of Subpart W of Part 98—Default Methane Emission 

Factors for LNG Import and Export Equipment

Table W-7 of Subpart W of Part 98—Default Methane Emission 

Factors for Natural Gas Distribution
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§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, and portable non-self-propelled equipment which 

includes well drilling and completion equipment, workover 

equipment, gravity separation equipment, auxiliary nontransportation-related equipment, and leased, rented or 
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contracted equipment) used in the production, extraction, 

recovery, lifting, stabilization, separation or treating of 

petroleum and/or natural gas (including condensate). This 

equipment also includes associated storage or measurement 

vessels and all enhanced oil recovery (EOR) operations using CO2

or natural gas injection, and 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.

(3) Onshore natural gas processing. Natural gas processing 

means the separation of natural gas liquids (NGLs) or nonmethane 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.
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(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.

(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.
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(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 regasification 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 municipallyowned distribution system. This segment also excludes customer 

meters and regulators, infrastructure, and pipelines (both 

interstate and intrastate) delivering natural gas directly to 
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major industrial users and farm taps upstream of the local 

distribution company inlet.

(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). Facilities must 

report emissions from the onshore petroleum and natural gas 

production industry segment only if emission sources specified 

in paragraph §98.232(c) emit 25,000 metric tons of CO2 equivalent

or more per year. Facilities must report emissions from the 

natural gas distribution industry segment only if emission 

sources specified in paragraph §98.232(i) 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 paragraph (b) through (i) of this 

section, CO2, CH4, and N2O emissions from each flare as specified 

in paragraph (b) through (i) of this section, and stationary and 
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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.

(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) Gas well venting during well completions with hydraulic 

fracturing.

(7) Gas well venting during well workovers without 

hydraulic fracturing.
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(8) Gas well venting during well workovers with hydraulic 

fracturing.

(9) Flare stack emissions.

(10) Storage tanks vented emissions from produced 

hydrocarbons.

(11) Reciprocating compressor rod packing 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.

(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 
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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 rod packing 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.

(e) For onshore natural gas transmission compression, 

report CO2, CH4, and N2O emissions from the following sources:

(1) Reciprocating compressor rod packing venting.

(2) Centrifugal compressor venting.
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(3) Transmission storage tanks.

(4) Blowdown vent stacks.

(5) Natural gas pneumatic device venting.

(6) [Reserved]

(7) Equipment leaks from valves, connectors, open ended 

lines, pressure relief valves, and meters.

(f) For underground natural gas storage, report CO2, CH4,

and N2O emissions from the following sources:

(1) Reciprocating compressor rod packing venting.

(2) Centrifugal compressor venting.

(3) Natural gas pneumatic device venting.

(4) [Reserved]

(5) Equipment leaks from valves, connectors, open ended 

lines, pressure relief valves, and meters.

(g) For LNG storage, report CO2, CH4, and N2O emissions from 

the following sources:

(1) Reciprocating compressor rod packing venting.

(2) Centrifugal compressor venting.

(3) Equipment leaks from valves; pump seals; connectors; 

vapor recovery compressors, and other equipment leak sources.

(h) LNG import and export equipment, report CO2, CH4, and 

N2O emissions from the following sources:

(1) Reciprocating compressor rod packing venting.
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(2) Centrifugal compressor venting.

(3) Blowdown vent stacks.

(4) Equipment leaks from valves, pump seals, connectors, 

vapor recovery compressors, and other equipment leak sources.

(i) For natural gas distribution, report CO2, CH4, and N2O

emissions from the following sources:

(1) Meters, regulators, and associated equipment at above 

grade transmission-distribution transfer stations, including 

equipment leaks from connectors, block valves, control valves, 

pressure relief valves, orifice meters, regulators, and open 

ended lines.

(2) Equipment leaks from vaults at below grade 

transmission-distribution transfer stations.

(3) Meters, regulators, and associated equipment at above 

grade metering-regulating station.

(4) Equipment leaks from vaults at below grade meteringregulating stations.

(5) Pipeline main equipment leaks.

(6) Service line 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) [Reserved]
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(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 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.

(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.

§98.233 Calculating GHG emissions.

You must calculate and report the annual GHG emissions as 

prescribed in this section. For actual conditions, 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 emissions from continuous high bleed, continuous low bleed, 
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and intermittent bleed natural gas pneumatic devices using 

Equation W-1 of this section.

Masst i Countt EFt GHGi Convi Tt* * * * ,  (Eq. W-1)

Where:

Masst,i = Annual total mass GHG emissions in metric tons CO2e 

per year from a natural gas pneumatic device vent 

of type “t”, 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), (a)(2), and (a)(3) of this 

section.

EFt = Population emission factors for natural gas 

pneumatic device venting listed in Tables W-1A, W3, 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.

GHGi = For onshore petroleum and natural gas production 

facilities, concentration of GHGi, CH4, or CO2, in 

natural gas as defined in paragraph (u)(2)(i) of 

this section and for onshore natural gas 

transmission compression and underground natural 

gas storage, GHGi equals 0.975 for CH4 and 1.1 × 10−2

for CO2.

Convi = Conversion from standard cubic feet to metric tons 

CO2e; 0.000479 for CH4, and 0.00005262 for CO2.

Tt = Average estimated number of hours in the operating 

year the devices, of each type t, were operational. 

Default is 8760 hours.

(1) For onshore petroleum and natural gas production, 

provide the total number of continuous high bleed, continuous 
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low bleed, or intermittent bleed natural gas pneumatic devices 

of each type as follows:

(i) In the first calendar year, for the total number of 

each type, you may count the total of each type, or count any 

percentage number of each type plus an engineering estimate 

based on best available data of the number not counted.

(ii) In the second consecutive year, for the total number 

of each type, you may count the total of each type, or count any 

percentage number of each type plus an engineering estimate 

based on best available data of the number not counted.

(iii) In the third consecutive calendar year, complete the 

count of all pneumatic devices, including any changes to 

equipment counted in prior years.

(iv) For the calendar year immediately following the third 

consecutive calendar year, and for calendar years thereafter, 

facilities must update the total count of pneumatic devices and 

adjust accordingly to reflect any modifications due to changes 

in equipment.

(2) For onshore natural gas transmission compression and 

underground natural gas storage, all natural gas pneumatic 

devices must be counted in the first year and updated every 

calendar year.
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(3) For all industry segments, determine the type of 

pneumatic device using engineering estimates based on best 

available information.

(b) [Reserved]

(c) Natural gas driven pneumatic pump venting. Calculate CH4

and CO2 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 paragraph (c) of this section.

Massi  Count * EF * GHGi*Convi* T (Eq. W-2)

Where:

Massi = Annual total mass GHG emissions in metric tons CO2e 

per year from all natural gas pneumatic pump 

venting, for GHGi.

Count = Total number of natural gas pneumatic pumps.

EF = Population emissions factors for natural gas 

pneumatic pump venting listed in Tables W-1A of 

this subpart for onshore petroleum and natural gas 

production.

GHGi = Concentration of GHGi, CH4, or CO2, in produced 

natural gas as defined in paragraph (u)(2)(i) of 

this section.

Convi = Conversion from standard cubic feet to metric tons 

CO2e; 0.000479 for CH4, and 0.00005262 for CO2.

T = Average estimated number of hours in the operating 

year the pumps were operational. Default is 8760 

hours.

(d) Acid gas removal (AGR) vents. For AGR vent (including 

processes such as amine, membrane, molecular sieve or other 
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absorbents and adsorbents), calculate emissions for CO2 only (not 

CH4 ) vented directly to the atmosphere or 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 methodologies 

described in paragraph (d) of this section, as applicable.

(1) Calculation Methodology 1. If you operate and maintain 

a 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 Methodology 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 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 Methodology in subpart C of this part (General 

Stationary Fuel Combustion). The calculation and reporting of CH4

and N2O emissions is not required as part of the Tier 4 

requirements for AGRs.
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(2) Calculation Methodology 2. If 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.

Ea,CO2 = VS * VolCO2 (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 = Volume fraction of CO2 content in vent gas out of 

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

section.

(3) Calculation Methodology 3. If 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

1

, 2 (Eq. W-4A)
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















 

I

I O

a CO out Vol

Vol Vol E V

1

, 2 (Eq. W-4B)

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 condition 

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 condition 

as determined using methods specified in paragraph 

(d)(5) of this section.

VolI = Volume fraction of CO2 content in natural gas into 

the AGR unit as determined in paragraph (d)(7) of 

this section.

Volo = Volume fraction of CO2 content in natural gas out of 

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

this section.

(4) Calculation Methodology 4. If CEMS or a vent meter is 

not installed, you may calculate emissions using any standard 

simulation software packages, such as AspenTech HYSYS® and 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.
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(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) Record the gas flow rate of the inlet and outlet 

natural gas stream of an AGR unit using a meter according to 

methods set 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) If 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 to determine 

VolCO2 according to methods set forth in §98.234(b).

(7) If a continuous gas analyzer is installed on the inlet 

gas stream, then the continuous gas analyzer results must be 

used. If continuous gas analyzer is not available, either 

install a continuous gas analyzer or take quarterly gas samples 

from the inlet gas stream to determine VolI according to methods 

set forth in §98.234(b).
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(8) Determine volume fraction of CO2 content in natural gas 

out of the AGR unit using one of the methods specified in 

paragraph (d)(8) 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 to determine VolO according to methods set forth in 

§98.234(b).

(iii) Use sales line quality specification for CO2 in 

natural gas.

(9) Calculate CO2 volumetric emissions at standard 

conditions using calculations in paragraph (t) of this section.

(10) Mass CO2 emissions shall be calculated from volumetric 

CO2 emissions using calculations in paragraph (v) of this 

section.

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

and transferred outside the facility. Adjust the emission 

estimated in paragraphs (d)(1) through (d)(10) of this section 

downward by the magnitude of emission recovered and transferred 

outside the facility.
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(e) Dehydrator vents. For dehydrator vents, calculate 

annual CH4, CO2 and N2O emissions using any of the calculation 

methodologies described in paragraph (e) of this section.

(1) Calculation Methodology 1. Calculate annual mass 

emissions from dehydrator vents with annual average daily 

throughput greater than or equal to 0.4 million standard cubic 

feet per day using a software program, such as AspenTech HYSYS®

or GRI-GLYCalc, 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. A minimum of 

the following parameters determined by engineering estimate 

based on best available data must be used to characterize 

emissions from dehydrators:

(i) Feed natural gas flow rate.

(ii) Feed natural gas water content.

(iii) Outlet natural gas water content.

(iv) Absorbent circulation pump type (natural gas 

pneumatic/air pneumatic/electric).

(v) Absorbent circulation rate.

(vi) Absorbent type: including triethylene glycol (TEG), 

diethylene glycol (DEG) or ethylene glycol (EG).
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(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 

by selecting one of the methods described under paragraph 

(e)(1)(xi) of this section.

(A) Use the wet natural gas composition as defined in 

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

(B) If wet natural gas composition cannot be determined 

using paragraph (u)(2)(i) or (u)(2)(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 Methodology 2. Calculate annual CH4 and CO2

emissions from glycol dehydrators with annual average daily 

throughput less than 0.4 million standard cubic feet per day 

using Equation W-5 of this section:
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* *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 CH4and 3.21 for CO2 at 60 °F and 

14.7 psia.

Count = Total number of glycol dehydrators with throughput 

less than 0.4 million standard cubic feet per day.

1000 = Conversion of EFi in thousand standard cubic feet to 

standard cubic feet.

(3) Determine if dehydrator unit has vapor recovery. Adjust 

the emissions estimated in paragraphs (e)(1) or (e)(2) of this 

section downward by the magnitude of emissions captured.

(4) Calculate annual emissions from dehydrator vents to 

flares or regenerator fire-box/fire tubes as follows:

(A) Use the dehydrator vent volume and gas composition as 

determined in paragraphs (e)(1) and (e)(2) of this section.

(B) Use the calculation methodology of flare stacks in 

paragraph (n) of this section to determine dehydrator vent 

emissions from the flare or regenerator combustion gas vent.

(5) Dehydrators that use desiccant shall 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 dehydrators covered in 
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Page 24 of 151

(e)(5) of this section do not have to report emissions under (i) 

of this section.

Es,n = (H*D2*P*P2*%G*365days/yr) (Eq. W-6)

 (4*P1*T*1,000cf/Mcf*100)

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).

P = pi (3.14).

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

N = Number of dehydrator openings in the calendar year.

100 = Conversion of %G to fraction.

(6) For glycol dehydrators, both CH4 and CO2 mass emissions 

shall be calculated from volumetric GHGi emissions using 

calculations in paragraph (v) of this section. For dehydrators 

that use desiccant, both CH4 and CO2 volumetric and mass 

emissions shall be calculated from volumetric natural gas 

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

section.

(f) Well venting for liquids unloadings. Calculate CO2 and 

CH4 emissions from well venting for liquids unloading using one 
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Page 25 of 151

of the calculation methodologies described in paragraphs (f)(1), 

(f)(2) or (f)(3) of this section.

(1) Calculation Methodology 1. For at least one well of 

each unique well tubing diameter group and pressure group 

combination in each sub-basin category (see §98.238 for the 

definitions of tubing diameter group, pressure group, and subbasin category), where gas wells are vented to the atmosphere to 

expel liquids accumulated in the tubing, a recording flow meter 

shall be installed 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 emissions from well venting for liquids 

unloading using Equation W-7 of this section.





h

p

Ea n TpFRp

1

, (Eq. W-7)

Where:

Ea,n = Annual natural gas emissions for all wells of the 

same tubing diameter group and pressure group 

combination in a sub-basin at actual conditions in 

cubic feet.

h = Total number of wells of the same tubing diameter 

group and pressure group combination in a subbasin.

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 
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Page 26 of 151

pressure group combination in a sub-basin during 

the year.

FR = Average flow rate in cubic feet per hour for all 

measured wells venting for the duration of the 

liquids unloading, under actual conditions as 

determined in paragraph (f)(1)(i) of this section.

(i) Determine the well vent average flow rate as specified 

under paragraph (f)(1)(i) of this section for at least one well 

in a unique well tubing diameter group and pressure group 

combination in each sub-basin category.

(A) The average flow rate per hour of venting is calculated 

for each unique tubing diameter group and pressure group 

combination in each sub-basin category by dividing the recorded 

total flow by the recorded time (in hours) for all measured 

liquid unloading events with venting to the atmosphere.

(B) This average flow rate per hour is applied 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) A new average flow rate is calculated every other 

calendar year for each reporting sub-basin category starting the 

first calendar year of data collection. For a new producing subbasin category, an average flow rate is calculated beginning in 

the first year of production.

(ii) Calculate natural gas volumetric emissions at standard 

conditions using calculations in paragraph (t) of this section.
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(2) Calculation Methodology 2. Calculate the total 

emissions for well venting for liquids unloading using Equation 

W-8 of this section.

       

 



















         

W

p

V

q

s n p p p p q 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,n = Annual natural gas emissions at standard 

conditions, in cubic feet/year.

W = Total number of wells with well venting for liquids 

unloading for each sub-basin.

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); or casing-totubing pressure ratio of one well with no packer 

from the same sub-basin multiplied by the tubing 

pressure of each well, p, in the sub-basin, in 

pounds per square inch absolute (psia).

Vp = Number of unloading events per year per well, p.

SFRp = Average flow-line rate of gas for well, p, at 

standard conditions in cubic feet per hour. Use 

Equation W-33 to calculate the average flow-line 

rate at standard conditions.

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.
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Page 28 of 151

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 Methodology 3. Calculate emissions 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 n p p p p q 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,n = Annual natural gas emissions at standard 

conditions, in cubic feet/year.

W = Total number of wells with plunger lift assist and 

well venting for liquids unloading for each subbasin.

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.

Vp = Number of unloading events per year for each well, 

p.

SFRp = Average flow-line rate of gas for well, p, at 

standard conditions in cubic feet per hour. Use 

Equation W-33 to calculate the average flow-line 

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.
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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.

(i)-(ii) [Reserved]

(4) Both CH4 and CO2 volumetric and mass emissions shall be 

calculated from volumetric natural gas emissions using 

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

(g) Gas well venting during completions and workovers from 

hydraulic fracturing. Calculate CH4, CO2 and N2O annual emissions 

from gas well venting during completions involving hydraulic 

fracturing in wells and well workovers using Equation W-10A or 

Equation W-10B of this section. Equation W-10A applies to well 

venting when the backflow rate is measured or calculated, 

Equation W-10B applies when the backflow vent or flare volume is 

measured. Use Equation W-10A if the flow rate for backflow 

during well completions and workovers from hydraulic fracturing 

is known for the specified number of wells per paragraph (g)(1) 

in a sub-basin and well type (horizontal or vertical) 

combination. Use Equation W-10B if the flow volume for backflow 

during well completions and workovers from hydraulic fracturing 

is known for all wells in a sub-basin and well type (horizontal 

or vertical) combination. Both CH4 and CO2 volumetric and mass 

emissions shall be calculated from volumetric total gas 
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Page 30 of 151

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

section.

 



    

W

p

Es n Tp FRM PRp EnFp SGp

1

, (Eq. W-10A)

 



 

W

p

Es n FVp EnFp

1

, (Eq. W-10B)

Where:

Es,n = Annual volumetric total gas emissions in cubic feet 

at standard conditions from gas well venting during 

completions or workovers following hydraulic 

fracturing for each sub-basin and well type 

(horizontal vs. vertical) combination.

W = Total number of wells completed or worked over 

using hydraulic fracturing in a sub-basin and well 

type (horizontal vs. vertical) combination.

Tp = Cumulative amount of time of backflow for the 

completion or workover, in hours, for each well, p, 

in a sub-basin and well type (horizontal vs. 

vertical) combination during the reporting year.

FRMs = Ratio of flowback during well completions and 

workovers from hydraulic fracturing to 30-day 

production rate from Equation W-12.

PRs,p = First 30-day average production flow rate in 

standard cubic feet per hour of each well p, as 

required in paragraph (g)(1) of this section.

EnFs,p = Volume of CO2 or N2 injected gas in cubic feet at 

standard conditions that was injected into the 

reservoir during an energized fracture job for each 

well p. If the fracture process did not inject gas 

into the reservoir, then EnFs,p is 0. If injected 

gas is CO2 then EnFs,p is 0.

SGs,p = Volume of natural gas in cubic feet at standard 

conditions that was recovered into a flow-line for 

well p as per paragraph (g)(3) of this section. 

This parameter includes any natural gas that is 
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Page 31 of 151

injected into the well for clean-up. If no gas was 

recovered, SGs,p is 0.

FVs,p = Flow volume of each well (p) in standard cubic feet 

measured using a recording flow meter (digital or 

analog) on the vent line to measure flowback during 

the completion or workover according to methods set 

forth in §98.234(b).

(1) The average flow rate for flowback during well 

completions and workovers from hydraulic fracturing shall be 

determined using measurement(s) for Calculation Methodology 1 or 

calculation(s) for Calculation Methodology 2 described in this 

paragraph (g)(1) of this section. If Equation W-10A is used, the 

number of measurements or calculations shall be determined per 

sub-basin and well type (horizontal or vertical) as follows: at 

least one measurement or calculation for less than or equal to 

25 completions or workovers; at least two measurements or 

calculations for 26 to 50 completions or workovers; at least 

three measurements or calculations for 51 to 100 completions or 

workovers; at least four measurements or calculations for 101 to 

250 completions or workovers; and at least five measurements or 

calculations for greater than 250 completions or workovers.

(i) Calculation Methodology 1. When using Equation W-10A, 

for each measured well completion(s) in each gas producing subbasin category and well type (horizontal or vertical) 

combination and for each measured well workover(s) in each gas 

producing sub-basin category and well type (horizontal or 
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Page 32 of 151

vertical) combination, a recording flow meter (digital or 

analog) shall be installed on the vent line, ahead of a flare or 

vent if used, to measure the backflow rate according to methods 

set forth in §98.234(b).

(ii) Calculation Methodology 2. When using Equation W-10A, 

for each calculated horizontal well completion and each 

calculated vertical well completion in each gas producing subbasin category and for each calculated well horizontal workover 

and for each calculated vertical well workover in each gas 

producing sub-basin category, record the well flowing pressure 

upstream (and downstream in subsonic flow) of a well choke 

according to methods set forth in §98.234(b) to calculate the 

well backflow during well completions and workovers from 

hydraulic fracturing. Calculate emissions using Equation W-11A 

of this section for subsonic flow or Equation W-11B of this 

section for sonic flow. Use best engineering estimate 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 is greater than or equal to 2, 

then flow is sonic; otherwise, flow is subsonic:

































 















 

1.758

1

2

1.515

1

5 2

1.27 10 * * 3430 * *

P

P

P

P

FR A Tu

(Eq. W-11A)

Where:
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Page 33 of 151

FRa = Average flow rate in cubic feet per hour, under 

actual subsonic flow conditions.

A = Cross sectional open area of the restriction 

orifice (m2).

P1 = Upstream pressure (psia).

Tu = Upstream temperature (degrees Kelvin).

P2 = Downstream pressure (psia).

3430 = Constant with units of m2 /(sec2 * K).

1.27*105 = Conversion from m 3 /second to ft3/hour.

FR A 08*Tu 1.27 10 * * 187.

5

  (Eq. W-11B)

Where:

FRa = Average flow rate in cubic feet per hour, under 

actual sonic flow conditions.

A = Cross sectional open area of the restriction 

orifice (m2).

Tu = Upstream temperature (degrees Kelvin).

187.08 = Constant with units of m2 /(sec2 * K).

1.27*105 = Conversion from m 3 /second to ft 3 /hour.

2

1

P

R  P

(Eq. W-11C)

Where:

R = Pressure ratio

P1 = Pressure upstream of the restriction orifice in 

pounds per square inch absolute.

P2 = Pressure downstream of the restriction orifice in 

pounds per square inch absolute.

(iii) For Equation W-10A, the ratio of backflow rate during 

well completions and workovers from hydraulic fracturing to 30-
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Page 34 of 151

day production rate is calculated using Equation W-12 of this 

section.









 W

p

p

W

p

p

PR

FR

FRM

1

1

(Eq. W-12)

Where:

FRMs = Ratio of flowback rate during well completions and 

workovers from hydraulic fracturing to 30-day 

production rate.

FRs,p = Measured flowback rate from Calculation Methodology 

1 described in paragraph (g)(1)(i) of this section 

or calculated flow rate from Calculation 

Methodology 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 

(horizontal or vertical) combination. Measured and 

calculated FRa values shall be converted from actual 

conditions (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 converted to a flow rate for this 

parameter.

PRs,p = First 30-day production rate in standard cubic feet 

per hour for each well p that was measured in the 

sub-basin and well type combination.

N = Number of measured or calculated well completions 

or workovers using hydraulic fracturing in a subbasin and well type combination.

(iv) For Equation W-10A, the ratio of backflow rate during 

well completions and workovers from hydraulic fracturing to 30-

day production rate for horizontal and vertical wells are 

applied to all horizontal and vertical well completions in the 
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Page 35 of 151

gas producing sub-basin and well type combination and to all 

horizontal and vertical well workovers, respectively, in the gas 

producing sub-basin and well type combination for the total 

number of hours of backflow for each of these wells.

(v) For Equation W-10A, new flow rates for horizontal and 

vertical gas well completions and horizontal and vertical gas 

well workovers in each sub-basin category shall be calculated 

once every two years starting in the first calendar year of data 

collection.

(2) The volume of CO2 or N2 injected into the well reservoir 

during energized hydraulic fractures will be measured using an 

appropriate meter as described in 98.234(b) or using receipts of 

gas purchases that are used for the energized fracture job.

(i) Calculate gas volume at standard conditions using 

calculations in paragraph (t) of this section.

(ii) [Reserved]

(3) Determine if the backflow gas from the well completion 

or workover from hydraulic fracturing is recovered with purpose 

designed equipment that separates natural gas from the backflow, 

and sends this natural gas to a flow-line (e.g.,reduced 

emissions completion or workovers).

(i) Use the factor SGs,P in Equation W-10A of this section, 

to adjust the emissions estimated in paragraphs (g)(1) through 
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Page 36 of 151

(g)(4) of this section by the magnitude of emissions captured 

using purpose designed equipment that separates saleable gas 

from the flowback as determined by engineering estimate based on 

best available data.

(ii) [Reserved]

(iii) Calculate gas volume at standard conditions using 

calculations in paragraph (t) of this section.

(4) Both CH4 and CO2 volumetric and mass emissions shall be 

calculated from volumetric total emissions using calculations in 

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

(5) Calculate annual emissions from gas well venting during 

well completions and workovers from hydraulic fracturing to 

flares as follows:

(i) Use the total gas well venting volume during well 

completions and workovers as determined in paragraph (g) of this 

section.

(ii) Use the calculation methodology of flare stacks in 

paragraph (n) of this section to determine gas well venting 

during well completions and workovers using hydraulic fracturing 

emissions from the flare. This adjustment to emissions from 

completions using flaring versus completions without flaring 

accounts for the conversion of CH4 to CO2 in the flare.
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(h) Gas well venting during completions and workovers 

without hydraulic fracturing. Calculate CH4, CO2 and N2O

emissions from each gas well venting during well completions and 

workovers not involving hydraulic fracturing using Equation W-13 

of this section:

p

f

p

Es n Nwo * EFwo Vp* T

1

, 

  (Eq. W-13)

Where:

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

from gas well venting during well completions and 

workovers without hydraulic fracturing.

Nwo = Number of workovers per sub-basin category that 

flare gas or vent gas to the atmosphere and 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. EFwo = 3114 standard cubic feet 

natural gas per well workover 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.

Vp = Average daily gas production rate in standard cubic 

feet per hour for each well completion without 

hydraulic fracturing, p. 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.
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Tp = Time each well completion without hydraulic 

fracturing, p, was venting in hours during the 

year.

(1) Volumetric emissions for both CH4 and CO2 shall be 

calculated from volumetric natural gas emissions using 

calculations in paragraph (u) of this section. Mass emissions 

for both CH4 and CO2 shall be calculated from volumetric natural 

gas emissions using calculations in paragraphs (v) of this 

section.

(2) Calculate annual emissions from gas well venting during 

well completions and workovers not involving hydraulic 

fracturing to flares as follows:

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

and workovers as determined in paragraph (h) of this section.

(ii) Use the calculation methodology of flare stacks in 

paragraph (n) of this section to determine gas well venting 

during well completions and workovers emissions without 

hydraulic fracturing from the flare.

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

vent stack emissions from depressurizing equipment(s) to reduce 

system pressure for planned or emergency shutdowns resulting 

from human intervention or to take equipment out of service for 

maintenance (excluding depressurizing to a flare, over-pressure 

relief, operating pressure control venting and blowdown of non-
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Page 39 of 151

GHG gases; desiccant dehydrator blowdown venting before 

reloading is covered in paragraph (e)(5) of this section) as 

follows:

(1) Calculate the unique physical volume (including 

pipelines, compressor case or cylinders, manifolds, suction 

bottles, discharge bottles, and vessels) between isolation 

valves determined by engineering estimates based on best 

available data.

(2) If the unique physical volume between isolation valves 

is greater than or equal to 50 cubic feet, retain logs of the 

number of blowdowns for each unique physical volume (including 

but not limited to compressors, vessels, pipelines, headers, 

fractionators, and tanks). Unique physical volumes smaller than 

50 cubic feet are exempt from reporting under paragraph (i) of 

this section.

(3) Calculate the total annual venting emissions for unique 

volumes using either Equation W-14A or W-14B of this section.

 

 





































 V C

T P

T P

E N V

a s

s a

s n

*

459.67

459.67 * , (Eq. W-14A)

Where:

Es,n = Annual natural gas venting emissions at standard 

conditions from blowdowns in cubic feet.

N = Number of occurrences of blowdowns for each unique 

physical volume in calendar year.
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Page 40 of 151

V = Unique physical volume (including pipelines, 

compressors and vessels) between isolation valves 

in cubic feet.

C = Purge factor that is 1 if the unique physical 

volume is not purged or zero 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).

Ps = Absolute pressure at standard conditions (14.7 

psia).

Pa = Absolute pressure at actual conditions in the 

unique physical volume (psia).

  

   

































 



N

p a s

s a b p a e p

s n

T P

T P P

E V

1

, , , ,

,

459.67

459.67

(Eq. W-14B)

Where:

Es,n = Annual natural gas venting emissions at standard 

conditions from blowdowns 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.

V = Total physical volume (including pipelines, 

compressors and vessels) 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”.
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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 

non-GHG gases.

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

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

(j) Onshore production 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 

(including stationary liquid storage not owned or operated by 

the reporter), calculate annual CH4 and CO2 emissions using any 

of the calculation methodologies described in this paragraph 

(j).

(1) Calculation Methodology 1. For separators with annual 

average daily throughput of oil greater than or equal to 10 

barrels per day. Calculate annual CH4 and CO2 emissions from 

onshore production storage tanks using operating conditions in 

the last wellhead gas-liquid separator 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 enters an atmospheric pressure storage tank. 

A minimum of the following parameters determined for typical 
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operating conditions over the year by engineering estimate and 

process knowledge based on best available data must be used to 

characterize emissions from liquid transferred to tanks.

(i) Separator temperature.

(ii) Separator 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 oil composition and Reid vapor pressure. If 

this data is not available, determine these parameters by 

selecting one of the methods described under paragraph (j)(1) 

(vii) of this section.

(A) If separator oil composition and Reid vapor pressure 

default data are provided with the software program, select the 

default values that most closely match your separator pressure 

first, and API gravity secondarily.

(B) If separator 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.

(C) Analyze a representative sample of separator oil in 

each sub-basin category for oil composition and Reid vapor 
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pressure using an appropriate standard method published by a 

consensus-based standards organization.

(2) Calculation Methodology 2. Calculate annual CH4 and CO2

emissions from onshore production storage tanks for wellhead

gas-liquid separators with annual average daily throughput of 

oil greater than or equal to 10 barrels per day by assuming 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.

(3) Calculation Methodology 3. For wells with annual 

average daily oil production greater than or equal to 10 barrels 

per day that flow directly to atmospheric storage tanks without 

passing through a wellhead separator, calculate annual CH4 and 

CO2 emissions by either of the methods in paragraph (j)(3) of 

this section:

(i) If well production oil and gas compositions are 

available through your previous analysis, select the latest 

available analysis that is representative of produced oil and 
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gas from the sub-basin category and assume all of the CH4 and CO2

in both oil and gas are emitted from the tank.

(ii) 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 

your 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.

(4) Calculation Methodology 4. For wells with annual 

average daily oil production greater than or equal to 10 barrels 

per day that flow to a separator not at the well pad, calculate 

annual CH4 and CO2 emissions by either of the methods in 

paragraph (j)(4) of this section:

(i) If well production oil and gas compositions are 

available through your previous analysis, select the latest 

available analysis that is representative of oil at separator 

pressure determined by best available data and assume all of the 

CH4and CO2 in the oil is emitted from the tank.

(ii) If well production oil composition is not available, 

use default oil composition in software programs, such as API 

4697 E&P Tank, that most closely match your well production API 

gravity and pressure in the off-well pad separator determined by 
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best available data. Assume all of the CH4 and CO2 in the oil 

phase is emitted from the tank.

(5) Calculation Methodology 5. For well pad gas-liquid 

separators and for wells flowing off a well pad without passing 

through a gas-liquid separator with annual average daily 

throughput of oil less than 10 barrels per day use 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 or wells 

in thousand standard cubic feet per separator or 

well 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 or wells with annual 

average daily throughput less than 10 barrels per 

day. Count only separators or wells that feed oil 

directly to the storage tank.

1,000 = Conversion from thousand standard cubic feet to 

standard cubic feet.

(6) Determine if the storage tank receiving your separator 

oil has a vapor recovery system.

(i) Adjust the emissions estimated in paragraphs (j)(1) 

through (j)(5) of this section downward by the magnitude of 
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emissions recovered using a vapor recovery system as determined 

by engineering estimate based on best available data.

(ii) [Reserved]

(7) 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.

(ii) Use the calculation methodology of flare stacks in 

paragraph (n) of this section to determine your contribution to 

storage tank emissions from the flare.

(8) Calculate emissions from occurrences of well pad gasliquid separator liquid dump valves not closing during the 

calendar year by using Equation W-16 of this section.

 











  











 n

n

n

n

s i n T

E

T

E

E CF * 8760

8760

*

8760 , * (Eq. W-16)

Where:

Es,i = Annual total volumetric GHG emissions at standard 

conditions from each storage tank in cubic feet.

En = Storage tank emissions as determined in Calculation 

Methodologies 1, 2, or 4 in paragraphs (j)(1), 

(j)(2) and (j)(4) of this section (with wellhead 

separators) in standard cubic feet per year.

Tn = Total time the dump valve is not closing properly 

in the calendar year in hours. Tn is estimated by 

maintenance or operations records (records) such 

that when a record shows the valve to be open 

improperly, it is assumed the valve was open for 

the entire time period preceding the record 
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starting at either the beginning of the calendar 

year or the previous record showing it closed 

properly within the calendar year. If a subsequent 

record shows it is closing properly, then assume 

from that time forward the valve closed properly 

until either the next record of it not closing 

properly or, if there is no subsequent record, the 

end of the calendar year.

CFn = Correction factor for tank emissions for time 

period Tn is 3.87 for crude oil production. 

Correction factor for tank emissions for time 

period Tn is 5.37 for gas condensate production. 

Correction factor for tank emissions for time 

period Tn is 1.0 for periods when the dump valve is 

closed.

8,760 = Conversion to hourly emissions.

(9) Calculate both CH4 and CO2 mass emissions from 

volumetric natural gas 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, CO2 and N2O annual 

emissions from compressor scrubber dump valve leakage as 

follows:

(1) Monitor the tank vapor vent stack annually for 

emissions using an optical gas imaging instrument according to 

methods set forth in §98.234(a)(1) or by directly measuring the 

tank vent using a flow meter or high volume sampler according to 

methods in §98.234(b) through (d) for a duration of 5 minutes, 
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or a calibrated bag according to methods in §98.234(b). Or 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 acoustic leak detection device detects a 

leak, then use one of the following two methods in paragraph 

(k)(2) of this section to quantify annual emissions:

(i) Use a meter, such as a turbine meter, calibrated bag, 

or high flow 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 §98.233(k)(1) of this section to detect continuous 

leakage, this serves as the measurement.

(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).

(iii) Use the appropriate gas composition in paragraph 

(u)(2)(iii) of this section.

(iv) Calculate GHG volumetric and mass emissions at 

standard conditions using calculations in paragraphs (t), (u), 
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and (v) of this section, as applicable to the monitoring 

equipment used.

(3) If the leaking dump valve(s) is fixed following leak 

detection, the annual emissions shall be calculated from the 

beginning of the calendar year to the time the valve(s) is 

repaired.

(4) Calculate annual emissions from storage tanks to flares 

as follows:

(i) Use the storage tank emissions volume and gas 

composition as determined in paragraphs (k)(1) through (k)(3) of 

this section.

(ii) Use the calculation methodology 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, CO2 and 

N2O (when flared) well testing venting and flaring emissions as 

follows:

(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 
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according to one of the two procedures in paragraph (l)(2) 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) Or you may use an industry standard practice as 

described in §98.234(b).

(3) Estimate venting emissions using Equation W-17A or 

Equation W-17B 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 = 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 year, 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 volumetric natural gas emissions using calculations in 

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

(6) Calculate emissions from well testing to flares as 

follows:

(i) Use the well testing emissions volume and gas 

composition as determined in paragraphs (l)(1) through (3) of 

this section.

(ii) Use the calculation methodology 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, CO2

and N2O (when flared) associated gas venting and flaring 

emissions not in conjunction with well testing (refer to 

paragraph (l): Well testing venting and flaring of this section) 

as follows:

(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, the GOR from a cluster of 

wells in the same sub-basin category shall be used.

(2) If GOR cannot be determined from your available data, 

then use one of the two procedures in paragraph (m)(2) of this 

section to determine GOR:
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(i) You may use an appropriate standard method published by 

a consensus-based standards organization if such a method 

exists.

(ii) Or 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

Ea n GORp q Vp q

1 1

, , , (Eq. W-18)

Where:

Ea,n = Annual volumetric natural gas emissions, at the 

facility level, from associated gas venting under 

actual conditions, in cubic feet.

GORp,q = Gas to oil ratio, for well p in sub-basin q, in 

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 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 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 volumetric natural gas emissions using calculations in 

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

(6) Calculate emissions from associated natural gas to 

flares as follows:

(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 methodology 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 follows:

(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 

continuous flow measurement device on the flare, you can install 

a flow measuring device on the flare or use engineering 

calculations based on process knowledge, company records, and 

best available data.
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(2) If you have a continuous gas composition analyzer on 

gas to the flare, you must use these compositions in calculating 

emissions. If you do not have a continuous gas composition 

analyzer on gas to the flare, you must use the appropriate gas 

compositions for each stream of hydrocarbons going to the flare 

as follows:

(i) For onshore natural gas production, determine natural 

gas composition using (u)(2)(i) of this section.

(ii) For onshore natural gas processing, when the stream 

going to flare is natural gas, use the GHG mole percent in feed 

natural gas for all streams upstream of the de-methanizer or dew 

point control, and GHG mole percent in facility specific residue 

gas to transmission pipeline systems for all emissions sources 

downstream of the de-methanizer overhead or dew point control 

for onshore natural gas processing facilities. 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.

(iii) For any applicable industry segment, 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 
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the source for the stream determined by engineering calculation 

based on process knowledge and best available data.

(3) Determine flare combustion efficiency from 

manufacturer. If not available, assume that flare combustion 

efficiency is 98 percent.

(4) Calculate GHG volumetric emissions at actual conditions 

using Equations W-19, W-20, and W-21 of this section.

  , 4 * 4 *(1 ) a CH Va X CH E un  combusted  

(Eq. W-19)

  a,CO2 Va * X CO2 E un  combusted 

(Eq. W-20)

   





5

1

, 2

* * *

J

a CO Va Yj Rj E combusted  (Eq. W-21)

Where:

Ea,CH4 (un-combusted) = Contribution of annual un-combusted CH4

emissions from flare stack in cubic feet, 

under actual conditions.

Ea,CO2 (un-combusted) = Contribution of annual un-combusted CO2

emissions from flare stack in cubic feet, 

under actual conditions.

Ea,CO2 (combusted) = Contribution of annual combusted CO2

emissions from flare stack in cubic feet, 

under actual conditions.

Va = Volume of gas sent to flare in cubic feet, during 

the year.

η = Fraction of gas combusted by a burning flare 

(default is 0.98). For gas sent to an unlit flare, 

η is zero.

XCH4 = Mole fraction of CH4 in gas to the flare.

XCO2 = Mole fraction of CO2 in gas to the flare.
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Yj = Mole fraction of gas hydrocarbon constituents j 

(such as methane, ethane, propane, butane, and 

pentanes-plus).

Rj = Number of carbon atoms in the gas hydrocarbon 

constituent j: 1 for methane, 2 for ethane, 3 for 

propane, 4 for butane, and 5 for pentanes-plus).

(5) Calculate GHG volumetric emissions at standard 

conditions using calculations in paragraph (t) of this section.

(6) Calculate both CH4 and CO2 mass emissions from 

volumetric CH4 and CO2 emissions using calculation in paragraph 

(v) of this section.

(7) [Reserved]

(8) Calculate N2O emissions from flare stacks using Equation 

W-40 in paragraph (z) of this section.

(9) If you operate and maintain a CEMS that has both a CO2

concentration monitor and volumetric flow rate monitor, you must 

calculate only CO2 emissions for the flare. You must follow the

Tier 4 Calculation Methodology 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 (n)(7) are not required. If a CO2 concentration monitor 

and volumetric flow rate monitor are not available, you may 

elect to install a CO2 concentration monitor and a volumetric 
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flow rate monitor that comply with all of the requirements 

specified for the Tier 4 Calculation Methodology in subpart C of 

this part (General Stationary Fuel Combustion).

(10) The flare emissions determined under paragraph (n) of 

this section must be corrected for flare emissions calculated 

and reported under other paragraphs of this section to avoid 

double counting of these emissions.

(11) If source types in §98.233 use Equations W-19 through 

W-21 of this section, use estimate of emissions under actual 

conditions for the parameter, Va, in these equations.

(o) Centrifugal compressor venting. Calculate CH4, CO2 and 

N2O (when flared) emissions from both wet seal and dry seal 

centrifugal compressor vents as follows:

(1) For each centrifugal compressor covered by §98.232 

(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) you must conduct an 

annual measurement in the operating mode in which it is found. 

Measure emissions from all vents (including emissions manifolded 

to common vents) including wet seal oil degassing vents, unit 

isolation valve vents, and blowdown valve vents. Record 

emissions from the following vent types in the specified 

compressor modes during the annual measurement.

(i) Operating mode, blowdown valve leakage through the 

blowdown vent, wet seal and dry seal compressors.
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(ii) Operating mode, wet seal oil degassing vents.

(iii) Not operating, depressurized mode, unit isolation 

valve leakage through open blowdown vent, without blind flanges, 

wet seal and dry seal compressors.

(A) For the not operating, depressurized mode, each 

compressor must be measured at least once in any three 

consecutive calendar years. If a compressor is not operated and 

has blind flanges in place throughout the 3 year period, 

measurement is not required in this mode. If the compressor is 

in standby depressurized mode without blind flanges in place and 

is not operated throughout the 3 year period, it must be 

measured in the standby depressurized mode.

(2) For wet seal oil degassing vents, determine vapor 

volumes sent to an atmospheric vent or flare, using a temporary 

meter such as a vane anemometer or permanent flow meter 

according to 98.234(b) of this section. If you do not have a 

permanent flow meter, you may install a permanent flow meter on 

the wet seal oil degassing tank vent.

(3) For blowdown valve leakage and unit isolation valve 

leakage to open ended vents, you can use one of the following 

methods: Calibrated bagging or high volume sampler according to 

methods set forth in §98.234(c) and §98.234(d), respectively. 

For through valve leakage, such as isolation valves, you may use 
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an acoustic leak detection device according to methods set forth 

in §98.234(a). If you do not have a flow meter, you may install 

a port for insertion of a temporary meter, or a permanent flow 

meter, on the vents.

(4) Estimate annual emissions using the flow measurement 

and Equation W-22 of this section.

* * *(1 ) Es,i,m MTm Tm Mi,m  Bm (Eq. W-22)

Where:

Es,i,m = Annual GHGi (either CH4 or CO2 ) volumetric 

emissions at standard conditions, in cubic feet.

MTm = Measured gas emissions in standard cubic feet per 

hour.

Tm = Total time the compressor is in the mode for which 

Es,i is being calculated, in the calendar year in 

hours.

Mi,m = Mole fraction of GHGi in the vent gas; use the 

appropriate gas compositions in paragraph (u)(2) of 

this section.

Bm = Fraction of operating time that the vent gas is 

sent to vapor recovery or fuel gas as determined by 

keeping logs of the number of operating hours for 

the vapor recovery system and the time that vent 

gas is directed to the fuel gas system or sales.

(5) Calculate annual emissions from each centrifugal 

compressor using Equation W-23 of this section.

mEs,i EFm *Tm *GHGi (Eq. W-23)

Where:
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Es,i,m = Annual total volumetric GHG emissions at standard 

conditions from each centrifugal compressor for 

mode-source combination m, in cubic feet.

EFm = Reporter emission factor for each mode m, in cubic 

feet per hour, from Equation W-24 of this section 

as calculated in paragraph 6.

Tm = Total time in hours per year the compressor was in 

each mode, as listed in paragraph (o)(1)(i) through 

(o)(1)(iii).

GHGi = For onshore natural gas processing facilities, 

concentration of GHGi, CH4 or CO2, in produced 

natural gas or feed natural gas; for other 

facilities listed in §98.230(a)(4) through 

(a)(8),GHGi equals 1.

(6) You shall use the flow measurements of operating mode 

wet seal oil degassing vent, operating mode blowdown valve vent 

and not operating depressurized mode isolation valve vent for 

all the reporter's compressor modes not measured in the calendar

year to develop the following emission factors using Equation W24 of this section for each emission source and mode as listed 

in paragraph (o)(1)(i) through (o)(1)(iii).

 m

m

m

Count

MT EF (Eq. W-24)

Where:

EFm = Reporter emission factors for compressor in the 

three modes m (as listed in paragraph (o)(1)(i) 

through (o)(1)(iii)) in cubic feet per hour.

MTm,p = Flow measurements from all centrifugal compressor 

sources in each mode-source combination, m, for 

each measured compressor, p, in standard cubic feet 

per hour.
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Countm = Total number of compressors measured.

m = Compressor mode-source combination as listed in 

paragraphs (o)(1)(i) through (o)(1)(iii).

(i) The emission factors must be calculated annually. You 

must use all measurements from the current calendar year and the 

preceding two calendar years, totaling three consecutive 

calendar years of measurements in paragraph (o)(6) of this 

section.

(ii) [Reserved]

(7) Onshore petroleum and natural gas production shall 

calculate emissions from centrifugal compressor wet seal oil 

degassing vents as follows:

Es i Count EFi* ,  (Eq. W-25)

Where:

Es,i = Annual total volumetric GHG emissions at standard 

conditions from centrifugal compressor wet seals in 

cubic feet.

Count = Total number of centrifugal compressors for the 

reporter.

EFi = Emission factor for 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.

(8) Calculate both CH4 and CO2 mass emissions from 

volumetric emissions using calculations in paragraph (v) of this 

section.
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(9) Calculate emissions from seal oil degassing vent vapors 

to flares as follows:

(i) Use the seal oil degassing vent vapor volume and gas 

composition as determined in paragraphs (o)(5) of this section.

(ii) Use the calculation methodology of flare stacks in 

paragraph (n) of this section to determine degassing vent vapor 

emissions from the flare.

(p) Reciprocating compressor venting. Calculate CH4 and CO2

emissions from all reciprocating compressor vents as follows. 

For each reciprocating compressor covered in §98.232(d)(1), 

(e)(1), (f)(1), (g)(1), and (h)(1) you must conduct an annual 

measurement for each compressor in the mode in which it is found 

during the annual measurement, except as specified in paragraph 

(p)(9) of this section. Measure emissions from (including 

emissions manifolded to common vents) reciprocating rod packing 

vents, unit isolation valve vents, and blowdown valve vents. 

Record emissions from the following vent types in the specified 

compressor modes during the annual measurement as follows:

(1) Operating or standby pressurized mode, blowdown vent 

leakage through the blowdown vent stack.

(2) Operating mode, reciprocating rod packing emissions.

(3) Not operating, depressurized mode, unit isolation valve 

leakage through the blowdown vent stack, without blind flanges.
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(i) For the not operating, depressurized mode, each 

compressor must be measured at least once in any three 

consecutive calendar years if this mode is not found in the 

annual measurement. If a compressor is not operated and has 

blind flanges in place throughout the 3 year period, measurement 

is not required in this mode. If the compressor is in standby 

depressurized mode without blind flanges in place and is not 

operated throughout the 3 year period, it must be measured in 

the standby depressurized mode.

(ii) [Reserved]

(4) If reciprocating rod packing and blowdown vent are 

connected to an open-ended vent line use one of the following 

two methods to calculate emissions:

(i) Measure emissions from all vents (including emissions 

manifolded to common vents) including rod packing, unit 

isolation valves, and blowdown vents using either calibrated 

bagging or high volume sampler according to methods set forth in 

§98.234(c) and §98.234(d), respectively.

(ii) Use a temporary meter such as a vane anemometer or a 

permanent meter such as an orifice meter to measure emissions 

from all vents (including emissions manifolded to a common vent) 

including rod packing vents and unit isolation valve leakage 

through blowdown vents according to methods set forth in 
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§98.234(b). If you do not have a permanent flow meter, you may 

install a port for insertion of a temporary meter or a permanent 

flow meter on the vents. For through-valve leakage to open ended 

vents, such as unit isolation valves on not operating, 

depressurized compressors and blowdown valves on pressurized 

compressors, you may use an acoustic detection device according 

to methods set forth in §98.234(a).

(5) If reciprocating rod packing is not equipped with a 

vent line use the following method to calculate emissions:

(i) You must use the methods described in §98.234(a) to 

conduct annual leak detection of equipment leaks from the 

packing case into an open distance piece, or from the compressor 

crank case breather cap or other vent with a closed distance 

piece.

(ii) Measure emissions found in paragraph (p)(5)(i) of this 

section using an appropriate meter, or calibrated bag, or high 

volume sampler according to methods set forth in §98.234(b), 

(c), and (d), respectively.

(6) Estimate annual emissions using the flow measurement 

and Equation W-26 of this section.

Es,i,m MTm Tm Mi,m  * * (Eq. W-26)

Where:
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Es,i,m = Annual GHG i (either CH4 or CO2 ) volumetric 

emissions at standard conditions, in cubic feet.

MTm = Measured gas emissions in standard cubic feet per 

hour.

Tm = Total time the compressor is in the mode for which 

Es,i,m is being calculated, in the calendar year in 

hours.

Mi,m = Mole fraction of GHG i in gas; use the appropriate 

gas compositions in paragraph (u)(2) of this 

section.

(7) Calculate annual emissions from each reciprocating 

compressor using Equation W-27 of this section.

mEs,i EFm *Tm *GHGi (Eq. W-27)

Where:

Es,i,m = Annual total volumetric GHG emissions at standard 

conditions from each reciprocating compressor for 

mode-source combination m, in cubic feet.

EFm = Reporter emission factor for each mode, m, in cubic 

feet per hour, from Equation W-28 of this section 

as calculated in paragraph (p)(7)(i) of this 

section.

Tm = Total time in hours per year the compressor was in 

each mode, m, as listed in paragraph (p)(1) through 

(p)(3).

GHGi = For onshore natural gas processing facilities, 

concentration of GHG i, CH4 or CO2, in produced 

natural gas or feed natural gas; for other 

facilities listed in §98.230(a)(4) through (a)(8), 

GHGi equals 1.

m = Compressor mode as listed in paragraph (p)(1) 

through (p)(3).

(i) You shall use the flow meter readings from measurements 

of operating and standby pressurized blowdown vent, operating 
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mode vents, not operating depressurized isolation valve vent for 

all the reporter's compressor modes not measured in the calendar 

year to develop the following emission factors using Equation W28 of this section for each mode as listed in paragraph (p)(1) 

through (p)(3).

 m

m

m

Count

MT EF (Eq. W-28)

Where:

EFm = Reporter emission factors for compressor in the 

three modes, m, in cubic feet per hour.

MTm,p = Flow measurements from all reciprocating compressor 

sources in each mode-source combination, m, for 

each measured compressor, p, in standard cubic feet 

per hour.

Countm = Total number of compressors measured in each mode, 

m.

m = Compressor mode-source combination as listed in 

(p)(1) through (p)(3).

(A) You must combine emissions for blowndown vents, 

measured in the operating and standby pressurized modes.

(B) The emission factors must be calculated annually. You 

must use all measurements from the current calendar year and the 

preceding two calendar years, totaling three consecutive 

calendar years of measurements.

(ii) [Reserved]
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(8) Determine if the reciprocating compressor vent vapors 

are sent to a vapor recovery system.

(i) Adjust the emissions estimated in paragraphs (p)(7) of 

this section downward by the magnitude of emissions recovered 

using a vapor recovery system as determined by engineering 

estimate based on best available data.

(ii) [Reserved]

(9) Onshore petroleum and natural gas production shall 

calculate emissions from reciprocating compressors as follows:

Es i Count EFi* ,  (Eq. W-29)

Where:

Es,i = Annual total volumetric GHG emissions at standard 

conditions from reciprocating compressors in cubic 

feet.

Count = Total number of reciprocating compressors for the 

reporter.

EFi = Emission factor for 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.

(10) Estimate CH4 and CO2 volumetric and mass emissions from 

volumetric natural gas emissions using the calculations in 

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

(q) Leak detection and leaker emission factors. You must 

use the methods described in §98.234(a) to conduct leak 

detection(s) of equipment leaks from all component types listed 
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in §98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). 

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 10 percent 

CH4 plus CO2 by weight do not need to be reported. Tubing systems 

equal to or less than one half inch diameter are exempt from the 

requirements of this paragraph (q) and do not need to be 

reported. If equipment leaks are detected for sources listed in 

this paragraph (q), calculate equipment leak emissions per 

component type per reporting facility using Equations W-30A or 

W-30B of this section for each component type. Use Equation W30A for industry segments listed in 98.230(a)(3)-(a)(7). Use 

Equation W-30B for industry segments listed in 98.230(a)(8).

 





x

p

Es i GHGi EF Tp

1

, * * (Eq. W-30A)

  

   



t

q t n

x

p

Es i GHGi EF Tp q

1 1

, * * , (Eq. W-30B)

Where:

Es,i = Annual total volumetric GHG emissions at standard 

conditions from each component type in cubic feet, 

as specified in (q)(1) through (q)(8) of this 

section.

x = Total number of each component type.

EF = Leaker emission factor for specific component types 

listed in Table W-2 through Table W-7 of this 

subpart.
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GHGi = 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 = The total time the component, p, was found leaking 

and operational, in hours. If one leak detection 

survey is conducted, assume the component was 

leaking for the entire calendar year. If multiple 

leak detection surveys are conducted, assume that 

the component found to be leaking has been leaking 

since the previous survey (if not found leaking in 

the previous survey) or the beginning of the 

calendar year (if it was found leaking in the 

previous survey). 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.

t = Calendar year of reporting.

n = The number of years over which one complete cycle 

of leak detection is conducted over all the T-D 

transfer stations in a natural gas distribution 

facility; 0 < n ≤ 5. For the first (n-1) calendar 

years of reporting the summation in Equation W-30B 

should be for years that the data is available.

Tp,q = The total time the component, p, was found leaking 

and operational, in hours, in year q. If one leak 

detection survey is conducted, assume the component 

was leaking for the entire period n. If multiple 

leak detection surveys are conducted, assume that 

the component found to be leaking has been leaking 

since the previous survey (if not found to be 

leaking in the previous survey) or the beginning of 

the calendar year (if it was found to be leaking in 

the previous survey). For the last leak detection

survey in the cycle, assume that all leaking 

components continue to leak until the end of the 

cycle.
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(1) You must select to conduct either one leak detection 

survey in a calendar year or multiple complete leak detection 

surveys in a calendar year. The number of leak detection surveys 

selected must be conducted during the calendar year.

(2) Calculate GHG mass emissions in carbon dioxide 

equivalent at standard conditions using calculations in 

paragraph (v) of this section.

(3) Onshore natural gas processing facilities shall use the 

appropriate default leaker emission factors listed in Table W-2 

of this subpart for equipment leaks detected from valves, 

connectors, open ended lines, pressure relief valves, and 

meters.

(4) Onshore natural gas transmission compression facilities 

shall use the appropriate default leaker emission factors listed 

in Table W-3 of this subpart for equipment leaks detected from 

valves, connectors, open ended lines, pressure relief valves, 

and meters.

(5) Underground natural gas storage facilities for storage 

stations shall use the appropriate default leaker emission 

factors listed in Table W-4 of this subpart for equipment leaks 

detected from valves, connectors, open ended lines, pressure 

relief valves, and meters.
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(6) LNG storage facilities shall use the appropriate 

default leaker emission factors listed in Table W-5 of this 

subpart for equipment leaks detected from valves, pump seals, 

connectors, and other.

(7) LNG import and export facilities shall use the 

appropriate default leaker emission factors listed in Table W-6 

of this subpart for equipment leaks detected from valves, pump 

seals, connectors, and other.

(8) Natural gas distribution facilities for above grade 

transmission-distribution transfer stations, shall use the 

appropriate default leaker emission factors listed in Table W-7 

of this subpart for equipment leaks detected from connectors, 

block valves, control valves, pressure relief valves, orifice 

meters, regulators, and open ended lines. Leak detection at 

natural gas distribution facilities is only required at above 

grade stations that qualify as transmission-distribution 

transfer stations. Below grade transmission-distribution 

transfer stations and all metering-regulating stations that do 

meet the definition of transmission-distribution transfer 

stations are not required to perform component leak detection 

under this section.

(i) Natural gas distribution facilities may choose to 

conduct leak detection at the T-D transfer stations over 
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multiple years, not exceeding a five year period to cover all TD transfer stations. If the facility chooses to use the multiple 

year option then the number of T-D transfer stations that are 

monitored in each year should be approximately equal across all 

years in the cycle without monitoring the same station twice 

during the multiple year survey.

(ii) [Reserved]

(r) Population count and emission factors. This paragraph 

applies to emissions sources listed in §98.232 (c)(21), (f)(5), 

(g)(3), (h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on 

streams with gas content greater than 10 percent CH4 plus CO2 by 

weight. Emissions sources in streams with gas content less than 

10 percent CH4 plus CO2 by weight do not need to be reported. 

Tubing systems equal 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. Calculate emissions from all 

sources listed in this paragraph using Equation W-31 of this 

section.

Es i Counts EFs GHGi Ts* * * ,  (Eq. W-31)

Where:

Es,i = Annual volumetric GHG emissions at standard 

conditions from each component type in cubic feet.

Counts = Total number of this type of emission source at the 

facility. For onshore petroleum and natural gas 
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production, 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. Underground natural gas storage shall 

count the components listed for population emission 

factors in Table W-4. LNG Storage shall count the 

number of vapor recovery compressors. LNG import 

and export shall count the number of vapor recovery 

compressors. Natural gas distribution shall count 

the meter/regulator runs as described in paragraph 

(r)(6) of this section.

EF = Population emission factor for the specific 

component type, as listed in Table W-1A and Tables 

W-3 through Table W-7 of this subpart. Use 

appropriate population emission factor for 

operations in Eastern and Western U.S., according 

to Table W-1D of this subpart. EF for 

meter/regulator runs at above grade meteringregulating stations is determined in Equation W-32 

of this section.

GHGi = For onshore petroleum and natural gas production 

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 × 10−2CO2.

Ts = Average estimated time that each component type 

associated with the equipment leak emission was 

operational in the calendar year, in hours, 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.
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(2) Onshore petroleum and natural gas production facilities 

shall use the appropriate default population emission factors 

listed in Table W-1A of this subpart for equipment leaks from 

valves, connectors, open ended lines, pressure relief valves, 

pump, flanges, and other. Major equipment and components 

associated with gas wells are considered gas service components 

in reference to Table W-1A of this subpart and major natural gas 

equipment in reference to Table W-1B of this subpart. Major 

equipment and components associated with crude oil wells are 

considered crude service components in reference to Table 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 methodologies described in this 

paragraph (r)(2). The same methodology must be used for the 

entire calendar year.

(i) Component Count Methodology 1. For all onshore 

petroleum and natural gas production operations in the facility 

perform the following activities:
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(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.

(B) Multiply major equipment counts by the average 

component counts listed in Table W-1B and W-1C of this subpart 

for onshore natural gas production and onshore oil production, 

respectively. Use the appropriate factor in Table W-1A of this 

subpart for operations in Eastern and Western U.S. according to 

the mapping in Table W-1D of this subpart.

(ii) Component Count Methodology 2. Count each component 

individually for the facility. Use the appropriate factor in 

Table W-1A of this subpart for operations in Eastern and Western 

U.S. according to the mapping in Table W-1D of this subpart.

(3) Underground natural gas storage facilities for storage 

wellheads shall use the appropriate default population emission 

factors listed in Table W-4 of this subpart for equipment leak 

from connectors, valves, pressure relief valves, and open ended 

lines.

(4) LNG storage facilities shall use the appropriate 

default population emission factors listed in Table W-5 of this 

subpart for equipment leak from vapor recovery compressors.

(5) LNG import and export facilities shall use the 

appropriate default population emission factor listed in Table 
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W-6 of this subpart for equipment leak from vapor recovery 

compressors.

(6) Natural gas distribution facilities shall use the 

appropriate emission factors as described in paragraph (r)(6) of 

this section.

(i) Below grade metering-regulating stations; distribution 

mains; and distribution services, shall use the appropriate 

default population emission factors listed in Table W-7 of this 

subpart. Below grade T-D transfer stations shall use the 

emission factor for below grade metering-regulating stations.

(ii) Emissions from all above grade metering-regulating 

stations (including above grade TD transfer stations) shall be 

calculated by applying the emission factor calculated in 

Equation W-32 and the total count of meter/regulator runs at all 

above grade metering-regulating stations (inclusive of TD 

transfer stations) to Equation W-31. The facility wide emission 

factor in Equation W-32 will be calculated by using the total 

volumetric GHG emissions at standard conditions for all 

equipment leak sources calculated in Equation W-30B in paragraph 

(q)(8) of this section and the count of meter/regulator runs 

located at above grade transmission-distribution transfer 

stations that were monitored over the years that constitute one 

complete cycle as per paragraph (q)(8)(i) of this section. A 
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meter on a regulator run is considered one meter/regulator run. 

Reporters that do not have above grade T-D transfer stations 

shall report a count of above grade metering-regulating stations 

only and do not have to comply with §98.236(c)(16)(xix).

Count

E

EF s,i  8760 (Eq. W-32)

Where:

EF = Facility emission factor for a meter/regulator run 

per component type at above grade meteringregulating for GHGi in cubic feet per 

meter/regulator run per hour.

Es,i = Annual volumetric GHG i emissions, CO2 or CH4 at 

standard condition from each component type at all 

above grade TD transfer stations, from Equation W30B.

Count = Total number of meter/regulator runs at all TD 

transfer stations that were monitored over the 

years that constitute one complete cycle as per 

(q)(8)(i) of this section.

8760 = Conversion to hourly emissions

(s) Offshore petroleum and natural gas production 

facilities. Report CO2, CH4, and N2O emissions for offshore 

petroleum and natural gas production from all equipment leaks, 

vented emission, and flare emission source types as identified 

in the data collection and emissions estimation study conducted 

by BOEMRE in compliance with 30 CFR 250.302 through 304.

(1) Offshore production facilities under BOEMRE 

jurisdiction shall report the same annual emissions as 
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calculated and reported by BOEMRE in data collection and 

emissions estimation study published by BOEMRE referenced in 30 

CFR 250.302 through 304 (GOADS).

(i) For any calendar year that does not overlap with the 

most recent BOEMRE emissions study publication year, report the 

most recent BOEMRE reported emissions data published by BOEMRE 

referenced in 30 CFR 250.302 through 304 (GOADS). Adjust 

emissions based on the operating time for the facility relative 

to the operating time in the most recent BOEMRE published study.

(ii) [Reserved]

(2) Offshore production facilities that are not under 

BOEMRE jurisdiction shall use monitoring methods and calculation 

methodologies published by BOEMRE referenced in 30 CFR 250.302 

through 304 to calculate and report emissions (GOADS).

(i) For any calendar year that does not overlap with the 

most recent BOEMRE emissions study publication, report the most 

recent reported emissions data with emissions adjusted based on 

the operating time for the facility relative to operating time 

in the previous reporting period.

(ii) [Reserved]

(3) If BOEMRE discontinues or delays their data collection 

effort by more than 4 years, then offshore reporters shall once 

in every 4 years use the most recent BOEMRE data collection and 
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emissions estimation methods to report emission from the 

facility sources.

(4) For either first or subsequent year reporting, offshore 

facilities either within or outside of BOEMRE jurisdiction that 

were not covered in the previous BOEMRE data collection cycle 

shall use the most recent BOEMRE data collection and emissions 

estimation methods published by BOEMRE referenced in 30 CFR 

250.302 through 304 to calculate and report emissions (GOADS) to 

report emissions.

(t) Volumetric emissions. If equation parameters in §98.233 

are already at standard conditions, 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 n s a

s n

T P

E T P

E

459.67 *

, * 459.67 *

,





 (Eq. W-33)
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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).

(2) Calculate GHG volumetric emissions at standard 

conditions using actual GHG emissions temperature and pressure, 

and Equation W-34 of this section.

(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).

 

  a s

a i s a

s i

T P

E T P

E

459 .67 *

, * 459 .67 *

,






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(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. Calculate GHG volumetric 

emissions at standard conditions as specified in paragraphs 

(u)(1) and (2) of this section, with mole fraction of GHGs in 

the natural gas determined by engineering estimate based on best 

available data unless otherwise specified.

(1) Estimate CH4 and CO2 emissions from natural gas 

emissions using Equation W-35 of this section.

(Eq. W-35)

Where:

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

standard conditions in cubic feet.

Es,n = Natural gas volumetric emissions at standard 

conditions in cubic feet.

Mi = Mole fraction of GHG i in the natural gas.

(2) For Equation W-35 of this section, the mole fraction, 

Mi, shall be the annual average mole fraction for each 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. If you have a 

continuous gas composition analyzer for produced natural gas, 

Es i Es n M i* ,  ,
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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 de-methanizer or dew point 

control and GHG mole fraction in facility specific residue gas 

to transmission pipeline systems for all emissions sources 

downstream of the de-methanizer overhead or dew point control 

for onshore natural gas processing facilities. For onshore 

natural gas processing plants that solely fractionate a liquid 

stream, use the GHG mole percent in feed natural gas liquid for 

all streams. If you have a continuous gas composition analyzer 

on feed natural gas, you must use these values for determining 

the mole fraction. If you do not have a continuous gas 

composition analyzer, then annual samples must be taken 

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

(iii) GHG mole fraction in transmission pipeline natural 

gas that passes through the facility for the onshore natural gas 

transmission compression industry segment. You may use a default 
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95 percent methane and 1 percent carbon dioxide fraction for GHG 

mole fraction in natural gas.

(iv) GHG mole fraction in natural gas stored in the 

underground natural gas storage industry segment. You may use a 

default 95 percent methane and 1 percent carbon dioxide fraction 

for GHG mole fraction in natural gas.

(v) GHG mole fraction in natural gas stored in the LNG 

storage industry segment. You may use a default 95 percent 

methane and 1 percent carbon dioxide fraction for GHG mole 

fraction in natural gas.

(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 a default 

95 percent methane and 1 percent carbon dioxide fraction for GHG 

mole fraction in natural gas.

(vii) GHG mole fraction in local distribution pipeline 

natural gas that passes through the facility for natural gas 

distribution facilities. You may use a default 95 percent 

methane and 1 percent carbon dioxide fraction for GHG mole 

fraction in natural gas.

(v) GHG mass emissions. Calculate GHG mass emissions in 

carbon dioxide equivalent by converting the GHG volumetric 
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emissions at standard conditions into mass emissions using 

Equation W-36 of this section.

3

, * * *10  Massi Es i i GWP (Eq. W-36)

Where:

Massi = GHGi (either CH4, CO2, or N2O) mass emissions in 

metric tons CO2e.

Es,i = GHGi (either CH4, CO2, or N2O) volumetric emissions 

at standard conditions, in cubic feet.

Pi = 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.

GWP = Global warming potential, 1 for CO2, 25 for CH4, and 

298 for N2O.

(w) EOR injection pump blowdown. Calculate CO2 pump blowdown 

emissions as follows:

(1) Calculate the total volume in cubic feet (including 

pipelines, manifolds and vessels) between isolation valves.

(2) Retain logs of the number of blowdowns per calendar 

year.

(3) Calculate the total annual venting emissions using 

Equation W-37 of this section:

3

2

* * *

2

*10 MassCO  N Vv Rc GHGCO (Eq. W-37)

Where:

MassCO2 = Annual EOR injection gas venting emissions in 

metric tons from blowdowns.

N = Number of blowdowns for the equipment in the 

calendar year.
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Vv = Total volume in cubic feet of blowdown equipment 

chambers (including pipelines, manifolds and 

vessels) between isolation valves.

Rc = Density of critical phase EOR injection gas in 

kg/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.

1 × 10−3= Conversion factor from kilograms to metric tons.

(x) EOR hydrocarbon liquids dissolved CO2. Calculate 

dissolved CO2 in hydrocarbon liquids produced through EOR 

operations as follows:

(1) Determine the amount of CO2 retained in hydrocarbon 

liquids after flashing in tankage at STP conditions. Annual 

samples must be taken according to methods set forth in 

§98.234(b) to determine retention of CO2 in hydrocarbon liquids 

immediately downstream of the storage tank. Use the annual 

analysis for the calendar year.

(2) Estimate emissions using Equation W-38 of this section.

MassCO2 = Shl * Vhl (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 in 

metric tons per barrel, under standard conditions.
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Vhl = Total volume of hydrocarbon liquids produced at the 

EOR operations in barrels in the calendar year.

(y) [Reserved]

(z) Onshore petroleum and natural gas production and 

natural gas distribution combustion emissions. Calculate CO2,CH4,

and N2O combustion-related emissions from stationary or portable 

equipment, except as specified in paragraph (z)(3) and (z)(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 emissions according to (z)(1)(i). 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 methodology described 

in (z)(1)(i) 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 (z)(2). If the fuel is field gas, process vent gas, 

or a blend containing field gas or process vent gas, calculate 

emissions according to (z)(2).

(i) For fuels listed in Table C-1 or a blend containing one 

or more fuels listed in Table C-1, calculate CO2, CH4, and N2O
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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 natural gas and petroleum 

production facilities and at natural gas distribution facilities 

will be reported according to the requirements specified in 

98.236(c)(19) 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.

(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 
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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

, 2

( *

2

) * * *

j

Ea CO Va YCO  Va Yj Rj (Eq. W-39A)

  Ea,CH 4  Va * 1  *YCH 4 (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 cubic 

feet, during the year.

YCO2 = Concentration 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 = Concentration 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.
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YCH4 = Concentration of methane constituent in gas sent to 

combustion unit.

(iv) Calculate GHG volumetric emissions at standard 

conditions using calculations in paragraph (t) of this section.

(v) Calculate both combustion-related CH4 and CO2 mass 

emissions from volumetric CH4 and CO2 emissions using calculation 

in paragraph (v) of this section.

(vi) Calculate N2O mass emissions using Equation W-40 of 

this section.

Mass N O     Fuel  HHV  EF  GWP 3

2 1 10

(Eq. W-40)

Where:

MassN2O = Annual N2O emissions from the combustion of a 

particular type of fuel (metric tons CO2e).

Fuel = Mass or volume of the fuel combusted (mass or 

volume per year, choose appropriately to be 

consistent with the units of HHV).

HHV = For the higher heating value for field gas or 

process vent gas, use 1.235 × 10−3 mmBtu/scf for 

HHV.

EF = Use 1.0 × 10−4 kg N2O/mmBtu.

1 × 10−3= Conversion factor from kilograms to metric tons.

GWP = Global warming potential, as listed in Table A-1 of 

subpart A of this part.

(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 
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determination in §98.231(a). You must report the type and number 

of each external fuel combustion unit.

(4) Internal fuel combustion sources, not compressordrivers, 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.

§98.234 Monitoring and QA/QC requirements.

The GHG emissions data for petroleum and natural gas 

emissions sources must be quality assured as applicable as 

specified in this section. Offshore petroleum and natural gas 

production facilities shall adhere to the monitoring and QA/QC 

requirements as set forth in 30 CFR 250.

(a) You must use any of the methods described as follows in 

this paragraph to conduct leak detection(s) of equipment leaks 

and through-valve leakage from all source types listed in 

§98.233(k), (o), (p) and (q) that occur during a calendar year, 

except as provided in paragraph (a)(4) of this section.

(1) Optical gas imaging instrument. Use an optical gas 

imaging instrument for equipment leak detection in accordance 

with 40 CFR part 60, subpart A, §60.18 of the Alternative work 

practice for monitoring equipment leaks,§60.18(i)(1)(i); 
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§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 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. 
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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 through-valve 

leakage, you must use the instrument manufacturer's calculation 

methods to quantify the through-valve leak. When using the 

acoustic leak detection device, if a leak of 3.1 scf per hour or 

greater is calculated, a leak is detected. In addition, you must 

operate the acoustic leak detection device to monitor the source 

valves required by this subpart in accordance with the 

instrument manufacturer's operating parameters. Acoustic 
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stethoscope type devices designed to detect through valve 

leakage when put in contact with the valve body and that provide 

an audible leak signal but do not calculate a leak rate can be 

used to identify 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.

(b) You must operate and calibrate all flow meters, 

composition analyzers and pressure gauges used to measure 

quantities reported in §98.233 according to the procedures in 

§98.3(i) and the procedures in paragraph (b) of this section. 

You may use an appropriate standard method published by a 

consensus-based standards organization if such a method exists 

or you may use an industry standard practice. Consensus-based 

standards organizations include, but are not limited to, the 

following: ASTM International, the American National Standards 

Institute (ANSI), the American Gas Association (AGA), the 

American Society of Mechanical Engineers (ASME), the American 

Petroleum Institute (API), and the North American Energy 

Standards Board (NAESB).

(c) Use calibrated bags (also known as vent bags) only 

where the emissions are at near-atmospheric pressures and below 

the maximum temperature specified by the vent bag manufacturer 
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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).

(d) Use a high volume sampler to measure emissions within 

the capacity of the instrument.

(1) A technician following manufacturer instructions shall 

conduct measurements, including equipment manufacturer operating 

procedures and measurement methodologies relevant to using a 

high volume sampler, including positioning the instrument for 

complete capture of the equipment leak without creating 

backpressure on the source.
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(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 CH4and CO2

volumetric and mass emissions from volumetric natural gas 

emissions using the calculations in §98.233(u) and (v).

(4) Calibrate the instrument at 2.5 percent methane with 

97.5 percent air and 100 percent CH4 by using calibrated gas 

samples and by following manufacturer's instructions for 

calibration.

(e) Peng Robinson Equation of State means the equation of 

state defined by Equation W-41 of this section:

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.

Vm = Molar volume.
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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

  (Eq. W-42)

Where:

ω = Acentric factor of the species.

Tc = Critical temperature.

Pc = Critical pressure.

(f) Special reporting provisions

(1) Best available monitoring methods. EPA will allow 

owners or operators to use best available monitoring methods for 

parameters in §98.233 Calculating GHG Emissions as specified in 

paragraphs (f)(2), (f)(3), and (f)(4) of this section. If the 

reporter anticipates the potential need for best available 

monitoring for sources for which they need to petition EPA and 

the situation is unresolved at the time of the deadline, 

reporters should submit written notice of this potential 

situation to EPA by the specified deadline for requests to be 

considered. EPA reserves the right to review best available 

monitoring method requests submitted after the deadlines 

specified in this section, and will consider requests which 
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demonstrate unique or unusual circumstances unforeseen at the 

time of the applicable best available monitoring method 

deadline. The Administrator reserves the right to request 

further information in regard to all petition requests. The 

owner or operator must use the calculation methodologies and 

equations in §98.233 Calculating GHG Emissions. Best available 

monitoring methods means any of the following methods specified 

in paragraph (f)(1) of this section:

(i) Monitoring methods currently used by the facility that 

do not meet the specifications of this subpart.

(ii) Supplier data.

(iii) Engineering calculations.

(iv) Other company records.

(2) Best available monitoring methods for well-related 

emissions. During January 1, 2011 through December 31, 2011, 

owners and operators may use best available monitoring methods 

for any well-related data that cannot reasonably be measured 

according to the monitoring and QA/QC requirements of this 

subpart. These well-related sources are:

(i) Gas well venting during well completions and workovers 

with hydraulic fracturing as specified in §98.233(g).

(ii) Well testing venting and flaring as specified in 

§98.233(l).
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(3) Best available monitoring methods for specified 

activity data. During January 1, 2011 through December 31, 2011, 

owners or operators may use best available monitoring methods 

for activity data as listed below that cannot reasonably be 

obtained according to the monitoring and QA/QC requirements of 

this subpart. These sources are:

(i) Cumulative hours of venting, days, or times of 

operation in §98.233(e), (f), (g), (h), (l), (o), (p), (q), and 

(r).

(ii) Number of blowdowns, completions, workovers, or other 

events in §98.233(f), (g), (h), (i), and (w).

(iii) Cumulative volume produced, volume input or output, 

or volume of fuel used in paragraphs §98.233(d), (e), (j), (k), 

(l), (m), (n), (x), (y), and (z).

(4) Best available monitoring methods for leak detection 

and measurement. During January 1, 2011 through December 31, 

2011, owners or operators may use best available monitoring 

methods for sources requiring leak detection and/or measurement 

that cannot reasonably be obtained according to the monitoring 

and QA/QC requirements of this part. These sources include:

(i) Reciprocating compressor rod packing venting in onshore 

natural gas processing, onshore natural gas transmission 

compression, underground natural gas storage, LNG storage, and 
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LNG import and export equipment as specified in §98.232(d)(1), 

(e)(1), (f)(1), (g)(1), and (h)(1).

(ii) Centrifugal compressor wet seal oil degassing venting 

in onshore natural gas processing, onshore natural gas 

transmission compression, underground natural gas storage, LNG 

storage, and LNG import and export equipment as specified in 

§98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2).

(iii) Acid gas removal vent stacks in onshore petroleum and 

natural gas production and onshore natural gas processing as 

specified in §98.232(c)(17) and (d)(6).

(iv) Equipment leak emissions from valves, connectors, open 

ended lines, pressure relief valves, block valves, control 

valves, compressor blowdown valves, orifice meters, other 

meters, regulators, vapor recovery compressors, centrifugal 

compressor dry seals, and/or other equipment leaks in onshore 

natural gas processing, onshore natural gas transmission 

compression, underground natural gas storage, LNG storage, LNG 

import and export equipment, and natural gas distribution as 

specified in §98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and 

(i)(1).

(v) Condensate (oil and/or water) storage tanks in onshore 

natural gas transmission compression as specified in 

§98.232(e)(3).
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(5) Requests for the use of best available monitoring 

methods.

(i) No request or approval by the Administrator is 

necessary to use best available monitoring methods between 

January 1, 2011 and December 31, 2011 for the sources specified 

in paragraph (f)(2) of this section.

(ii) No request or approval by the Administrator is 

necessary to use best available monitoring methods between 

January 1, 2011 and December 31, 2011 for sources specified in 

paragraph (f)(3) of this section.

(iii) No request or approval by the Administrator is 

necessary to use best available monitoring methods between 

January 1, 2011 and December 31, 2011 for sources specified in 

paragraph (f)(4) of this section.

(iv) No request or approval by the Administrator is 

necessary to use best available monitoring methods for data that 

cannot reasonably be obtained between January 1, 2011 and 

December 31, 2011 for sources not listed in paragraph (f)(2), 

(f)(3), and (f)(4) of this section.

(6) [Reserved]

(7) [Reserved]
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(8) Requests for extension of the use of best available 

monitoring methods beyond 2011 for sources listed in paragraphs 

(f)(2), (f)(3), (f)(4), and (f)(5)(iv) of this section.

(i) Timing of Request. EPA does not anticipate a need for 

best available monitoring methods beyond 2011, but for all 

reporting years after 2011, best available monitoring methods 

will be considered for unique or unusual circumstances which 

include data collection methods that do not meet safety 

regulations, technical infeasibility, or counter to other local, 

State, or Federal regulations. For use of best available 

monitoring methods in 2012, an initial notice of intent to 

request best available monitoring methods must be submitted by 

December 31, 2011. Any notice of intent submitted prior to the 

effective date of this rule cannot be used to meet this December 

31, 2011 deadline; a new notice of intent must be signed and 

submitted by the designated representative. In addition to the 

initial notification of intent, owners or operators must also 

submit an extension request containing the information specified 

in 98.234(f)(8)(ii) by March 30, 2012. Any best available 

monitoring methods request submitted prior to the effective date 

of this rule cannot be used to meet the March 30, 2012 deadline; 

a new best available monitoring methods request must be signed 

and submitted by the designated representative. Owners or 
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operators that submit both a timely notice of intent and 

extension request consistent with 98.234(f)(8)(ii) can 

automatically use BAMM through June 30, 2012, for the specific 

parameters identified in their notification of intent and best 

available monitoring methods request regardless of whether the 

best available monitoring methods request is ultimately 

approved. Owners or operators that submit a notice of intent but 

do not follow up with a best available monitoring methods 

request by March 30, 2012 cannot use best available monitoring 

methods in 2012. For 2012, when an owner or operator has 

submitted a notice of intent and a subsequent best available 

monitoring method extension request, use of best available 

monitoring methods will be valid, upon approval by the 

Administrator, until the date indicated in the approval or until 

December 31, 2012, whichever is earlier. For reporting years 

after 2012 a new request to use best available monitoring 

methods must be submitted by September 30th of the year prior to 

the reporting year for which use of best available monitoring 

methods is sought.

(ii) Content of request. Requests must contain the 

following information:
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(A) A list of specific source categories and parameters for 

which the owner or operator is seeking use of best available 

monitoring methods.

(B) For each specific source for which an owner or operator 

is requesting use of best available monitoring methods, a 

description of the unique or unusual circumstances, such as data 

collection methods that do not meet safety regulations, 

technical infeasibility, or specific laws or regulations that 

are counter to data collection methods that conflict with each 

specific source.

(C) A detailed explanation and supporting documentation of 

how and when the owner or operator will comply with all of the 

subpart W reporting requirements for which use of best available 

monitoring methods are sought.

(iii) Approval criteria. To obtain approval to use best 

available monitoring methods after December 31, 2011, the owner 

or operator must submit a request demonstrating to the 

Administrator's satisfaction that the owner or operator faces 

unique or unusual circumstances which include, by way of example 

and not in limitation, clearly demonstrated data collection 

methods that do not meet safety regulations, technical 

infeasibility, or counter to other local, State, or Federal 

regulations, along with the reasons the owner or operator cannot 
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otherwise address the unique or unusual circumstances as 

required to be demonstrated in this paragraph.

(g) For the purposes of fulfilling requirements in 40 CFR 

98.233(f) and (g) which require measurements to be taken every 

other year beginning in the first year of data collection, 

reporters have the option of taking the first measurement in 

2012 to satisfy the requirements for the 2011-2012 data 

collection cycle.

(h) [Reserved]

§98.235 Procedures for estimating missing data.

A complete record of all estimated and/or measured 

parameters used in the GHG emissions calculations is required. 

If data are lost or an error occurs during annual emissions 

estimation or measurements, you must repeat the estimation or 

measurement activity for those sources as soon as possible, 

including in the subsequent calendar year if missing data are 

not discovered until after December 31 of the year in which data 

are collected, until valid data for reporting is obtained. Data 

developed and/or collected in a subsequent calendar year to 

substitute for missing data cannot be used for that subsequent 

year's emissions estimation. Where missing data procedures are 

used for the previous year, at least 30 days must separate 

emissions estimation or measurements for the previous year and 
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emissions estimation or measurements for the current year of 

data collection. For missing data which are continuously 

monitored or measured, (for example flow meters), or for missing 

temperature or pressure data that are required under §98.236, 

the reporter may use best available data for use in emissions 

determinations. The reporter must record and report the basis 

for the best available data in these cases.

§98.236 Data reporting requirements.

In addition to the information required by §98.3(c), each 

annual report must contain reported emissions and related 

information as specified in this section.

(a) Report annual emissions in metric tons of CO2e for each 

GHG separately for each of the industry segments listed in 

paragraphs (a)(1) through (8) of this section.

(1) Onshore petroleum and natural gas production.

(2) Offshore petroleum and natural gas production.

(3) Onshore natural gas processing.

(4) Onshore natural gas transmission compression.

(5) Underground natural gas storage.

(6) LNG storage.

(7) LNG import and export.

(8) Natural gas distribution.
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(b) For offshore petroleum and natural gas production, 

report emissions of CH4, CO2, and N2O as applicable to the source 

type (in metric tons CO2e per year at standard conditions) 

individually for all of the emissions source types listed in the 

most recent BOEMRE study.

(c) Report the information listed in this paragraph for 

each applicable source type in metric tons of CO2e for each GHG. 

If a facility operates under more than one industry segment, 

each piece of equipment should be reported under the unit's 

respective majority use segment. When a source type listed under 

this paragraph routes gas to flare, separately report the 

emissions that were vented directly to the atmosphere without 

flaring, and the emissions that resulted from flaring the gas. 

Both the vented and flared emissions will be reported under the 

respective source type and not under the flare source type.

(1) For natural gas pneumatic devices (refer to Equation W1 of §98.233), report the following:

(i) Actual count and estimated count separately of natural 

gas pneumatic high bleed devices as applicable.

(ii) Actual count and estimated count separately of natural 

gas pneumatic low bleed devices as applicable.

(iii) Actual count and estimated count separately of 

natural gas pneumatic intermittent bleed devices as applicable.
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(iv) Report annual CO2 and CH4 emissions at the facility 

level, expressed in metric tons CO2e for each gas, for each of 

the following pieces of equipment: high bleed pneumatic devices; 

intermittent bleed pneumatic devices; low bleed pneumatic 

devices.

(2) For natural gas driven pneumatic pumps (refer to 

Equation W-2 of §98.233), report the following,

(i) Count of natural gas driven pneumatic pumps.

(ii) Report annual CO2 and CH4 emissions at the facility 

level, expressed in metric tons CO2e for each gas, for all 

natural gas driven pneumatic pumps combined.

(3) For each acid gas removal unit (refer to Equation W-3 

and Equation W-4 of §98.233), report the following:

(i) Total throughput off the acid gas removal unit using a 

meter or engineering estimate based on process knowledge or best 

available data in million cubic feet per year.

(ii) For Calculation Methodology 1 and Calculation 

Methodology 2 of §98.233(d), annual average fraction of CO2

content in the vent from the acid gas removal unit (refer to 

§98.233(d)(6)).

(iii) For Calculation Methodology 3 of §98.233(d), annual 

average volume fraction of CO2 content of natural gas into and 
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out of the acid gas removal unit (refer to §98.233(d)(7) and 

(d)(8)).

(iv) Report the annual quantity of CO2, expressed in metric 

tons CO2e, that was recovered from the AGR unit and transferred 

outside the facility, under subpart PP of this part.

(v) Report annual CO2 emissions for the AGR unit, expressed 

in metric tons CO2e.

(vi) For the onshore natural gas processing industry 

segment only, report a unique name or ID number for the AGR 

unit.

(vii) An indication of which calculation methodology was

used for the AGR.

(4) For dehydrators, report the following:

(i) For each Glycol dehydrator with a throughput greater 

than or equal to 0.4 MMscfd (refer to §98.233(e)(1)), report the 

following:

(A) Glycol dehydrator feed natural gas flow rate in MMscfd, 

determined by engineering estimate based on best available data.

(B) Glycol dehydrator absorbent circulation pump type.

(C) Whether stripper gas is used in glycol dehydrator.

(D) Whether a flash tank separator is used in glycol 

dehydrator.

(E) Type of absorbent.
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(F) Total time the glycol dehydrator is operating in hours.

(G) Temperature, in degrees Fahrenheit and pressure, in 

psig, of the wet natural gas.

(H) Concentration of CH4 and CO2 in wet natural gas.

(I) What vent gas controls are used (refer to §98.233(e)(3) 

and (e)(4)).

(J) For each glycol dehydrator, report annual CO2 and CH4

emissions that resulted from venting gas directly to the 

atmosphere, expressed in metric tons CO2e for each gas.

(K) For each glycol dehydrator, report annual CO2, CH4, and 

N2O emissions that resulted from flaring process gas from the 

dehydrator, expressed in metric tons CO2e for each gas.

(L) For the onshore natural gas processing industry segment 

only, report a unique name or ID number for glycol dehydrator.

(ii) For all glycol dehydrators with a throughput less than 

0.4 MMscfd (refer to §98.233, Equation W-5 of §98.233), report 

the following:

(A) Count of glycol dehydrators.

(B) Which vent gas controls are used (refer to 

§98.233(e)(3) and (e)(4)).

(C) Report annual CO2 and CH4 emissions at the facility 

level that resulted from venting gas directly to the atmosphere, 

expressed in metric tons CO2e for each gas, combined for all 
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glycol dehydrators with annual average daily throughput of less 

than 0.4 MMscfd.

(D) Report annual CO2, CH4, and N2O emissions at the 

facility level that resulted from the flaring of process gas, 

expressed in metric tons CO2e for each gas, combined for all 

glycol dehydrators with annual average daily throughput of less 

than 0.4 MMscfd.

(iii) For absorbent desiccant dehydrators (refer to 

Equation W-6 of §98.233), report the following:

(A) Count of desiccant dehydrators.

(B) Report annual CO2 and CH4 emissions at the facility 

level, expressed in metric tons CO2e for each gas, for all 

absorbent desiccant dehydrators combined.

(5) For well venting for liquids unloading, report the 

following:

(i) For Calculation Methodology 1 (refer to Equation W-7 of 

§98.233), report the following for each tubing diameter group 

and pressure group combination within each sub-basin category:

(A) Count of wells vented to the atmosphere for liquids 

unloading.

(B) Count of plunger lifts. Whether the selected well from 

the tubing diameter and pressure group combination had a plunger 

lift (yes/no).
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(C) Cumulative number of unloadings vented to the 

atmosphere.

(D) Average flow rate of the measured well venting in cubic 

feet per hour (refer to §98.233(f)(1)(i)(A)).

(E) Internal casing diameter or internal tubing diameter in 

inches, where applicable, and well depth of each well, in feet, 

selected to represent emissions in that tubing size and pressure 

combination.

(F) Casing pressure, in psia, of each well selected to 

represent emissions in that tubing size group and pressure group 

combination that does not have a plunger lift.

(G) Tubing pressure, in psia, of each well selected to 

represent emissions in a tubing size group and pressure group 

combination that has a plunger lift.

(H) Report annual CO2 and CH4 emissions, expressed in metric 

tons CO2e for each gas.

(ii) For Calculation Methodologies 2 and 3 (refer to 

Equation W-8 and W-9 of §98.233), report the following for each 

sub-basin category:

(A) Count of wells vented to the atmosphere for liquids 

unloading.

(B) Count of plunger lifts.
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(C) Cumulative number of unloadings vented to the 

atmosphere.

(D) Average internal casing diameter, in inches, for all 

wells, where applicable.

(E) Report annual CO2 and CH4 emissions, expressed in metric 

tons CO2e for each GHG gas.

(6) For well completions and workovers, report the 

following for each sub-basin category:

(i) For gas well completions and workovers with hydraulic 

fracturing by sub-basin and well type (horizontal or vertical) 

combination (refer to Equation W-10A and W-10B of §98.233), 

report the following:

(A) Total count of completions in calendar year.

(B) When using Equation W-10A, measured flow rate of 

backflow during well completion in standard cubic feet per hour.

(C) Total count of workovers in calendar year that flare 

gas or vent gas to the atmosphere.

(D) When using Equation W-10A, measured flow rate of 

backflow during well workover in standard cubic feet per hour.

(E) When using Equation W-10A, total number of days of 

backflow from all wells during completions.

(F) When using Equation W-10A, total number of days of 

backflow from all wells during workovers.
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(G) Report number of completions employing purposely 

designed equipment that separates natural gas from the backflow 

and the amount of natural gas, in standard cubic feet, recovered 

using engineering estimate based on best available.

(H) Report number of workovers employing purposely designed 

equipment that separates natural gas from the backflow and the 

amount of natural gas, in standard cubic feet, recovered using 

engineering estimate based on best available data.

(I) Annual CO2 and CH4 emissions that resulted from venting 

gas directly to the atmosphere, expressed in metric tons CO2e for 

each gas.

(J) Annual CO2, CH4, and N2O emissions that resulted from 

flares, expressed in metric tons CO2e for each gas.

(ii) For gas well completions and workovers without 

hydraulic fracturing (refer to Equation W-13 of §98.233):

(A) Total count of completions in calendar year.

(B) Total count of workovers in calendar year that flare 

gas or vent gas to the atmosphere.

(C) Total number of days of gas venting to the atmosphere 

during backflow for completion.

(D) Annual CO2 and CH4 emissions that resulted from venting 

gas directly to the atmosphere, expressed in metric tons CO2e for 

each gas.
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(E) Annual CO2, CH4, and N2O emissions that resulted from 

flares, expressed in metric tons CO2e for each gas.

(7) For blowdown vent stack emission source, (refer to 

Equation W-14A and Equation W-14B of §98.233), report the 

following:

(i) For each unique physical volume that is blown down more 

than once during the calendar year, report the following:

(A) Total number of blowdowns for each unique physical 

volume in the calendar year.

(B) Annual CO2 and CH4 emissions, for each unique physical 

blowdown volume, expressed in metric tons CO2e for each gas.

(C) A unique name or ID number for the unique physical 

volume.

(ii) For all unique volumes that are blown down once during 

the calendar year, report the following:

(A) Total number of blowdowns for all unique physical 

volumes in the calendar year.

(B) Annual CO2 and CH4 emissions from all unique physical 

volumes as an aggregate per facility, expressed in metric tons 

CO2e for each gas.

(8) For gas emitted from produced oil sent to atmospheric 

tanks:
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(i) For wellhead gas-liquid separator with oil throughput 

greater than or equal to 10 barrels per day, using Calculation 

Methodology 1 and 2 of §98.233(j), report the following by subbasin category, unless otherwise specified:

(A) Number of wellhead separators sending oil to 

atmospheric tanks.

(B) Estimated average separator temperature, in degrees 

Fahrenheit, and estimated average pressure, in psig.

(C) Estimated average sales oil stabilized API gravity, in 

degrees.

(D) Count of hydrocarbon tanks at well pads.

(E) Best estimate of count of stock tanks not at well pads 

receiving your oil.

(F) Total volume of oil from all wellhead separators sent 

to tank(s) in barrels per year.

(G) Count of tanks with emissions control measures, either 

vapor recovery system or flaring, for tanks at well pads.

(H) Best estimate of count of stock tanks assumed to have 

emissions control measures not at well pads, receiving your oil.

(I) Range of concentrations of flash gas, CH4 and CO2.

(J) Annual CO2 and CH4 emissions that resulted from venting 

gas to the atmosphere, expressed in metric tons CO2e for each 

gas, for all wellhead gas-liquid separators or storage tanks 
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using Calculation Methodology 1, and for all wellhead gas-liquid 

separators or storage tanks using Calculation Methodology 2 of 

§98.233(j).

(K) Annual CO2 and CH4 gas quantities that were recovered, 

expressed in metric tons CO2e for each gas, for all wellhead gasliquid separators or storage tanks using Calculation Methodology 

1, and for all wellhead gas-liquid separators or storage tanks 

using Calculation Methodology 2 of §98.233(j).

(L) Annual CO2, CH4, and N2O emissions that resulted from 

flaring gas, expressed in metric tons CO2e for each gas, for all 

wellhead gas-liquid separators or storage tanks using 

Calculation Methodology 1, and for all wellhead gas-liquid 

separators or storage tanks using Calculation Methodology 2 of 

§98.233(j).

(ii) For wells with oil production greater than or equal to 

10 barrels per day, using Calculation Methodology 3 and 4 of 

§98.233(j), report the following by sub-basin category:

(A) Total volume of sales oil from all wells in barrels per 

year.

(B) Total number of wells sending oil directly to tanks.

(C) Total number of wells sending oil to separators off the 

well pads.
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(D) Sales oil API gravity range for wells in (c)(8)(ii)(B) 

and (c)(8)(ii)(C) of this section, in degrees.

(E) Count of hydrocarbon tanks on wellpads.

(F) Count of hydrocarbon tanks, both on and off well pads 

assumed to have emissions control measures: either vapor 

recovery system or flaring of tank vapors.

(G) Annual CO2 and CH4 emissions that resulted from venting 

gas to the atmosphere, expressed in metric tons CO2e for each 

gas, at the sub-basin level for Calculation Methodology 3 or 4 

of §98.233(j).

(H) Annual CO2 and CH4 gas quantities that were recovered, 

expressed in metric tons CO2e for each gas, at the sub-basin 

level for Calculation Methodology 3 or 4 of §98.233(j).

(I) Annual CO2, CH4, and N2O emissions that resulted from 

flaring gas, expressed in metric tons CO2e for each gas, at the 

sub-basin level for Calculation Methodology 3 and 4 of 

§98.233(j).

(iii) For wellhead gas-liquid separators and wells with 

throughput less than 10 barrels per day, using Calculation 

Methodology 5 of §98.233(j) Equation W-15 of §98.233, report the 

following:

(A) Number of wellhead separators.

(B) Number of wells without wellhead separators.
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(C) Total volume of oil production in barrels per year.

(D) Best estimate of fraction of production sent to tanks 

with assumed control measures: either vapor recovery system or 

flaring of tank vapors.

(E) Count of hydrocarbon tanks on well pads.

(F) Annual CO2 and CH4 emissions that resulted from venting 

gas to the atmosphere, expressed in metric tons CO2e for each 

gas, at the sub-basin level for Calculation Methodology 5 of 

§98.233(j).

(G) Annual CO2 and CH4 gas quantities that were recovered, 

expressed in metric tons CO2e for each gas, at the sub-basin 

level for Calculation Methodology 5 of §98.233(j).

(H) Annual CO2, CH4, and N2O emissions that resulted from 

flaring gas, expressed in metric tons CO2e for each gas, at the 

sub-basin level for Calculation Methodology 5 of §98.233(j).

(iv) If wellhead separator dump valve is functioning 

improperly during the calendar year (refer to Equation W-16 of 

§98.233), report the following:

(A) Count of wellhead separators that dump valve factor is 

applied.

(B) Annual CO2 and CH4 emissions that resulted from venting 

gas to the atmosphere, expressed in metric tons CO2e for each 
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gas, at the sub-basin level for improperly functioning dump 

valves.

(9) For transmission tank emissions identified in 

§98.233(k) from scrubber dump valves report the following:

(i) For each vent stack, report annual CO2 and CH4 emissions 

that resulted from venting gas directly to the atmosphere, 

expressed in metric tons CO2e for each gas.

(ii) For each transmission storage tank, report annual CO2,

CH4, and N2O emissions that resulted from flaring process gas 

from the transmission storage tank, expressed in metric tons CO2e 

for each gas.

(iii) A unique name or ID number for the vent stack 

monitored according to 40 CFR 98.233(k).

(10) For well testing venting and flaring (refer to 

Equation W-17A or W-17B of §98.233), report the following:

(i) Number of wells tested per basin in calendar year.

(ii) Average gas to oil ratio for each basin.

(iii) Average number of days the well is tested in a basin.

(iv) Report annual CO2 and CH4 emissions at the facility 

level, expressed in metric tons CO2e for each gas, emissions from 

well testing venting.
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(v) Report annual CO2, CH4, and N2O emissions at the facility 

level, expressed in metric tons CO2e for each gas, emissions from 

well testing flaring.

(11) For associated natural gas venting and flaring (refer 

to Equation W-18 of §98.233), report the following for each 

basin:

(i) Number of wells venting or flaring associated natural 

gas in a calendar year.

(ii) Average gas to oil ratio for each basin.

(iii) Report annual CO2 and CH4 emissions at the facility 

level, expressed in metric tons CO2e for each gas, emissions from 

associated natural gas venting.

(iv) Report annual CO2, CH4, and N2O emissions at the 

facility level, expressed in metric tons CO2e for each gas, 

emissions from associated natural gas flaring.

(12) For flare stacks (refer to Equation W-19, W-20, and W21 of §98.233), report the following for each flare:

(i) Whether flare has a continuous flow monitor.

(ii) Volume of gas sent to flare in cubic feet per year.

(iii) Percent of gas sent to un-lit flare determined by 

engineering estimate and process knowledge based on best 

available data and operating records.

(iv) Whether flare has a continuous gas analyzer.
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(v) Flare combustion efficiency.

(vi) Report uncombusted CH4 emissions, in metric tons CO2e 

(refer to Equation W-19 of §98.233).

(vii) Report uncombusted CO2 emissions, in metric tons CO2e 

(refer to Equation W-20 of §98.233).

(viii) Report combusted CO2 emissions, in metric tons CO2e 

(refer to Equation W-21 of §98.233).

(ix) Report N2O emissions, in metric tons CO2e.

(x) For the natural gas processing industry segment, a 

unique name or ID number for the flare stack.

(xi) In the case that a CEMS is used to measure CO2

emissions for the flare stack, indicate that a CEMS was used in 

the annual report and report the combusted CO2 and uncombusted 

CO2 as a combined number.

(13) For each centrifugal compressor:

(i) For compressors with wet seals in operational mode 

(refer to Equations W-22 through W-24 of §98.233), report the 

following for each degassing vent:

(A) Number of wet seals connected to the degassing vent.

(B) Fraction of vent gas recovered for fuel or sales or 

flared.

(C) Annual throughput in million scf, use an engineering 

calculation based on best available data.
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(D) Type of meters used for making measurements.

(E) Reporter emission factor for wet seal oil degassing 

vents in cubic feet per hour (refer to Equation W-24 of 

§98.233).

(F) Total time the compressor is operating in hours.

(G) Report seal oil degassing vent emissions for 

compressors measured and for compressors not measured in metric 

tons of CO2e for each gas.

(ii) For wet and dry seal centrifugal compressors in 

operating mode, (refer to Equations W-22 through W-24 of 

§98.233), report the following:

(A) Total time in hours the compressor is in operating 

mode.

(B) Reporter emission factor for blowdown vents in cubic 

feet per hour (refer to Equation W-24 of §98.233).

(C) Report blowdown vent emissions when in operating mode 

in metric tons of CO2e for each gas.

(iii) For wet and dry seal centrifugal compressors in not 

operating, depressurized mode (refer to Equations W-22 through 

W-24 of §98.233), report the following:

(A) Total time in hours the compressor is in shutdown, 

depressurized mode.
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(B) Reporter emission factor for isolation valve emissions 

in shutdown, depressurized mode in cubic feet per hour (refer to 

Equation W-24 of §98.233).

(C) Report the isolation valve leakage emissions in not 

operating, depressurized mode in metric tons of CO2e for each 

gas.

(iv) Report total annual compressor emissions from all 

modes of operation in metric tons of CO2e for each gas.

(v) For centrifugal compressors in onshore petroleum and 

natural gas production (refer to Equation W-25 of §98.233), 

report the following:

(A) Count of compressors.

(B) Report annual emissions in metric tons of CO2e for each 

gas (refer to Equation W-25 of §98.233) collectively.

(14) For reciprocating compressors:

(i) For reciprocating compressors rod packing emissions 

with or without a vent in operating mode, report the following:

(A) Annual throughput in million scf, use an engineering 

calculation based on best available data.

(B) Total time in hours the reciprocating compressor is in 

operating mode.
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(C) Report rod packing emissions for compressors measured 

and for compressors not measured in metric tons of CO2e for each 

gas.

(ii) For reciprocating compressors blowdown vents not 

manifold to rod packing vents, in operating and standby 

pressurized mode (refer to Equations W-26 through W-28 of 

§98.233), report the following:

(A) Total time in hours the compressor is in standby, 

pressurized mode.

(B) Reporter emission factor for blowdown vents in cubic 

feet per hour (refer to §98.233, Equation W-28).

(C) Report blowdown vent emissions when in operating and 

standby pressurized modes in metric tons of CO2e for each gas.

(iii) For reciprocating compressors in not operating, 

depressurized mode (refer to Equations W-26 through W-28 of 

§98.233), report the following:

(A) Total time the compressor is in not operating, 

depressurized mode.

(B) Reporter emission factor for isolation valve emissions 

in not operating, depressurized mode in cubic feet per hour 

(refer to Equation W-28 of §98.233).
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(C) Report isolation valve leakage emissions in not 

operating, depressurized mode in metric tons of CO2e for each 

gas.

(iv) Report total annual compressor emissions from all 

modes of operation in metric tons of CO2e for each gas.

(v) For reciprocating compressors in onshore petroleum and 

natural gas production (refer to Equation W-29 of §98.233), 

report the following:

(A) Count of compressors.

(B) Report annual emissions in metric tons of CO2e for each 

gas collectively (refer to Equation W-29 of §98.233).

(15) For each component type (major equipment type for 

onshore production) that uses emission factors for estimating 

emissions (refer to §98.233(q) and (r))

(i) For equipment leaks found in each leak survey (refer to 

§98.233(q)), report the following:

(A) Total count of leaks found in each complete survey 

listed by date of survey and each component type for which there 

is a leaker emission factor in Tables W-2, W-3, W-4, W-5, W-6, 

and W-7 of this subpart.

(B) For onshore natural gas processing, range of 

concentrations of CH4 and CO2 (refer to Equation W-30A of 

§98.233).
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(C) Annual CO2 and CH4 emissions in metric tons CO2e for 

each gas (refer to Equation W-30A of §98.233), by component 

type.

(ii) For equipment leaks calculated using population counts 

and factors (refer to §98.233(r)), report the following:

(A) For source categories §98.230(a)(5), (a)(6), and 

(a)(7), total count for each component type in Tables W-4, W-5, 

and W-6 of this subpart for which there is a population emission 

factor, listed by major heading and component type.

(B) For onshore production (refer to §98.230 paragraph 

(a)(2)), total count for each type of major equipment in Table 

W-1B and Table W-1C of this subpart, by facility.

(C) Annual CO2 and CH4 emissions, in metric tons CO2e for 

each gas (refer to Equation W-31 of §98.233), by component type.

(16) For local distribution companies, report the 

following:

(i) Total number of above grade T-D transfer stations in 

the facility.

(ii) Number of years over which all T-D transfer stations 

will be monitored at least once.

(iii) Number of T-D stations monitored in calendar year.

(iv) Total number of below grade T-D transfer stations in 

the facility.
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(v) Total number of above grade metering-regulating 

stations (this count will include above grade T-D transfer 

stations) in the facility.

(vi) Total number of below grade metering-regulating 

stations (this count will include below grade T-D transfer 

stations) in the facility.

(vii) [Reserved]

(viii) Leak factor for meter/regulator run developed in 

Equation W-32 of §98.233.

(ix) Number of miles of unprotected steel distribution 

mains.

(x) Number of miles of protected steel distribution mains.

(xi) Number of miles of plastic distribution mains.

(xii) Number of miles of cast iron distribution mains.

(xiii) Number of unprotected steel distribution services.

(xiv) Number of protected steel distribution services.

(xv) Number of plastic distribution services.

(xvi) Number of copper distribution services.

(xvii) Annual CO2 and CH4 emissions, in metric tons CO2e for 

each gas, from all above grade T-D transfer stations combined.

(xviii) Annual CO2 and CH4 emissions, in metric tons CO2e

for each gas, from all below grade T-D transfer stations 

combined.
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(xix) Annual CO2 and CH4 emissions, in metric tons CO2e for 

each gas, from all above grade metering-regulating stations 

(including T-D transfer stations) combined.

(xx) Annual CO2 and CH4 emissions, in metric tons CO2e for 

each gas, from all below grade metering-regulating stations 

(including T-D transfer stations) combined.

(xxi) Annual CO2 and CH4 emissions, in metric tons CO2e for 

each gas, from all distribution mains combined.

(xxii) Annual CO2 and CH4 emissions, in metric tons CO2e for 

each gas, from all distribution services combined.

(17) For each EOR injection pump blowdown (refer to 

Equation W-37 of §98.233), report the following:

(i) Pump capacity, in barrels per day.

(ii) Volume of critical phase gas between isolation valves.

(iii) Number of blowdowns per year.

(iv) Critical phase EOR injection gas density.

(v) For each EOR pump, report annual CO2 emissions, 

expressed in metric tons CO2e for each gas.

(18) For EOR hydrocarbon liquids dissolved CO2 for each subbasin category (refer to Equation W-38 of §98.233), report the 

following:

(i) Volume of crude oil produced in barrels per year.
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(ii) Amount of CO2 retained in hydrocarbon liquids in metric 

tons per barrel, under standard conditions.

(iii) Report annual CO2 emissions at the sub-basin level, 

expressed in metric tons CO2e.

(19) For onshore petroleum and natural gas production and 

natural gas distribution combustion emissions, report the 

following:

(i) Cumulative number of external fuel combustion units 

with a rated heat capacity equal to or less than 5 mmBtu/hr, by 

type of unit.

(ii) Cumulative number of external fuel combustion units 

with a rated heat capacity larger than 5 mmBtu/hr, by type of 

unit.

(iii) Report annual CO2, CH4, and N2O emissions from 

external fuel combustion units with a rated heat capacity larger 

than 5 mmBtu/hr, expressed in metric tons CO2e for each gas, by 

type of unit.

(iv) Cumulative volume of fuel combusted in external fuel 

combustion units with a rated heat capacity larger than 5 

mmBtu/hr, by fuel type.

(v) Cumulative number of internal fuel combustion units, 

not compressor-drivers, with a rated heat capacity equal to or 

less than 1 mmBtu/hr or 130 horsepower, by type of unit.
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(vi) Report annual CO2, CH4, and N2O emissions from internal 

combustion units greater than 1mmBtu/hr, expressed in metric 

tons CO2e for each gas, by type of unit.

(vii) Cumulative volume of fuel combusted in internal 

combustion units with a rated heat capacity larger than 1 

mmBtu/hr or 130 horsepower, by fuel type.

(d) Report annual throughput as determined by engineering 

estimate based on best available data for each industry segment 

listed in paragraphs (a)(1) through (a)(8) of this section.

(e) For onshore petroleum and natural gas production, 

report the best available estimate of API gravity, best 

available estimate of gas to oil ratio, and best available 

estimate of average low pressure separator pressure for each oil 

sub-basin category.

§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.
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(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.

§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 (H2 S) and/or carbon dioxide 

(CO2 ) contaminants that are separated from sour natural gas by 

an acid gas removal unit.

Acid gas removal unit (AGR) means a process unit that 

separates hydrogen sulfide and/or carbon dioxide from sour 

natural gas using liquid or solid absorbents or membrane 

separators.

Acid gas removal vent emissions mean the acid gas separated 

from the acid gas absorbing medium (e.g., an amine solution) and 

released with methane and other light hydrocarbons to the 

atmosphere or a flare.
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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 well-pads, 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: AAPGCSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by 

Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., 

Volume 75, Number 10 (October 1991) (incorporated by reference, 

see §98.7) and the Alaska Geological Province Boundary Map, 

Compiled by the American Association of Petroleum Geologists 

Committee on Statistics of Drilling in Cooperation with the 

USGS, 1978 (incorporated by reference, see §98.7).

Component means each metal to metal joint or seal of nonwelded connection separated by a compression gasket, screwed 

thread (with or without thread sealing compound), metal to metal 

compression, or fluid barrier through which natural gas or 

liquid can escape to the atmosphere.
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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.

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.

Distribution pipeline means a pipeline that is designated 

as such by the Pipeline and Hazardous Material Safety 

Administration (PHMSA) 49 CFR 192.3.

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.
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Equipment leak means those emissions which could not 

reasonably pass through a stack, chimney, vent, or other 

functionally-equivalent opening.

Equipment leak detection means the process of identifying 

emissions from equipment, components, and other point sources.

External combustion means fired combustion in which the 

flame and products of combustion are separated from contact with 

the process fluid to which the energy is delivered. Process 

fluids may be air, hot water, or hydrocarbons. External 

combustion equipment may include fired heaters, industrial 

boilers, and commercial and domestic combustion units.

Facility with respect to natural gas distribution for 

purposes of 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 
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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 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 CO2e OR operations that are under common 

ownership or common control including leased, rented, or 

contracted activities by an onshore petroleum and natural gas 

production owner or operator and that are located in a single 

hydrocarbon basin as defined in §98.238. Where a person or 

entity owns or operates more than one well in a basin, then all 

onshore petroleum and natural gas production equipment 

associated with all wells that the person or entity owns or 

operates in the basin would be considered one facility.

Farm Taps are pressure regulation stations that deliver gas 

directly from transmission pipelines to generally rural 

customers. 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 
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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 CH4emissions 

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 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 
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condensation of water or hydrocarbon liquids through passive 

reduction in pressure or temperature, or portable dewpoint 

suppression skids.

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 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 
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through the tank insulation and heat energy dissipated in the 

LNG by internal pumps.

Meter/regulator run means a series of components used in 

regulating pressure or metering natural gas flow or both.

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.

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 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 
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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.

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-totubing 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.
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Pump seal emissions means hydrocarbon gas released from the 

seal face between the pump internal chamber and the atmosphere.

Reservoir means a porous and permeable underground natural 

formation containing significant quantities of hydrocarbon 

liquids and/or gases.

Residue Gas and Residue Gas Compression mean, respectively, 

production lease natural gas from which gas liquid products and, 

in some cases, non-hydrocarbon components have been extracted 

such that it meets the specifications set by a pipeline 

transmission company, and/or a distribution company; and the 

compressors operated by the processing facility, whether inside 

the processing facility boundary fence or outside the fenceline, 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 reservoir 
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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 from high permeability gas, shale gas, coal 

seam, or other tight 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 wells that produce hydrocarbon 

liquids 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 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-
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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 

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-
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set horizontally from the surface location, intercepting the 

targets either vertically or at an angle.

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.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80590, 

Dec. 23, 2011]

Table W-1A of Subpart W of Part 98—Default Whole Gas Emission 

Factors for Onshore Petroleum and Natural Gas Production

Onshore petroleum and

natural gas production

Emission factor 

(scf/hour/component)

Eastern U.S.

Population Emission Factors—All Components, Gas Service1

Valve 0.027

Connector 0.003

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
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Onshore petroleum and

natural gas production

Emission factor 

(scf/hour/component)

Pump 0.01

Other 5 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

Other 5 0.003

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

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
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1 For multi-phase flow that includes gas, use the gas service emissions 

factors.

2 Emission Factor is in units of “scf/hour/device.”

3 Emission Factor is in units of “scf/hour/pump.”

4 Hydrocarbon liquids greater than or equal to 20°API are considered “light 

crude.”

5 “Others” category includes instruments, loading arms, pressure relief 

valves, stuffing boxes, compressor seals, dump lever arms, and vents.

6 Hydrocarbon liquids less than 20°API are considered “heavy crude.”

Table W-1B to Subpart W of Part 98—Default Average Component 

Counts for Major Onshore Natural Gas Production Equipment

Major equipment Valves Connectors Open-ended lines

Pressure relief 

valves

Eastern U.S.

Wellheads 8 38 0.5 0

Separators 1 6 0 0

Meters/piping 12 45 0 0

Compressors 12 57 0 0

In-line heaters 14 65 2 1

Dehydrators 24 90 2 2

Western U.S.

Wellheads 11 36 1 0

Separators 34 106 6 2

Meters/piping 14 51 1 1

Compressors 73 179 3 4

In-line heaters 14 65 2 1

Dehydrators 24 90 2 2

Table W-1C to Subpart W of Part 98—Default Average Component 

Counts For Major Crude Oil Production Equipment

Major equipment Valves Flanges Connectors

Open-ended 

lines

Other 

components

Eastern U.S.

Wellhead 5 10 4 0 1

Separator 6 12 10 0 0
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Major equipment Valves Flanges Connectors

Open-ended 

lines

Other 

components

Heater-treater 8 12 20 0 0

Header 5 10 4 0 0

Western U.S.

Wellhead 5 10 4 0 1

Separator 6 12 10 0 0

Heater-treater 8 12 20 0 0

Header 5 10 4 0 0

Table W-1D of Subpart W of Part 98—Designation of Eastern And 

Western U.S.

Eastern U.S. Western U.S.

Connecticut Alabama

Delaware Alaska

Florida Arizona

Georgia Arkansas

Illinois California

Indiana Colorado

Kentucky Hawaii

Maine Idaho

Maryland Iowa

Massachusetts Kansas

Michigan Louisiana

New Hampshire Minnesota

New Jersey Mississippi

New York Missouri

North Carolina Montana

Ohio Nebraska

Pennsylvania Nevada

Rhode Island New Mexico

South Carolina North Dakota

Tennessee Oklahoma
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Eastern U.S. Western U.S.

Vermont Oregon

Virginia South Dakota

West Virginia Texas

Wisconsin Utah

 Washington

 Wyoming

Table W-2 of 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

1 Valves include control valves, block valves and regulator valves.

Table W-3 of Subpart W of Part 98—Default Total Hydrocarbon 

Emission Factors for Onshore Natural Gas Transmission 

Compression

Onshore natural gas transmission compression

Emission factor 

(scf/hour/component)

Leaker Emission Factors—Compressor Components, Gas Service

Valve 1 14.84
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Onshore natural gas transmission compression

Emission factor 

(scf/hour/component)

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

Population Emission Factors—Gas Service

Low Continuous Bleed Pneumatic Device 

Vents2

1.37

High Continuous Bleed Pneumatic 

Device Vents2

18.20

Intermittent Bleed Pneumatic Device 

Vents2

2.35

1 Valves include control valves, block valves and regulator valves.

2 Emission Factor is in units of “scf/hour/device.”

Table W-4 of Subpart W of Part 98—Default Total Hydrocarbon 

Emission Factors for Underground Natural Gas Storage

Underground natural gas storage

Emission factor 

(scf/hour/component)

Leaker Emission Factors—Storage Station, Gas Service

Valve 1 14.84

Connector 5.59

Open-Ended Line 17.27

Pressure Relief Valve 39.66

Meter 19.33

Population Emission Factors—Storage Wellheads, Gas Service

Connector 0.01

Valve 0.1
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Underground natural gas storage

Emission factor 

(scf/hour/component)

Pressure Relief Valve 0.17

Open Ended Line 0.03

Population Emission Factors—Other Components, Gas Service

Low Continuous Bleed Pneumatic Device 

Vents 2

1.37

High Continuous Bleed Pneumatic 

Device Vents 2

18.20

Intermittent Bleed Pneumatic Device 

Vents 2

2.35

1 Valves include control valves, block valves and regulator valves.

2 Emission Factor is in units of “scf/hour/device.”

Table W-5 of 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

Other 1 1.77

Population Emission Factors—LNG Storage Compressor, Gas Service

Vapor Recovery Compressor 2 4.17

1 “Other” equipment type should be applied for any equipment type other than 

connectors, pumps, or valves.

2 Emission Factor is in units of “scf/hour/device.”

Table W-6 of 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
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Other 1 1.77

Population Emission Factors—LNG Terminals Compressor, Gas Service

Vapor Recovery Compressor2 4.17

1 “Other” equipment type should be applied for any equipment type other than 

connectors, pumps, or valves.

2 Emission Factors is in units of “scf/hour/compressor.”

Table W-7 of 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
***DRAFT DELIBERATIVE – DO NOT CITE OR QUOTE - This file has not been 

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Natural gas distribution

Emission factor (scf/hour/

component)

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.”