e-CFR data is current as of July 21, 2015

Title 40: Protection of Environment 

PART 98—MANDATORY GREENHOUSE GAS REPORTING

Subpart W—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 to 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 to Subpart W of Part 98—Designation Of Eastern And Western U.S.

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

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

Compression

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

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

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

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

SOURCE: 75 FR 74488, Nov. 30, 2010, unless otherwise noted. 

§98.230 Definition of the source category.

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

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

is any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses 

equipment to extract hydrocarbons from the ocean or lake floor and that processes and/or transfers such 

hydrocarbons to storage, transport vessels, or onshore. In addition, offshore production includes 

secondary platform structures connected to the platform structure via walkways, storage tanks associated 

with the platform structure and floating production and storage offloading equipment (FPSO). This source 

category does not include reporting of emissions from offshore drilling and exploration that is not 

conducted on production platforms.

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

means all equipment on a single well-pad or associated with a single well-pad (including but not limited to 

compressors, generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and 

processing equipment, and portable non-self-propelled equipment, which includes well drilling and 

completion equipment, workover equipment, and leased, rented or contracted equipment) used in the 

production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural 

gas (including condensate). This equipment also includes associated storage or measurement vessels, 

all petroleum and natural gas production equipment located on islands, artificial islands, or structures
connected by a causeway to land, an island, or an artificial island. Onshore petroleum and natural gas 

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

pad using CO2 or natural gas injection.

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

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

more component mixtures. Separation includes one or more of the following: forced extraction of natural 

gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or the capture of CO2 separated 

from natural gas streams. This segment also includes all residue gas compression equipment owned or 

operated by the natural gas processing plant. This industry segment includes processing plants that 

fractionate gas liquids, and processing plants that do not fractionate gas liquids but have an annual 

average throughput of 25 MMscf per day or greater.

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

means any stationary combination of compressors that move natural gas from production fields, natural 

gas processing plants, or other transmission compressors through transmission pipelines to natural gas 

distribution pipelines, LNG storage facilities, or into underground storage. In addition, a transmission 

compressor station includes equipment for liquids separation, and tanks for the storage of water and 

hydrocarbon liquids. Residue (sales) gas compression that is part of onshore natural gas processing 

plants are included in the onshore natural gas processing segment and are excluded from this segment.

(5) Underground natural gas storage. Underground natural gas storage means subsurface storage, 

including depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been 

transferred from its original location for the primary purpose of load balancing (the process of equalizing 

the receipt and delivery of natural gas); natural gas underground storage processes and operations 

(including compression, dehydration and flow measurement, and excluding transmission pipelines); and 

all the wellheads connected to the compression units located at the facility that inject and recover natural 

gas into and from the underground reservoirs.

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

above ground, equipment for liquefying natural gas, compressors to capture and re-liquefy boil-off-gas, 

re-condensers, and vaporization units for re-gasification of the liquefied natural gas.

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

equipment that receives imported LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers regasified natural gas to a natural gas transmission or distribution system. LNG export equipment means all 

onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers 

the LNG via ocean transportation to any location, including locations in the United States.

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

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

Company (LDC) within a single state that is regulated as a separate operating company by a public utility 

commission or that is operated as an independent municipally-owned distribution system. This segment 

also excludes customer meters and regulators, infrastructure, and pipelines (both interstate and 

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

distribution company inlet.

(b) [Reserved]

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80574, Dec. 23, 2011; 79 FR 70385, Nov. 25, 2014]

§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 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.

(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 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 stationary or portable fuel combustion equipment that cannot move on roadways 

under its own power and drive train, and that is located at an onshore petroleum and natural gas 

production facility as defined in §98.238. Stationary or portable equipment are the following equipment, 

which are integral to the extraction, processing, or movement of oil or natural gas: well drilling and 

completion equipment, workover equipment, natural gas dehydrators, natural gas compressors, electrical 

generators, steam boilers, and process heaters.

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

sources:

(1) Reciprocating compressor venting.

(2) Centrifugal compressor venting.

(3) Blowdown vent stacks.

(4) Dehydrator vents.

(5) Acid gas removal vents.

(6) Flare stack emissions.

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

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

following sources:

(1) Reciprocating compressor venting.

(2) Centrifugal compressor venting.

(3) Transmission storage tanks.

(4) Blowdown vent stacks.
(5) Natural gas pneumatic device venting.

(6) Flare stack emissions.

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

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

sources:

(1) Reciprocating compressor venting.

(2) Centrifugal compressor venting.

(3) Natural gas pneumatic device venting.

(4) Flare stack emissions.

(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 venting.

(2) Centrifugal compressor venting.

(3) Equipment leaks from valves; pump seals; connectors; vapor recovery compressors, and other 

equipment leak sources.

(4) Flare stack emissions.

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

sources:

(1) Reciprocating compressor venting.

(2) Centrifugal compressor venting.

(3) Blowdown vent stacks.

(4) Equipment leaks from valves, pump seals, connectors, vapor recovery compressors, and other 

equipment leak sources.

(5) Flare stack emissions.

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

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

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

(2) Equipment leaks at below grade transmission-distribution transfer stations.
(3) Equipment leaks at above grade metering-regulating stations that are not above grade 

transmission-distribution transfer stations.

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

(5) Distribution main equipment leaks.

(6) Distribution services equipment leaks.

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

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

(j) [Reserved]

(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.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80574, Dec. 23, 2011; 79 FR 70385, Nov. 25, 2014]

§98.233 Calculating GHG emissions.

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

calculations that specify measurements in actual conditions, reporters may use a flow or volume 

measurement system that corrects to standard conditions and determine the flow or volume at standard 

conditions; otherwise, reporters must use average atmospheric conditions or typical operating conditions 

as applicable to the respective monitoring methods in this section.

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

continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices using 

Equation W-1 of this section.

Where:

Es,i = Annual total volumetric GHG emissions at standard conditions in standard cubic feet per year from natural gas 

pneumatic device vents, of types “t” (continuous high bleed, continuous low bleed, intermittent bleed), for 

GHGi.

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

intermittent bleed) as determined in paragraph (a)(1) or (a)(2) of this section.

EFt = Population emission factors for natural gas pneumatic device vents (in standard cubic feet per hour per device) 

of each type “t” listed in Tables W-1A, W-3, and W-4 of this subpart for onshore petroleum and natural 

gas production, onshore natural gas transmission compression, and underground natural gas storage 

facilities, respectively.
GHGi = For onshore petroleum and natural gas production facilities, onshore natural gas transmission compression 

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

natural gas or processed natural gas for each facility as specified in paragraphs (u)(2)(i), (iii), and (iv) of 

this section.

Tt = Average estimated number of hours in the operating year the devices, of each type “t”, were operational using 

engineering estimates based on best available data. Default is 8,760 hours.

(1) For all industry segments, determine “Countt” for Equation W-1 of this subpart for each type of 

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

counting the devices, except as specified in paragraph (a)(2) of this section. The reported number of 

devices must represent the total number of devices for the reporting year.

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

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

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

bleed) using engineering estimates based on best available data.

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

based on best available information.

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

paragraph (v) of this section.

(b) [Reserved]

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

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

pneumatic pumps covered in paragraph (e) of this section do not have to report emissions under this 

paragraph (c).

Where:

Es,i = Annual total volumetric GHG emissions at standard conditions in standard cubic feet per year from all natural 

gas driven pneumatic pump venting, for GHGi.

Count = Total number of natural gas driven pneumatic pumps.

EF = Population emissions factors for natural gas driven pneumatic pumps (in standard cubic feet per hour per pump) 

listed in Table W-1A of this subpart for onshore petroleum and natural gas production.

GHGi = Concentration of GHGi, CH4, or CO2, in produced natural gas as defined in paragraph (u)(2)(i) of this section.

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

estimates based on best available data. Default is 8,760 hours.

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

paragraph (v) of this section.

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

molecular sieve or other absorbents and adsorbents), calculate emissions for CO2 only (not CH4) vented 

directly to the atmosphere or emitted through a flare, engine (e.g., permeate from a membrane or deadsorbed gas from a pressure swing adsorber used as fuel supplement), or sulfur recovery plant, using 

any of the calculation methods described in this paragraph (d), as applicable.
(1) Calculation Method 1. If you operate and maintain a continuous emissions monitoring system 

(CEMS) that has both a CO2 concentration monitor and volumetric flow rate monitor, you must calculate 

CO2 emissions under this subpart by following the Tier 4 Calculation Method and all associated 

calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this 

part (General Stationary Fuel Combustion Sources). Alternatively, you may follow the manufacturer's 

instructions or industry standard practice. If a CO2 concentration monitor and volumetric flow rate monitor 

are not available, you may elect to install a CO2 concentration monitor and a volumetric flow rate monitor 

that comply with all of the requirements specified for the Tier 4 Calculation Method in subpart C of this 

part (General Stationary Fuel Combustion Sources). The calculation and reporting of CH4 and N2O 

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

(2) Calculation Method 2. If a CEMS is not available but a vent meter is installed, use the CO2

composition and annual volume of vent gas to calculate emissions using Equation W-3 of this section.

Where:

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

VS = Total annual volume of vent gas flowing out of the AGR unit in cubic feet per year at actual conditions as 

determined by flow meter using methods set forth in §98.234(b). Alternatively, you may follow the 

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

VolCO2 = Annual average volumetric fraction of CO2 content in vent gas flowing out of the AGR unit as determined in 

paragraph (d)(6) of this section.

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

gas flow rate of the acid gas removal unit to calculate emissions for CO2 using Equations W-4A or W-4B 

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

Equation W-4B.

Where:

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

Vin = Total annual volume of natural gas flow into the AGR unit in cubic feet per year at actual conditions as 

determined using methods specified in paragraph (d)(5) of this section.

Vout = Total annual volume of natural gas flow out of the AGR unit in cubic feet per year at actual conditions as 

determined using methods specified in paragraph (d)(5) of this section.

VolI = Annual average volumetric fraction of CO2 content in natural gas flowing into the AGR unit as determined in 

paragraph (d)(7) of this section.

Volo = Annual average volumetric fraction of CO2 content in natural gas flowing out of the AGR unit as determined in 

paragraph (d)(8) of this section.

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

using any standard simulation software package, such as AspenTech HYSYS®, or API 4679 AMINECalc, 

that uses the Peng-Robinson equation of state and speciates CO2 emissions. A minimum of the following, 
determined for typical operating conditions over the calendar year by engineering estimate and process 

knowledge based on best available data, must be used to characterize emissions:

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

(ii) Acid gas content of feed natural gas.

(iii) Acid gas content of outlet natural gas.

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

(v) Exit temperature of natural gas.

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

(5) For Calculation Method 3, determine the gas flow rate of the inlet when using Equation W-4A of 

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

stream of an AGR unit using a meter according to methods set forth in §98.234(b). If you do not have a 

continuous flow meter, either install a continuous flow meter or use an engineering calculation to 

determine the flow rate.

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

install a continuous gas analyzer or take quarterly gas samples from the vent gas stream for each quarter 

that the AGR unit is operating to determine VolCO2 in Equation W-3 of this section, according to the 

methods set forth in §98.234(b).

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

the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, either 

install a continuous gas analyzer or take quarterly gas samples from the inlet gas stream for each quarter 

that the AGR unit is operating to determine VolI in Equation W-4A or W-4B of this section, according to 

the methods set forth in §98.234(b).

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

gas flowing out of the AGR unit using one of the methods specified in paragraphs (d)(8)(i) through 

(d)(8)(iii) of this section.

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

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

gas analyzer.

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

from the outlet gas stream for each quarter that the AGR unit is operating to determine VolO in Equation 

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

(iii) If a continuous gas analyzer is not available or installed, you may use sales line quality 

specification for CO2 in natural gas.

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

paragraph (t) of this section.

(10) Calculate annual mass CO2 emissions using calculations in paragraph (v) of this section.
(11) Determine if CO2 emissions from the AGR unit are recovered and transferred outside the 

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

by the magnitude of CO2 emissions recovered and transferred outside the facility.

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

applicable calculation methods described in paragraphs (e)(1) through (e)(4) of this section. If emissions 

from dehydrator vents are routed to a vapor recovery system, you must adjust the emissions downward 

according to paragraph (e)(5) of this section. If emissions from dehydrator vents are routed to a flare or 

regenerator fire-box/fire tubes, you must calculate CH4, CO2, and N2O annual emissions as specified in 

paragraph (e)(6) of this section.

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

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

feet per day by using a software program, such as AspenTech HYSYS® or GRI-GLYCalcTM, that uses the 

Peng-Robinson equation of state to calculate the equilibrium coefficient, speciates CH4 and CO2

emissions from dehydrators, and has provisions to include regenerator control devices, a separator flash 

tank, stripping gas and a gas injection pump or gas assist pump. The following parameters must be 

determined by engineering estimate based on best available data and must be used at a minimum to 

characterize emissions from dehydrators:

(i) Feed natural gas flow rate.

(ii) Feed natural gas water content.

(iii) Outlet natural gas water content.

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

(v) Absorbent circulation rate.

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

(vii) Use of stripping gas.

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

(ix) Hours operated.

(x) Wet natural gas temperature and pressure.

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

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

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

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

select a representative analysis.

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

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

§98.234(b) to sample and analyze wet natural gas composition.
(D) If only composition data for dry natural gas is available, assume the wet natural gas is saturated.

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

an annual average of daily natural gas throughput that is less than 0.4 million standard cubic feet per day 

using Equation W-5 of this section:

Where:

Es,i = Annual total volumetric GHG emissions (either CO2 or CH4) at standard conditions in cubic feet.

EFi = Population emission factors for glycol dehydrators in thousand standard cubic feet per dehydrator per year. Use 

73.4 for CH4 and 3.21 for CO2 at 60 °F and 14.7 psia.

Count = Total number of glycol dehydrators that have an annual average of daily natural gas throughput that is less 

than 0.4 million standard cubic feet per day.

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

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

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

refilling process using Equation W-6 of this section. Desiccant dehydrator emissions covered in this 

paragraph do not have to be calculated separately using the method specified in paragraph (i) of this 

section for blowdown vent stacks.

Where:

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

H = Height of the dehydrator vessel (ft).

D = Inside diameter of the vessel (ft).

P1 = Atmospheric pressure (psia).

P2 = Pressure of the gas (psia).

π = pi (3.14).

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

N = Number of dehydrator openings in the calendar year.

100 = Conversion of %G to fraction.

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

calculate both CH4 and CO2 mass emissions from volumetric GHGi emissions using calculations in 

paragraph (v) of this section. For desiccant dehydrators that use the calculation method in paragraph 
(e)(3) of this section, calculate both CH4 and CO2 volumetric and mass emissions from volumetric natural 

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

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

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

vapor recovery system as determined by engineering estimate based on best available data.

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

follows:

(i) Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(1) through 

(5) of this section, as applicable.

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

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

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

venting for liquids unloading using one of the calculation methods described in paragraphs (f)(1), (2), or 

(3) of this section. Calculate annual CH4 and CO2 volumetric and mass emissions using the method 

described in paragraph (f)(4) of this section.

(1) Calculation Method 1. Calculate emissions from wells with plunger lifts and wells without plunger 

lifts separately. For at least one well of each unique well tubing diameter group and pressure group 

combination in each sub-basin category (see §98.238 for the definitions of tubing diameter group, 

pressure group, and sub-basin category), where gas wells are vented to the atmosphere to expel liquids 

accumulated in the tubing, install a recording flow meter on the vent line used to vent gas from the well 

(e.g., on the vent line off the wellhead separator or atmospheric storage tank) according to methods set 

forth in §98.234(b). Calculate the total emissions from well venting to the atmosphere for liquids unloading 

using Equation W-7A of this section. For any tubing diameter group and pressure group combination in a 

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

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

Where:

Ea = Annual natural gas emissions for all wells of the same tubing diameter group and pressure group combination in 

a sub-basin at actual conditions, a, in cubic feet. Calculate emission from wells with plunger lifts and wells 

without plunger lifts separately.

h = Total number of wells of the same tubing diameter group and pressure group combination in a sub-basin either 

with or without plunger lifts.

p = Wells 1 through h of the same tubing diameter group and pressure group combination in a sub-basin.

Tp = Cumulative amount of time in hours of venting for each well, p, of the same tubing diameter group and pressure 

group combination in a sub-basin during the year. If the available venting data do not contain a record of 

the date of the venting events and data are not available to provide the venting hours for the specific time 

period of January 1 to December 31, you may calculate an annualized vent time, Tp, using Equation W7B of this section.
FR = Average flow rate in cubic feet per hour for all measured wells of the same tubing diameter group and pressure 

group combination in a sub-basin, over the duration of the liquids unloading, under actual conditions as 

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

Where:

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

MPp = Time period, in days, of the monitoring period for each well, p. A minimum of 300 days in a calendar year are 

required. The next period of data collection must start immediately following the end of data collection for 

the previous reporting year.

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

year).

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

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

group and pressure group combination in each sub-basin category. Calculate emissions from wells with 

plunger lifts and wells without plunger lifts separately.

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

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

recorded time (in hours) for all measured liquid unloading events with venting to the atmosphere.

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

wells in the same pressure group that have the same tubing diameter group, for the number of hours of 

venting these wells.

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

of data collection. For a new producing sub-basin category, calculate an average flow rate beginning in 

the first year of production.

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

paragraph (t) of this section.

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

atmosphere for liquids unloading without plunger lift assist using Equation W-8 of this section.

Where:

Es = Annual natural gas emissions for each sub-basin at standard conditions, s, in cubic feet per year.

W = Total number of wells with well venting for liquids unloading for each sub-basin.

p = Wells 1 through W with well venting for liquids unloading for each sub-basin.
Vp = Total number of unloading events in the monitoring period per well, p.

0.37×10−3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet).

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

WDp = Well depth from either the top of the well or the lowest packer to the bottom of the well, for each well, p, in feet.

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

each well with no packers, in pounds per square inch absolute (psia). If casing pressure is not available 

for each well, you may determine the casing pressure by multiplying the tubing pressure of each well with 

a ratio of casing pressure to tubing pressure from a well in the same sub-basin for which the casing 

pressure is known. The tubing pressure must be measured during gas flow to a flow-line. The shut-in 

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

the well production is impeded by liquids loading or closed to the flow-line by surface valves.

SFRp = Average flow-line rate of gas for well, p, at standard conditions in cubic feet per hour. Use Equation W-33 of 

this section to calculate the average 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.

q = Unloading event.

Zp,q = If HRp,q is less than 1.0 then Zp,q is equal to 0. If HRp,q is greater than or equal to 1.0 then Zp,q is equal to 1.

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

atmosphere for liquids unloading with plunger lift assist using Equation W-9 of this section.

Where:

Es = Annual natural gas emissions for each sub-basin at standard conditions, s, in cubic feet per year.

W = Total number of wells with plunger lift assist and well venting for liquids unloading for each sub-basin.

p = Wells 1 through W with well venting for liquids unloading for each sub-basin.

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

0.37×10−3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet).

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

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

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

based on best available data.

SFRp = Average flow-line rate of gas for well, p, at standard conditions in cubic feet per hour. Use Equation W-33 of 

this section to calculate the average 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.
q = Unloading event.

Zp,q = If HRp,q is less than 0.5 then Zp,q is equal to 0. If HRp,q is greater than or equal to 0.5 then Zp,q is equal to 1.

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

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

(g) Gas well venting during completions and workovers with hydraulic fracturing. Calculate annual 

volumetric natural gas emissions from gas well venting during completions and workovers involving 

hydraulic fracturing using Equation W-10A or Equation W-10B of this section. Equation W-10A applies to 

well venting when the flowback rate is measured from a specified number of example completions or 

workovers and Equation W-10B applies when the flowback vent or flare volume is measured for each 

completion or workover. Completion and workover activities are separated into two periods, an initial 

period when flowback is routed to open pits or tanks and a subsequent period when gas content is 

sufficient to route the flowback to a separator or when the gas content is sufficient to allow measurement 

by the devices specified in paragraph (g)(1) of this section, regardless of whether a separator is actually 

utilized. If you elect to use Equation W-10A of this section, you must follow the procedures specified in 

paragraph (g)(1) of this section. Emissions must be calculated separately for completions and workovers, 

for each sub-basin, and for each well type combination identified in paragraph (g)(2) of this section. You 

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

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

routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (g)(4) 

of this section.

Where:

Es,n = Annual volumetric natural gas emissions in standard cubic feet from gas well venting during completions or 

workovers following hydraulic fracturing for each sub-basin and well type combination.

W = Total number of wells completed or worked over using hydraulic fracturing in a sub-basin and well type 

combination.

Tp,s = Cumulative amount of time of flowback, after sufficient quantities of gas are present to enable separation, where 

gas vented or flared for the completion or workover, in hours, for each well, p, in a sub-basin and well 

type combination during the reporting year. This may include non-contiguous periods of venting or flaring.

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

quantities of gas are present to enable separation, for the completion or workover, in hours, for each well, 

p, in a sub-basin and well type combination during the reporting year. This may include non-contiguous 

periods of routing to open tanks/pits.

FRMs = Ratio of average flowback, during the period when sufficient quantities of gas are present to enable 

separation, of well completions and workovers from hydraulic fracturing to 30-day production rate for the 

sub-basin and well type combination, calculated using procedures specified in paragraph (g)(1)(iii) of this 

section, expressed in standard cubic feet per hour.

FRMi = Ratio of initial flowback rate during well completions and workovers from hydraulic fracturing to 30-day 

production rate for the sub-basin and well type combination, calculated using procedures specified in 

paragraph (g)(1)(iv) of this section, expressed in standard cubic feet per hour, for the period of flow to 

open tanks/pits.
PRs,p = Average production flow rate during the first 30 days of production after completions of newly drilled gas wells 

or gas well workovers using hydraulic fracturing in standard cubic feet per hour of each well p, that was 

measured in the sub-basin and well type combination.

EnFs,p = Volume of N2 injected gas in cubic feet at standard conditions that was injected into the reservoir during an 

energized fracture job for each well, p, as determined by using an appropriate meter according to 

methods described in §98.234(b), or by using receipts of gas purchases that are used for the energized 

fracture job. Convert to standard conditions using paragraph (t) of this section. If the fracture process did 

not inject gas into the reservoir or if the injected gas is CO2 then EnFs,p is 0.

FVs,p = Flow volume vented or flared 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 separation period of the completion or 

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

FRp,i = Flow rate vented or flared of each well, p, in standard cubic feet per hour measured using a recording flow 

meter (digital or analog) on the vent line to measure the flowback, at the beginning of the period of time 

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

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

(1) If you elect to use Equation W-10A of this section, you must use Calculation Method 1 as 

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

of this section, to determine the value of FRMs and FRMi. These values must be based on the flow rate for 

flowback, once sufficient gas is present to enable separation. The number of measurements or 

calculations required to estimate FRMs and FRMi must be determined individually for completions and 

workovers per sub-basin and well type combination as follows: Complete measurements or calculations 

for at least one completion or workover for less than or equal to 25 completions or workovers for each 

well type combination within a sub-basin; complete measurements or calculations for at least two 

completions or workovers for 26 to 50 completions or workovers for each sub-basin and well type 

combination; complete measurements or calculations for at least three completions or workovers for 51 to 

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

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

sub-basin and well type combination; and complete measurements or calculations for at least five 

completions or workovers for greater than 250 completions or workovers for each sub-basin and well type 

combination.

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

section to determine the value of FRMs. You must use Equation W-12B as specified in paragraph 

(g)(1)(iv) of this section to determine the value of FRMi. The procedures specified in paragraphs (g)(1)(v) 

and (vi) also apply. When making flowback measurements for use in Equations W-12A and W-12B of this 

section, you must use a recording flow meter (digital or analog) installed on the vent line, ahead of a flare 

or vent, to measure the flowback rates in units of standard cubic feet per hour according to methods set 

forth in §98.234(b).

(ii) Calculation Method 2. You must use Equation W-12A as specified in paragraph (g)(1)(iii) of this 

section to determine the value of FRMs. You must use Equation W-12B as specified in paragraph 

(g)(1)(iv) of this section to determine the value of FRMi. The procedures specified in paragraphs (g)(1)(v) 

and (vi) also apply. When calculating the flowback rates for use in Equations W-12A and W-12B of this 

section based on well parameters, you must record the well flowing pressure immediately upstream (and 

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

calculate the well flowback. The upstream pressure must be surface pressure and reservoir pressure 

cannot be assumed. The downstream pressure must be measured after the choke and atmospheric 

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

flow or Equation W-11B of this section for sonic flow. You must use best engineering estimates based on 

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

is sonic or subsonic. If the value of R in Equation W-11C of this section is greater than or equal to 2, then 

flow is sonic; otherwise, flow is subsonic. Convert calculated FRa values from actual conditions upstream 
of the restriction orifice to standard conditions (FRs,p and FRi,p) for use in Equations W-12A and W-12B of 

this section using Equation W-33 in paragraph (t) of this section.

Where:

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

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

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

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

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

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

1.27*105 = Conversion from m3/second to ft3/hour.

Where:

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

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

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

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

1.27*105 = Conversion from m3/second to ft3/hour.

Where:

R = Pressure ratio.

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

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

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

FRMs = Ratio of average flowback rate, during the period of time when sufficient quantities of gas are present to 

enable separation, of well completions and workovers from hydraulic fracturing to 30-day production rate 

for each sub-basin and well type combination.

FRs,p = Measured average flowback rate from Calculation Method 1 described in paragraph (g)(1)(i) of this section or 

calculated average flowback rate from Calculation Method 2 described in paragraph (g)(1)(ii) of this 

section, during the separation period in standard cubic feet per hour for well(s) p for each sub-basin and 

well type combination. Convert measured and calculated FRa values from actual conditions upstream of 

the restriction orifice (FRa) to standard conditions (FRs,p) for each well p using Equation W-33 in paragraph 

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

this parameter.

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

or gas well workovers using hydraulic fracturing, in standard cubic feet per hour for each well, p, that was 

measured in the sub-basin and well type combination.

N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub-basin and 

well type combination.

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

Where:

FRMi = Ratio of flowback gas rate while flowing to open tanks/pits during well completions and workovers from 

hydraulic fracturing to 30-day production rate.

FRi,p = Initial measured gas flowback rate from Calculation Method 1 described in paragraph (g)(1)(i) of this section or 

initial calculated flow rate from Calculation Method 2 described in paragraph (g)(1)(ii) of this section in 

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

calculated FRi,p values must be based on flow conditions at the beginning of the separation period and 

must be expressed at standard conditions.

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

or gas well workovers using hydraulic fracturing, in standard cubic feet per hour of each well, p, that was 

measured in the sub-basin and well type combination.

N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub-basin and 

well type combination.

(v) For Equation W-10A of this section, the ratio of flowback 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 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 flowback and for the first 30 day average production rate 

for each of these wells.
(vi) For Equation W-12A and W-12B of this section, calculate new flowback rates for horizontal and 

vertical gas well completions and horizontal and vertical gas well workovers in each sub-basin category 

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

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

are completed separately for workovers and completions per sub-basin and well type combination. A well 

type combination is a unique combination of the parameters listed in paragraphs (g)(2)(i) through (iii) of 

this section.

(i) Vertical or horizontal (directional drilling).

(ii) With flaring or without flaring.

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

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

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

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

hydraulic fracturing where all or a portion of the gas is flared as specified in paragraphs (g)(4)(i) and (ii) of 

this section.

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

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

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

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

the portion of gas flared during well completions and workovers using hydraulic fracturing. This 

adjustment to emissions from completions using flaring, versus completions without flaring, accounts for 

the conversion of CH4 to CO2 in the flare and for the formation on N2O during flaring.

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

annual volumetric natural gas emissions from each gas well venting during workovers without hydraulic 

fracturing using Equation W-13A of this section. Calculate annual volumetric natural gas emissions from 

each gas well venting during completions without hydraulic fracturing using Equation W-13B of this 

section. You must convert annual volumetric natural gas emissions to CH4 and CO2 volumetric and mass 

emissions as specified in paragraph (h)(1) of this section. If emissions from gas well venting during 

completions and workovers without hydraulic fracturing are routed to a flare, you must calculate CH4, CO2, 

and N2O annual emissions as specified in paragraph (h)(2) of this section.

Where:

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

without hydraulic fracturing.

Nwo = Number of workovers per sub-basin category that do not involve hydraulic fracturing in the reporting year.
EFwo = Emission factor for non-hydraulic fracture well workover venting in standard cubic feet per workover. Use 

3,114 standard cubic feet natural gas per well workover without hydraulic fracturing.

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

without hydraulic fracturing.

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

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

Vp = Average daily gas production rate in standard cubic feet per hour for each well, p, undergoing completion without 

hydraulic fracturing. This is the total annual gas production volume divided by total number of hours the 

wells produced to the flow-line. For completed wells that have not established a production rate, you may 

use the average flow rate from the first 30 days of production. In the event that the well is completed less 

than 30 days from the end of the calendar year, the first 30 days of the production straddling the current 

and following calendar years shall be used.

Tp = Time that gas is vented to either the atmosphere or a flare for each well, p, undergoing completion without 

hydraulic fracturing, in hours during the year.

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

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

emissions vented to atmosphere using calculations in paragraph (v) of this section.

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

completions and workovers not involving hydraulic fracturing as specified in paragraphs (h)(2)(i) and (ii) of 

this section.

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

are flared as determined using the methods specified in paragraphs (h) and (h)(1) of this section.

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

from the flare for gas well venting to a flare during completions and workovers without hydraulic 

fracturing.

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

depressurization of equipment to reduce system pressure for planned or emergency shutdowns resulting 

from human intervention or to take equipment out of service for maintenance as specified in either 

paragraph (i)(2) or (3) of this section. You may use the method in paragraph (i)(2) of this section for some 

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

vent stacks at your facility. Equipment with a unique physical volume of less than 50 cubic feet as 

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

through (4) of this section. The requirements in this paragraph (i) do not apply to blowdown vent stack 

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

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

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

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

and vessels) between isolation valves, in cubic feet, by using engineering estimates based on best 

available data.

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

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

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

specified in paragraph (i)(2)(i) of this section and either paragraph (i)(2)(ii) or, if applicable, paragraph 

(i)(2)(iii) of this section for each equipment or event type. Equipment or event types must be grouped into 
the following seven categories: Facility piping (i.e., piping within the facility boundary other than physical 

volumes associated with distribution pipelines), pipeline venting (i.e., physical volumes associated with 

distribution pipelines vented within the facility boundary), compressors, scrubbers/strainers, pig launchers 

and receivers, emergency shutdowns (this category includes emergency shutdown blowdown emissions 

regardless of equipment type), and all other equipment with a physical volume greater than or equal to 50 

cubic feet. If a blowdown event resulted in emissions from multiple equipment types and the emissions 

cannot be apportioned to the different equipment types, then categorize the blowdown event as the 

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

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

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

Where:

Es,n = Annual natural gas emissions at standard conditions from each unique physical volume that is blown down, in 

cubic feet.

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

V = Unique physical volume between isolation valves, in cubic feet, as calculated in paragraph (i)(1) of this section.

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

non-GHG gases.

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

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

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

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

Za = Compressibility factor at actual conditions for natural gas. You may use either a default compressibility factor of 

1, or a site-specific compressibility factor based on actual temperature and pressure conditions.

Where:

Es,n = Annual natural gas emissions at standard conditions from each unique physical volume that is blown down, in 

cubic feet.

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

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

Vp = Unique physical volume between isolation valves, in cubic feet, for each blowdown “p.”

Ts = Temperature at standard conditions (60 °F).
Ta,p = Temperature at actual conditions in the unique physical volume ( °F) for each blowdown “p”.

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

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

“p”.

Pa,e,p = Absolute pressure at actual conditions in the unique physical volume (psia) at the end of the blowdown “p”; 0 if 

blowdown volume is purged using non-GHG gases.

Za = Compressibility factor at actual conditions for natural gas. You may use either a default compressibility factor of 

1, or a site-specific compressibility factor based on actual temperature and pressure conditions.

(ii) Except as allowed in paragraph (i)(2)(iii) of this section, calculate annual CH4 and CO2 volumetric 

and mass emissions from each unique physical volume that is blown down by using the annual natural 

gas emission value as calculated in either Equation W-14A or Equation W-14B of paragraph (i)(2)(i) of 

this section and the calculation method specified in paragraph (i)(4) of this section. Calculate the total 

annual CH4 and CO2 emissions for each equipment or event type by summing the annual CH4 and CO2

mass emissions for all unique physical volumes associated with the equipment or event type.

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

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

to sum the annual natural gas emissions as calculated using either Equation W-14A or Equation W-14B

of paragraph (i)(2)(i) of this section for all unique physical volumes associated with the equipment type or 

event type. Calculate the total annual CH4 and CO2 volumetric and mass emissions for each equipment 

type or event type using the sums of the total annual natural gas emissions for each equipment type and 

the calculation method specified in paragraph (i)(4) of this section.

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

determining emissions from blowdown vent stacks as specified in paragraph (i)(2) of this section, you may 

use a flow meter and measure blowdown vent stack emissions for any unique physical volumes 

determined according to paragraph (i)(1) of this section to be greater than or equal to 50 cubic feet. If you 

choose to use this method, you must measure the natural gas emissions from the blowdown(s) through 

the monitored stack(s) using a flow meter according to methods in §98.234(b), and calculate annual CH4

and CO2 volumetric and mass emissions measured by the meters according to paragraph (i)(4) of this 

section.

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

Calculate both CH4 and CO2 volumetric and mass emissions using the methods specified in paragraphs 

(u) and (v) of this section.

(j) Onshore production 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), as specified in this paragraph (j). For wells flowing to gas-liquid separators with annual 

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

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

directly to atmospheric storage tanks without passing through a wellhead separator with throughput 

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

Method 2 as specified in paragraph (j)(2) of this section. For wells flowing to gas-liquid separators or 

directly to atmospheric storage tanks with throughput less than 10 barrels per day, use Calculation 

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

Method 2, you must also calculate emissions that may have occurred due to dump valves not closing 

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

pressure fixed roof storage tanks are routed to a vapor recovery system, you must adjust the emissions 

downward according to paragraph (j)(4) of this section. If emissions from atmospheric pressure fixed roof 
storage tanks are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified 

in paragraph (j)(5) of this section.

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

tanks 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. The following parameters must be determined for typical operating conditions over the year by 

engineering estimate and process knowledge based on best available data, and must be used at a 

minimum to characterize emissions from liquid transferred to tanks:

(i) Separator 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 using one of the methods described in paragraphs (j)(1)(vii)(A) through (C) 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 pressure using an appropriate standard method published by a consensus-based 

standards organization.

(2) Calculation Method 2. Calculate annual CH4 and CO2 emissions using the methods in paragraph 

(j)(2)(i) of this section for wells flowing to gas-liquid separators with annual average daily throughput of oil 

greater than or equal to 10 barrels per day. Calculate annual CH4 and CO2 emissions using the methods 

in paragraph (j)(2)(ii) of this section for wells with annual average daily oil production greater than or 

equal to 10 barrels per day that flow directly to atmospheric storage tanks.

(i) Flow to storage tank after passing through a separator. Assume that all of the CH4 and CO2 in 

solution at separator temperature and pressure is emitted from oil sent to storage tanks. You may use an 

appropriate standard method published by a consensus-based standards organization if such a method 

exists or you may use an industry standard practice as described in §98.234(b) to sample and analyze 

separator oil composition at separator pressure and temperature.

(ii) Flow to storage tank direct from wells. Calculate CH4 and CO2 emissions using either of the 

methods in paragraph (j)(2)(ii)(A) or (B) of this section.
(A) If well production oil and gas compositions are available through your previous analysis, select 

the latest available analysis that is representative of produced oil and gas from the sub-basin category 

and assume all of the CH4 and CO2 in both oil and gas are emitted from the tank.

(B) If well production oil and gas compositions are not available, use default oil and gas 

compositions in software programs, such as API 4697 E&P Tank, that most closely match 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.

(3) Calculation Method 3. Calculate CH4 and CO2 emissions using Equation W-15 of this section:

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.

(4) Determine if the storage tank receiving your separator oil has a vapor recovery system.

(i) Adjust the emissions estimated in paragraphs (j)(1) through (3) of this section downward by the 

magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate 

based on best available data.

(ii) [Reserved]

(5) Determine if the storage tank receiving your separator oil is sent to flare(s).

(i) Use your separator flash gas volume and gas composition as determined in this section.

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

tank emissions from the flare.

(6) If you use Calculation Method 1 or Calculation Method 2 in paragraph (j)(1) or (2) of this section, 

calculate emissions from occurrences of well pad gas-liquid separator liquid dump valves not closing 

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

Where:
Es,i,o = Annual volumetric GHG emissions at standard conditions from each storage tank in cubic feet that resulted 

from the dump valve on the gas-liquid separator not closing properly.

En = Storage tank emissions as determined in paragraphs (j)(1), (j)(2) and, if applicable, (j)(4) of this section in 

standard cubic feet per year.

Tn = Total time a dump valve is not closing properly in the calendar year in hours. Estimate Tn based on maintenance, 

operations, or routine well pad inspections that indicate the period of time when the valve was 

malfunctioning in open or partially open position.

CFn = Correction factor for tank emissions for time period Tn is 2.87 for crude oil production. Correction factor for tank 

emissions for time period Tn is 4.37 for gas condensate production.

8,760 = Conversion to hourly emissions.

(7) Calculate both CH4 and CO2 mass emissions from natural gas volumetric emissions using 

calculations in paragraph (v) of this section.

(k) Transmission storage tanks. For vent stacks connected to one or more transmission condensate 

storage tanks, either water or hydrocarbon, without vapor recovery, in onshore natural gas transmission 

compression, calculate CH4 and CO2 annual emissions from compressor scrubber dump valve leakage as 

specified in paragraphs (k)(1) through (k)(4) of this section. If emissions from compressor scrubber dump 

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

in paragraph (k)(5) of this section.

(1) Except as specified in paragraph (k)(1)(iv) of this section, you must monitor the tank vapor vent 

stack annually for emissions using one of the methods specified in paragraphs (k)(1)(i) through (iii) of this 

section.

(i) Use an optical gas imaging instrument according to methods set forth in §98.234(a)(1).

(ii) Measure the tank vent directly using a flow meter or high volume sampler according to methods 

in §98.234(b) or (d) for a duration of 5 minutes.

(iii) Measure the tank vent using a calibrated bag according to methods in §98.234(c) for a duration 

of 5 minutes or until the bag is full, whichever is shorter.

(iv) You may annually monitor leakage through compressor scrubber dump valve(s) into the tank 

using an acoustic leak detection device according to methods set forth in §98.234(a)(5).

(2) If the tank vapors from the vent stack are continuous for 5 minutes, or the optical gas imaging 

instrument or acoustic leak detection device detects a leak, then you must use one of the methods in 

either paragraph (k)(2)(i) or (ii) of this section.

(i) Use a flow meter, such as a turbine meter, calibrated bag, or high volume sampler to estimate 

tank vapor volumes from the vent stack according to methods set forth in §98.234(b) through (d). If you 

do not have a continuous flow measurement device, you may install a flow measuring device on the tank 

vapor vent stack. If the vent is directly measured for five minutes under paragraph (k)(1)(ii) or (iii) of this 

section to detect continuous leakage, this serves as the measurement.

(ii) Use an acoustic leak detection device on each scrubber dump valve connected to the tank 

according to the method set forth in §98.234(a)(5).

(3) If a leaking dump valve is identified, the leak must be counted as having occurred since the 

beginning of the calendar year, or from the previous test that did not detect leaking in the same calendar 
year. If the leaking dump valve is fixed following leak detection, the leak duration will end upon being 

repaired. If a leaking dump valve is identified and not repaired, the leak must be counted as having 

occurred through the rest of the calendar year.

(4) Use the requirements specified in paragraphs (k)(4)(i) and (ii) of this section to quantify annual 

emissions.

(i) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section.

(ii) Calculate CH4 and CO2 volumetric and mass emissions at standard conditions using calculations 

in paragraphs (t), (u), and (v) of this section, as applicable to the monitoring equipment used.

(5) Calculate annual emissions from storage tanks to flares as specified in paragraphs (k)(5)(i) and 

(ii) of this section.

(i) Use the storage tank emissions volume and gas composition as determined in paragraphs (k)(1) 

through (4) of this section.

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

tank emissions sent to a flare.

(l) Well testing venting and flaring. Calculate CH4 and CO2 annual emissions from well testing 

venting as specified in paragraphs (l)(1) through (5) of this section. If emissions from well testing venting 

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

(l)(6) of this section.

(1) Determine the gas to oil ratio (GOR) of the hydrocarbon production from oil well(s) tested. 

Determine the production rate from gas well(s) tested.

(2) If GOR cannot be determined from your available data, then you must measure quantities 

reported in this section according to one of the procedures specified in paragraph (l)(2)(i) or (ii) of this 

section to determine GOR.

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

organization if such a method exists.

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

(3) Estimate venting emissions using Equation W-17A (for oil wells) or Equation W-17B (for gas 

wells) of this section.

Where:

Ea,n = Annual volumetric natural gas emissions from well(s) testing in cubic feet under actual conditions.

GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API 

gravities.
FR = Average annual flow rate in barrels of oil per day for the oil well(s) being tested.

PR = Average annual production rate in actual cubic feet per day for the gas well(s) being tested.

D = Number of days during the calendar year that the well(s) is tested.

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

paragraph (t) of this section.

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

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

(6) Calculate emissions from well testing if emissions are routed to a flare as specified in paragraphs 

(l)(6)(i) and (ii) of this section.

(i) Use the well testing emissions volume and gas composition as determined in paragraphs (l)(1) 

through (4) of this section.

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

testing emissions from the flare.

(m) Associated gas venting and flaring. Calculate CH4 and CO2 annual emissions from associated 

gas venting not in conjunction with well testing (refer to paragraph (l): Well testing venting and flaring of 

this section) as specified in paragraphs (m)(1) through (4) of this section. If emissions from associated 

gas venting are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in 

paragraph (m)(5) of this section.

(1) Determine the GOR of the hydrocarbon production from each well whose associated natural gas 

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

same sub-basin category.

(2) If GOR cannot be determined from your available data, then you must use one of the procedures 

specified in paragraphs (m)(2)(i) or (ii) of this section to determine GOR.

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

organization if such a method exists.

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

(3) Estimate venting emissions using Equation W-18 of this section.

Where:

Es,n = Annual volumetric natural gas emissions, at the facility level, from associated gas venting at standard 

conditions, in cubic feet.

GORp,q = Gas to oil ratio, for well p in sub-basin q, in standard cubic feet of gas per barrel of oil; oil here refers to 

hydrocarbon liquids produced of all API gravities.
Vp,q = Volume of oil produced, for well p in sub-basin q, in barrels in the calendar year during time periods in which 

associated gas was vented or flared.

SGp,q = Volume of associated gas sent to sales, for well p in sub-basin q, in standard cubic feet of gas in the calendar 

year during time periods in which associated gas was vented or flared.

x = Total number of wells in sub-basin that vent or flare associated gas.

y = Total number of sub-basins in a basin that contain wells that vent or flare associated gas.

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

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

(5) Calculate emissions from associated natural gas if emissions are routed to a flare as specified in 

paragraphs (m)(5)(i) and (ii) of this section.

(i) Use the associated natural gas volume and gas composition as determined in paragraph (m)(1) 

through (4) of this section.

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

associated gas emissions from the flare.

(n) Flare stack emissions. Calculate CO2, CH4, and N2O emissions from a flare stack as specified in 

paragraphs (n)(1) through (9) of this section.

(1) If you have a continuous flow measurement device on the flare, you must use the measured flow 

volumes to calculate the flare gas emissions. If all of the flare gas is not measured by the existing flow 

measurement device, then the flow not measured can be estimated using engineering calculations based 

on best available data or company records. If you do not have a continuous flow measurement device on 

the flare, you can use engineering calculations based on process knowledge, company records, and best 

available data.

(2) If you have a continuous gas composition analyzer on gas to the flare, you must use these 

compositions in calculating emissions. If you do not have a continuous gas composition analyzer on gas 

to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the 

flare as specified in paragraphs (n)(2)(i) through (iii) of this section.

(i) For onshore natural gas production, determine the GHG mole fraction using paragraph (u)(2)(i) of 

this section.

(ii) For onshore natural gas processing, when the stream going to flare is natural gas, use the GHG 

mole fraction in feed natural gas for all streams upstream of the de-methanizer or dew point control, and 

GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions 

sources downstream of the de-methanizer overhead or dew point control for onshore natural gas 

processing facilities. For onshore natural gas processing plants that solely fractionate a liquid stream, use 

the GHG mole fraction in feed natural gas liquid for all streams.

(iii) For any industry segment required to report to flare stack emissions under §98.232, when the 

stream going to the flare is a hydrocarbon product stream, such as methane, ethane, propane, butane, 

pentane-plus and mixed light hydrocarbons, then you may use a representative composition from the 

source for the stream determined by engineering calculation based on process knowledge and best 

available data.
(3) Determine flare combustion efficiency from manufacturer. If not available, assume that flare 

combustion efficiency is 98 percent.

(4) Convert GHG volumetric emissions to standard conditions using calculations in paragraph (t) of 

this section.

(5) Calculate GHG volumetric emissions from flaring at standard conditions using Equations W-19 

and W-20 of this section.

Where:

Es,CH4 = Annual CH4 emissions from flare stack in cubic feet, at standard conditions.

Es,CO2 = Annual CO2 emissions from flare stack in cubic feet, at standard conditions.

Vs = Volume of gas sent to flare in standard cubic feet, during the year as determined in paragraph (n)(1) of this 

section.

η = Flare combustion efficiency, expressed as fraction of gas combusted by a burning flare (default is 0.98).

XCH4 = Mole fraction of CH4 in the feed gas to the flare as determined in paragraph (n)(2) of this section.

XCO2 = Mole fraction of CO2 in the feed gas to the flare as determined in paragraph (n)(2) of this section.

ZU = Fraction of the feed gas sent to an un-lit flare determined by engineering estimate and process knowledge based 

on best available data and operating records.

ZL = Fraction of the feed gas sent to a burning flare (equal to 1 − ZU).

Yj = Mole fraction of hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes-plus) in 

the feed gas to the flare as determined in paragraph (n)(1) of this section.

Rj = Number of carbon atoms in the hydrocarbon constituent j in the feed gas to the flare: 1 for methane, 2 for ethane, 

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

(6) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculation in 

paragraph (v) of this section.

(7) Calculate N2O emissions from flare stacks using Equation W-40 in paragraph (z) of this section.

(8) If you operate and maintain a CEMS that has both a CO2 concentration monitor and volumetric 

flow rate monitor for the combustion gases from the flare, you must calculate only CO2 emissions for the 

flare. You must follow the Tier 4 Calculation Method and all associated calculation, quality assurance, 

reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel 

Combustion Sources). If a CEMS is used to calculate flare stack emissions, the requirements specified in 

paragraphs (n)(1) through (7) of this section are not required.

(9) The flare emissions determined under this paragraph (n) must be corrected for flare emissions 

calculated and reported under other paragraphs of this section to avoid double counting of these 

emissions.
(o) Centrifugal compressor venting. If you are required to report emissions from centrifugal 

compressor venting as specified in §98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct 

volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified 

in paragraphs (o)(2) through (5) of this section; perform calculations specified in paragraphs (o)(6) 

through (9) of this section; and calculate CH4 and CO2 mass emissions as specified in paragraph (o)(11) 

of this section. If emissions from a compressor source are routed to a flare, paragraphs (o)(1) through 

(11) of this section do not apply and instead you must calculate CH4, CO2, and N2O emissions as specified 

in paragraph (o)(12) of this section. If emissions from a compressor source are captured for fuel use or 

are routed to a thermal oxidizer, paragraphs (o)(1) through (12) of this section do not apply and instead 

you must calculate and report emissions as specified in subpart C of this part. If emissions from a 

compressor source are routed to vapor recovery, paragraphs (o)(1) through (12) of this section do not 

apply. If you are required to report emissions from centrifugal compressor venting at an onshore 

petroleum and natural gas production facility as specified in §98.232(c)(19), you must calculate volumetric 

emissions as specified in paragraph (o)(10) of this section; and calculate CH4 and CO2 mass emissions as 

specified in paragraph (o)(11) of this section.

(1) General requirements for conducting volumetric emission measurements. You must conduct 

volumetric emission measurements on each centrifugal compressor as specified in this paragraph. 

Compressor sources (as defined in §98.238) without manifolded vents must use a measurement method 

specified in paragraph (o)(1)(i) or (ii) of this section. Manifolded compressor sources (as defined in 

§98.238) must use a measurement method specified in paragraph (o)(1)(i), (ii), (iii), or (iv) of this section.

(i) Centrifugal compressor source as found measurements. Measure venting from each compressor 

according to either paragraph (o)(1)(i)(A) or (B) of this section at least once annually, based on the 

compressor mode (as defined in §98.238) in which the compressor was found at the time of 

measurement, except as specified in paragraphs (o)(1)(i)(C) and (D) of this section. If additional 

measurements beyond the required annual testing are performed (including duplicate measurements or 

measurement of additional operating modes), then all measurements satisfying the applicable monitoring 

and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this 

section.

(A) For a compressor measured in operating-mode, you must measure volumetric emissions from 

blowdown valve leakage through the blowdown vent as specified in either paragraph (o)(2)(i)(A) or (B) of 

this section and, if the compressor has wet seal oil degassing vents, measure volumetric emissions from 

wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section.

(B) For a compressor measured in not-operating-depressurized-mode, you must measure 

volumetric emissions from isolation valve leakage as specified in either paragraph (o)(2)(i)(A), (B), or (C) 

of this section. If a compressor is not operated and has blind flanges in place throughout the reporting 

period, measurement is not required in this compressor mode.

(C) You must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section at least 

once in any three consecutive calendar years, provided the measurement can be taken during a 

scheduled shutdown. If three consecutive calendar years occur without measuring the compressor in notoperating-depressurized-mode, you must measure the compressor as specified in paragraph (o)(1)(i)(B) 

of this section at the next scheduled depressurized shutdown. The requirement specified in this 

paragraph does not apply if the compressor has blind flanges in place throughout the reporting year. For 

purposes of this paragraph, a scheduled shutdown means a shutdown that requires a compressor to be 

taken off-line for planned or scheduled maintenance. A scheduled shutdown does not include instances 

when a compressor is taken offline due to a decrease in demand but must remain available.

(D) An annual as found measurement is not required in the first year of operation for any new 

compressor that begins operation after as found measurements have been conducted for all existing 

compressors. For only the first year of operation of new compressors, calculate emissions according to 

paragraph (o)(6)(ii) of this section.
(ii) Centrifugal compressor source continuous monitoring. Instead of measuring the compressor 

source according to paragraph (o)(1)(i) of this section for a given compressor, you may elect to 

continuously measure volumetric emissions from a compressor source as specified in paragraph (o)(3) of 

this section.

(iii) Manifolded centrifugal compressor source as found measurements. For a compressor source 

that is part of a manifolded group of compressor sources (as defined in §98.238), instead of measuring 

the compressor source according to paragraph (o)(1)(i), (ii), or (iv) of this section, you may elect to 

measure combined volumetric emissions from the manifolded group of compressor sources by 

conducting measurements at the common vent stack as specified in paragraph (o)(4) of this section. The 

measurements must be conducted at the frequency specified in paragraphs (o)(1)(iii)(A) and (B) of this 

section.

(A) A minimum of one measurement must be taken for each manifolded group of compressor 

sources in a calendar year.

(B) The measurement may be performed while the compressors are in any compressor mode.

(iv) Manifolded centrifugal compressor source continuous monitoring. For a compressor source that 

is part of a manifolded group of compressor sources, instead of measuring the compressor source 

according to paragraph (o)(1)(i), (ii), or (iii) of this section, you may elect to continuously measure 

combined volumetric emissions from the manifolded group of compressor sources as specified in 

paragraph (o)(5) of this section.

(2) Methods for performing as found measurements from individual centrifugal compressor sources.

If conducting measurements for each compressor source, you must determine the volumetric emissions 

from blowdown valves and isolation valves as specified in paragraph (o)(2)(i) of this section, and the 

volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section.

(i) For blowdown valves on compressors in operating-mode and for isolation valves on compressors 

in not-operating-depressurized-mode, determine the volumetric emissions using one of the methods 

specified in paragraphs (o)(2)(i)(A) through (D) of this section.

(A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated 

bagging or high volume sampler according to methods set forth in §98.234(c) and §98.234(d), 

respectively.

(B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary 

meter such as a vane anemometer according to methods set forth in §98.234(b).

(C) Use an acoustic leak detection device according to methods set forth in §98.234(a)(5).

(D) You may choose to use any of the methods set forth in §98.234(a) to screen for emissions. If 

emissions are detected using the methods set forth in §98.234(a), then you must use one of the methods 

specified in paragraph (o)(2)(i)(A) through (C) of this section. If emissions are not detected using the 

methods in §98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of 

this paragraph, when using any of the methods in §98.234(a), emissions are detected whenever a leak is 

detected according to the methods.

(ii) For wet seal oil degassing vents in operating-mode, determine vapor volumes at standard 

conditions, using a temporary meter such as a vane anemometer or permanent flow meter according to 

methods set forth in §98.234(b).
(3) Methods for continuous measurement from individual centrifugal compressor sources. If you 

elect to conduct continuous volumetric emission measurements for an individual compressor source as 

specified in paragraph (o)(1)(ii) of this section, you must measure volumetric emissions as specified in 

paragraphs (o)(3)(i) and (ii) of this section.

(i) Continuously measure the volumetric flow for the individual compressor source at standard 

conditions using a permanent meter according to methods set forth in §98.234(b).

(ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph 

(o)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions 

for the compressor source and do not need to be calculated separately using the method specified in 

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

(4) Methods for performing as found measurements from manifolded groups of centrifugal 

compressor sources. If conducting measurements for a manifolded group of compressor sources, you 

must measure volumetric emissions as specified in paragraphs (o)(4)(i) and (ii) of this section.

(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, 

prior to comingling with other non-compressor emission sources.

(ii) Determine the volumetric flow at standard conditions from the common stack using one of the 

methods specified in paragraphs (o)(4)(ii)(A) through (E) of this section.

(A) A temporary meter such as a vane anemometer according the methods set forth in §98.234(b).

(B) Calibrated bagging according to methods set forth in §98.234(c).

(C) A high volume sampler according to methods set forth §98.234(d).

(D) An acoustic leak detection device according to methods set forth in §98.234(a)(5).

(E) You may choose to use any of the methods set forth in §98.234(a) to screen for emissions. If 

emissions are detected using the methods set forth in §98.234(a), then you must use one of the methods 

specified in paragraph (o)(4)(ii)(A) through (o)(4)(ii)(D) of this section. If emissions are not detected using 

the methods in §98.234(a), then you may assume that the volumetric emissions are zero. For the 

purposes of this paragraph, when using any of the methods in §98.234(a), emissions are detected 

whenever a leak is detected according to the method.

(5) Methods for continuous measurement from manifolded groups of centrifugal compressor 

sources. If you elect to conduct continuous volumetric emission measurements for a manifolded group of 

compressor sources as specified in paragraph (o)(1)(iv) of this section, you must measure volumetric 

emissions as specified in paragraphs (o)(5)(i) through (iii) of this section.

(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, 

prior to comingling with other non-compressor emission sources.

(ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at 

standard conditions using a permanent meter according to methods set forth in §98.234(b).

(iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph 

(o)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported 

emissions for the manifolded group of compressor sources and do not need to be calculated separately 

using the method specified in paragraph (i) of this section for blowdown vent stacks.
(6) Method for calculating volumetric GHG emissions from as found measurements for individual 

centrifugal compressor sources. For compressor sources measured according to paragraph (o)(1)(i) of 

this section, you must calculate annual GHG emissions from the compressor sources as specified in 

paragraphs (o)(6)(i) through (iv) of this section.

(i) Using Equation W-21 of this section, calculate the annual volumetric GHG emissions for each 

centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) and (B) of this 

section that was measured during the reporting year.

Where:

Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for measured compressor mode-source combination m, 

at standard conditions, in cubic feet.

MTs,m = Volumetric gas emissions for measured compressor mode-source combination m, in standard cubic feet per 

hour, measured according to paragraph (o)(2) of this section. If multiple measurements are performed for 

a given mode-source combination m, use the average of all measurements.

Tm = Total time the compressor is in the mode-source combination for which Es,i,m is being calculated in the reporting 

year, in hours.

GHGi,m = Mole fraction of GHGi in the vent gas for measured compressor mode-source combination m; use the 

appropriate gas compositions in paragraph (u)(2) of this section.

m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section that was 

measured for the reporting year.

(ii) Using Equation W-22 of this section, calculate the annual volumetric GHG emissions from each 

centrifugal compressor mode-source combination specified in paragraph (o)(1)(i)(A) and (B) of this 

section that was not measured during the reporting year.

Where:

Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for unmeasured compressor mode-source combination 

m, at standard conditions, in cubic feet.

EFs,m = Reporter emission factor for compressor mode-source combination m, in standard cubic feet per hour, as 

calculated in paragraph (o)(6)(iii) of this section.

Tm = Total time the compressor was in the unmeasured mode-source combination m, for which Es,i,m is being 

calculated in the reporting year, in hours.

GHGi,m = Mole fraction of GHGi in the vent gas for unmeasured compressor mode-source combination m; use the 

appropriate gas compositions in paragraph (u)(2) of this section.

m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section that was 

not measured in the reporting year.
(iii) Using Equation W-23 of this section, develop an emission factor for each compressor modesource combination specified in paragraph (o)(1)(i)(A) and (B) of this section. These emission factors 

must be calculated annually and used in Equation W-22 of this section to determine volumetric emissions 

from a centrifugal compressor in the mode-source combinations that were not measured in the reporting 

year.

Where:

EFs,m = Reporter emission factor to be used in Equation W-22 of this section for compressor mode-source 

combination m, in standard cubic feet per hour. The reporter emission factor must be based on all 

compressors measured in compressor mode-source combination m in the current reporting year and the 

preceding two reporting years.

MTs,m,p = Average volumetric gas emission measurement for compressor mode-source combination m, for compressor 

p, in standard cubic feet per hour, calculated using all volumetric gas emission measurements (MTs,m in 

Equation W-21 of this section) for compressor mode-source combination m for compressor p in the 

current reporting year and the preceding two reporting years.

Countm = Total number of compressors measured in compressor mode-source combination m in the current reporting 

year and the preceding two reporting years.

m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section.

(iv) The reporter emission factor in Equation W-23 of this section may be calculated by using all 

measurements from a single owner or operator instead of only using measurements from a single facility. 

If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the 

owner or operator.

(7) Method for calculating volumetric GHG emissions from continuous monitoring of individual 

centrifugal compressor sources. For compressor sources measured according to paragraph (o)(1)(ii) of 

this section, you must use the continuous volumetric emission measurements taken as specified in 

paragraph (o)(3) of this section and calculate annual volumetric GHG emissions associated with the 

compressor source using Equation W-24A of this section.

Where:

Es,i,v = Annual volumetric GHGi (either CH4 or CO2) emissions from compressor source v, at standard conditions, in 

cubic feet.

Qs,v = Volumetric gas emissions from compressor source v, for reporting year, in standard cubic feet.

GHGi,v = Mole fraction of GHGi in the vent gas for compressor source v; use the appropriate gas compositions in 

paragraph (u)(2) of this section.

(8) Method for calculating volumetric GHG emissions from as found measurements of manifolded

groups of centrifugal compressor sources. For manifolded groups of compressor sources measured 
according to paragraph (o)(1)(iii) of this section, you must calculate annual volumetric GHG emissions 

using Equation W-24B of this section. If the centrifugal compressors included in the manifolded group of 

compressor sources share the manifold with reciprocating compressors, you must follow the procedures 

in either this paragraph (o)(8) or paragraph (p)(8) of this section to calculate emissions from the 

manifolded group of compressor sources.

Where:

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions for manifolded group of compressor sources g, at 

standard conditions, in cubic feet.

Tg = Total time the manifolded group of compressor sources g had potential for emissions in the reporting year, in 

hours. Include all time during which at least one compressor source in the manifolded group of 

compressor sources g was in a mode-source combination specified in either paragraph (o)(1)(i)(A), 

(o)(1)(i)(B), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. Default of 8760 hours may be used.

MTs,g,avg = Average volumetric gas emissions of all measurements performed in the reporting year according to 

paragraph (o)(4) of this section for the manifolded group of compressor sources g, in standard cubic feet 

per hour.

GHGi,g = Mole fraction of GHGi in the vent gas for manifolded group of compressor sources g; use the appropriate gas 

compositions in paragraph (u)(2) of this section.

(9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded 

group of centrifugal compressor sources. For a manifolded group of compressor sources measured 

according to paragraph (o)(1)(iv) of this section, you must use the continuous volumetric emission 

measurements taken as specified in paragraph (o)(5) of this section and calculate annual volumetric GHG 

emissions associated with each manifolded group of compressor sources using Equation W-24C of this 

section. If the centrifugal compressors included in the manifolded group of compressor sources share the 

manifold with reciprocating compressors, you must follow the procedures in either this paragraph (o)(9) or 

paragraph (p)(9) of this section to calculate emissions from the manifolded group of compressor sources.

Where:

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions from manifolded group of compressor sources g, at 

standard conditions, in cubic feet.

Qs,g = Volumetric gas emissions from manifolded group of compressor sources g, for reporting year, in standard cubic 

feet.

GHGi,g = Mole fraction of GHGi in the vent gas for measured manifolded group of compressor sources g; use the 

appropriate gas compositions in paragraph (u)(2) of this section.

(10) Method for calculating volumetric GHG emissions from wet seal oil degassing vents at an 

onshore petroleum and natural gas production facility. You must calculate emissions from centrifugal 

compressor wet seal oil degassing vents at an onshore petroleum and natural gas production facility 

using Equation W-25 of this section.
Where:

Es,i = Annual volumetric GHGi (either CH4 or CO2) emissions from centrifugal compressor wet seals, at standard 

conditions, in cubic feet.

Count = Total number of centrifugal compressors that have wet seal oil degassing vents.

EFi,s = Emission factor for GHGi. Use 1.2 × 107 standard cubic feet per year per compressor for CH4 and 5.30 × 105

standard cubic feet per year per compressor for CO2 at 60 °F and 14.7 psia.

(11) Method for converting from volumetric to mass emissions. You must calculate both CH4 and 

CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.

(12) General requirements for calculating volumetric GHG emissions from centrifugal compressors 

routed to flares. You must calculate and report emissions from all centrifugal compressor sources that are 

routed to a flare as specified in paragraphs (o)(12)(i) through (iii) of this section.

(i) Paragraphs (o)(1) through (11) of this section are not required for compressor sources that are 

routed to a flare.

(ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as 

specified in paragraph (n) of this section and report emissions from the flare as specified in §98.236(n), 

without subtracting emissions attributable to compressor sources from the flare.

(iii) Report all applicable activity data for compressors with compressor sources routed to flares as 

specified in §98.236(o).

(p) Reciprocating compressor venting. If you are required to report emissions from reciprocating 

compressor venting as specified in §98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct 

volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified 

in paragraphs (p)(2) through (5) of this section; perform calculations specified in paragraphs (p)(6) 

through (9) of this section; and calculate CH4 and CO2 mass emissions as specified in paragraph (p)(11) 

of this section. If emissions from a compressor source are routed to a flare, paragraphs (p)(1) through 

(11) of this section do not apply and instead you must calculate CH4, CO2, and N2O emissions as specified 

in paragraph (p)(12) of this section. If emissions from a compressor source are captured for fuel use or 

are routed to a thermal oxidizer, paragraphs (p)(1) through (12) of this section do not apply and instead 

you must calculate and report emissions as specified in subpart C of this part. If emissions from a 

compressor source are routed to vapor recovery, paragraphs (p)(1) through (12) of this section do not 

apply. If you are required to report emissions from reciprocating compressor venting at an onshore 

petroleum and natural gas production facility as specified in §98.232(c)(11), you must calculate volumetric 

emissions as specified in paragraph (p)(10) of this section; and calculate CH4 and CO2 mass emissions as 

specified in paragraph (p)(11) of this section.

(1) General requirements for conducting volumetric emission measurements. You must conduct 

volumetric emission measurements on each reciprocating compressor as specified in this paragraph. 

Compressor sources (as defined in §98.238) without manifolded vents must use a measurement method 

specified in paragraph (p)(1)(i) or (ii) of this section. Manifolded compressor sources (as defined in 

§98.238) must use a measurement method specified in paragraph (p)(1)(i), (ii), (iii), or (iv) of this section.

(i) Reciprocating compressor source as found measurements. Measure venting from each 

compressor according to either paragraph (p)(1)(i)(A), (B), or (C) of this section at least once annually, 

based on the compressor mode (as defined in §98.238) in which the compressor was found at the time of 

measurement, except as specified in paragraphs (p)(1)(i)(D) and (E) of this section. If additional 
measurements beyond the required annual testing are performed (including duplicate measurements or 

measurement of additional operating modes), then all measurements satisfying the applicable monitoring 

and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this 

section.

(A) For a compressor measured in operating-mode, you must measure volumetric emissions from 

blowdown valve leakage through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (B) of 

this section, and measure volumetric emissions from reciprocating rod packing as specified in paragraph 

(p)(2)(ii) of this section.

(B) For a compressor measured in standby-pressurized-mode, you must measure volumetric 

emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph 

(p)(2)(i)(A) or (B) of this section.

(C) For a compressor measured in not-operating-depressurized-mode, you must measure 

volumetric emissions from isolation valve leakage as specified in either paragraph (p)(2)(i)(A), (B), or (C) 

of this section. If a compressor is not operated and has blind flanges in place throughout the reporting 

period, measurement is not required in this compressor mode.

(D) You must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at least 

once in any three consecutive calendar years, provided the measurement can be taken during a 

scheduled shutdown. If there is no scheduled shutdown within three consecutive calendar years, you 

must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at the next scheduled 

depressurized shutdown. For purposes of this paragraph, a scheduled shutdown means a shutdown that 

requires a compressor to be taken off-line for planned or scheduled maintenance. A scheduled shutdown 

does not include instances when a compressor is taken offline due to a decrease in demand but must 

remain available.

(E) An annual as found measurement is not required in the first year of operation for any new 

compressor that begins operation after as found measurements have been conducted for all existing 

compressors. For only the first year of operation of new compressors, calculate emissions according to 

paragraph (p)(6)(ii) of this section.

(ii) Reciprocating compressor source continuous monitoring. Instead of measuring the compressor 

source according to paragraph (p)(1)(i) of this section for a given compressor, you may elect to 

continuously measure volumetric emissions from a compressor source as specified in paragraph (p)(3) of 

this section.

(iii) Manifolded reciprocating compressor source as found measurements. For a compressor source 

that is part of a manifolded group of compressor sources (as defined in §98.238), instead of measuring 

the compressor source according to paragraph (p)(1)(i), (ii), or (iv) of this section, you may elect to 

measure combined volumetric emissions from the manifolded group of compressor sources by 

conducting measurements at the common vent stack as specified in paragraph (p)(4) of this section. The 

measurements must be conducted at the frequency specified in paragraphs (p)(1)(iii)(A) and (B) of this 

section.

(A) A minimum of one measurement must be taken for each manifolded group of compressor 

sources in a calendar year.

(B) The measurement may be performed while the compressors are in any compressor mode.

(iv) Manifolded reciprocating compressor source continuous monitoring. For a compressor source 

that is part of a manifolded group of compressor sources, instead of measuring the compressor source 

according to paragraph (p)(1)(i), (ii), or (iii) of this section, you may elect to continuously measure 
combined volumetric emissions from the manifolded group of compressors sources as specified in 

paragraph (p)(5) of this section.

(2) Methods for performing as found measurements from individual reciprocating compressor 

sources. If conducting measurements for each compressor source, you must determine the volumetric 

emissions from blowdown valves and isolation valves as specified in paragraph (p)(2)(i) of this section. 

You must determine the volumetric emissions from reciprocating rod packing as specified in paragraph 

(p)(2)(ii) or (iii) of this section.

(i) For blowdown valves on compressors in operating-mode or standby-pressurized-mode, and for 

isolation valves on compressors in not-operating-depressurized-mode, determine the volumetric 

emissions using one of the methods specified in paragraphs (p)(2)(i)(A) through (D) of this section.

(A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated 

bagging or high volume sampler according to methods set forth in §98.234(c) and (d), respectively.

(B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary 

meter such as a vane anemometer, according to methods set forth in §98.234(b).

(C) Use an acoustic leak detection device according to methods set forth in §98.234(a)(5).

(D) You may choose to use any of the methods set forth in §98.234(a) to screen for emissions. If 

emissions are detected using the methods set forth in §98.234(a), then you must use one of the methods 

specified in paragraphs (p)(2)(i)(A) through (C) of this section. If emissions are not detected using the 

methods in §98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of 

this paragraph, when using any of the methods in §98.234(a), emissions are detected whenever a leak is 

detected according to the method.

(ii) For reciprocating rod packing equipped with an open-ended vent line on compressors in 

operating-mode, determine the volumetric emissions using one of the methods specified in paragraphs 

(p)(2)(ii)(A) through (C) of this section.

(A) Determine the volumetric flow at standard conditions from the open-ended vent line using 

calibrated bagging or high volume sampler according to methods set forth in §98.234(c) and (d), 

respectively.

(B) Determine the volumetric flow at standard conditions from the open-ended vent line using a 

temporary meter such as a vane anemometer, according to methods set forth in §98.234(b).

(C) You may choose to use any of the methods set forth in §98.234(a) to screen for emissions. If 

emissions are detected using the methods set forth in §98.234(a), then you must use one of the methods 

specified in paragraph (p)(2)(ii)(A) and (p)(4)(ii)(B) of this section. If emissions are not detected using the 

methods in §98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of 

this paragraph, when using any of the methods in §98.234(a), emissions are detected whenever a leak is 

detected according to the method.

(iii) For reciprocating rod packing not equipped with an open-ended vent line on compressors in 

operating-mode, you must determine the volumetric emissions using the method specified in paragraphs 

(p)(2)(iii)(A) and (B) of this section.

(A) You must use the methods described in §98.234(a) to conduct annual leak detection of 

equipment leaks from the packing case into an open distance piece, or for compressors with a closed 
distance piece, conduct annual detection of gas emissions from the rod packing vent, distance piece vent, 

compressor crank case breather cap, or other vent emitting gas from the rod packing.

(B) You must measure emissions found in paragraph (p)(2)(iii)(A) of this section using an 

appropriate meter, calibrated bag, or high volume sampler according to methods set forth in §98.234(b), 

(c), and (d), respectively.

(3) Methods for continuous measurement from individual reciprocating compressor sources. If you 

elect to conduct continuous volumetric emission measurements for an individual compressor source as 

specified in paragraph (p)(1)(ii) of this section, you must measure volumetric emissions as specified in 

paragraphs (p)(3)(i) and (p)(3)(ii) of this section.

(i) Continuously measure the volumetric flow for the individual compressor sources at standard 

conditions using a permanent meter according to methods set forth in §98.234(b).

(ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph 

(p)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions 

for the compressor source and do not need to be calculated separately using the method specified in 

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

(4) Methods for performing as found measurements from manifolded groups of reciprocating 

compressor sources. If conducting measurements for a manifolded group of compressor sources, you 

must measure volumetric emissions as specified in paragraphs (p)(4)(i) and (ii) of this section.

(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, 

prior to comingling with other non-compressor emission sources.

(ii) Determine the volumetric flow at standard conditions from the common stack using one of the 

methods specified in paragraph (p)(4)(ii)(A) through (E) of this section.

(A) A temporary meter such as a vane anemometer according the methods set forth in §98.234(b).

(B) Calibrated bagging according to methods set forth in §98.234(c).

(C) A high volume sampler according to methods set forth §98.234(d).

(D) An acoustic leak detection device according to methods set forth in §98.234(a)(5).

(E) You may choose to use any of the methods set forth in §98.234(a) to screen for emissions. If 

emissions are detected using the methods set forth in §98.234(a), then you must use one of the methods 

specified in paragraph (p)(4)(ii)(A) through (D) of this section. If emissions are not detected using the 

methods in §98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of 

this paragraph, when using any of the methods in §98.234(a), emissions are detected whenever a leak is 

detected according to the method.

(5) Methods for continuous measurement from manifolded groups of reciprocating compressor 

sources. If you elect to conduct continuous volumetric emission measurements for a manifolded group of 

compressor sources as specified in paragraph (p)(1)(iv) of this section, you must measure volumetric 

emissions as specified in paragraphs (p)(5)(i) through (iii) of this section.

(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, 

prior to comingling with other non-compressor emission sources.
(ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at 

standard conditions using a permanent meter according to methods set forth in §98.234(b).

(iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph 

(p)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported 

emissions for the manifolded group of compressor sources and do not need to be calculated separately 

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

(6) Method for calculating volumetric GHG emissions from as found measurements for individual 

reciprocating compressor sources. For compressor sources measured according to paragraph (p)(1)(i) of 

this section, you must calculate GHG emissions from the compressor sources as specified in paragraphs 

(p)(6)(i) through (iv) of this section.

(i) Using Equation W-26 of this section, calculate the annual volumetric GHG emissions for each 

reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of 

this section that was measured during the reporting year.

Where:

Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for measured compressor mode-source combination m, 

at standard conditions, in cubic feet.

MTs,m = Volumetric gas emissions for measured compressor mode-source combination m, in standard cubic feet per 

hour, measured according to paragraph (p)(2) of this section. If multiple measurements are performed for 

a given mode-source combination m, use the average of all measurements.

Tm = Total time the compressor is in the mode-source combination m, for which Es,i,m is being calculated in the 

reporting year, in hours.

GHGi,m = Mole fraction of GHGi in the vent gas for measured compressor mode-source combination m; use the 

appropriate gas compositions in paragraph (u)(2) of this section.

m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), or (C) of this section that was 

measured for the reporting year.

(ii) Using Equation W-27 of this section, calculate the annual volumetric GHG emissions from each 

reciprocating compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), and (C) of this 

section that was not measured during the reporting year.

Where:

Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for unmeasured compressor mode-source combination 

m, at standard conditions, in cubic feet.

EFs,m = Reporter emission factor for compressor mode-source combination m, in standard cubic feet per hour, as 

calculated in paragraph (p)(6)(iii) of this section.

Tm = Total time the compressor was in the unmeasured mode-source combination m, for which Es,i,m is being 

calculated in the reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas for unmeasured compressor mode-source combination m; use the 

appropriate gas compositions in paragraph (u)(2) of this section.

m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this 

section that was not measured for the reporting year.

(iii) Using Equation W-28 of this section, develop an emission factor for each compressor modesource combination specified in paragraph (p)(1)(i)(A), (B), and (C) of this section. These emission factors 

must be calculated annually and used in Equation W-27 of this section to determine volumetric emissions 

from a reciprocating compressor in the mode-source combinations that were not measured in the 

reporting year.

Where:

EFs,m = Reporter emission factor to be used in Equation W-27 of this section for compressor mode-source 

combination m, in standard cubic feet per hour. The reporter emission factor must be based on all 

compressors measured in compressor mode-source combination m in the current reporting year and the 

preceding two reporting years.

MTs,m,p = Average volumetric gas emission measurement for compressor mode-source combination m, for compressor 

p, in standard cubic feet per hour, calculated using all volumetric gas emission measurements (MTs,m in 

Equation W-26 of this section) for compressor mode-source combination m for compressor p in the 

current reporting year and the preceding two reporting years.

Countm = Total number of compressors measured in compressor mode-source combination m in the current reporting 

year and the preceding two reporting years.

m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), or (C) of this section.

(iv) The reporter emission factor in Equation W-28 of this section may be calculated by using all 

measurements from a single owner or operator instead of only using measurements from a single facility. 

If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the 

owner or operator.

(7) Method for calculating volumetric GHG emissions from continuous monitoring of individual 

reciprocating compressor sources. For compressor sources measured according to paragraph (p)(1)(ii) of 

this section, you must use the continuous volumetric emission measurements taken as specified in 

paragraph (p)(3) of this section and calculate annual volumetric GHG emissions associated with the 

compressor source using Equation W-29A of this section.

Where:

Es,i,v = Annual volumetric GHGi (either CH4 or CO2) emissions from compressor source v, at standard conditions, in 

cubic feet.

Qs,v = Volumetric gas emissions from compressor source v, for reporting year, in standard cubic feet.
GHGi,v = Mole fraction of GHGi in the vent gas for compressor source v; use the appropriate gas compositions in 

paragraph (u)(2) of this section.

(8) Method for calculating volumetric GHG emissions from as found measurements of manifolded 

groups of reciprocating compressor sources. For manifolded groups of compressor sources measured 

according to paragraph (p)(1)(iii) of this section, you must calculate annual GHG emissions using 

Equation W-29B of this section. If the reciprocating compressors included in the manifolded group of 

compressor sources share the manifold with centrifugal compressors, you must follow the procedures in 

either this paragraph (p)(8) or paragraph (o)(8) of this section to calculate emissions from the manifolded 

group of compressor sources.

Where:

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions for manifolded group of compressor sources g, at 

standard conditions, in cubic feet.

Tg = Total time the manifolded group of compressor sources g had potential for emissions in the reporting year, in 

hours. Include all time during which at least one compressor source in the manifolded group of 

compressor sources g was in a mode-source combination specified in either paragraph (o)(1)(i)(A), 

(o)(1)(i)(B), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. Default of 8760 hours may be used.

MTs,g,avg = Average volumetric gas emissions of all measurements performed in the reporting year according to 

paragraph (p)(4) of this section for the manifolded group of compressor sources g, in standard cubic feet 

per hour.

GHGi,g = Mole fraction of GHGi in the vent gas for manifolded group of compressor sources g; use the appropriate gas 

compositions in paragraph (u)(2) of this section.

(9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded 

group of reciprocating compressor sources. For a manifolded group of compressor sources measured 

according to paragraph (p)(1)(iv) of this section, you must use the continuous volumetric emission 

measurements taken as specified in paragraph (p)(5) of this section and calculate annual volumetric GHG 

emissions associated with each manifolded group of compressor sources using Equation W-29C of this 

section. If the reciprocating compressors included in the manifolded group of compressor sources share 

the manifold with centrifugal compressors, you must follow the procedures in either this paragraph (p)(9) 

or paragraph (o)(9) of this section to calculate emissions from the manifolded group of compressor 

sources.

Where:

Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions from manifolded group of compressor sources g, at 

standard conditions, in cubic feet.

Qs,g = Volumetric gas emissions from manifolded group of compressor sources g, for reporting year, in standard cubic 

feet.

GHGi,g = Mole fraction of GHGi in the vent gas for measured manifolded group of compressor sources g; use the 

appropriate gas compositions in paragraph (u)(2) of this section.
(10) Method for calculating volumetric GHG emissions from reciprocating compressor venting at an 

onshore petroleum and natural gas production facility. You must calculate emissions from reciprocating 

compressor venting at an onshore petroleum and natural gas production facility using Equation W-29D of 

this section.

Where:

Es,i = Annual volumetric GHGi (either CH4 or CO2) emissions from reciprocating compressors, at standard conditions, 

in cubic feet.

Count = Total number of reciprocating compressors.

EFi,s = Emission factor for GHGi. Use 9.48 × 103 standard cubic feet per year per compressor for CH4 and 5.27 × 102

standard cubic feet per year per compressor for CO2 at 60 °F and 14.7 psia.

(11) Method for converting from volumetric to mass emissions. You must calculate both CH4 and 

CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section.

(12) General requirements for calculating volumetric GHG emissions from reciprocating 

compressors routed to flares. You must calculate and report emissions from all reciprocating compressor 

sources that are routed to a flare as specified in paragraphs (p)(12)(i) through (iii) of this section.

(i) Paragraphs (p)(1) through (11) of this section are not required for compressor sources that are 

routed to a flare.

(ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as 

specified in paragraph (n) of this section and report emissions from the flare as specified in §98.236(n), 

without subtracting emissions attributable to compressor sources from the flare.

(iii) Report all applicable activity data for compressors with compressor sources routed to flares as 

specified in §98.236(p).

(q) Equipment leak surveys. You must use the methods described in §98.234(a) to conduct leak 

detection(s) of equipment leaks from all component types listed 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 or equal to 

10 percent CH4 plus CO2 by weight are exempt from the requirements of this paragraph (q) and do not 

need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the 

requirements of this paragraph (q) and do not need to be reported. For industry segments listed in 

§98.230(a)(3) through (8), if equipment leaks are detected for component types listed in this paragraph 

(q), then you must calculate equipment leak emissions per component type per reporting facility using 

Equation W-30 of this section. For the industry segment listed in §98.230(a)(8), the results from Equation 

W-30 are used to calculate population emission factors on a meter/regulator run basis using Equation W31 of this section. If you chose to conduct equipment leak surveys at all above grade transmissiondistribution transfer stations over multiple years, “n,” according to paragraph (q)(8)(i) of this section, then 

you must calculate the emissions from all above grade transmission-distribution transfer stations as 

specified in paragraph (q)(9) of this section.
Where:

Es,p,i = Annual total volumetric emissions of GHGi from specific component type “p” (listed in §98.232(d)(7), (e)(7), 

(f)(5), (g)(3), (h)(4), and (i)(1)) in standard (“s”) cubic feet, as specified in paragraphs (q)(1) through (q)(8) 

of this section.

xp = Total number of specific component type “p” detected as leaking during annual leak surveys.

EFs,p = Leaker emission factor for specific component types listed in Table W-2 through Table W-7 of this subpart.

GHGi = For onshore natural gas processing facilities, concentration of GHGi, CH4 or CO2, in the total hydrocarbon of 

the feed natural gas; for onshore natural gas transmission compression and underground natural gas 

storage, GHGi equals 0.975 for CH4 and 1.1 × 10−2 for CO2 ; for LNG storage and LNG import and export 

equipment, GHGi equals 1 for CH4 and 0 for CO2 ; and for natural gas distribution, GHGi equals 1 for CH4

and 1.1 × 10−2 CO2.

Tp,z = The total time the surveyed component “z”, component type “p”, was assumed to be leaking and operational, in 

hours. If one leak detection survey is conducted in the calendar year, assume the component was leaking 

for the entire calendar year, accounting for time the component was not operational (i.e., not operating 

under pressure) using engineering estimate based on best available data. If multiple leak detection 

surveys are conducted in the calendar year, 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), accounting for time the component was not 

operational using engineering estimate based on best available data. For the last leak detection survey in 

the calendar year, assume that all leaking components continue to leak until the end of the calendar year, 

accounting for time the component was not operational using engineering estimate based on best 

available data.

(1) You must conduct either one leak detection survey in a calendar year or multiple complete leak 

detection surveys in a calendar year. The leak detection surveys selected must be conducted during the 

calendar year.

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

(3) Onshore natural gas processing facilities must use the appropriate default total hydrocarbon 

leaker emission factors for compressor components in gas service and non-compressor components in 

gas service listed in Table W-2 of this subpart.

(4) Onshore natural gas transmission compression facilities must use the appropriate default total 

hydrocarbon leaker emission factors for compressor components in gas service and non-compressor 

components in gas service listed in Table W-3 of this subpart.

(5) Underground natural gas storage facilities must use the appropriate default total hydrocarbon 

leaker emission factors for storage stations in gas service listed in Table W-4 of this subpart.

(6) LNG storage facilities must use the appropriate default methane leaker emission factors for LNG 

storage components in gas service listed in Table W-5 of this subpart.

(7) LNG import and export facilities must use the appropriate default methane leaker emission 

factors for LNG terminals components in LNG service listed in Table W-6 of this subpart.

(8) Natural gas distribution facilities must use Equation W-30 of this section and the default methane 

leaker emission factors for transmission-distribution transfer station components in gas service listed in 

Table W-7 of this subpart to calculate component emissions from annual equipment leak surveys 

conducted at above grade transmission-distribution transfer stations. Natural gas distribution facilities are 
required to perform equipment leak surveys only at above grade stations that qualify as transmissiondistribution transfer stations. Below grade transmission-distribution transfer stations and all meteringregulating stations that do not meet the definition of transmission-distribution transfer stations are not 

required to perform equipment leak surveys under this section.

(i) Natural gas distribution facilities may choose to conduct equipment leak surveys at all above 

grade transmission-distribution transfer stations over multiple years “n”, not exceeding a five year period 

to cover all above grade transmission-distribution transfer stations. If the facility chooses to use the 

multiple year option, then the number of transmission-distribution transfer stations that are monitored in 

each year should be approximately equal across all years in the cycle.

(ii) Use Equation W-31 of this section to determine the meter/regulator run population emission 

factors for each GHGi. As additional survey data become available, you must recalculate the 

meter/regulator run population emission factors for each GHGi annually according to paragraph (q)(8)(iii) 

of this section.

Where:

EFs,MR,i = Meter/regulator run population emission factor for GHGi based on all surveyed above grade transmissiondistribution transfer stations over “n” years, in standard cubic feet of GHGi per operational hour of all 

meter/regulator runs.

Es,p,i,y = Annual total volumetric emissions at standard conditions of GHGi from component type “p” during year “y” in 

standard (“s”) cubic feet, as calculated using Equation W-30 of this section.

p = Seven component types listed in Table W-7 of this subpart for transmission-distribution transfer stations.

Tw,y = The total time the surveyed meter/regulator run “w” was operational, in hours during survey year “y” using 

engineering estimate based on best available data.

CountMR,y = Count of meter/regulator runs surveyed at above grade transmission-distribution transfer stations in year 

“y”.

y = Year of data included in emission factor “EFs,MR,i” according to paragraph (q)(8)(iii) of this section.

n = Number of years of data, according to paragraph (q)(8)(i) of this section, whose results are used to calculate 

emission factor “EFs,MR,i” according to paragraph (q)(8)(iii) of this section.

(iii) The emission factor “EFs,MR,i”, based on annual equipment leak surveys at above grade 

transmission-distribution transfer stations, must be calculated annually. If you chose to conduct 

equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, 

“n,” according to paragraph (q)(8)(i) of this section and you have submitted a smaller number of annual 

reports than the duration of the selected cycle period of 5 years or less, then all available data from the 

current year and previous years must be used in the calculation of the emission factor “EFs,MR,i” from 

Equation W-31 of this section. After the first survey cycle of “n” years is completed and beginning in 

calendar year (n+1), the survey will continue on a rolling basis by including the survey results from the 

current calendar year “y” and survey results from all previous (n-1) calendar years, such that each annual 

calculation of the emission factor “EFs,MR,i” from Equation W-31 of this section is based on survey results 

from “n” years. Upon completion of a cycle, you may elect to change the number of years in the next 

cycle period (to be 5 years or less). If the number of years in the new cycle is greater than the number of 
years in the previous cycle, calculate “EFs,MR,i” from Equation W-31 of this section in each year of the new 

cycle using the survey results from the current calendar year and the survey results from the preceding 

number years that is equal to the number of years in the previous cycle period. If the number of years, 

“nnew”, in the new cycle is smaller than the number of years in the previous cycle, “n”, calculate “EFs,MR,i” 

from Equation W-31 of this section in each year of the new cycle using the survey results from the current 

calendar year and survey results from all previous (nnew−1) calendar years.

(9) If you chose to conduct equipment leak surveys at all above grade transmission-distribution 

transfer stations over multiple years, “n,” according to paragraph (q)(8)(i) of this section, you must use the 

meter/regulator run population emission factors calculated using Equation W-31 of this section and the 

total count of all meter/regulator runs at above grade transmission-distribution transfer stations to 

calculate emissions from all above grade transmission-distribution transfer stations using Equation W-32B 

in paragraph (r) of this section.

(r) Equipment leaks by population count. This paragraph 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 

or equal to 10 percent CH4 plus CO2 by weight are exempt from the requirements of this paragraph (r) and

do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from 

the requirements of paragraph (r) of this section and do not need to be reported. You must calculate 

emissions from all emission sources listed in this paragraph using Equation W-32A of this section, except 

for natural gas distribution facility emission sources listed in §98.232(i)(3). Natural gas distribution facility 

emission sources listed in §98.232(i)(3) must calculate emissions using Equation W-32B and according to 

paragraph (r)(6)(ii) of this section.

Where:

Es,e,i = Annual volumetric emissions of GHGi from the emission source type in standard cubic feet. The emission 

source type may be a component (e.g. connector, open-ended line, etc.), below grade meteringregulating station, below grade transmission-distribution transfer station, distribution main, or distribution 

service.

Es,MR,i = Annual volumetric emissions of GHGi from all meter/regulator runs at above grade metering regulating stations 

that are not above grade transmission-distribution transfer stations or, when used to calculate emissions 

according to paragraph (q)(9) of this section, the annual volumetric emissions of GHGi from all 

meter/regulator runs at above grade transmission-distribution transfer stations, in standard cubic feet.

Counte = Total number of the emission source type at the facility. For onshore petroleum and natural gas production 

facilities, 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 facilities must 

count each component listed in Table W-4 of this subpart. LNG storage facilities must count the number 

of vapor recovery compressors. LNG import and export facilities must count the number of vapor 

recovery compressors. Natural gas distribution facilities must count: (1) The number of distribution 

services by material type; (2) miles of distribution mains by material type; and (3) number of below grade 

metering-regulating stations, by pressure type; as listed in Table W-7 of this subpart.

CountMR = Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade 

transmission-distribution transfer stations or, when used to calculate emissions according to paragraph 

(q)(9) of this section, the total number of meter/regulator runs at above grade transmission-distribution 

transfer stations.
EFs,e = Population emission factor for the specific emission source type, as listed in Tables W-1A and W-4 through W7 of this subpart. Use appropriate population emission factor for operations in Eastern and Western U.S., 

according to Table W-1D of this subpart.

EFs,MR,i = Meter/regulator run population emission factor for GHGi based on all surveyed above grade transmissiondistribution transfer stations over “n” years, in standard cubic feet of GHGi per operational hour of all 

meter/regulator runs, as determined in Equation W-31.

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.

Te = Average estimated time that each emission source type associated with the equipment leak emission was 

operational in the calendar year, in hours, using engineering estimate based on best available data.

Tw,avg = Average estimated time that each meter/regulator run was operational in the calendar year, in hours per 

meter/regulator run, using engineering estimate based on best available data.

(1) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in 

paragraph (v) of this section.

(2) Onshore petroleum and natural gas production facilities must use the appropriate default whole 

gas population emission factors listed in Table W-1A of this subpart. Major equipment and components 

associated with gas wells 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 calculation methods described in this paragraph (r)(2). The same 

calculation method must be used for the entire calendar year.

(i) Component Count Method 1. For all onshore petroleum and natural gas production operations in 

the facility perform the following activities:

(A) Count all major equipment listed in Table W-1B and Table W-1C of this subpart. For 

meters/piping, use one meters/piping per well-pad.

(B) Multiply major equipment counts by the average component counts listed in Table W-1B and W1C 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 Method 2. Count each component individually for the facility. Use the 

appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to 

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

(3) Underground natural gas storage facilities must use the appropriate default total hydrocarbon 

population emission factors for storage wellheads in gas service listed in Table W-4 of this subpart.

(4) LNG storage facilities must use the appropriate default methane population emission factor for 

LNG storage compressors in gas service listed in Table W-5 of this subpart.
(5) LNG import and export facilities must use the appropriate default methane population emission 

factor for LNG terminal compressors in gas service listed in Table W-6 of this subpart.

(6) Natural gas distribution facilities must use the appropriate methane emission factors as 

described in paragraphs (r)(6)(i) and (ii) of this section.

(i) Below grade metering-regulating stations, distribution mains, and distribution services must use 

the appropriate default methane population emission factors listed in Table W-7 of this subpart. Below 

grade transmission-distribution transfer stations must use the emission factor for below grade meteringregulating stations.

(ii) Above grade metering-regulating stations that are not above grade transmission-distribution 

transfer stations must use the meter/regulator run population emission factor calculated in Equation W31. Natural gas distribution facilities that do not have above grade transmission-distribution transfer 

stations are not required to calculate emissions for above grade metering-regulating stations and are not 

required to report GHG emissions in §98.236(r)(2)(v).

(s) Offshore petroleum and natural gas production facilities. Report CO2, CH4, and N2O emissions for 

offshore petroleum and natural gas production from all equipment leaks, vented emission, and flare 

emission source types as identified in the data collection and emissions estimation study conducted by 

BOEMRE in compliance with 30 CFR 250.302 through 304.

(1) Offshore production facilities under BOEMRE jurisdiction shall report the same annual emissions 

as calculated and reported by BOEMRE in data collection and emissions estimation study published by 

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

(i) For any calendar year that does not overlap with the most recent BOEMRE emissions study 

publication year, report the most recent BOEMRE reported emissions data published by BOEMRE 

referenced in 30 CFR 250.302 through 304 (GOADS). Adjust emissions based on the operating time for 

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

(ii) [Reserved]

(2) Offshore production facilities that are not under BOEMRE jurisdiction must use the most recent 

monitoring methods and calculation methods published by BOEMRE referenced in 30 CFR 250.302 

through 250.304 to calculate and report annual emissions (GOADS).

(i) For any calendar year that does not overlap with the most recent BOEMRE emissions study 

publication, you may report the most recently reported emissions data submitted to demonstrate 

compliance with this subpart of part 98, with emissions adjusted based on the operating time for the 

facility relative to operating time in the previous reporting period.

(ii) [Reserved]

(3) If BOEMRE discontinues or delays their data collection effort by more than 4 years, then offshore 

reporters shall once in every 4 years use the most recent BOEMRE data collection and emissions 

estimation methods to estimate emissions. These emission estimates would be used to report emissions 

from the facility sources as required in paragraph (s)(1)(i) of this section.

(4) For either first or subsequent year reporting, offshore facilities either within or outside of 

BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle must use the 

most recent BOEMRE data collection and emissions estimation methods published by BOEMRE 

referenced in 30 CFR 250.302 through 250.304 to calculate and report emissions.
(t) GHG volumetric emissions using actual conditions. If equation parameters in §98.233 are already 

determined at standard conditions as provided in the introductory text in §98.233, which results in 

volumetric emissions at standard conditions, then this paragraph does not apply. Calculate volumetric 

emissions at standard conditions as specified in paragraphs (t)(1) or (2) of this section, with actual 

pressure and temperature determined by engineering estimates based on best available data unless 

otherwise specified.

(1) Calculate natural gas volumetric emissions at standard conditions using actual natural gas 

emission temperature and pressure, and Equation W-33 of this section for conversions of Ea,n or 

conversions of FRa (whether sub-sonic or sonic).

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).

Za = Compressibility factor at actual conditions for natural gas. You may use either a default compressibility factor of 

1, or a site-specific compressibility factor based on actual temperature and pressure conditions.

(2) Calculate GHG volumetric emissions at standard conditions using actual GHG emissions 

temperature and pressure, and Equation W-34 of this section.

Where:

Es,i = GHG i volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet.

Ea,i = GHG i volumetric emissions at actual conditions in cubic feet.

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

Ta = Temperature at actual emission conditions ( °F).

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

Pa = Absolute pressure at actual conditions (psia).

Za = Compressibility factor at actual conditions for GHG i.
You may use either a default compressibility factor of 1, or a site-specific compressibility factor 

based on actual temperature and pressure conditions.

(3) Reporters using 68 °F for standard temperature may use the ratio 519.67/527.67 to convert 

volumetric emissions from 68 °F to 60 °F.

(u) GHG volumetric emissions at standard conditions. Calculate GHG volumetric emissions at 

standard conditions as specified in paragraphs (u)(1) and (2) of this section.

(1) Estimate CH4 and CO2 emissions from natural gas emissions using Equation W-35 of this 

section.

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, 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 either a default 95 

percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site 

specific engineering estimates based on best available data.

(iv) GHG mole fraction in natural gas stored in the underground natural gas storage industry 

segment. You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for 

GHG mole fraction in natural gas or site specific engineering estimates based on best available data.
(v) GHG mole fraction in natural gas stored in the LNG storage industry segment. You may use 

either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in 

natural gas or site specific engineering estimates based on best available data.

(vi) GHG mole fraction in natural gas stored in the LNG import and export industry segment. For 

export facilities that receive gas from transmission pipelines, you may use either a default 95 percent 

methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific 

engineering estimates based on best available data.

(vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility for 

natural gas distribution facilities. You may use either a default 95 percent methane and 1 percent carbon 

dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best 

available data.

(v) GHG mass emissions. Calculate GHG mass emissions in metric tons by converting the GHG 

volumetric emissions at standard conditions into mass emissions using Equation W-36 of this section.

Where:

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

Es,i = GHGi (either CH4, CO2, or N2O) volumetric emissions at standard conditions, in cubic feet.

ρi = Density of GHGi. Use 0.0526 kg/ft3for CO2 and N2O, and 0.0192 kg/ft3for CH4 at 60 °F and 14.7 psia.

(w) EOR injection pump blowdown. Calculate CO2 pump blowdown emissions from each EOR 

injection pump system as follows:

(1) Calculate the total injection pump system volume in cubic feet (including pipelines, manifolds and 

vessels) between isolation valves.

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

(3) Calculate the total annual CO2 emissions from each EOR injection pump system using Equation 

W-37 of this section:

Where:

MassCO2 = Annual EOR injection pump system emissions in metric tons from blowdowns.

N = Number of blowdowns for the EOR injection pump system in the calendar year.

Vv = Total volume in cubic feet of EOR injection pump system chambers (including pipelines, manifolds and vessels) 

between isolation valves.
Rc = Density of critical phase EOR injection gas in kg/ft3

. You may use an appropriate standard method published by 

a consensus-based standards organization if such a method exists or you may use an industry standard 

practice to determine density of super critical EOR injection gas.

GHGCO2 = Mass fraction of CO2 in critical phase injection gas.

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

(x) EOR hydrocarbon liquids dissolved CO2. Calculate CO2 emissions downstream of the storage 

tank from dissolved CO2 in hydrocarbon liquids produced through EOR operations as follows:

(1) Determine the amount of CO2 retained in hydrocarbon liquids after flashing in tankage at STP 

conditions. Annual samples of hydrocarbon liquids downstream of the storage tank must be taken 

according to methods set forth in §98.234(b) to determine retention of CO2 in hydrocarbon liquids 

immediately downstream of the storage tank. Use the annual analysis for the calendar year.

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

Where:

MassCO2 = Annual CO2 emissions from CO2 retained in hydrocarbon liquids produced through EOR operations beyond 

tankage, in metric tons.

Shl = Amount of CO2 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel, 

under standard conditions.

Vhl = Total volume of hydrocarbon liquids produced at the EOR operations in barrels in the calendar year.

(y) [Reserved]

(z) Onshore petroleum and natural gas production 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 

paragraph (z)(1)(i) of this section. If the fuel combusted is natural gas and is of pipeline quality 

specification and has a minimum high heat value of 950 Btu per standard cubic foot, use the calculation 

method described in paragraph (z)(1)(i) of this section and you may use the emission factor provided for 

natural gas as listed in Table C-1. If the fuel is natural gas, and is not pipeline quality or has a high heat 

value of less than 950 Btu per standard cubic feet, calculate emissions according to paragraph (z)(2) of 

this section. If the fuel is field gas, process vent gas, or a blend containing field gas or process vent gas, 

calculate emissions according to paragraph (z)(2) of this section.

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

CO2, CH4, and N2O emissions according to any Tier listed in subpart C of this part. You must follow all 

applicable calculation requirements for that tier listed in §98.33, any monitoring or QA/QC requirements 

listed for that tier in §98.34, any missing data procedures specified in §98.35, and any recordkeeping 

requirements specified in §98.37.
(ii) Emissions from fuel combusted in stationary or portable equipment at onshore natural gas and 

petroleum production facilities and at natural gas distribution facilities will be reported according to the 

requirements specified in §98.236(z) and not according to the reporting requirements specified in subpart 

C of this part.

(2) For fuel combustion units that combust field gas, process vent gas, a blend containing field gas 

or process vent gas, or natural gas that is not of pipeline quality or that has a high heat value of less than 

950 Btu per standard cubic feet, calculate combustion emissions as follows:

(i) You may use company records to determine the volume of fuel combusted in the unit during the 

reporting year.

(ii) If you have a continuous gas composition analyzer on fuel to the combustion unit, you must use 

these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to 

the unit. If you do not have a continuous gas composition analyzer on gas to the combustion unit, you 

must use the appropriate gas compositions for each stream of hydrocarbons going to the combustion unit 

as specified in the applicable paragraph in (u)(2) of this section.

(iii) Calculate GHG volumetric emissions at actual conditions using Equations W-39A and W-39B of 

this section:

Where:

Ea,CO2 = Contribution of annual CO2 emissions from portable or stationary fuel combustion sources in cubic feet, under 

actual conditions.

Va = Volume of gas sent to combustion unit in actual cubic feet, during the year.

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

Ea,CH4 = Contribution of annual CH4 emissions from portable or stationary fuel combustion sources in cubic feet, under 

actual conditions.

η = Fraction of gas combusted for portable and stationary equipment determined using engineering estimation. For 

internal combustion devices, a default of 0.995 can be used.

Yj = Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes plus) 

in gas sent to combustion unit.

Rj = Number of carbon atoms in the gas hydrocarbon constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 for 

butane, and 5 for pentanes plus, in gas sent to combustion unit.

YCH4 = Mole fraction of methane constituent in gas sent to combustion unit.

(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.

Where:

MassN2O = Annual N2O emissions from the combustion of a particular type of fuel (metric tons).

Fuel = Annual mass or volume of the fuel combusted (mass or volume per year, choose appropriately to be 

consistent with the units of HHV).

HHV = Higher heating value of fuel, mmBtu/unit of fuel (in units consistent with the fuel quantity combusted). For field 

gas or process vent gas, you may use either a default higher heating value of 1.235 × 10−3 mmBtu/scf or 

a site-specific higher heating value. For natural gas that is not of pipeline quality or that has a high heat 

value less than 950 Btu per standard cubic foot, use a site-specific higher heating value.

EF = Use 1.0 × 10−4 kg N2O/mmBtu.

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

(3) External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do 

not need to report combustion emissions or include these emissions for threshold determination in 

§98.231(a). You must report the type and number of each external fuel combustion unit.

(4) Internal fuel combustion sources, not compressor-drivers, with a rated heat capacity equal to or 

less than 1 mmBtu/hr (or the equivalent of 130 horsepower), do not need to report combustion emissions 

or include these emissions for threshold determination in §98.231(a). You must report the type and 

number of each internal fuel combustion unit.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80575, Dec. 23, 2011; 77 FR 51490, Aug. 24, 2012; 78 FR 

71960, Nov. 29, 2013; 79 FR 70408, Nov. 25, 2014]

§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.

(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); §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. 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 

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 nonleakers 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 nearatmospheric pressures and below the maximum temperature specified by the vent bag manufacturer 

such that the bag is safe to handle. The bag opening must be of sufficient size that the entire emission 

can be tightly encompassed for measurement till the bag is completely filled.

(1) Hold the bag in place enclosing the emissions source to capture the entire emissions and record 

the time required for completely filling the bag. If the bag inflates in less than one second, assume one 

second inflation time.

(2) Perform three measurements of the time required to fill the bag, report the emissions as the 

average of the three readings.

(3) Estimate natural gas volumetric emissions at standard conditions using calculations in 

§98.233(t).
(4) Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions 

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

(d) Use a high volume sampler to measure emissions within the capacity of the instrument.

(1) A technician following manufacturer instructions shall conduct measurements, including 

equipment manufacturer operating procedures and measurement methods relevant to using a high 

volume sampler, including positioning the instrument for complete capture of the equipment leak without 

creating backpressure on the source.

(2) If the high volume sampler, along with all attachments available from the manufacturer, is not 

able to capture all the emissions from the source then use anti-static wraps or other aids to capture all 

emissions without violating operating requirements as provided in the instrument manufacturer's manual.

(3) Estimate natural gas volumetric emissions at standard conditions using calculations in 

§98.233(t). Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions 

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

(4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH4 by 

using calibrated gas samples and by following manufacturer's instructions for calibration.

(e) Peng Robinson Equation of State means the equation of state defined by Equation W-41 of this 

section:

Where:

p = Absolute pressure.

R = Universal gas constant.

T = Absolute temperature.

Vm = Molar volume.

Where:

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

Pc = Critical pressure.

(f) Special reporting provisions for best available monitoring methods in reporting year 2015—(1) 

Best available monitoring methods. From January 1, 2015 to March 31, 2015, for a facility subject to this 

subpart, you must use the calculation methodologies and equations in §98.233 “Calculating GHG 

Emissions”, but you may use the best available monitoring method for any parameter for which it is not 

reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 

1, 2015 as specified in paragraphs (f)(2) and (3) of this section. Starting no later than April 1, 2015, you 

must discontinue using best available methods and begin following all applicable monitoring and QA/QC 

requirements of this part, except as provided in paragraph (f)(4) of this section. Best available monitoring 

methods means any of the following methods:

(i) Monitoring methods currently used by the facility that do not meet the specifications of this 

subpart.

(ii) Supplier data.

(iii) Engineering calculations.

(iv) Other company records.

(2) Best available monitoring methods for well-related measurement data. You may use best 

available monitoring methods for well-related measurement data identified in paragraphs (f)(2)(i) and (ii) 

of this section that cannot reasonably be measured according to the monitoring and QA/QC requirements 

of this subpart.

(i) If Calculation Method 1 for liquids unloading in §98.233(f)(1) was used in calendar year 2014 and 

will be used again in calendar year 2015, the vented natural gas flow rate for any well in a unique tubing 

diameter group and pressure group combination that has not been previously measured.

(ii) If using Equation W-10A of this subpart to determine natural gas emissions from completions and 

workovers for representative wells, the initial and average flowback rates (when using Calculation Method 

1 in §98.233(g)(1)(i)) or pressures upstream and downstream of the choke (when using Calculation 

Method 2 in §98.233(g)(1)(ii)) for any well in a well type combination that has not been previously 

measured.

(3) Best available monitoring methods for emissions measurement. You may use best available 

monitoring methods for sources listed in paragraphs (f)(3)(i) and (ii) of this section if the required 

measurement data cannot reasonably be obtained according to the monitoring and QA/QC requirements 

of this part.

(i) Centrifugal compressor as found measurements of manifolded emissions from groups of 

centrifugal compressor sources according to §98.233(o)(4) and (5), in onshore natural gas processing, 

onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG 

import and export equipment as specified in §98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2).

(ii) Reciprocating compressor as found measurements of manifolded emissions from groups of 

reciprocating compressor sources according to §98.233(p)(4) and (5), in onshore natural gas processing, 

onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG 

import and export equipment as specified in §98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1).
(4) Requests for extension of the use of best available monitoring methods beyond March 31, 2015.

You may submit a request to the Administrator to use one or more best available monitoring methods for 

sources listed in paragraphs (f)(2) and (3) of this section beyond March 31, 2015.

(i) Timing of request. The extension request must be submitted to EPA no later than January 31, 

2015.

(ii) Content of request. Requests must contain the following information:

(A) A list of specific source types and parameters for which you are seeking use of best available 

monitoring methods.

(B) For each specific source type for which you are requesting use of best available monitoring 

methods, a description of the reasons that the needed equipment could not be obtained and installed 

before April 1, 2015.

(C) A description of the specific actions you will take to obtain and install the equipment as soon as 

reasonably feasible and the expected date by which the equipment will be installed and operating.

(iii) Approval criteria. To obtain approval to use best available monitoring methods after March 31, 

2015, you must submit a request demonstrating to the Administrator's satisfaction that it is not reasonably 

feasible to acquire, install, and operate a required piece of monitoring equipment by April 1, 2015. The 

use of best available methods under paragraph (f) of this section will not be approved beyond December 

31, 2015.

(g) [Reserved]

(h) For well venting for liquids unloading, if a monitoring period other than the full calendar year is 

used to determine the cumulative amount of time in hours of venting for each well (the term “Tp” in 

Equation W-7A and W-7B of §98.233) or the number of unloading events per well (the term “Vp” in 

Equations W-8 and W-9 of §98.233), then the monitoring period must begin before February 1 of the 

reporting year and must not end before December 1 of the reporting year. The end of one monitoring 

period must immediately precede the start of the next monitoring period for the next reporting year. All 

production days must be monitored and all venting accounted for.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 22827, Apr. 25, 2011; 76 FR 59540, Sept. 27, 2011; 76 FR 

80586, Dec. 23, 2011; 78 FR 25395, May 1, 2013; 79 FR 70410, Nov. 25, 2014]

§98.235 Procedures for estimating missing data.

Except as specified in §98.233, whenever a value of a parameter is unavailable for a GHG emission 

calculation required by this subpart (including, but not limited to, if a measuring device malfunctions 

during unit operation or activity data are not collected), you must follow the procedures specified in 

paragraphs (a) through (i) of this section, as applicable.

(a) For stationary and portable combustion sources that use the calculation methods of subpart C of 

this part, you must use the missing data procedures in subpart C of this part.

(b) For each missing value of a parameter that should have been measured quarterly or more 

frequently using equipment including, but not limited to, a continuous flow meter, composition analyzer, 

thermocouple, or pressure gauge, you must substitute the arithmetic average of the quality-assured 

values of that parameter immediately preceding and immediately following the missing data incident. If 

the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the 
missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the 

missing data incident, you must use the first quality-assured value obtained after the missing data period 

as the substitute data value. A value is quality-assured according to the procedures specified in §98.234.

(c) For each missing value of a parameter that should have been measured annually, you must 

repeat the estimation or measurement activity for those sources as soon as possible, including in the 

subsequent calendar year if missing data are not discovered until after December 31 of the year in which 

data are collected, until valid data for reporting are obtained. Data developed and/or collected in a 

subsequent calendar year to substitute for missing data cannot be used for that subsequent year's 

emissions estimation. Where missing data procedures are used for the previous year, at least 30 days 

must separate emissions estimation or measurements for the previous year and emissions estimation or 

measurements for the current year of data collection.

(d) For each missing value of a parameter that should have been measured biannually (every two 

years), you must conduct the estimation or measurement activity for those sources as soon as possible in 

the subsequent calendar year if the estimation or measurement was not made in the appropriate year 

(first year of data collection and every two years thereafter), until valid data for reporting are obtained. 

Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be 

used to alternate or postpone subsequent biannual emissions estimations or measurements.

(e) For the first 6 months of required data collection, facilities that become newly subject to this 

subpart W may use best engineering estimates for any data that cannot reasonably be measured or 

obtained according to the requirements of this subpart.

(f) For the first 6 months of required data collection, facilities that are currently subject to this subpart 

W and that acquire new sources from another facility that were not previously subject to this subpart W 

may use best engineering estimates for any data related to those newly acquired sources that cannot 

reasonably be measured or obtained according to the requirements of this subpart.

(g) Unless addressed in another paragraph of this section, for each missing value of any activity 

data, you must substitute data value(s) using the best available estimate(s) of the parameter(s), based on 

all applicable and available process or other data (including, but not limited to, processing rates, operating 

hours).

(h) You must report information for all measured and substitute values of a parameter, and the 

procedures used to substitute an unavailable value of a parameter per the requirements in §98.236(bb).

(i) You must follow recordkeeping requirements listed in §98.237(f).

[79 FR 70410, Nov. 25, 2014]

§98.236 Data reporting requirements.

In addition to the information required by §98.3(c), each annual report must contain reported 

emissions and related information as specified in this section. Reporters that use a flow or volume 

measurement system that corrects to standard conditions as provided in the introductory text in §98.233 

for data elements that are otherwise required to be determined at actual conditions, report gas volumes at 

standard conditions rather the gas volumes at actual conditions and report the standard temperature and 

pressure used by the measurement system rather than the actual temperature and pressure.
(a) The annual report must include the information specified in paragraphs (a)(1) through (8) of this 

section for each applicable industry segment. The annual report must also include annual emissions 

totals, in metric tons of each GHG, for each applicable industry segment listed in paragraphs (a)(1) 

through (8) of this section, and each applicable emission source listed in paragraphs (b) through (z) of 

this section.

(1) Onshore petroleum and natural gas production. For the equipment/activities specified in 

paragraphs (a)(1)(i) through (xvii) of this section, report the information specified in the applicable 

paragraphs of this section.

(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.

(ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph (c) of this 

section.

(iii) Acid gas removal units. Report the information specified in paragraph (d) of this section.

(iv) Dehydrators. Report the information specified in paragraph (e) of this section.

(v) Liquids unloading. Report the information specified in paragraph (f) of this section.

(vi) Completions and workovers with hydraulic fracturing. Report the information specified in 

paragraph (g) of this section.

(vii) Completions and workovers without hydraulic fracturing. Report the information specified in 

paragraph (h) of this section.

(viii) Onshore production storage tanks. Report the information specified in paragraph (j) of this 

section.

(ix) Well testing. Report the information specified in paragraph (l) of this section.

(x) Associated natural gas. Report the information specified in paragraph (m) of this section.

(xi) Flare stacks. Report the information specified in paragraph (n) of this section.

(xii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.

(xiii) Reciprocating compressors. Report the information specified in paragraph (p) of this section.

(xiv) Equipment leaks by population count. Report the information specified in paragraph (r) of this 

section.

(xv) EOR injection pumps. Report the information specified in paragraph (w) of this section.

(xvi) EOR hydrocarbon liquids. Report the information specified in paragraph (x) of this section.

(xvii) Combustion equipment. Report the information specified in paragraph (z) of this section.

(2) Offshore petroleum and natural gas production. Report the information specified in paragraph (s) 

of this section.
(3) Onshore natural gas processing. For the equipment/activities specified in paragraphs (a)(3)(i) 

through (vii) of this section, report the information specified in the applicable paragraphs of this section.

(i) Acid gas removal units. Report the information specified in paragraph (d) of this section.

(ii) Dehydrators. Report the information specified in paragraph (e) of this section.

(iii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.

(iv) Flare stacks. Report the information specified in paragraph (n) of this section.

(v) Centrifugal compressors. Report the information specified in paragraph (o) of this section.

(vi) Reciprocating compressors. Report the information specified in paragraph (p) of this section.

(vii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.

(4) Onshore natural gas transmission compression. For the equipment/activities specified in 

paragraphs (a)(4)(i) through (vii) of this section, report the information specified in the applicable 

paragraphs of this section.

(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.

(ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.

(iii) Transmission storage tanks. Report the information specified in paragraph (k) of this section.

(iv) Flare stacks. Report the information specified in paragraph (n) of this section.

(v) Centrifugal compressors. Report the information specified in paragraph (o) of this section.

(vi) Reciprocating compressors. Report the information specified in paragraph (p) of this section.

(vii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.

(5) Underground natural gas storage. For the equipment/activities specified in paragraphs (a)(5)(i) 

through (vi) of this section, report the information specified in the applicable paragraphs of this section.

(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.

(ii) Flare stacks. Report the information specified in paragraph (n) of this section.

(iii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.

(iv) Reciprocating compressors. Report the information specified in paragraph (p) of this section.

(v) Equipment leak surveys. Report the information specified in paragraph (q) of this section.

(vi) Equipment leaks by population count. Report the information specified in paragraph (r) of this 

section.
(6) LNG storage. For the equipment/activities specified in paragraphs (a)(6)(i) through (v) of this 

section, report the information specified in the applicable paragraphs of this section.

(i) Flare stacks. Report the information specified in paragraph (n) of this section.

(ii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.

(iii) Reciprocating compressors. Report the information specified in paragraph (p) of this section.

(iv) Equipment leak surveys. Report the information specified in paragraph (q) of this section.

(v) Equipment leaks by population count. Report the information specified in paragraph (r) of this 

section.

(7) LNG import and export equipment. For the equipment/activities specified in paragraphs (a)(7)(i) 

through (vi) of this section, report the information specified in the applicable paragraphs of this section.

(i) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.

(ii) Flare stacks. Report the information specified in paragraph (n) of this section.

(iii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.

(iv) Reciprocating compressors. Report the information specified in paragraph (p) of this section.

(v) Equipment leak surveys. Report the information specified in paragraph (q) of this section.

(vi) Equipment leaks by population count. Report the information specified in paragraph (r) of this 

section.

(8) Natural gas distribution. For the equipment/activities specified in paragraphs (a)(8)(i) through (iii) 

of this section, report the information specified in the applicable paragraphs of this section.

(i) Combustion equipment. Report the information specified in paragraph (z) of this section.

(ii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.

(iii) Equipment leaks by population count. Report the information specified in paragraph (r) of this 

section.

(b) Natural gas pneumatic devices. You must indicate whether the facility contains the following 

types of equipment: Continuous high bleed natural gas pneumatic devices, continuous low bleed natural 

gas pneumatic devices, and intermittent bleed natural gas pneumatic devices. If the facility contains any 

continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic 

devices, or intermittent bleed natural gas pneumatic devices, then you must report the information 

specified in paragraphs (b)(1) through (b)(4) of this section.

(1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) and (ii) of this 

section.

(i) The total number of devices of each type, determined according to §98.233(a)(1) and (2).
(ii) If the reported value in paragraph (b)(1)(i) of this section is an estimated value determined 

according to §98.233(a)(2), then you must report the information specified in paragraphs (b)(1)(ii)(A) 

through (C) of this section.

(A) The number of devices of each type reported in paragraph (b)(1)(i) of this section that are 

counted.

(B) The number of devices of each type reported in paragraph (b)(1)(i) of this section that are 

estimated (not counted).

(C) Whether the calendar year is the first calendar year of reporting or the second calendar year of 

reporting.

(2) For each type of pneumatic device, the estimated average number of hours in the calendar year 

that the natural gas pneumatic devices reported in paragraph (b)(1)(i) of this section were operating in the 

calendar year (“Tt” in Equation W-1 of this subpart).

(3) Annual CO2 emissions, in metric tons CO2, for the natural gas pneumatic devices combined, 

calculated using Equation W-1 of this subpart and §98.233(a)(4), and reported in paragraph (b)(1)(i) of 

this section.

(4) Annual CH4 emissions, in metric tons CH4, for the natural gas pneumatic devices combined, 

calculated using Equation W-1 of this subpart and §98.233(a)(4), and reported in paragraph (b)(1)(i) of 

this section.

(c) Natural gas driven pneumatic pumps. You must indicate whether the facility has any natural gas 

driven pneumatic pumps. If the facility contains any natural gas driven pneumatic pumps, then you must 

report the information specified in paragraphs (c)(1) through (4) of this section.

(1) Count of natural gas driven pneumatic pumps.

(2) Average estimated number of hours in the calendar year the pumps were operational (“T” in 

Equation W-2 of this subpart).

(3) Annual CO2 emissions, in metric tons CO2, for all natural gas driven pneumatic pumps combined, 

calculated according to §98.233(c)(1) and (2).

(4) Annual CH4 emissions, in metric tons CH4, for all natural gas driven pneumatic pumps combined, 

calculated according to §98.233(c)(1) and (2).

(d) Acid gas removal units. You must indicate whether your facility has any acid gas removal units 

that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant. If your facility 

contains any acid gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur 

recovery plant, then you must report the information specified in paragraphs (d)(1) and (2) of this section.

(1) You must report the information specified in paragraphs (d)(1)(i) through (vi) of this section for 

each acid gas removal unit.

(i) A unique name or ID number for the acid gas removal unit. For the onshore petroleum and 

natural gas production industry segment, a different name or ID may be used for a single acid gas 

removal unit for each location it operates at in a given year.
(ii) Total feed rate entering the acid gas removal unit, using a meter or engineering estimate based 

on process knowledge or best available data, in million cubic feet per year.

(iii) The calculation method used to calculate CO2 emissions from the acid gas removal unit, as 

specified in §98.233(d).

(iv) Whether any CO2 emissions from the acid gas removal unit are recovered and transferred 

outside the facility, as specified in §98.233(d)(11). If any CO2 emissions from the acid gas removal unit 

were recovered and transferred outside the facility, then you must report the annual quantity of CO2, in 

metric tons CO2, that was recovered and transferred outside the facility under subpart PP of this part.

(v) Annual CO2 emissions, in metric tons CO2, from the acid gas removal unit, calculated using any 

one of the calculation methods specified in §98.233(d) and as specified in §98.233(d)(10) and (11).

(vi) Sub-basin ID that best represents the wells supplying gas to the unit (for the onshore petroleum 

and natural gas production industry segment only).

(2) You must report information specified in paragraphs (d)(2)(i) through (iii) of this section, 

applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, for each acid gas 

removal unit.

(i) If you used Calculation Method 1 or Calculation Method 2 as specified in §98.233(d) to calculate 

CO2 emissions from the acid gas removal unit, then you must report the information specified in 

paragraphs (d)(2)(i)(A) and (B) of this section.

(A) Annual average volumetric fraction of CO2 in the vent gas exiting the acid gas removal unit.

(B) Annual volume of gas vented from the acid gas removal unit, in cubic feet.

(ii) If you used Calculation Method 3 as specified in §98.233(d) to calculate CO2 emissions from the 

acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(ii)(A) through 

(D) of this section.

(A) Indicate which equation was used (Equation W-4A or W-4B).

(B) Annual average volumetric fraction of CO2 in the natural gas flowing out of the acid gas removal 

unit, as specified in Equation W-4A or Equation W-4B of this subpart.

(C) Annual average volumetric fraction of CO2 content in natural gas flowing into the acid gas 

removal unit, as specified in Equation W-4A or Equation W-4B of this subpart.

(D) The natural gas flow rate used, as specified in Equation W-4A of this subpart, reported as either 

total annual volume of natural gas flow into the acid gas removal unit in cubic feet at actual conditions; or 

total annual volume of natural gas flow out of the acid gas removal unit, as specified in Equation W-4B of 

this subpart, in cubic feet at actual conditions.

(iii) If you used Calculation Method 4 as specified in §98.233(d) to calculate CO2 emissions from the 

acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(iii)(A) through 

(L) of this section, as applicable to the simulation software package used.

(A) The name of the simulation software package used.
(B) Natural gas feed temperature, in degrees Fahrenheit.

(C) Natural gas feed pressure, in pounds per square inch.

(D) Natural gas flow rate, in standard cubic feet per minute.

(E) Acid gas content of the feed natural gas, in mole percent.

(F) Acid gas content of the outlet natural gas, in mole percent.

(G) Unit operating hours, excluding downtime for maintenance or standby, in hours per year.

(H) Exit temperature of the natural gas, in degrees Fahrenheit.

(I) Solvent pressure, in pounds per square inch.

(J) Solvent temperature, in degrees Fahrenheit.

(K) Solvent circulation rate, in gallons per minute.

(L) Solvent weight, in pounds per gallon.

(e) Dehydrators. You must indicate whether your facility contains any of the following equipment: 

Glycol dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 

million standard cubic feet per day, glycol dehydrators with an annual average daily natural gas 

throughput less than 0.4 million standard cubic feet per day, and dehydrators that use desiccant. If your 

facility contains any of the equipment listed in this paragraph (e), then you must report the applicable 

information in paragraphs (e)(1) through (3).

(1) For each glycol dehydrator that has an annual average daily natural gas throughput greater than 

or equal to 0.4 million standard cubic feet per day (as specified in §98.233(e)(1)), you must report the 

information specified in paragraphs (e)(1)(i) through (xviii) of this section for the dehydrator.

(i) A unique name or ID number for the dehydrator. For the onshore petroleum and natural gas 

production industry segment, a different name or ID may be used for a single dehydrator for each location 

it operates at in a given year.

(ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, determined by 

engineering estimate based on best available data.

(iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet.

(iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet.

(v) Dehydrator absorbent circulation pump type (e.g., natural gas pneumatic, air pneumatic, or 

electric).

(vi) Dehydrator absorbent circulation rate, in gallons per minute.

(vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene glycol (DEG), or ethylene glycol 

(EG)).
(viii) Whether stripper gas is used in dehydrator.

(ix) Whether a flash tank separator is used in dehydrator.

(x) Total time the dehydrator is operating, in hours.

(xi) Temperature of the wet natural gas, in degrees Fahrenheit.

(xii) Pressure of the wet natural gas, in pounds per square inch gauge.

(xiii) Mole fraction of CH4 in wet natural gas.

(xiv) Mole fraction of CO2 in wet natural gas.

(xv) Whether any dehydrator emissions are vented to a vapor recovery device.

(xvi) Whether any dehydrator emissions are vented to a flare or regenerator firebox/fire tubes. If any 

emissions are vented to a flare or regenerator firebox/fire tubes, report the information specified in 

paragraphs (e)(1)(xvi)(A) through (C) of this section for these emissions from the dehydrator.

(A) Annual CO2 emissions, in metric tons CO2, for the dehydrator, calculated according to 

§98.233(e)(6).

(B) Annual CH4 emissions, in metric tons CH4, for the dehydrator, calculated according to 

§98.233(e)(6).

(C) Annual N2O emissions, in metric tons N2O, for the dehydrator, calculated according to 

§98.233(e)(6).

(xvii) Whether any dehydrator emissions are vented to the atmosphere without being routed to a 

flare or regenerator firebox/fire tubes. If any emissions are not routed to a flare or regenerator firebox/fire 

tubes, then you must report the information specified in paragraphs (e)(1)(xvii)(A) and (B) of this section 

for those emissions from the dehydrator.

(A) Annual CO2 emissions, in metric tons CO2, for the dehydrator when not venting to a flare or 

regenerator firebox/fire tubes, calculated according to §98.233(e)(1), and, if applicable, (e)(5).

(B) Annual CH4 emissions, in metric tons CH4, for the dehydrator when not venting to a flare or 

regenerator firebox/fire tubes, calculated according to §98.233(e)(1) and, if applicable, (e)(5).

(xviii) Sub-basin ID that best represents the wells supplying gas to the dehydrator (for the onshore 

petroleum and natural gas production industry segment only).

(2) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million 

standard cubic feet per day (as specified in §98.233(e)(2)), you must report the information specified in 

paragraphs (e)(2)(i) through (v) of this section for the entire facility.

(i) The total number of dehydrators at the facility.

(ii) Whether any dehydrator emissions were vented to a vapor recovery device. If any dehydrator 

emissions were vented to a vapor recovery device, then you must report the total number of dehydrators 

at the facility that vented to a vapor recovery device.
(iii) Whether any dehydrator emissions were vented to a control device other than a vapor recovery 

device or a flare or regenerator firebox/fire tubes. If any dehydrator emissions were vented to a control 

device(s) other than a vapor recovery device or a flare or regenerator firebox/fire tubes, then you must 

specify the type of control device(s) and the total number of dehydrators at the facility that were vented to 

each type of control device.

(iv) Whether any dehydrator emissions were vented to a flare or regenerator firebox/fire tubes. If any 

dehydrator emissions were vented to a flare or regenerator firebox/fire tubes, then you must report the 

information specified in paragraphs (e)(2)(iv)(A) through (D) of this section.

(A) The total number of dehydrators venting to a flare or regenerator firebox/fire tubes.

(B) Annual CO2 emissions, in metric tons CO2, for the dehydrators reported in paragraph (e)(2)(iv)(A) 

of this section, calculated according to §98.233(e)(6).

(C) Annual CH4 emissions, in metric tons CH4, for the dehydrators reported in paragraph (e)(2)(iv)(A) 

of this section, calculated according to §98.233(e)(6).

(D) Annual N2O emissions, in metric tons N2O, for the dehydrators reported in paragraph (e)(2)(iv)(A) 

of this section, calculated according to §98.233(e)(6).

(v) For dehydrator emissions that were not vented to a flare or regenerator firebox/fire tubes, report 

the information specified in paragraphs (e)(2)(v)(A) and (B) of this section.

(A) Annual CO2 emissions, in metric tons CO2, for emissions from all dehydrators reported in 

paragraph (e)(2)(i) of this section that were not vented to a flare or regenerator firebox/fire tubes, 

calculated according to §98.233(e)(2), (e)(4), and, if applicable, (e)(5), where emissions are added 

together for all such dehydrators.

(B) Annual CH4 emissions, in metric tons CH4, for emissions from all dehydrators reported in 

paragraph (e)(2)(i) of this section that were not vented to a flare or regenerator firebox/fire tubes, 

calculated according to §98.233(e)(2), (e)(4), and, if applicable, (e)(5), where emissions are added 

together for all such dehydrators.

(3) For dehydrators that use desiccant (as specified in §98.233(e)(3)), you must report the 

information specified in paragraphs (e)(3)(i) through (iii) of this section for the entire facility.

(i) The same information specified in paragraphs (e)(2)(i) through (iv) of this section for glycol 

dehydrators, and report the information under this paragraph for dehydrators that use desiccant.

(ii) Annual CO2 emissions, in metric tons CO2, for emissions from all desiccant dehydrators reported 

under paragraph (e)(3)(i) of this section that are not venting to a flare or regenerator firebox/fire tubes, 

calculated according to §98.233(e)(3), (e)(4), and, if applicable, (e)(5), and summing for all such 

dehydrators.

(iii) Annual CH4 emissions, in metric tons CH4, for emissions from all desiccant dehydrators reported 

in paragraph (e)(3)(i) of this section that are not venting to a flare or regenerator firebox/fire tubes, 

calculated according to §98.233(e)(3), (e)(4), and, if applicable, (e)(5), and summing for all such 

dehydrators.

(f) Liquids unloading. You must indicate whether well venting for liquids unloading occurs at your 

facility, and if so, which methods (as specified in §98.233(f)) were used to calculate emissions. If your 

facility performs well venting for liquids unloading and uses Calculation Method 1, then you must report 
the information specified in paragraph (f)(1) of this section. If the facility performs liquids unloading and 

uses Calculation Method 2 or 3, then you must report the information specified in paragraph (f)(2) of this 

section.

(1) For each sub-basin and well tubing diameter and pressure group for which you used Calculation 

Method 1 to calculate natural gas emissions from well venting for liquids unloading, report the information 

specified in paragraphs (f)(1)(i) through (xii) of this section. Report information separately for wells with 

plunger lifts and wells without plunger lifts.

(i) Sub-basin ID.

(ii) Well tubing diameter and pressure group ID.

(iii) Plunger lift indicator.

(iv) Count of wells vented to the atmosphere for the sub-basin/well tubing diameter and pressure 

group.

(v) Percentage of wells for which the monitoring period used to determine the cumulative amount of 

time venting was not the full calendar year.

(vi) Cumulative amount of time wells were vented (sum of “Tp” from Equation W-7A or W-7B of this 

subpart), in hours.

(vii) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across 

all wells in the sub-basin/well tubing diameter and pressure group.

(viii) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, 

calculated according to §98.233(f)(1).

(ix) Annual CO2 emissions, in metric tons CO2, from well venting for liquids unloading, calculated 

according to §98.233(f)(1) and (4).

(x) Annual CH4 emissions, in metric tons CH4, from well venting for liquids unloading, calculated 

according to §98.233(f)(1) and (4).

(xi) For each well tubing diameter group and pressure group combination, you must report the 

information specified in paragraphs (f)(1)(xi)(A) through (E) of this section for each individual well not 

using a plunger lift that was tested during the year.

(A) API Well Number of tested well.

(B) Casing pressure, in pounds per square inch absolute.

(C) Internal casing diameter, in inches.

(D) Measured depth of the well, in feet.

(E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic 

feet per hour.
(xii) For each well tubing diameter group and pressure group combination, you must report the 

information specified in paragraphs (f)(1)(xii)(A) through (E) of this section for each individual well using a 

plunger lift that was tested during the year.

(A) API Well Number.

(B) The tubing pressure, in pounds per square inch absolute.

(C) The internal tubing diameter, in inches.

(D) Measured depth of the well, in feet.

(E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic 

feet per hour.

(2) For each sub-basin for which you used Calculation Method 2 or 3 (as specified in §93.233(f)) to 

calculate natural gas emissions from well venting for liquids unloading, you must report the information in 

(f)(2)(i) through (x) of this section. Report information separately for each calculation method.

(i) Sub-basin ID.

(ii) Calculation method.

(iii) Plunger lift indicator.

(iv) Number of wells vented to the atmosphere.

(v) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all 

wells.

(vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, 

calculated according to §98.233(f)(2) or (3), as applicable.

(vii) Annual CO2 emissions, in metric tons CO2, from well venting for liquids unloading, calculated 

according to §98.233(f)(2) or (3), as applicable, and §98.233(f)(4).

(viii) Annual CH4 emissions, in metric tons CH4, from well venting for liquids unloading, calculated 

according to §98.233(f)(2) or (3), as applicable, and §98.233(f)(4).

(ix) For wells without plunger lifts, the average internal casing diameter, in inches.

(x) For wells with plunger lifts, the average internal tubing diameter, in inches.

(g) Completions and workovers with hydraulic fracturing. You must indicate whether your facility had 

any gas well completions or workovers with hydraulic fracturing during the calendar year. If your facility 

had gas well completions or workovers with hydraulic fracturing during the calendar year, then you must 

report information specified in paragraphs (g)(1) through (10) of this section, for each sub-basin and well 

type combination. Report information separately for completions and workovers.

(1) Sub-basin ID.

(2) Well type combination.
(3) Number of completions or workovers in the sub-basin and well type combination category.

(4) Calculation method used.

(5) If you used Equation W-10A to calculate annual volumetric total gas emissions, then you must 

report the information specified in paragraphs (g)(5)(i) and (ii) of this section.

(i) Cumulative gas flowback time, in hours, from when gas is first detected until sufficient quantities 

are present to enable separation, and the cumulative flowback time, in hours, after sufficient quantities of 

gas are present to enable separation (sum of “Tp,i” and sum of “Tp,s” values used in Equation W-10A). You 

may delay the reporting of this data element if you indicate in the annual report that wildcat wells and/or 

delineation wells are the only wells included in this number. If you elect to delay reporting of this data 

element, you must report by the date specified in §98.236(cc) the total number of hours of flowback from 

all wells during completions or workovers and the API Well Number(s) for the well(s) included in the 

number.

(ii) For the measured well(s), the flowback rate, in standard cubic feet per hour (average of “FRs,p” 

values used in Equation W-12A). You may delay the reporting of this data element if you indicate in the 

annual report that wildcat wells and/or delineation wells are the only wells that can be used for the 

measurement. If you elect to delay reporting of this data element, you must report by the date specified in 

§98.236(cc) the measured flowback rate during well completion or workover and the API Well Number(s) 

for the well(s) included in the measurement.

(6) If you used Equation W-10B to calculate annual volumetric total gas emissions, then you must 

report the information specified in paragraphs (g)(6)(i) and (ii) of this section.

(i) Vented natural gas volume, in standard cubic feet, for each well in the sub-basin (“FVs,p” in 

Equation W-10B).

(ii) Flow rate at the beginning of the period of time when sufficient quantities of gas are present to 

enable separation, in standard cubic feet per hour, for each well in the sub-basin (“FRp,i” in Equation W10B).

(7) Annual gas emissions, in standard cubic feet (“Es,n” in Equation W-10A or W-10B).

(8) Annual CO2 emissions, in metric tons CO2.

(9) Annual CH4 emissions, in metric tons CH4.

(10) If the well emissions were vented to a flare, then you must report the total N2O emissions, in 

metric tons N2O.

(h) Completions and workovers without hydraulic fracturing. You must indicate whether the facility 

had any gas well completions without hydraulic fracturing or any gas well workovers without hydraulic 

fracturing, and if the activities occurred with or without flaring. If the facility had gas well completions or 

workovers without hydraulic fracturing, then you must report the information specified in paragraphs (h)(1) 

through (4) of this section, as applicable.

(1) For each sub-basin with gas well completions without hydraulic fracturing and without flaring, 

report the information specified in paragraphs (h)(1)(i) through (vi) of this section.

(i) Sub-basin ID.
(ii) Number of well completions that vented gas directly to the atmosphere without flaring.

(iii) Total number of hours that gas vented directly to the atmosphere during venting for all 

completions in the sub-basin category (the sum of all “Tp” for completions that vented to the atmosphere 

as used in Equation W-13B).

(iv) Average daily gas production rate for all completions without hydraulic fracturing in the subbasin without flaring, in standard cubic feet per hour (average of all “Vp” used in Equation W-13B). You 

may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or 

delineation wells are the only wells that can be used for the measurement. If you elect to delay reporting 

of this data element, you must report by the date specified in §98.236(cc) the measured average daily 

gas production rate for all wells during completions and the API Well Number(s) for the well(s) included in 

the measurement.

(v) Annual CO2 emissions, in metric tons CO2, that resulted from completions venting gas directly to 

the atmosphere (“Es,p” from Equation W-13B for completions that vented directly to the atmosphere, 

converted to mass emissions according to §98.233(h)(1)).

(vi) Annual CH4 emissions, in metric tons CH4, that resulted from completions venting gas directly to 

the atmosphere (“Es,p” from Equation W-13B for completions that vented directly to the atmosphere, 

converted to mass emissions according to §98.233(h)(1)).

(2) For each sub-basin with gas well completions without hydraulic fracturing and with flaring, report 

the information specified in paragraphs (h)(2)(i) through (vii) of this section.

(i) Sub-basin ID.

(ii) Number of well completions that flared gas.

(iii) Total number of hours that gas vented to a flare during venting for all completions in the subbasin category (the sum of all “Tp” for completions that vented to a flare from Equation W-13B).

(iv) Average daily gas production rate for all completions without hydraulic fracturing in the subbasin with flaring, in standard cubic feet per hour (the average of all “Vp” from Equation W-13B). You may 

delay reporting of this data element if you indicate in the annual report that wildcat wells and/or 

delineation wells are the only wells that can be used for the measurement. If you elect to delay reporting 

of this data element, you must report by the date specified in §98.236(cc) the measured average daily 

gas production rate for all wells during completions and the API Well Number(s) for the well(s) included in 

the measurement.

(v) Annual CO2 emissions, in metric tons CO2, that resulted from completions that flared gas 

calculated according to §98.233(h)(2).

(vi) Annual CH4 emissions, in metric tons CH4, that resulted from completions that flared gas 

calculated according to §98.233(h)(2).

(vii) Annual N2O emissions, in metric tons N2O, that resulted from completions that flared gas 

calculated according to §98.233(h)(2).

(3) For each sub-basin with gas well workovers without hydraulic fracturing and without flaring, 

report the information specified in paragraphs (h)(3)(i) through (iv) of this section.

(i) Sub-basin ID.
(ii) Number of workovers that vented gas to the atmosphere without flaring.

(iii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from workovers venting gas 

directly to the atmosphere (“Es,wo” in Equation W-13A for workovers that vented directly to the atmosphere, 

converted to mass emissions as specified in §98.233(h)(1)).

(iv) Annual CH4 emissions, in metric tons CH4 per year, that resulted from workovers venting gas 

directly to the atmosphere (“Es,wo” in Equation W-13A for workovers that vented directly to the atmosphere, 

converted to mass emissions as specified in §98.233(h)(1)).

(4) For each sub-basin with gas well workovers without hydraulic fracturing and with flaring, report 

the information specified in paragraphs (h)(4)(i) through (v) of this section.

(i) Sub-basin ID.

(ii) Number of workovers that flared gas.

(iii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from workovers that flared gas 

calculated as specified in §98.233(h)(2).

(iv) Annual CH4 emissions, in metric tons CH4 per year, that resulted from workovers that flared gas, 

calculated as specified in §98.233(h)(2).

(v) Annual N2O emissions, in metric tons N2O per year, that resulted from workovers that flared gas 

calculated as specified in §98.233(h)(2).

(i) Blowdown vent stacks. You must indicate whether your facility has blowdown vent stacks. If your 

facility has blowdown vent stacks, then you must report whether emissions were calculated by equipment 

or event type or by using flow meters or a combination of both. If you calculated emissions by equipment 

or event type for any blowdown vent stacks, then you must report the information specified in paragraph 

(i)(1) of this section considering, in aggregate, all blowdown vent stacks for which emissions were 

calculated by equipment or event type. If you calculated emissions using flow meters for any blowdown 

vent stacks, then you must report the information specified in paragraph (i)(2) of this section considering, 

in aggregate, all blowdown vent stacks for which emissions were calculated using flow meters.

(1) Report by equipment or event type. If you calculated emissions from blowdown vent stacks by 

the seven categories listed in §98.233(i)(2), then you must report the equipment or event types and the 

information specified in paragraphs (i)(1)(i) through (iii) of this section for each equipment or event type. If 

a blowdown event resulted in emissions from multiple equipment types, and the emissions cannot be 

apportioned to the different equipment types, then you may report the information in paragraphs (i)(1)(i) 

through (iii) of this section for the equipment type that represented the largest portion of the emissions for 

the blowdown event.

(i) Total number of blowdowns in the calendar year for the equipment or event type (the sum of 

equation variable “N” from Equation W-14A or Equation W-14B of this subpart, for all unique physical 

volumes for the equipment or event type).

(ii) Annual CO2 emissions for the equipment or event type, in metric tons CO2, calculated according 

to §98.233(i)(2)(iii).

(iii) Annual CH4 emissions for the equipment or event type, in metric tons CH4, calculated according 

to §98.233(i)(2)(iii).
(2) Report by flow meter. If you elect to calculate emissions from blowdown vent stacks by using a 

flow meter according to §98.233(i)(3), then you must report the information specified in paragraphs 

(i)(2)(i) and (ii) of this section for the facility.

(i) Annual CO2 emissions from all blowdown vent stacks at the facility for which emissions were 

calculated using flow meters, in metric tons CO2 (the sum of all CO2 mass emission values calculated 

according to §98.233(i)(3), for all flow meters).

(ii) Annual CH4 emissions from all blowdown vent stacks at the facility for which emissions were 

calculated using flow meters, in metric tons CH4, (the sum of all CH4 mass emission values calculated 

according to §98.233(i)(3), for all flow meters).

(j) Onshore production storage tanks. You must indicate whether your facility sends produced oil to 

atmospheric tanks. If your facility sends produced oil to atmospheric tanks, then you must indicate which 

Calculation Method(s) you used to calculate GHG emissions, and you must report the information 

specified in paragraphs (j)(1) and (2) of this section as applicable. If you used Calculation Method 1 or 

Calculation Method 2, and any atmospheric tanks were observed to have malfunctioning dump valves 

during the calendar year, then you must indicate that dump valves were malfunctioning and you must 

report the information specified in paragraph (j)(3) of this section.

(1) If you used Calculation Method 1 or Calculation Method 2 to calculate GHG emissions, then you 

must report the information specified in paragraphs (j)(1)(i) through (xiv) of this section for each sub-basin 

and by calculation method.

(i) Sub-basin ID.

(ii) Calculation method used, and name of the software package used if using Calculation Method 1.

(iii) The total annual oil volume from gas-liquid separators and direct from wells that is sent to 

applicable onshore production storage tanks, in barrels. You may delay reporting of this data element if 

you indicate in the annual report that wildcat wells and delineation wells are the only wells in the subbasin with oil production greater than or equal to 10 barrels per day and flowing to gas-liquid separators 

or direct to storage tanks. If you elect to delay reporting of this data element, you must report by the date 

specified in §98.236(cc) the total volume of oil from all wells and the API Well Number(s) for the well(s) 

included in this volume.

(iv) The average gas-liquid separator temperature, in degrees Fahrenheit.

(v) The average gas-liquid separator pressure, in pounds per square inch gauge.

(vi) The average sales oil or stabilized oil API gravity, in degrees.

(vii) The minimum and maximum concentration (mole fraction) of CO2 in flash gas from onshore 

production storage tanks.

(viii) The minimum and maximum concentration (mole fraction) of CH4 in flash gas from onshore 

production storage tanks.

(ix) The number of wells sending oil to gas-liquid separators or directly to atmospheric tanks.

(x) The number of atmospheric tanks.

(xi) An estimate of the number of atmospheric tanks, not on well-pads, receiving your oil.
(xii) If any emissions from the atmospheric tanks at your facility were controlled with vapor recovery 

systems, then you must report the information specified in paragraphs (j)(1)(xii)(A) through (E) of this 

section.

(A) The number of atmospheric tanks that control emissions with vapor recovery systems.

(B) Total CO2 mass, in metric tons CO2, that was recovered during the calendar year using a vapor 

recovery system.

(C) Total CH4 mass, in metric tons CH4, that was recovered during the calendar year using a vapor 

recovery system.

(D) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks equipped with vapor recovery 

systems.

(E) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks equipped with vapor recovery 

systems.

(xiii) If any atmospheric tanks at your facility vented gas directly to the atmosphere without using a 

vapor recovery system or without flaring, then you must report the information specified in paragraphs 

(j)(1)(xiii)(A) through (C) of this section.

(A) The number of atmospheric tanks that vented gas directly to the atmosphere without using a 

vapor recovery system or without flaring.

(B) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to the 

atmosphere.

(C) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to the 

atmosphere.

(xiv) If you controlled emissions from any atmospheric tanks at your facility with one or more flares, 

then you must report the information specified in paragraphs (j)(1)(xiv)(A) through (D) of this section.

(A) The number of atmospheric tanks that controlled emissions with flares.

(B) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled emissions with 

one or more flares.

(C) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled emissions with 

one or more flares.

(D) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled emissions with 

one or more flares.

(2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the 

information specified in paragraphs (j)(2)(i) through (iii) of this section.

(i) Report the information specified in paragraphs (j)(2)(i)(A) through (F) of this section, at the basin 

level, for atmospheric tanks where emissions were calculated using Calculation Method 3.
(A) The total annual oil throughput that is sent to all atmospheric tanks in the basin, in barrels. You 

may delay reporting of this data element if you indicate in the annual report that wildcat wells and 

delineation wells are the only wells in the sub-basin with oil production less than 10 barrels per day and 

that send oil to atmospheric tanks. If you elect to delay reporting of this data element, you must report by 

the date specified in §98.236(cc) the total annual oil throughput from all wells and the API Well Number(s) 

for the well(s) included in this volume.

(B) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) of this section sent 

to atmospheric tanks in the basin that controlled emissions with flares.

(C) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) of this section sent 

to atmospheric tanks in the basin that controlled emissions with vapor recovery systems.

(D) The number of atmospheric tanks in the basin.

(E) The number of wells with gas-liquid separators (“Count” from Equation W-15 of this subpart) in 

the basin.

(F) The number of wells without gas-liquid separators (“Count” from Equation W-15 of this subpart) 

in the basin.

(ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (D) of this section for each 

sub-basin with atmospheric tanks whose emissions were calculated using Calculation Method 3 and that 

did not control emissions with flares.

(A) Sub-basin ID.

(B) The number of atmospheric tanks in the sub-basin that did not control emissions with flares.

(C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks in the sub-basin that did not 

control emissions with flares, calculated using Equation W-15 of this subpart and adjusted for vapor 

recovery, if applicable.

(D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks in the sub-basin that did not 

control emissions with flares, calculated using Equation W-15 of this subpart and adjusted for vapor 

recovery, if applicable.

(iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (E) of this section for each 

sub-basin with atmospheric tanks whose emissions were calculated using Calculation Method 3 and that 

controlled emissions with flares.

(A) Sub-basin ID.

(B) The number of atmospheric tanks in the sub-basin that controlled emissions with flares.

(C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled emissions with 

flares.

(D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled emissions with 

flares.
(E) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled emissions with 

flares.

(3) If you used Calculation Method 1 or Calculation Method 2, and any gas-liquid separator liquid 

dump values did not close properly during the calendar year, then you must report the information 

specified in paragraphs (j)(3)(i) through (iv) of this section for each sub-basin.

(i) The total number of gas-liquid separators whose liquid dump valves did not close properly during 

the calendar year.

(ii) The total time the dump valves on gas-liquid separators did not close properly in the calendar 

year, in hours (sum of the “Tn” values used in Equation W-16 of this subpart).

(iii) Annual CO2 emissions, in metric tons CO2, that resulted from dump valves on gas-liquid 

separators not closing properly during the calendar year, calculated using Equation W-16 of this subpart.

(iv) Annual CH4 emissions, in metric tons CH4, that resulted from the dump valves on gas-liquid 

separators not closing properly during the calendar year, calculated using Equation W-16 of this subpart.

(k) Transmission storage tanks. You must indicate whether your facility contains any transmission 

storage tanks. If your facility contains at least one transmission storage tank, then you must report the 

information specified in paragraphs (k)(1) through (3) of this section for each transmission storage tank 

vent stack.

(1) For each transmission storage tank vent stack, report the information specified in (k)(1)(i) 

through (iv) of this section.

(i) The unique name or ID number for the transmission storage tank vent stack.

(ii) Method used to determine if dump valve leakage occurred.

(iii) Indicate whether scrubber dump valve leakage occurred for the transmission storage tank vent 

according to §98.233(k)(2).

(iv) Indicate if there is a flare attached to the transmission storage tank vent stack.

(2) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported 

in paragraph (k)(1)(iii) of this section, and the vent stack vented directly to the atmosphere during the 

calendar year, then you must report the information specified in paragraphs (k)(2)(i) through (v) of this 

section for each transmission storage vent stack where scrubber dump valve leakage occurred.

(i) Method used to measure the leak rate.

(ii) Measured leak rate (average leak rate from a continuous flow measurement device), in standard 

cubic feet per hour.

(iii) Duration of time that the leak is counted as having occurred, in hours, as determined in 

§98.233(k)(3) (may use best available data if a continuous flow measurement device was used).

(iv) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to the 

atmosphere, calculated according to §98.233(k)(1) through (4).
(v) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to the 

atmosphere, calculated according to §98.233(k)(1) through (4).

(3) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported 

in paragraph (k)(1)(iii), and the vent stack vented to a flare during the calendar year, then you must report 

the information specified in paragraphs (k)(3)(i) through (vi) of this section.

(i) Method used to measure the leak rate.

(ii) Measured leakage rate (average leak rate from a continuous flow measurement device) in 

standard cubic feet per hour.

(iii) Duration of time that flaring occurred in hours, as defined in §98.233(k)(3) (may use best 

available data if a continuous flow measurement device was used).

(iv) Annual CO2 emissions, in metric tons CO2, that resulted from flaring gas, calculated according to 

§98.233(k)(5).

(v) Annual CH4 emissions, in metric tons CH4, that resulted from flaring gas, calculated according to 

§98.233(k)(5).

(vi) Annual N2O emissions, in metric tons N2O, that resulted from flaring gas, calculated according to 

§98.233(k)(5).

(l) Well testing. You must indicate whether you performed gas well or oil well testing, and if the 

testing of gas wells or oil wells resulted in vented or flared emissions during the calendar year. If you 

performed well testing that resulted in vented or flared emissions during the calendar year, then you must 

report the information specified in paragraphs (l)(1) through (4) of this section, as applicable.

(1) If you used Equation W-17A to calculate annual volumetric natural gas emissions at actual 

conditions from oil wells and the emissions are not vented to a flare, then you must report the information 

specified in paragraphs (l)(1)(i) through (vi) of this section.

(i) Number of wells tested in the calendar year.

(ii) Average number of well testing days per well for well(s) tested in the calendar year.

(iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.

(iv) Average flow rate for well(s) tested, in barrels of oil per day. You may delay reporting of this data 

element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells 

that are tested. If you elect to delay reporting of this data element, you must report by the date specified 

in §98.236(cc) the measured average flow rate for well(s) tested and the API Well Number(s) for the 

well(s) included in the measurement.

(v) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).

(vi) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).

(2) If you used Equation W-17A to calculate annual volumetric natural gas emissions at actual 

conditions from oil wells and the emissions are vented to a flare, then you must report the information 

specified in paragraphs (l)(2)(i) through (vii) of this section.
(i) Number of wells tested in the calendar year.

(ii) Average number of well testing days per well for well(s) tested in the calendar year.

(iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.

(iv) Average flow rate for well(s) tested, in barrels of oil per day. You may delay reporting of this data 

element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells 

that are tested. If you elect to delay reporting of this data element, you must report by the date specified 

in §98.236(cc) the measured average flow rate for well(s) tested and the API Well Number(s) for the 

well(s) included in the measurement.

(v) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).

(vi) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).

(vii) Annual N2O emissions, in metric tons N2O, calculated according to §98.233(l).

(3) If you used Equation W-17B to calculate annual volumetric natural gas emissions at actual 

conditions from gas wells and the emissions were not vented to a flare, then you must report the 

information specified in paragraphs (l)(3)(i) through (v) of this section.

(i) Number of wells tested in the calendar year.

(ii) Average number of well testing days per well for well(s) tested in the calendar year.

(iii) Average annual production rate for well(s) tested, in actual cubic feet per day. You may delay 

reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells 

are the only wells that are tested. If you elect to delay reporting of this data element, you must report by 

the date specified in §98.236(cc) the measured average annual production rate for well(s) tested and the 

API Well Number(s) for the well(s) included in the measurement.

(iv) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).

(v) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).

(4) If you used Equation W-17B to calculate annual volumetric natural gas emissions at actual 

conditions from gas wells and the emissions were vented to a flare, then you must report the information 

specified in paragraphs (l)(4)(i) through (vi) of this section.

(i) Number of wells tested in calendar year.

(ii) Average number of well testing days per well for well(s) tested in the calendar year.

(iii) Average annual production rate for well(s) tested, in actual cubic feet per day. You may delay 

reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells 

are the only wells that are tested. If you elect to delay reporting of this data element, you must report by 

the date specified in §98.236(cc) the measured average annual production rate for well(s) tested and the 

API Well Number(s) for the well(s) included in the measurement.

(iv) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).
(v) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).

(vi) Annual N2O emissions, in metric tons N2O, calculated according to §98.233(l).

(m) Associated natural gas. You must indicate whether any associated gas was vented or flared 

during the calendar year. If associated gas was vented or flared during the calendar year, then you must 

report the information specified in paragraphs (m)(1) through (8) of this section for each sub-basin.

(1) Sub-basin ID.

(2) Indicate whether any associated gas was vented directly to the atmosphere without flaring.

(3) Indicate whether any associated gas was flared.

(4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil (average of the “GOR” 

values used in Equation W-18 of this subpart).

(5) Volume of oil produced, in barrels, in the calendar year during the time periods in which 

associated gas was vented or flared (the sum of “Vp,q” used in Equation W-18 of this subpart). You may 

delay reporting of this data element if you indicate in the annual report that wildcat wells and/or 

delineation wells are the only wells from which associated gas was vented or flared. If you elect to delay 

reporting of this data element, you must report by the date specified in §98.236(cc) the volume of oil 

produced for well(s) with associated gas venting and flaring and the API Well Number(s) for the well(s) 

included in the measurement.

(6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year during 

time periods in which associated gas was vented or flared (the sum of “SG” values used in Equation W18 of §98.233(m)). You may delay reporting of this data element if you indicate in the annual report that 

wildcat wells and/or delineation wells from which associated gas was vented or flared. If you elect to 

delay reporting of this data element, you must report by the date specified in §98.236(cc) the measured 

total volume of associated gas sent to sales for well(s) with associated gas venting and flaring and the 

API Well Number(s) for the well(s) included in the measurement.

(7) If you had associated gas emissions vented directly to the atmosphere without flaring, then you 

must report the information specified in paragraphs (m)(7)(i) through (iii) of this section for each subbasin.

(i) Total number of wells for which associated gas was vented directly to the atmosphere without 

flaring.

(ii) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(m)(3) and (4).

(iii) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(m)(3) and (4).

(8) If you had associated gas emissions that were flared, then you must report the information 

specified in paragraphs (m)(8)(i) through (iv) of this section for each sub-basin.

(i) Total number of wells for which associated gas was flared.

(ii) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(m)(5).

(iii) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(m)(5).
(iv) Annual N2O emissions, in metric tons N2O, calculated according to §98.233(m)(5).

(n) Flare stacks. You must indicate if your facility contains any flare stacks. You must report the 

information specified in paragraphs (n)(1) through (12) of this section for each flare stack at your facility, 

and for each industry segment applicable to your facility.

(1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production 

industry segment, a different name or ID may be used for a single flare stack for each location where it 

operates at in a given calendar year.

(2) Indicate whether the flare stack has a continuous flow measurement device.

(3) Indicate whether the flare stack has a continuous gas composition analyzer on feed gas to the 

flare.

(4) Volume of gas sent to the flare, in standard cubic feet (“Vs” in Equations W-19 and W-20 of this 

subpart).

(5) Fraction of the feed gas sent to an un-lit flare (“Zu” in Equation W-19 of this subpart).

(6) Flare combustion efficiency, expressed as the fraction of gas combusted by a burning flare.

(7) Mole fraction of CH4 in the feed gas to the flare (“XCH4” in Equation W-19 of this subpart).

(8) Mole fraction of CO2 in the feed gas to the flare (“XCO2” in Equation W-20 of this subpart).

(9) Annual CO2 emissions, in metric tons CO2 (refer to Equation W-20 of this subpart).

(10) Annual CH4 emissions, in metric tons CH4 (refer to Equation W-19 of this subpart).

(11) Annual N2O emissions, in metric tons N2O (refer to Equation W-40 of this subpart).

(12) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used 

to measure emissions from the flare, then you are not required to report N2O and CH4 emissions for the 

flare stack.

(o) Centrifugal compressors. You must indicate whether your facility has centrifugal compressors. 

You must report the information specified in paragraphs (o)(1) and (2) of this section for all centrifugal 

compressors at your facility. For each compressor source or manifolded group of compressor sources 

that you conduct as found leak measurements as specified in §98.233(o)(2) or (4), you must report the 

information specified in paragraph (o)(3) of this section. For each compressor source or manifolded group 

of compressor sources that you conduct continuous monitoring as specified in §98.233(o)(3) or (5), you 

must report the information specified in paragraph (o)(4) of this section. Centrifugal compressors in 

onshore petroleum and natural gas production are not required to report information in paragraphs (o)(1) 

through (4) of this section and instead must report the information specified in paragraph (o)(5) of this 

section.

(1) Compressor activity data. Report the information specified in paragraphs (o)(1)(i) through (xiv) of 

this section for each centrifugal compressor located at your facility.

(i) Unique name or ID for the centrifugal compressor.
(ii) Hours in operating-mode.

(iii) Hours in not-operating-depressurized-mode.

(iv) Indicate whether the compressor was measured in operating-mode.

(v) Indicate whether the compressor was measured in not-operating-depressurized-mode.

(vi) Indicate which, if any, compressor sources are part of a manifolded group of compressor 

sources.

(vii) Indicate which, if any, compressor sources are routed to a flare.

(viii) Indicate which, if any, compressor sources have vapor recovery.

(ix) Indicate which, if any, compressor source emissions are captured for fuel use or are routed to a 

thermal oxidizer.

(x) Indicate whether the compressor has blind flanges installed and associated dates.

(xi) Indicate whether the compressor has wet or dry seals.

(xii) If the compressor has wet seals, the number of wet seals.

(xiii) Power output of the compressor driver (hp).

(xiv) Indicate whether the compressor had a scheduled depressurized shutdown during the reporting 

year.

(2) Compressor source. (i) For each compressor source at each compressor, report the information 

specified in paragraphs (o)(2)(i)(A) through (C) of this section.

(A) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(i) of this section.

(B) Centrifugal compressor source (wet seal, isolation valve, or blowdown valve).

(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of 

compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If 

multiple compressor sources are released through a single vent for which continuous measurements are 

used, use the same leak or vent ID for each compressor source released via the measured vent. For a 

single compressor using as found measurements, you must provide a different leak or vent ID for each 

compressor source.

(ii) For each leak or vent, report the information specified in paragraphs (o)(2)(ii)(A) through (E) of 

this section.

(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of 

compressor sources and whether the emissions from the leak or vent are released to the atmosphere, 

routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.

(B) Indicate whether an as found measurement(s) as identified in §98.233(o)(2) or (4) was 

conducted on the leak or vent.
(C) Indicate whether continuous measurements as identified in §98.233(o)(3) or (5) were conducted 

on the leak or vent.

(D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(1) and (2) of this section for the leak or 

vent. If the leak or vent is routed to a flare, combustion, or vapor recovery, you are not required to report 

emissions under this paragraph.

(1) Annual CO2 emissions, in metric tons CO2.

(2) Annual CH4 emissions, in metric tons CH4.

(E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the percentage of time 

that the respective device was operational when the compressor source emissions were routed to the 

device.

(3) As found measurement sample data. If the measurement methods specified in §98.233(o)(2) or 

(4) are conducted, report the information specified in paragraph (o)(3)(i) of this section. If the calculation 

specified in §98.233(o)(6)(ii) is performed, report the information specified in paragraph (o)(3)(ii) of this 

section.

(i) For each as found measurement performed on a leak or vent, report the information specified in 

paragraphs (o)(3)(i)(A) through (F) of this section.

(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.

(B) Measurement date.

(C) Measurement method. If emissions were not detected when using a screening method, report 

the screening method. If emissions were detected using a screening method, report only the method 

subsequently used to measure the volumetric emissions.

(D) Measured flow rate, in standard cubic feet per hour.

(E) For each compressor attached to the leak or vent, report the compressor mode during which the 

measurement was taken.

(F) If the measurement is for a manifolded group of compressor sources, indicate whether the 

measurement location is prior to or after comingling with non-compressor emission sources.

(ii) For each compressor mode-source combination where a reporter emission factor as calculated 

in Equation W-23 was used to calculate emissions in Equation W-22, report the information specified in 

paragraphs (o)(3)(ii)(A) through (D) of this section.

(A) The compressor mode-source combination.

(B) The compressor mode-source combination reporter emission factor, in standard cubic feet per 

hour (EFs,m in Equation W-23).

(C) The total number of compressors measured in the compressor mode-source combination in the 

current reporting year and the preceding two reporting years (Countm in Equation W-23).
(D) Indicate whether the compressor mode-source combination reporter emission factor is facilityspecific or based on all of the reporter's applicable facilities.

(4) Continuous measurement data. If the measurement methods specified in §98.233(o)(3) or (5) 

are conducted, report the information specified in paragraphs (o)(4)(i) through (iv) of this section for each 

continuous measurement conducted on each leak or vent associated with each compressor source or 

manifolded group of compressor sources.

(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.

(ii) Measured volume of flow during the reporting year, in million standard cubic feet.

(iii) Indicate whether the measured volume of flow during the reporting year includes compressor 

blowdown emissions as allowed for in §98.233(o)(3)(ii) and (o)(5)(iii).

(iv) If the measurement is for a manifolded group of compressor sources, indicate whether the 

measurement location is prior to or after comingling with non-compressor emission sources.

(5) Onshore petroleum and natural gas production. Centrifugal compressors with wet seal 

degassing vents in onshore petroleum and natural gas production must report the information specified in 

paragraphs (o)(5)(i) through (iii) of this section.

(i) Number of centrifugal compressors that have wet seal oil degassing vents.

(ii) Annual CO2 emissions, in metric tons CO2, from centrifugal compressors with wet seal oil 

degassing vents.

(iii) Annual CH4 emissions, in metric tons CH4, from centrifugal compressors with wet seal oil 

degassing vents.

(p) Reciprocating compressors. You must indicate whether your facility has reciprocating 

compressors. You must report the information specified in paragraphs (p)(1) and (2) of this section for all 

reciprocating compressors at your facility. For each compressor source or manifolded group of 

compressor sources that you conduct as found leak measurements as specified in §98.233(p)(2) or (4), 

you must report the information specified in paragraph (p)(3) of this section. For each compressor source 

or manifolded group of compressor sources that you conduct continuous monitoring as specified in 

§98.233(p)(3) or (5), you must report the information specified in paragraph (p)(4) of this section. 

Reciprocating compressors in onshore petroleum and natural gas production are not required to report 

information in paragraphs (p)(1) through (4) of this section and instead must report the information 

specified in paragraph (p)(5) of this section.

(1) Compressor activity data. Report the information specified in paragraphs (p)(1)(i) through (xiv) of 

this section for each reciprocating compressor located at your facility.

(i) Unique name or ID for the reciprocating compressor.

(ii) Hours in operating-mode.

(iii) Hours in standby-pressurized-mode.

(iv) Hours in not-operating-depressurized-mode.
(v) Indicate whether the compressor was measured in operating-mode.

(vi) Indicate whether the compressor was measured in standby-pressurized-mode.

(vii) Indicate whether the compressor was measured in not-operating-depressurized-mode.

(viii) Indicate which, if any, compressor sources are part of a manifolded group of compressor 

sources.

(ix) Indicate which, if any, compressor sources are routed to a flare.

(x) Indicate which, if any, compressor sources have vapor recovery.

(xi) Indicate which, if any, compressor source emissions are captured for fuel use or are routed to a 

thermal oxidizer.

(xii) Indicate whether the compressor has blind flanges installed and associated dates.

(xiii) Power output of the compressor driver (hp).

(xiv) Indicate whether the compressor had a scheduled depressurized shutdown during the reporting 

year.

(2) Compressor source. (i) For each compressor source at each compressor, report the information 

specified in paragraphs (p)(2)(i)(A) through (C) of this section.

(A) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of this section.

(B) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing).

(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of 

compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If 

multiple compressor sources are released through a single vent for which continuous measurements are 

used, use the same leak or vent ID for each compressor source released via the measured vent. For a 

single compressor using as found measurements, you must provide a different leak or vent ID for each 

compressor source.

(ii) For each leak or vent, report the information specified in paragraphs (p)(2)(ii)(A) through (E) of 

this section.

(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of 

compressor sources and whether the emissions from the leak or vent are released to the atmosphere, 

routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.

(B) Indicate whether an as found measurement(s) as identified in §98.233(p)(2) or (4) was 

conducted on the leak or vent.

(C) Indicate whether continuous measurements as identified in §98.233(p)(3) or (5) were conducted 

on the leak or vent.
(D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(1) and (2) of this section for the leak or 

vent. If the leak or vent is routed to flare, combustion, or vapor recovery, you are not required to report 

emissions under this paragraph.

(1) Annual CO2 emissions, in metric tons CO2.

(2) Annual CH4 emissions, in metric tons CH4.

(E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the percentage of time 

that the respective device was operational when the compressor source emissions were routed to the 

device.

(3) As found measurement sample data. If the measurement methods specified in §98.233(p)(2) or 

(4) are conducted, report the information specified in paragraph (p)(3)(i) of this section. If the calculation 

specified in §98.233(p)(6)(ii) is performed, report the information specified in paragraph (p)(3)(ii) of this 

section.

(i) For each as found measurement performed on a leak or vent, report the information specified in 

paragraphs (p)(3)(i)(A) through (F) of this section.

(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.

(B) Measurement date.

(C) Measurement method. If emissions were not detected when using a screening method, report 

the screening method. If emissions were detected using a screening method, report only the method 

subsequently used to measure the volumetric emissions.

(D) Measured flow rate, in standard cubic feet per hour.

(E) For each compressor attached to the leak or vent, report the compressor mode during which the 

measurement was taken.

(F) If the measurement is for a manifolded group of compressor sources, indicate whether the 

measurement location is prior to or after comingling with non-compressor emission sources.

(ii) For each compressor mode-source combination where a reporter emission factor as calculated 

in Equation W-28 was used to calculate emissions in Equation W-27, report the information specified in 

paragraphs (p)(3)(ii)(A) through (D) of this section

(A) The compressor mode-source combination.

(B) The compressor mode-source combination reporter emission factor, in standard cubic feet per 

hour (EFs,m in Equation W-28).

(C) The total number of compressors measured in the compressor mode-source combination in the 

current reporting year and the preceding two reporting years (Countm in Equation W-28).

(D) Indicate whether the compressor mode-source combination reporter emission factor is facilityspecific or based on all of the reporter's applicable facilities.
(4) Continuous measurement data. If the measurement methods specified in §98.233(p)(3) or (5) 

are conducted, report the information specified in paragraphs (p)(4)(i) through (iv) of this section for each 

continuous measurement conducted on each leak or vent associated with each compressor source or 

manifolded group of compressor sources.

(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.

(ii) Measured volume of flow during the reporting year, in million standard cubic feet.

(iii) Indicate whether the measured volume of flow during the reporting year includes compressor 

blowdown emissions as allowed for in §98.233(p)(3)(ii) and (p)(5)(iii).

(iv) If the measurement is for a manifolded group of compressor sources, indicate whether the 

measurement location is prior to or after comingling with non-compressor emission sources.

(5) Onshore petroleum and natural gas production. Reciprocating compressors in onshore 

petroleum and natural gas production must report the information specified in paragraphs (p)(5)(i) through 

(iii) of this section.

(i) Number of reciprocating compressors.

(ii) Annual CO2 emissions, in metric tons CO2, from reciprocating compressors.

(iii) Annual CH4 emissions, in metric tons CH4, from reciprocating compressors.

(q) Equipment leak surveys. If your facility is subject to the requirements of §98.233(q), then you 

must report the information specified in paragraphs (q)(1) and (2) of this section. Natural gas distribution 

facilities with emission sources listed in §98.232(i)(1) must also report the information specified in 

paragraph (q)(3) of this section.

(1) You must report the information specified in paragraphs (q)(1)(i) and (ii) of this section.

(i) Except as specified in paragraph (q)(1)(ii) of this section, the number of complete equipment leak 

surveys performed during the calendar year.

(ii) Natural gas distribution facilities performing equipment leak surveys across a multiple year leak 

survey cycle must report the number of years in the leak survey cycle.

(2) You must indicate whether your facility contains any of the component types listed in 

§98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), or (i)(1), for your facility's industry segment. For each 

component type that is located at your facility, you must report the information specified in paragraphs 

(q)(2)(i) through (v) of this section. If a component type is located at your facility and no leaks were 

identified from that component, then you must report the information in paragraphs (q)(2)(i) through (v) of 

this section but report a zero (“0”) for the information required according to paragraphs (q)(2)(iii), (iv), and 

(v) of this section.

(i) Component type.

(ii) Total number of the surveyed component type that were identified as leaking in the calendar year 

(“xp” in Equation W-30 of this subpart for the component type).
(iii) Average time the surveyed components are assumed to be leaking and operational, in hours 

(average of “Tp,z” from Equation W-30 of this subpart for the component type).

(iv) Annual CO2 emissions, in metric tons CO2, for the component type as calculated using Equation 

W-30 (for surveyed components only).

(v) Annual CH4 emissions, in metric tons CH4, for the component type as calculated using Equation 

W-30 (for surveyed components only).

(3) Natural gas distribution facilities with emission sources listed in §98.232(i)(1) must also report 

the information specified in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix) of this section.

(i) Number of above grade transmission-distribution transfer stations surveyed in the calendar year.

(ii) Number of meter/regulator runs at above grade transmission-distribution transfer stations 

surveyed in the calendar year (“CountMR,y” from Equation W-31 of this subpart, for the current calendar 

year).

(iii) Average time that meter/regulator runs surveyed in the calendar year were operational, in hours 

(average of “Tw,y” from Equation W-31 of this subpart, for the current calendar year).

(iv) Number of above grade transmission-distribution transfer stations surveyed in the current leak 

survey cycle.

(v) Number of meter/regulator runs at above grade transmission-distribution transfer stations 

surveyed in current leak survey cycle (sum of “CountMR,y” from Equation W-31 of this subpart, for all 

calendar years in the current leak survey cycle).

(vi) Average time that meter/regulator runs surveyed in the current leak survey cycle were 

operational, in hours (average of “Tw,y” from Equation W-31 of this subpart, for all years included in the 

leak survey cycle).

(vii) Meter/regulator run CO2 emission factor based on all surveyed transmission-distribution transfer 

stations in the current leak survey cycle, in standard cubic feet of CO2 per operational hour of all 

meter/regulator runs (“EFs,MR,i” for CO2 calculated using Equation W-31 of this subpart).

(viii) Meter/regulator run CH4 emission factor based on all surveyed transmission-distribution transfer 

stations in the current leak survey cycle, in standard cubic feet of CH4 per operational hour of all 

meter/regulator runs (“EFs,MR,i” for CH4 calculated using Equation W-31 of this subpart).

(ix) If your natural gas distribution facility performs equipment leak surveys across a multiple year 

leak survey cycle, you must also report:

(A) The total number of meter/regulator runs at above grade transmission-distribution transfer 

stations at your facility (“CountMR” in Equation W-32B of this subpart).

(B) Average estimated time that each meter/regulator run at above grade transmission-distribution 

transfer stations was operational in the calendar year, in hours per meter/regulator run (“Tw,avg” in Equation 

W-32B of this subpart).

(C) Annual CO2 emissions, in metric tons CO2, for all above grade transmission-distribution transfer 

stations at your facility.
(D) Annual CH4 emissions, in metric tons CH4, for all above grade transmission-distribution transfer 

stations at your facility.

(r) Equipment leaks by population count. If your facility is subject to the requirements of §98.233(r), 

then you must report the information specified in paragraphs (r)(1) through (3) of this section, as 

applicable.

(1) You must indicate whether your facility contains any of the emission source types required to use 

Equation W-32A of this subpart. You must report the information specified in paragraphs (r)(1)(i) through 

(v) of this section separately for each emission source type required to use Equation W-32A of this 

subpart that is located at your facility. Onshore petroleum and natural gas production facilities must report 

the information specified in paragraphs (r)(1)(i) through (v) of this section separately by component type, 

service type, and geographic location (i.e., Eastern U.S. or Western U.S.).

(i) Emission source type. Onshore petroleum and natural gas production facilities must report the 

component type, service type and geographic location.

(ii) Total number of the emission source type at the facility (“Counte” in Equation W-32A of this 

subpart).

(iii) Average estimated time that the emission source type was operational in the calendar year, in 

hours (“Te” in Equation W-32A of this subpart).

(iv) Annual CO2 emissions, in metric tons CO2, for the emission source type.

(v) Annual CH4 emissions, in metric tons CH4, for the emission source type.

(2) Natural gas distribution facilities must also report the information specified in paragraphs (r)(2)(i) 

through (v) of this section.

(i) Number of above grade transmission-distribution transfer stations at the facility.

(ii) Number of above grade metering-regulating stations that are not transmission-distribution 

transfer stations at the facility.

(iii) Total number of meter/regulator runs at above grade metering-regulating stations that are not 

above grade transmission-distribution transfer stations (“CountMR” in Equation W-32B of this subpart).

(iv) Average estimated time that each meter/regulator run at above grade metering-regulating 

stations that are not above grade transmission-distribution transfer stations was operational in the 

calendar year, in hours per meter/regulator run (“Tw,avg” in Equation W-32B of this subpart).

(v) If your facility has above grade metering-regulating stations that are not above grade 

transmission-distribution transfer stations and your facility also has above grade transmission-distribution 

transfer stations, you must also report:

(A) Annual CO2 emissions, in metric tons CO2, from above grade metering-regulating stations that 

are not above grade transmission-distribution transfer stations.

(B) Annual CH4 emissions, in metric tons CH4, from above grade metering regulating stations that 

are not above grade transmission-distribution transfer stations.
(3) Onshore petroleum and natural gas production facilities must also report the information 

specified in paragraphs (r)(3)(i) and (ii) of this section.

(i) Calculation method used.

(ii) Onshore petroleum and natural gas production facilities must report the information specified in 

paragraphs (r)(3)(ii)(A) and (B) of this section, for each major equipment type, production type (i.e.,

natural gas or crude oil), and geographic location combination in Tables W-1B and W-1C of this subpart.

(A) An indication of whether the facility contains the major equipment type.

(B) If the facility does contain the equipment type, the count of the major equipment type.

(s) Offshore petroleum and natural gas production. You must report the information specified in 

paragraphs (s)(1) through (3) of this section for each emission source type listed in the most recent 

BOEMRE study.

(1) Annual CO2 emissions, in metric tons CO2.

(2) Annual CH4 emissions, in metric tons CH4.

(3) Annual N2O emissions, in metric tons N2O.

(t) [Reserved]

(u) [Reserved]

(v) [Reserved]

(w) EOR injection pumps. You must indicate whether CO2 EOR injection was used at your facility 

during the calendar year and if any EOR injection pump blowdowns occurred during the year. If any EOR 

injection pump blowdowns occurred during the calendar year, then you must report the information 

specified in paragraphs (w)(1) through (8) of this section for each EOR injection pump system.

(1) Sub-basin ID.

(2) EOR injection pump system identifier.

(3) Pump capacity, in barrels per day.

(4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“Vv” in Equation 

W-37 of this subpart).

(5) Number of blowdowns for the EOR injection pump system in the calendar year.

(6) Density of critical phase EOR injection gas, in kilograms per cubic foot (“Rc” in Equation W-37 of 

this subpart).

(7) Mass fraction of CO2 in critical phase EOR injection gas (“GHGCO2” in Equation W-37 of this 

subpart).

(8) Annual CO2 emissions, in metric tons CO2, from EOR injection pump system blowdowns.
(x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon liquids were produced 

through EOR operations. If hydrocarbon liquids were produced through EOR operations, you must report 

the information specified in paragraphs (x)(1) through (4) of this section for each sub-basin category with 

EOR operations.

(1) Sub-basin ID.

(2) Total volume of hydrocarbon liquids produced through EOR operations in the calendar year, in 

barrels (“Vhl” in Equation W-38 of this subpart).

(3) Average CO2 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per 

barrel under standard conditions (“Shl” in Equation W-38 of this subpart).

(4) Annual CO2 emissions, in metric tons CO2, from CO2 retained in hydrocarbon liquids produced 

through EOR operations downstream of the storage tank (“MassCO2” in Equation W-38 of this subpart).

(y) [Reserved]

(z) Combustion equipment at onshore petroleum and natural gas production facilities and natural 

gas distribution facilities. If your facility is required by §98.232(c)(22) or (i)(7) to report emissions from 

combustion equipment, then you must indicate whether your facility has any combustion units subject to 

reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section. If your facility contains any 

combustion units subject to reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section, then 

you must report the information specified in paragraphs (z)(1) and (2) of this section, as applicable.

(1) Indicate whether the combustion units include: External fuel combustion units with a rated heat 

capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units that are not 

compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or the equivalent of 130 

horsepower). If the facility contains external fuel combustion units with a rated heat capacity less than or 

equal to 5 million Btu per hour or internal fuel combustion units that are not compressor-drivers, with a 

rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 horsepower), 

then you must report the information specified in paragraphs (z)(1)(i) and (ii) of this section for each unit 

type.

(i) The type of combustion unit.

(ii) The total number of combustion units.

(2) Indicate whether the combustion units include: External fuel combustion units with a rated heat 

capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressordrivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 

horsepower); or, internal fuel combustion units of any heat capacity that are compressor-drivers. If your 

facility contains: External fuel combustion units with a rated heat capacity greater than 5 mmBtu/hr; 

internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 

million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of any heat 

capacity that are compressor-drivers, then you must report the information specified in paragraphs 

(z)(2)(i) through (vi) of this section for each combustion unit type and fuel type combination.

(i) The type of combustion unit.

(ii) The type of fuel combusted.
(iii) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, gallons, or 

tons.

(iv) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(z)(1) and (2).

(v) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(z)(1) and (2).

(vi) Annual N2O emissions, in metric tons N2O, calculated according to §98.233(z)(1) and (2).

(aa) Each facility must report the information specified in paragraphs (aa)(1) through (9) of this 

section, for each applicable industry segment, by using best available data. If a quantity required to be 

reported is zero, you must report zero as the value.

(1) For onshore petroleum and natural gas production, report the data specified in paragraphs 

(aa)(1)(i) and (ii) of this section.

(i) Report the information specified in paragraphs (aa)(1)(i)(A) through (C) of this section for the 

basin as a whole.

(A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. 

This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not 

include gas injected back into reservoirs or shrinkage resulting from lease condensate production.

(B) The quantity of gas produced in the calendar year for sales, in thousand standard cubic feet.

(C) The quantity of crude oil and condensate produced in the calendar year for sales, in barrels.

(ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (M) of this section for each 

unique sub-basin category.

(A) State.

(B) County.

(C) Formation type.

(D) The number of producing wells at the end of the calendar year (exclude only those wells 

permanently taken out of production, i.e., plugged and abandoned) .

(E) The number of producing wells acquired during the calendar year.

(F) The number of producing wells divested during the calendar year.

(G) The number of wells completed during the calendar year.

(H) The number of wells permanently taken out of production (i.e., plugged and abandoned) during 

the calendar year.

(I) Average mole fraction of CH4 in produced gas.

(J) Average mole fraction of CO2 in produced gas.
(K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic feet per 

barrel.

(L) If an oil sub-basin, report the average API gravity of all wells.

(M) If an oil sub-basin, report average low pressure separator pressure, in pounds per square inch 

gauge.

(2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) and (ii) of this 

section.

(i) The total quantity of gas handled at the offshore platform in the calendar year, in thousand 

standard cubic feet, including production volumes and volumes transferred via pipeline from another 

location.

(ii) The total quantity of oil and condensate handled at the offshore platform in the calendar year, in

barrels, including production volumes and volumes transferred via pipeline from another location.

(3) For natural gas processing, report the information specified in paragraphs (aa)(3)(i) through (vii) 

of this section.

(i) The quantity of natural gas received at the gas processing plant in the calendar year, in thousand 

standard cubic feet.

(ii) The quantity of processed (residue) gas leaving the gas processing plant in the calendar year, in 

thousand standard cubic feet.

(iii) The cumulative quantity of all NGLs (bulk and fractionated) received at the gas processing plant 

in the calendar year, in barrels.

(iv) The cumulative quantity of all NGLs (bulk and fractionated) leaving the gas processing plant in 

the calendar year, in barrels.

(v) Average mole fraction of CH4 in natural gas received.

(vi) Average mole fraction of CO2 in natural gas received.

(vii) Indicate whether the facility fractionates NGLs.

(4) For natural gas transmission compression, report the quantity specified in paragraphs (aa)(4)(i) 

through (v) of this section.

(i) The quantity of gas transported through the compressor station in the calendar year, in thousand 

standard cubic feet.

(ii) Number of compressors.

(iii) Total compressor power rating of all compressors combined, in horsepower.

(iv) Average upstream pipeline pressure, in pounds per square inch gauge.

(v) Average downstream pipeline pressure, in pounds per square inch gauge.
(5) For underground natural gas storage, report the quantities specified in paragraphs (aa)(5)(i) 

through (iii) of this section.

(i) The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet.

(ii) The quantity of gas withdrawn from storage in the calendar year, in thousand standard cubic feet.

(iii) Total storage capacity, in thousand standard cubic feet.

(6) For LNG import equipment, report the quantity of LNG imported in the calendar year, in thousand 

standard cubic feet.

(7) For LNG export equipment, report the quantity of LNG exported in the calendar year, in thousand 

standard cubic feet.

(8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (iii) of this 

section.

(i) The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet.

(ii) The quantity of LNG withdrawn from storage in the calendar year, in thousand standard cubic 

feet.

(iii) Total storage capacity, in thousand standard cubic feet.

(9) For natural gas distribution, report the quantities specified in paragraphs (aa)(9)(i) through (vii) of 

this section.

(i) The quantity of natural gas received at all custody transfer stations in the calendar year, in 

thousand standard cubic feet. This value may include meter corrections, but only for the calendar year 

covered by the annual report.

(ii) The quantity of natural gas withdrawn from in-system storage in the calendar year, in thousand 

standard cubic feet.

(iii) The quantity of natural gas added to in-system storage in the calendar year, in thousand 

standard cubic feet.

(iv) The quantity of natural gas delivered to end users, in thousand standard cubic feet. This value 

does not include stolen gas, or gas that is otherwise unaccounted for.

(v) The quantity of natural gas transferred to third parties such as other LDCs or pipelines, in 

thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise 

unaccounted for.

(vi) The quantity of natural gas consumed by the LDC for operational purposes, in thousand 

standard cubic feet.

(vii) The estimated quantity of gas stolen in the calendar year, in thousand standard cubic feet.

(bb) For any missing data procedures used, report the information in §98.3(c)(8) except as provided 

in paragraphs (bb)(1) and (2) of this section.
(1) For quarterly measurements, report the total number of quarters that a missing data procedure 

was used for each data element rather than the total number of hours.

(2) For annual or biannual (once every two years) measurements, you do not need to report the 

number of hours that a missing data procedure was used for each data element.

(cc) If you elect to delay reporting the information in paragraph (g)(5)(i), (g)(5)(ii), (h)(1)(iv), (h)(2)(iv), 

(j)(1)(iii), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), (l)(4)(iii), (m)(5), or (m)(6) of this section, you must report 

the information required in that paragraph no later than the date 2 years following the date specified in 

§98.3(b) introductory text.

[79 FR 70411, Nov. 24, 2014]

§98.237 Records that must be retained.

Monitoring Plans, as described in §98.3(g)(5), must be completed by April 1, 2011. In addition to the 

information required by §98.3(g), you must retain the following records:

(a) Dates on which measurements were conducted.

(b) Results of all emissions detected and measurements.

(c) Calibration reports for detection and measurement instruments used.

(d) Inputs and outputs of calculations or emissions computer model runs used for engineering 

estimation of emissions.

(e) The records required under §98.3(g)(2)(i) shall include an explanation of how company records, 

engineering estimation, or best available information are used to calculate each applicable parameter 

under this subpart.

(f) For each time a missing data procedure was used, keep a record listing the emission source 

type, a description of the circumstance that resulted in the need to use missing data procedures, the 

missing data provisions in §98.235 that apply, the calculation or analysis used to develop the substitute 

value, and the substitute value.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80590, Dec. 23, 2011; 79 FR 70424, Nov. 25, 2014]

§98.238 Definitions.

Except as provided in this section, all terms used in this subpart have the same meaning given in 

the Clean Air Act and subpart A of this part.

Acid gas means hydrogen sulfide (H2S) and/or carbon dioxide (CO2) contaminants that are 

separated from sour natural gas by an acid gas removal unit.

Acid gas removal unit (AGR) means a process unit that separates hydrogen sulfide and/or carbon 

dioxide from sour natural gas using liquid or solid absorbents or membrane separators.
Acid gas removal vent emissions mean the acid gas separated from the acid gas absorbing medium 

(e.g., an amine solution) and released with methane and other light hydrocarbons to the atmosphere or a 

flare.

Associated gas venting or flaring means the venting or flaring of natural gas which originates at 

wellheads that also produce hydrocarbon liquids and occurs either in a discrete gaseous phase at the 

wellhead or is released from the liquid hydrocarbon phase by separation. This does not include venting or 

flaring resulting from activities that are reported elsewhere, including tank venting, well completions, and 

well workovers.

Associated with a single well-pad means associated with the hydrocarbon stream as produced from 

one or more wells located on that single well-pad. The association ends where the stream from a single 

well-pad is combined with streams from one or more additional single 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: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard 

F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991) 

(incorporated by reference, see §98.7) and the Alaska Geological Province Boundary Map, Compiled by 

the American Association of Petroleum Geologists Committee on Statistics of Drilling in Cooperation with 

the USGS, 1978 (incorporated by reference, see §98.7).

Compressor means any machine for raising the pressure of a natural gas or CO2 by drawing in low 

pressure natural gas or CO2 and discharging significantly higher pressure natural gas or CO2.

Compressor mode means the operational and pressurized status of a compressor. For a centrifugal 

compressor, “mode” refers to either operating-mode or not-operating-depressurized-mode. For a 

reciprocating compressor, “mode” refers to either: Operating-mode, standby-pressurized-mode, or notoperating-depressurized-mode.

Compressor source means the source of certain venting or leaking emissions from a centrifugal or 

reciprocating compressor. For centrifugal compressors, “source” refers to blowdown valve leakage 

through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind 

flanges, and wet seal oil degassing vents. For reciprocating compressors, “source” refers to blowdown 

valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent 

without blind flanges, and rod packing emissions.

Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, 

separated from natural gas that condenses due to changes in the temperature, pressure, or both, and 

remains liquid at storage conditions.

Delineation well means a well drilled in order to determine the boundary of a field or producing 

reservoir.

Distribution pipeline means a pipeline that is designated as such by the Pipeline and Hazardous 

Material Safety Administration (PHMSA) 49 CFR 192.3.

Engineering estimation, for purposes of subpart W, means an estimate of emissions based on 

engineering principles applied to measured and/or approximated physical parameters such as 

dimensions of containment, actual pressures, actual temperatures, and compositions.
Enhanced oil recovery (EOR) means the use of certain methods such as water flooding or gas 

injection into existing wells to increase the recovery of crude oil from a reservoir. In the context of this 

subpart, EOR applies to injection of critical phase or immiscible carbon dioxide into a crude oil reservoir to 

enhance the recovery of oil.

External combustion means fired combustion in which the flame and products of combustion are 

separated from contact with the process fluid to which the energy is delivered. Process fluids may be air, 

hot water, or hydrocarbons. External combustion equipment may include fired heaters, industrial boilers, 

and commercial and domestic combustion units.

Facility with respect to natural gas distribution for purposes of reporting under this subpart and for 

the corresponding subpart A requirements means the collection of all distribution pipelines and meteringregulating 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 meteringregulating 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 onshore petroleum and natural gas production for purposes of reporting 

under this subpart and for the corresponding subpart A requirements means all petroleum or natural gas 

equipment on a single well-pad or associated with a single well-pad and CO2 EOR operations that are 

under common ownership or common control including leased, rented, or contracted activities by an 

onshore petroleum and natural gas production owner or operator and that are located in a single 

hydrocarbon basin as defined in §98.238. Where a person or entity owns or operates more than one well 

in a basin, then all onshore petroleum and natural gas production equipment associated with all wells that 

the person or entity owns or operates in the basin would be considered one facility.

Farm Taps are pressure regulation stations that deliver gas directly from transmission pipelines to 

generally rural customers. In some cases a nearby LDC may handle the billing of the gas to the 

customer(s).

Field means oil and gas fields identified in the United States as defined by the Energy Information 

Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08) (incorporated by reference, 

see §98.7).

Flare, for the purposes of subpart W, means a combustion device, whether at ground level or 

elevated, that uses an open or closed flame to combust waste gases without energy recovery.

Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole basis, that 

is combusted at the flare burner tip.

Flare stack emissions means CO2 and N2O from partial combustion of hydrocarbon gas sent to a 

flare plus CH4 emissions resulting from the incomplete combustion of hydrocarbon gas in flares.

Forced extraction of natural gas liquids means removal of ethane or higher carbon number 

hydrocarbons existing in the vapor phase in natural gas, by removing ethane or heavier hydrocarbons 

derived from natural gas into natural gas liquids by means of a forced extraction process. Forced 

extraction processes include but are not limited to refrigeration, absorption (lean oil), cryogenic expander, 

and combinations of these processes. Forced extraction does not include in and of itself; natural gas 

dehydration, or the collection or gravity separation of water or hydrocarbon liquids from natural gas at 
ambient temperature or heated above ambient temperatures, or the condensation of water or 

hydrocarbon liquids through passive reduction in pressure or temperature, or portable dewpoint 

suppression skids.

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 high-temperature and -

pressure gases produced by combustion applies direct force to a component of the engine, such as 

pistons, turbine blades, or a nozzle. This force moves the component over a distance, generating useful 

mechanical energy. Internal combustion equipment may include gasoline and diesel industrial engines, 

natural gas-fired reciprocating engines, and gas turbines.

Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by 

reducing its temperature to -260 degrees Fahrenheit at atmospheric pressure.

LNG boil-off gas means natural gas in the gaseous phase that vents from LNG storage tanks due to 

ambient heat leakage through the tank insulation and heat energy dissipated in the LNG by internal 

pumps.

Manifolded compressor source means a compressor source (as defined in this section) that is 

manifolded to a common vent that routes gas from multiple compressors.

Manifolded group of compressor sources means a collection of any combination of manifolded 

compressor sources (as defined in this section) that are manifolded to a common vent.

Meter/regulator run means a series of components used in regulating pressure or metering natural 

gas flow, or both, in the natural gas distribution industry segment. At least one meter, at least one 

regulator, or any combination of both on a single run of piping is considered one meter/regulator run.

Metering-regulating station means a station that meters the flowrate, regulates the pressure, or both, 

of natural gas in a natural gas distribution facility. This does not include customer meters, customer 

regulators, or farm taps.

Natural gas means a naturally occurring mixture or process derivative of hydrocarbon and nonhydrocarbon 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 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-to-tubing pressure of one well from the same sub-basin multiplied by the tubing 

pressure for each well in the sub-basin.

Pump means a device used to raise pressure, drive, or increase flow of liquid streams in closed or 

open conduits.

Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon dioxide 

containing light liquids from escaping the inside of a pump case to the atmosphere.

Pump seal emissions means hydrocarbon gas released from the seal face between the pump 

internal chamber and the atmosphere.

Reduced emissions completion means a well completion following hydraulic fracturing where gas 

flowback emissions from the gas outlet of the separator that are otherwise vented are captured, cleaned, 

and routed to the flow line or collection system, re-injected into the well or another well, used as an onsite fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with 

de minimis direct venting to the atmosphere. Short periods of flaring during a reduced emissions 

completion may occur.

Reduced emissions workover means a well workover with hydraulic fracturing (i.e., refracturing) 

where gas flowback emissions from the gas outlet of the separator that are otherwise vented are 

captured, cleaned, and routed to the flow line or collection system, re-injected into the well or another 

well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw 

material would serve, with de minimis direct venting to the atmosphere. Short periods of flaring during a 

reduced emissions workover may occur.

Reservoir means a porous and permeable underground natural formation containing significant 

quantities of hydrocarbon liquids and/or gases.

Residue Gas and Residue Gas Compression mean, respectively, production lease natural gas from 

which gas liquid products and, in some cases, non-hydrocarbon components have been extracted such 

that it meets the specifications set by a pipeline transmission company, and/or a distribution company; 

and the compressors operated by the processing facility, whether inside the processing facility boundary 

fence or outside the fence-line, that deliver the residue gas from the processing facility to a transmission 

pipeline.

Separator means a vessel in which streams of multiple phases are gravity separated into individual 

streams of single phase.

Sub-basin category, for onshore natural gas production, means a subdivision of a basin into the 

unique combination of wells with the surface coordinates within the boundaries of an individual county 

and subsurface completion in one or more of each of the following five formation types: Oil, high 

permeability gas, shale gas, coal seam, or other tight gas reservoir rock. The distinction between high 

permeability gas and tight gas reservoirs shall be designated as follows: High permeability gas reservoirs 

with >0.1 millidarcy permeability, and tight gas reservoirs with ≤0.1 millidarcy permeability. Permeability 

for a reservoir type shall be determined by engineering estimate. Wells that produce only from high 

permeability gas, shale gas, coal seam, or other tight gas reservoir rock are considered gas wells; gas 
wells producing from more than one of these formation types shall be classified into only one type based 

on the formation with the most contribution to production as determined by engineering knowledge. All 

wells that produce hydrocarbon liquids (with or without gas) and do not meet the definition of a gas well in 

this sub-basin category definition are considered to be in the oil formation. All emission sources that 

handle condensate from gas wells in high permeability gas, shale gas, or tight gas reservoir rock 

formations are considered to be in the formation that the gas well belongs to and not in the oil formation.

Transmission-distribution (T-D) transfer station means a metering-regulating station where a local 

distribution company takes part or all of the natural gas from a transmission pipeline and puts it into a 

distribution pipeline.

Transmission pipeline means a Federal Energy Regulatory Commission rate-regulated Interstate 

pipeline, a state rate-regulated Intrastate pipeline, or a pipeline that falls under the “Hinshaw Exemption” 

as referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 (w)(1994).

Tubing diameter groups are defined as follows: Outer diameter less than or equal to 1 inch; outer 

diameter greater than 1 inch and less than 2.375 inch; and outer diameter greater than or equal to 2.375 

inch.

Tubing systems means piping equal to or less than one half inch diameter as per nominal pipe size.

Turbine meter means a flow meter in which a gas or liquid flow rate through the calibrated tube 

spins a turbine from which the spin rate is detected and calibrated to measure the fluid flow rate.

Vented emissions means intentional or designed releases of CH4 or CO2 containing natural gas or 

hydrocarbon gas (not including stationary combustion flue gas), including process designed flow to the 

atmosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas 

used to power equipment (such as pneumatic devices).

Vertical well means a well bore that is primarily vertical but has some unintentional deviation or one 

or more intentional deviations to enter one or more subsurface targets that are off-set horizontally from 

the surface location, intercepting the targets either vertically or at an angle.

Well testing venting and flaring means venting and/or flaring of natural gas at the time the 

production rate of a well is determined for regulatory, commercial, or technical purposes. If well testing is 

conducted immediately after well completion or workover, then it is considered part of well completion or 

workover.

Wildcat well means a well outside known fields or the first well drilled in an oil or gas field where no 

other oil and gas production exists.

[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80590, Dec. 23, 2011; 79 FR 63794, Oct. 24, 2014; 79 FR 

70424, Nov. 25, 2014]
Table W-1A to Subpart W of Part 98—Default Whole Gas Emission Factors for Onshore Petroleum 

and Natural Gas Production

Onshore petroleum and

natural gas production

Emission factor (scf/hour/

component)

Eastern U.S.

Population Emission Factors—All Components, Gas 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

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

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

1For multi-phase flow that includes gas, use the gas service emissions factors.

2Emission Factor is in units of “scf/hour/device.”

3Emission Factor is in units of “scf/hour/pump.”

4Hydrocarbon 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.

6Hydrocarbon liquids less than 20°API are considered “heavy crude.”

[77 FR 51494, Aug. 24, 2012]

Table W-1B to Subpart W of Part 98—Default Average Component Counts for Major Onshore 

Natural Gas Production Equipment

Major equipment Valves Connectors Open-ended lines Pressure relief valves 

Eastern U.S.

Wellheads 8 38 0.5 0 

Separators 1 6 0 0 
Meters/piping 12 45 0 0 

Compressors 12 57 0 0 

In-line heaters 14 65 2 1 

Dehydrators 24 90 2 2 

Western U.S.

Wellheads 11 36 1 0 

Separators 34 106 6 2 

Meters/piping 14 51 1 1 

Compressors 73 179 3 4 

In-line heaters 14 65 2 1 

Dehydrators 24 90 2 2

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

Production Equipment 

Major equipment Valves Flanges Connectors Open-ended lines Other components

Eastern U.S.

Wellhead 5 10 4 0 1

Separator 6 12 10 0 0

Heater-treater 8 12 20 0 0

Header 5 10 4 0 0

Western U.S.

Wellhead 5 10 4 0 1

Separator 6 12 10 0 0

Heater-treater 8 12 20 0 0

Header 5 10 4 0 0

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

Eastern U.S. Western U.S.

Connecticut Alabama

Delaware Alaska

Florida Arizona

Georgia Arkansas
Illinois California

Indiana Colorado

Kentucky Hawaii

Maine Idaho

Maryland Iowa

Massachusetts Kansas

Michigan Louisiana

New Hampshire Minnesota

New Jersey Mississippi

New York Missouri

North Carolina Montana

Ohio Nebraska

Pennsylvania Nevada

Rhode Island New Mexico

South Carolina North Dakota

Tennessee Oklahoma

Vermont Oregon

Virginia South Dakota

West Virginia Texas

Wisconsin Utah

 Washington

 Wyoming

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

Natural Gas Processing

Onshore natural gas processing 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

1Valves include control valves, block valves and regulator valves.

[76 FR 80592, Dec. 23, 2011]

Table W-3 to Subpart W of Part 98—Default Total Hydrocarbon Emission Factors for Onshore 

Natural Gas Transmission Compression

Onshore natural gas transmission compression

Emission factor (scf/hour/

component)

Leaker Emission Factors—Compressor Components, Gas Service

Valve1 14.84

Connector 5.59 

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

1Valves include control valves, block valves and regulator valves.

2Emission Factor is in units of “scf/hour/device.”

[76 FR 80593, Dec. 23, 2011]
Table W-4 to Subpart W of Part 98—Default Total Hydrocarbon Emission Factors for Underground 

Natural Gas Storage

Underground natural gas storage

Emission factor (scf/hour/

component)

Leaker Emission Factors—Storage Station, Gas Service

Valve1 14.84

Connector 5.59

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

Pressure Relief Valve 0.17

Open Ended Line 0.03

Population Emission Factors—Other Components, 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

1Valves include control valves, block valves and regulator valves.

2Emission Factor is in units of “scf/hour/device.”

[76 FR 80593, Dec. 23, 2011]

Table W-5 to Subpart W of Part 98—Default Methane Emission Factors for Liquefied Natural Gas 

(LNG) Storage

LNG storage

Emission factor (scf/hour/

component)

Leaker Emission Factors—LNG Storage Components, LNG Service

Valve 1.19

Pump Seal 4.00

Connector 0.34

Other1 1.77
Population Emission Factors—LNG Storage 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.

2Emission Factor is in units of “scf/hour/device.”

[76 FR80594, Dec. 23, 2011, as amended at 77 FR 51495, Aug. 24, 2012]

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

Equipment

LNG import and export equipment

Emission factor (scf/hour/

component)

Leaker Emission Factors—LNG Terminals Components, LNG Service

Valve 1.19

Pump Seal 4.00

Connector 0.34

Other1 1.77

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.

2Emission Factors is in units of “scf/hour/compressor.”

[76 FR 80594, Dec. 23, 2011]

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

Natural gas distribution

Emission factor 

(scf/hour/

component)

Leaker Emission Factors—Transmission-Distribution 

Transfer Station1 Components, Gas Service

Connector 1.69

Block Valve 0.557 

Control Valve 9.34
Pressure Relief Valve 0.27

Orifice Meter 0.212

Regulator 0.772

Open-ended Line 26.131

Population Emission Factors—Below Grade MeteringRegulating station1 Components, Gas Service2

Below Grade M&R Station, 

Inlet Pressure >300 psig

1.30 Below Grade M&R Station, Inlet 

Pressure 100 to 300 psig

0.20

Below Grade M&R Station, 

Inlet Pressure <100 psig

0.10

Population Emission Factors—Distribution Mains, Gas 

Service3

Unprotected Steel 12.58

Protected Steel 0.35

Plastic 1.13

Cast Iron 27.25

Population Emission Factors—Distribution Services, 

Gas Service4

Unprotected Steel 0.19

Protected Steel 0.02

Plastic 0.001

Copper 0.03

1Excluding customer meters.

2Emission Factor is in units of “scf/hour/station.”

3Emission Factor is in units of “scf/hour/mile.”

4Emission Factor is in units of “scf/hour/number of services.”

[76 FR 80594, Dec. 23, 2011]