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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

WASHINGTON, D.C. 20460 

OFFICE OF 

 AIR AND RADIATION 

Petroleum and Natural Gas Systems (Subpart W) of the Greenhouse Gas Reporting Rule 

Docket: EPA-HQ-OAR-2009-0923 

Title: Equipment-Level Population Emission Factors for Onshore Production 

Summary: This memo discusses the development of major equipment-level population 

component counts and emission factors for the onshore petroleum and natural gas production 

industry segment, as outlined in the Subpart W – Petroleum and Natural Gas Systems - Final 

Rule, 40 CFR Part 98. 

 
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Equipment-Level Population Emission Factors for Onshore Production 

This memo discusses the development of major equipment-level population component counts 

and emission factors for the onshore petroleum and natural gas production industry segment, as 

outlined in the Subpart W – Petroleum and Natural Gas Systems - Final Rule, 40 CFR Part 98. 

This is a response to comments requesting EPA to significantly reduce reporting burden. The 

alternative proposed in today’s final rule does reduce burden significantly while sustaining an 

appropriate quality of data to inform future policy. 

Background 

Comments received on the April 2010 proposed rule identified the burden to count individual 

equipment leak components (flanges, connectors, valves, etc) at well-sites would be a major 

burden, given wells are geographically dispersed over many square miles in a single basin. 

Commenters also proposed the alternative approach whereby each owner-operator could 

perform a limited count of a selected number of wellheads, and create their own emission 

factors for component count per major piece of equipment. 

Alternative Methodologies 

EPA considered the commenters’ proposal, and decided that a method wherein each company 

selects their count, could not be described in a rule in terms that would be consistent across 

different reporters or be validated by EPA. First, EPA evaluated the component count data in the 

EPA/GRI5

 study titled Methane Emissions from the Natural Gas Industry, June 1996, to 

determine how well it was documented, how using it for the rule would reduce burden and how it 

might affect emissions estimation quality. 

EPA also reviewed API #46151, titled Emission Factors for Oil and Gas Production Operations, 

2009 API Compendium2

, the U.S. GHG Inventory3, EPA/Radian4, and EPA/GRI5 for average 

equipment component counts and emissions factors. The 2009 API Compendium provides the 

necessary data to estimate these elements; however, in onshore petroleum and natural gas 

production cases, it references the EPA/GRI study. The U.S. GHG Inventory uses the EPA/GRI 

study for its base year (1992), then extrapolates the equipment activities for future years using 

EIA well counts and production rates. API #4615 provides component emissions factors for 

components in light crude oil (≥ 20 ̊API) and heavy crude oil (< 20 ̊API) service, which are 

referenced in the 2009 API Compendium; however, it does not provide average component 

counts per common oil production equipment (taken from U.S. GHG Inventory, but originally an 

API publication). The 2009 API Compendium and U.S. GHG Inventory both point to the 1999 

EPA/Radian study for the component counts per oil production equipment. 

 

1

 API. Publication #4615, Emission Factors for Oil and Gas Production Operations. January 1995. 2

 API. Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry. August 

2009. 

3

 EPA. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2008. U.S. EPA #430-R-10-006. April 

2010. 

4

 EPA/Radian. Methane Emissions from the Petroleum Industry. 1999. 5

 EPA/GRI. Methane Emissions from the Natural Gas Industry. June 1996. 
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EPA concluded that major equipment component counts with population emission factors satisfy 

the objective of the reporting rule by providing sufficient activity data on actual count of major 

equipment at onshore production wellheads, and with that, emissions information sufficient to 

inform policies while minimizing the cost burden to reporters. 

EPA determined that most sources use EPA/GRI as the basis for natural gas production 

equipment component leak emission factors, and some variation of the information gathered in 

API#4615 for crude oil production equipment component leak emission factors. Therefore the 

source for gas service emission factors was EPA/GRI, and the source for crude oil service 

emission factors was API#4615. 

Basis of Development of Population Emission Factors and Population Counts Tables 

 

As outlined above, today’s final rule allows onshore production reporters to count the major 

equipment by type (e.g., dehydrators, compressors, heaters, wellheads, separators) and apply 

default average component counts based on the primary equipment count. This will provide 

EPA with valuable activity data for equipment counts and will result in significantly less burden 

to reporters than counting each component (valve, flange, open-ended line, connector, pressure 

relief valve, etc.) while ensuring a necessary quality of data to inform future policy. 

Onshore reporters may as an alternative count components individually for a facility and apply 

the appropriate population emission factors; however, if they choose to do so, it must be done for 

the entire onshore petroleum and natural gas production facility. For counting components 

individually, it was determined that tubing systems that are equal to or less than 0.5 inch in 

diameter do not need to be reported. 

The EPA/GRI study notes that regional differences exist in onshore production operations 

between those of the Eastern U.S. (comprising the Atlantic and the Great Lakes region) and the 

Western U.S. (comprising the rest of the country, excluding the Atlantic and the Great Lakes 

region). Equipment differences exist by way of differences in the service, number, type, age, and 

leak detection and repair characteristics in the equipment typically located at production sites 

that are distinct in the two geographical regions. Further, produced gas characteristics differ 

between the two regions. EPA/GRI notes that natural gas produced from wells in the Eastern 

U.S. region has a very low hydrogen sulfide (H2S) and carbon dioxide (CO2) content, making it 

sweeter than produced natural gas from wells in the Western U.S. region. Further, natural gas 

produced from wells in the Easter U.S. region have relatively low moisture content, and low 

production rates per well compared to gas produced in the other regions of the U.S. Thus, few inline heaters and glycol dehydrators exist for gas production in the Eastern region. Thus, 

EPA/GRI performed separate emissions measurement programs for these geographical regions 

and developed separate component counts for major equipment types and emission factors 

characteristic to each of these two distinct geographical regions. Therefore, population emission 

factors and major equipment component counts have been segregated into region-specific values 

for the Eastern and the Western U.S. geographical areas, and are cited in Tables W – 1A thru W1D of the Final Rule. 

 
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EPA/GRI defines the Eastern U.S. as “Atlantic and Great Lakes region” and the Western U.S. as 

the “rest of the country, excluding the Atlantic and Great Lakes region.” For the purposes of the 

GHG Reporting Rule, EPA will define the regions as shown in Table 1. The average component 

counts for major natural gas production equipment that were identified, for both the Eastern and 

the Western U.S. regions, are listed in Table 2A and Table 2B. 

In the EPA/GRI study, component counts for onshore petroleum and natural gas production in 

the Eastern U.S. region were collected based on the Eastern U.S. production fugitives study, with 

the assumption that the component counts for the in-line heaters and glycol dehydrators in the 

Eastern region are identical to those derived for the Western U.S. Component emission factors 

for onshore petroleum and natural gas production in the Eastern U.S. were obtained from a 

measurement program using a combination of screening to identify leaking components and the 

GRI Hi-Flow device to quantify emission rates from leaking components, wherein a total of 192 

individual well-sites were screened using EPA Method 21 at 12 eastern gas production facilities. 

The EPA/GRI data reports that component emission factors were adjusted for an average 

methane content in the produced gas of 78.8% by volume. 

For the Western U.S. region, component emission factors for onshore gas production were based 

on an API/GRO measurement program that made use of the EPA Method 21 protocol, where 

screening and bagging data were collected from 83 gas wells at 4 production sites in the Pacific, 

Mountain, Central and Gulf regions. Component emission factors were adjusted for an average 

methane content in the produced gas of 78.8% by volume. 

For light crude and heavy crude services, Subpart W final rule uses the population emissions 

factors from API Publication No. 4615. The API report developed average emission factors 

using screening data covering over 200,000 components from 24 facilities including light crude 

production, heavy crude production, gas production, gas processing and offshore production. 

Portable devices were used to screen components and mass emission rates were recorded using 

“bagged” methods. The data compiled and the analysis conducted represents the best existing 

measurement study and analysis available publicly for which the emission factors are used in 

subpart W in the onshore production sector. 

EPA used the reported component leak emissions factors from these studies and converted them 

to hourly whole gas leak rates using average methane contents. The default whole gas emission 

factors for the onshore petroleum and natural gas production sector as reported in Subpart W are 

presented in Table 3. 

Concluding Remarks 

EPA evaluated industry comments regarding the burden and alternative methods to estimate 

equipment leaks. EPA evaluated an alternative methodology documented in publicly available 

sources which will result in significant reductions to subpart W compliance burden while 

sustaining an appropriate quality of data to inform future policy. 
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Table 1. Table of Eastern and Western U.S. Designation 

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 2A. Subpart W–Default Average Component Counts For Major 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 
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Table 2B. Subpart W–Default Average Component Counts For Major Crude Oil 

Production Equipment

Equipment Valves Flanges Connecto

rs 

Openended 

Lines 

Other 

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 3 Subpart W–Default Whole Gas Emission Factors For Onshore 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 0.004 

Open-ended Line 0.062 

Pressure Relief Valve 0.041 

Low Continuous Bleed Pneumatic Device Vents2 1.80 

High Continuous Bleed Pneumatic Device Vents2 48.1 

Intermittent Bleed Pneumatic Device Vents2 17.4 

Pneumatic Pumps3 10.5 

Population Emission Factors - All Components, Light Crude 

Service4 

Valve 0.04 

Flange 0.002 

Connector 0.005 

Open-ended Line 0.04 

Pump 0.01 

Other5 0.23 

Population Emission Factors - All Components, Heavy Crude 

Service6 

Valve 0.0004 

Flange 0.0007 

Connector (other) 0.0002 

Open-ended Line 0.004 

Other5 0.002 

Western U.S. 

Population Emission Factors - All Components, Gas Service1

Valve 0.123 
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Connector 0.017 

Open-ended Line 0.032 

Pressure Relief Valve 0.196 

Low Continuous Bleed Pneumatic Device Vents2 1.80 

High Continuous Bleed Pneumatic Device Vents2 48.1 

Intermittent Bleed Pneumatic Device Vents2 17.4 

Pneumatic Pumps3 10.5 

Population Emission Factors - All Components, Light Crude 

Service4

Valve 0.04 

Flange 0.002 

Connector (other) 0.005 

Open-ended Line 0.04 

Pump 0.01 

Other5 0.23 

Population Emission Factors - All Components, Heavy Crude 

Service6

Valve 0.0004 

Flange 0.0007 

Connector (other) 0.0002 

Open-ended Line 0.004 

Other5 0.002 

1

 For multi-phase flow that includes gas, use the gas service emissions factors 

2

 Emission Factor is in units of "scf/hour/device" 

3

 Emission Factor is in units of "scf/hour/pump" 

4

 Hydrocarbon liquids greater than or equal to 20 ̊API are considered "light crude" 5

 ”Others” category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, 

dump lever arms, and vents.

6

 Hydrocarbon liquids less than 20 ̊API are considered "heavy crude"