GREENHOUSE GAS EMISSIONS REPORTING FROM THE 

PETROLEUM AND NATURAL GAS INDUSTRY 

BACKGROUND TECHNICAL SUPPORT DOCUMENT 

The Environmental Protection Agency (EPA) regulations cited in this technical support 

document (TSD) contain legally-binding requirements. In several chapters this TSD offers 

illustrative examples for complying with the minimum requirements indicated by the 

regulations. This is done to provide information that may be helpful for reporters’ 

implementation efforts. Such recommendations are prefaced by the words “may” or “should” 

and are to be considered advisory. They are not required elements of the regulations cited in 

this TSD. Therefore, this document does not substitute for the regulations cited in this TSD, 

nor is it a regulation itself, so it does not impose legally-binding requirements on EPA or the 

regulated community. It may not apply to a particular situation based upon the 

circumstances. Mention of trade names or commercial products does not constitute 

endorsement or recommendation for use. 

While EPA has made every effort to ensure the accuracy of the discussion in this document, 

the obligations of the regulated community are determined by statutes, regulations or other 

legally binding requirements. In the event of a conflict between the discussion in this 

document and any statute or regulation, this document would not be controlling. 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

CLIMATE CHANGE DIVISION 

WASHINGTON DC 
TABLE OF CONTENTS 

1. Segments in the Petroleum and Natural Gas Industry ......................................................... 4 

a. Petroleum Industry............................................................................................................ 4 

b. Natural Gas Industry......................................................................................................... 5 

2. Types of Emissions Sources and GHGs .............................................................................. 6 

3. GHG Emissions from the Petroleum and Natural Gas Industry ......................................... 7 

4. Methodology for Selection of Industry Segments and Emissions Sources Feasible for 

Inclusion in a GHG Reporting Rule.................................................................................. 10 

a. Review of Existing Regulations...................................................................................... 11 

b. Review of Existing Programs and Studies...................................................................... 12 

c. Selection of Emissions Sources for Reporting................................................................ 19 

i. Facility Definition Characterization ............................................................................ 19 

ii. Selection of Potential Emissions Sources for Reporting ............................................ 20 

iii. Address Sources with Large Uncertainties................................................................ 24 

iv. Identify Industry Segments to be Included................................................................ 25 

5. Options for Reporting Threshold....................................................................................... 27 

a. Threshold Analysis.......................................................................................................... 28 

6. Monitoring Method Options .............................................................................................. 33 

a. Review of Existing Relevant Reporting Programs/ Methodologies ............................... 33 

b. Potential Monitoring Methods ........................................................................................ 33 

i. Equipment Leak Detection ......................................................................................... 33 

ii. Emissions Measurement ............................................................................................ 36 

A. Direct Measurement............................................................................................... 36 

B. Engineering Estimation and Emission Factors....................................................... 39 

C. Emission Factors .................................................................................................... 47 

D. Combination of Direct Measurement and Engineering Estimation....................... 47 

c. Leak detection and leaker emission factors .................................................................... 63 

d. Population Count and Emission Factors......................................................................... 63 

e. Method 21 ...................................................................................................................... 64 

f. Portable VOC Detection Instruments for Leak Measurement........................................ 66 

g. Mass Balance for Quantification ................................................................................... 66 

h. Gulf Offshore Activity Data System program (GOADS).............................................. 67 

i. Additional Questions Regarding Potential Monitoring Methods .................................... 67 

i. Source Level Equipment Leak Detection Threshold............................................... 67 

ii. Duration of Equipment Leaks................................................................................. 69 

iii. Equipment Leak and Vented Emissions at Different Operational Modes............. 69 

iv. Natural Gas Composition....................................................................................... 70 

v. Physical Access for Leak Measurement ................................................................. 71 

7. Procedures for Estimating Missing Data ............................................................................ 71 

a. Emissions Measurement Data......................................................................................... 72 

b. Engineering Estimation Data .......................................................................................... 72 

c. Emissions Estimation Data for Storage Tanks and Flares .............................................. 72 

d. Emissions Estimation Data Using Emissions Factors .................................................... 73 

8. QA/QC Requirements........................................................................................................ 73 

Background Technical Support Document – Petroleum and Natural Gas Industry 2 
a. Equipment Maintenance.................................................................................................. 73 

b. Data Management ........................................................................................................... 73 

c. Calculation checks .......................................................................................................... 74 

9. Reporting Procedure ........................................................................................................... 75 

10. Verification of Reported Emissions.................................................................................. 75 

Appendix B: Development of revised estimates for four U.G. GHG Inventory emissions 

Appendix D: Analysis of potential facility definitions for onshore petroleum and natural gas 

Appendix E: Development of multipliers to scale emissions or miscellaneous sources 

Appendix A: Segregation of Emissions Sources using the Decision Process ........................ 76 

sources............................................................................................................................... 84 

Appendix C: Development of threshold analysis ................................................................... 92 

production ....................................................................................................................... 106 

connected to storage tanks .............................................................................................. 110 

Appendix F: Development of leaker emission Factors......................................................... 113 

Appendix G: Development of population emission factors.................................................. 123 

Appendix H: Glossary........................................................................................................... 134 

Appendix I: References......................................................................................................... 141 

Background Technical Support Document – Petroleum and Natural Gas Industry 3 
1. Segments in the Petroleum and Natural Gas Industry 

The U.S. petroleum and natural gas industry encompasses the production of raw gas and 

crude oil from wells to the delivery of processed gas and petroleum products to consumers. 

These segments use energy and emit greenhouse gases (GHG). It is convenient to view the 

industry in the following discrete segments: 

 Petroleum Industry – petroleum production, petroleum transportation, petroleum 

refining, petroleum storage terminals, and 

 Natural Gas Industry –natural gas production, natural gas gathering and boosting 

(natural gas gathering and boosting are not included in this rulemaking), natural gas 

processing, natural gas transmission and underground storage, liquefied natural gas 

(LNG) import and export terminals, and natural gas distribution. 

Each industry segment uses common processes and equipment in its facilities, most of which 

emit GHG. Each of these industry segments is described in further detail below. 

a. Petroleum Industry 

Petroleum Production. Petroleum or crude oil is produced from underground geologic 

formations. In some cases, natural gas is also produced from oil production wells; this gas is 

called associated natural gas. Production may require pumps or compressors for the injection 

of liquids or gas into the well to maintain production pressure. The produced crude oil is 

typically separated from water and gas, injected with chemicals, heated, and temporarily 

stored. GHG emissions from crude oil production result from combustion-related activities, 

and equipment leaks and vented emissions. Equipment counts and GHG-emitting practices 

are related to the number of producing crude oil wells and their production rates. 

As petroleum production matures in a field, the natural reservoir pressure is not sufficient to 

bring the petroleum to the surface. In such cases, enhanced oil recovery (EOR) techniques 

are used to extract oil that otherwise can not be produced using only reservoir pressure. In 

the United States, there are three predominant types of EOR operations currently used; 

thermal EOR, gas injection EOR, and chemical injection EOR. Thermal EOR is carried out 

by injecting steam into the reservoir to reduce the viscosity of heavy petroleum to allow the 

flow of the petroleum in the reservoir and up the production well. Gas injection EOR 

involves injecting of gases, such as natural gas, nitrogen, or carbon dioxide (CO2), to 

decrease the viscosity of the petroleum and push it towards and up the producing well. 

Chemical injection EOR is carried out by injecting surfactants or polymers to improve the 

flow of petroleum and/or enhance a water flood in the reservoir. Emissions sources from 

EOR operations are similar to those in conventional petroleum production fields. However, 

additional emissions occur when CO2 is used for recovery. This specific EOR operation 

requires pumps to inject supercritical CO2 into the reservoir while compressors maintain the 

recycled CO2’s supercritical state. Venting from these two emissions sources is a major 

source of emissions. 

Background Technical Support Document – Petroleum and Natural Gas Industry 4 
Petroleum Transportation. The crude oil stored at production sites is either pumped into 

crude oil transportation pipelines or loaded onto tankers and/or rail freight. Along the supply 

chain crude oil may be stored several times in tanks. These operational practices and storage 

tanks release mainly process GHG emissions. Emissions are related to the amount of crude 

oil transported and the transportation mode. 

Petroleum Refining Crude oil is delivered to refineries where it is temporarily stored 

before being fractionated by distillation and treated. The fractions are reformed or cracked 

and then blended into consumer petroleum products such as gasoline, diesel, aviation fuel, 

kerosene, fuel oil, and asphalt. These processes are energy intensive. Equipment counts and 

GHG gas emitting practices are related to the number and complexity of refineries. Subpart 

Y of the GHG reporting rule (40 CFR Part 98) published in the Federal Register on October 

30, 2009, addresses refineries and hence is not discussed further in this document. 

Petroleum products are then transported via trucks, rail cars, and barges across the supply 

chain network to terminals and finally to end users. 

b. Natural Gas Industry 

Natural Gas Production In natural gas production, wells are used to withdraw raw gas 

from underground formations. Wells must be drilled to access the underground formations, 

and often require natural gas well completion procedures or other practices that vent gas from 

the well depending on the underground formation. The produced raw gas commonly requires 

treatment in the form of separation of gas/liquids, heating, chemical injection, and 

dehydration before being compressed and injected into gathering lines. Combustion 

emissions, equipment leaks, and vented emissions arise from the wells themselves, gathering 

pipelines, and all well-site natural gas treatment processes and related equipment and control 

devices. Determining emissions, equipment counts, and frequency of GHG emitting 

practices is related to the number of producing wellheads and the amount of produced natural 

gas. Further details are provided on the individual sources of GHG emissions in Appendix 

A. 

Natural Gas Processing In the processing facility, natural gas liquids and various other 

constituents from the raw gas are separated, resulting in “pipeline quality” gas that is 

compressed and injected into the transmission pipelines. These separation processes include 

acid gas removal, dehydration, and fractionation. Most equipment and practices have 

associated GHG equipment leaks, energy consumption-related combustion GHG emissions, 

and/or process control related GHG vented emissions. Equipment counts and frequency of 

GHG emitting practices are related to the number and size of gas processing facilities. 

Further details are provided on the individual sources of GHG emissions in Appendix A. 

Natural Gas Transmission and Storage Natural gas transmission involves high pressure, 

large diameter pipelines that transport natural gas from petroleum and natural gas production 

sites and natural gas processing facilities to natural gas distribution pipelines or large volume 

customers such as power plants or chemical plants. Compressor station facilities containing 

Background Technical Support Document – Petroleum and Natural Gas Industry 5 
large reciprocating and / or centrifugal compressors, move the gas throughout the U.S. 

transmission pipeline system. Equipment counts and frequency of GHG emitting practices 

are related to the number and size of compressor stations and the length of transmission 

pipelines. 

Natural gas is also injected and stored in underground formations, or stored as LNG in above 

ground storage tanks during periods of low demand (e.g., spring or fall), and then withdrawn, 

processed, and distributed during periods of high demand (e.g., winter and summer). 

Compressors, pumps, and dehydrators are the primary contributors to emissions from these 

underground and LNG storage facilities. Equipment counts and GHG emitting practices are 

related to the number of storage stations. 

Imported and exported LNG also requires transportation and storage. These processes are 

similar to LNG storage and require compression and cooling processes. GHG emissions in 

this segment are related to the number of LNG import and export terminals and LNG storage 

facilities. Further details are provided on the individual sources of GHG emissions for all of 

transmission and storage in Appendix A. 

Natural Gas Distribution Natural gas distribution pipelines take high-pressure gas from 

the transmission pipelines at “city gate” stations, reduce and regulate the pressure, and 

distribute the gas through primarily underground mains and service lines to individual end 

users. There are also underground regulating vaults between distribution mains and service 

lines. GHG emissions from distribution systems are related to the pipelines, regulating 

stations and vaults, and customer/residential meters. Equipment counts and GHG emitting 

practices can be related to the number of regulating stations and the length of pipelines. 

Further details are provided on the individual sources of GHG emissions in Appendix A. 

2. Types of Emissions Sources and GHGs 

The three main GHGs that are relevant to the petroleum and natural gas industry are methane 

(CH4), carbon dioxide CO2, and nitrous oxide (N2O). All three gases were taken into account 

when developing the threshold analysis. 

Emissions from sources in the petroleum and gas industry can be classified into one of two 

types: 

Combustion-related emissions 

 Combustion-related emissions result from the use of petroleum-derived fuels and 

natural gas as fuel in equipment (e.g., heaters, engines, furnaces, etc.) in the 

petroleum and gas industry. CO2 is the predominant combustion-related emission; 

however, because combustion equipment is less than 100 percent efficient, CH4 and 

other unburned hydrocarbons are emitted. N2O results from both fuel-bound 

nitrogen and nitrogen from atmospheric air. For methodologies to quantify GHG 

emissions from combustion, please refer to Subpart C of the GHG reporting rule 

Background Technical Support Document – Petroleum and Natural Gas Industry 6 
 

(40 CFR Part 98), except for GHG emissions from flaring, onshore production 

stationary and portable combustion GHG emissions, and combustion emissions 

from stationary equipment involved in natural gas distribution. For methodologies 

to quantify combustion emissions from flaring, onshore production stationary and 

portable equipment, and combustion emissions from stationary equipment involved 

in natural gas distribution, please refer to Subpart W. 

Equipment leaks and vented emissions 

The Intergovernmental Panel on Climate Change (IPCC) and the Inventory of U.S. 

GHG Emissions and Sinks1 (henceforth referred to as the U.S. GHG Inventory) 

define fugitive emissions to be both intentional and unintentional emissions from 

systems that extract, process, and deliver fossil fuels. Intentional emissions are 

emissions designed into the equipment or system. For example, reciprocating 

compressor rod packing has a certain level of emissions by design, e.g., there is a 

clearance provided between the packing and the compressor rod for free movement 

of the rod that results in emissions. Also, by design, vent stacks in petroleum and 

natural gas production, natural gas processing, and petroleum refining facilities 

release natural gas to the atmosphere. Unintentional emissions result from wear and 

tear or damage to the equipment. For example, valves result in emissions due to 

wear and tear from continuous use over a period of time. Also, pipelines damaged 

during maintenance operations or corrosion result in unintentional emissions. 

IPCC’s definition is not intuitive since fugitive in itself means unintentional. 

Therefore, this document henceforth distinguishes between fugitive emissions 

(referred to as equipment leaks in the final subpart W) and vented emissions. 

Equipment leaks are those emissions which could not reasonably pass through a 

stack, chimney, vent, or other functionally-equivalent opening. 

Vented emissions are 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). 

3. GHG Emissions from the Petroleum and Natural Gas Industry 

The U.S. GHG Inventory provides estimates of equipment leaks and vented CH4 and CO2 

emissions from all segments of the petroleum and natural gas industry. These estimates are 

based mostly on emissions factors available from two major studies conducted by EPA/Gas 

1

 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006, 

(April 2008), USEPA #430-R-08-005 

Background Technical Support Document – Petroleum and Natural Gas Industry 7 
 

 

Research Institute (EPA/GRI)2 for the natural gas segment and EPA/Radian3 for the 

petroleum segment. These studies were conducted in the early and late 1990s respectively. 

Petroleum Segment 

According to the 2006 U.S. GHG Inventory, EPA estimates that crude oil production 

operations accounted for over 97 percent of total CH4 emissions from the petroleum industry. 

Crude oil transportation activities accounted for less than one half of a percent of total CH4 

emissions from the oil industry. Crude oil refining processes accounted for slightly over two 

percent of total CH4 emissions from the petroleum industry because most of the CH4 in crude 

oil is removed or escapes before the crude oil is delivered to the petroleum refineries. The 

2006 U.S. GHG Inventory for Petroleum Systems currently estimates CO2 emissions from 

only crude oil production operations. Research is underway to include other larger sources 

of CO2 emissions in future inventories. 

Natural Gas Segment 

Emissions from natural gas production accounted for approximately 66 percent of CH4 

emissions and about 25 percent of non-energy CO2 emissions from the natural gas industry in 

2006. Processing facilities accounted for about 6 percent of CH4 emissions and 

approximately 74 percent of non-energy CO2 emissions from the natural gas industry. CH4 

emissions from the natural gas transmission and storage segment accounted for 

approximately 17 percent of emissions, while CO2 emissions from natural gas transmission 

and storage accounted for less than one percent of the non-energy CO2 emissions from the 

natural gas industry. Natural gas distribution segment emissions, which account for 

approximately 10 percent of CH4 emissions from natural gas systems and less than one 

percent of non-energy CO2 emissions, result mainly from equipment leaks from gate stations 

and pipelines. 

Updates to Certain Emissions Sources 

The EPA/GRI study used the best available data and somewhat restricted knowledge of 

industry practices at the time to provide estimates of emissions from each source in the 

various segments of the natural gas industry. In addition, this study was conducted at a time 

when CH4 emissions were not a significant concern in the discussion about GHG emissions. 

Over the years, new data and increased knowledge of industry operations and practices have 

highlighted the fact that emissions estimates from the EPA/GRI study are outdated and 

potentially understated for some emissions sources. The following emissions sources are 

believed to be significantly underestimated in the U.S. GHG Inventory: well venting for 

liquids unloading; gas well venting during well completions; gas well venting during well 

workovers; crude oil and condensate storage tanks; centrifugal compressor wet seal 

degassing venting; scrubber dump valves; onshore combustion; and flaring. 

2

 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry. Prepared by Harrison, M., T. Shires, J. 

Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory, 

Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a. 

3

 EPA (1996) Methane Emissions from the U.S. Petroleum Industry (Draft). Prepared by Radian. U.S. 

Environmental Protection Agency. June 1996. 

Background Technical Support Document – Petroleum and Natural Gas Industry 8 
 

 

The understatement of emissions in the U.S. GHG Inventory were revised using publicly 

available information for all sources and included in the analysis, except crude oil and 

condensate storage tanks and flares, and scrubber dump valves.4

 The revised estimates for 

storage tanks are available in “Analysis of Tank Emissions”, found in the EPA-HQ-OAR2009-0923-0002 docket, but the revised emissions have not been included in this analysis 

(See Appendix C for further details). For further discussion on the inclusion of scrubber 

dump valves in this rulemaking please see the analysis “Scrubber Dump Valves” in EPAHQ-OAR-2009-0923 docket. EPA has limited publicly available information to accurately 

revise estimates on a national level for flaring and scrubber dump valves. For onshore 

combustion emissions, EPA used emissions estimates from the GHG inventory which are 

based on EIA data which EPA believes to be underestimated. Refer to section 4(c)(iii) of the 

TSD for further details. This is explained further below. Appendix B provides a detailed 

discussion on how new estimates were developed for each of the four underestimated 

sources. Table 1 provides a comparison of emissions factors as available from the EPA/GRI 

study and as revised in this document. Table 2 provides a comparison of emissions from 

each segment of the natural gas industry as available in the U.S. GHG Inventory and as 

calculated based on the revised estimates for the four underestimated sources. 

Table 1: Comparison of Emissions Factors from Four Updated Emissions Sources 

Emissions Source Name 

EPA/GRI 

Emissions 

Factor 

Revised 

Emissions 

Factor 

Units 

1) Well venting for liquids 

unloading 1.02 11 CH4 – metric tons/yearwell 

2) Gas well venting during completions 

Conventional well completions 0.02 0.71 CH4 – metric tons/yearcompletion 

Unconventional well completions 0.02 177 CH4 – metric tons/yearcompletion 

3) Gas well venting during well workovers 

Conventional well workovers 0.05 0.05 CH4 – metric tons/yearworkover 

Unconventional well workovers 0.05 177 CH4 – metric tons/yearworkover 

4) Centrifugal compressor wet 

seal degassing venting 0 233 CH4 – metric tons/yearcompressor 

1. Conversion factor: 0.01926 metric tons = 1 

Mcf 

4

 EPA did consider the data available from two new studies, TCEQ (2009) and TERC (2009). However, it was 

found that the data available from the two studies raise several questions regarding the magnitude of emissions 

from tanks and hence were not found appropriate for any further analysis until the issues are satisfactorily 

understood and/ or resolved by the authors and covered parties. 

Background Technical Support Document – Petroleum and Natural Gas Industry 9 
 

Table 2: Comparison of Process Emissions from each Segment of the Natural Gas and 

Petroleum Industries 

Segment Name 

U.S. GHG Inventory1 

Estimate for Year 2006 

(MMTCO2e) 

Revised Estimate for 

Year 2006 

(MMTCO2e) 

Production2 90.2 198.0 

Processing 35.9 39.5 

Transmission and Storage 48.4 52.6 

Distribution 27.3 27.3 

1. U.S. EPA (2008) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006. 

2.Production includes equipment leaks and vented emissions from both the natural gas and petroleum sectors’ onshore and offshore 

facilities. 

After revising the U.S. GHG Inventory emissions estimates for the sources listed in Table 1, 

total equipment leak and vented CH4 and CO2 emissions from the petroleum and natural gas 

industry were 317 million metric tons of CO2 equivalent (MMTCO2e) in 2006. Of this total, 

the natural gas industry emitted 261 MMTCO2e of CH4 and 28.50 MMTCO2e of CO2 in 

2006. Total CH4 and CO2 emissions from the petroleum industry in 2006 were 27.74 

MMTCO2e and 0.29 MMTCO2e respectively. 

4. Methodology for Selection of Industry Segments and Emissions Sources 

Feasible for Inclusion in a GHG Reporting Rule 

It is important to develop criteria to help identify GHG emissions sources in the petroleum 

and natural gas industry most likely to be of interest to policymakers. To identify sources for 

inclusion in a GHG reporting rule, two preliminary steps were taken; 1) review existing 

regulations to identify emissions sources already being regulated, and 2) review existing 

programs and guidance documents to identify a comprehensive list of emissions sources for 

potential inclusion in the proposed rule. 

The first step in determining emissions sources to be included in a GHG reporting rule was to 

review existing regulations that the industry is subject to. Reviewing existing reporting 

requirements highlighted those sources that are currently subject to regulation for other 

pollutants and may be good candidates for addressing GHG emissions. The second step was 

to establish a comprehensive list of emissions sources from the various existing programs 

and guidance documents on GHG emissions reporting. This provided an exhaustive list of 

emissions sources for the purposes of this analysis and avoided the exclusion of any 

emissions sources already being monitored for reporting under other program(s). Both of 

these steps are described below. 

Background Technical Support Document – Petroleum and Natural Gas Industry 10 
 

 

 

 

 

 

 

 

a. Review of Existing Regulations 

The first step was to understand existing regulations and consider adapting elements of the 

existing regulations to a reporting rule for GHG emissions. When the Mandatory Reporting 

Rule development process began, there were three emissions reporting regulations and six 

emissions reduction regulations in place for the petroleum and natural gas industry, including 

one voluntary reporting program included in the Code of Federal Regulations. This table also 

includes EPA’s final GHG reporting rule, which requires certain petroleum and gas facilities 

to report their combustion-related emissions. Table 3 provides a summary of each of these 

nine reporting and reduction regulations. 

Table 3: Summary of Regulations Related to the Petroleum and Natural Gas Industry 

Regulation Type 

Point/ Area/ 

Major/ Mobile 

Source 

Gases 

Covered Segment and Sources 

EPA 40 CFR Part 98 

Final Rule: Mandatory 

Reporting of 

Greenhouse Gases 

Mandatory 

Emissions 

Reporting 

Point, Area, 

Biogenic 

CO2, CH4, 

N2O, HFCs, 

PFCs, , SF6, 

NF3, and HFE 

Annual reporting of GHG 

emissions from direct 

emitters (including 

petroleum and natural gas 

systems) and suppliers of 

industrial GHGs in the 

United States. 

EPA 40 CFR Part 51 – 

Consolidated 

Emissions Reporting 

Emissions 

Reporting 

Point, Area, 

Mobile, 

VOCs, NOx, 

CO, NH3, 

PM10, PM2.5 

All segments of the 

petroleum and natural gas 

industry 

DOE 10 CFR Part 300 

– Voluntary GHG 

Reporting 

Voluntary 

GHG 

Reporting 

Point, Area, 

Mobile 

CO2, CH4, 

N2O, HFCs, 

PFCs, , SF6, 

and CFCs 

All segments of the 

petroleum and natural gas 

industry 

EPA 40 CFR Part 60, 

Subpart KKK 

NSPS2 Point VOCs Onshore processing plants; 

sources include compressor 

stations, dehydration units, 

sweetening units, 

underground storage tanks, 

field gas gathering systems, 

or liquefied natural gas 

units located in the plant 

EPA 40 CFR Part 60, 

Subpart LLL 

NSPS2 Point SO2 Onshore processing plants; 

Sweetening units, and 

sweetening units followed 

by a sulfur recovery unit 

EPA 40 CFR Part 63, 

NESHAP1 

,Subpart 

HHH 

MACT3

 Point (Glycol 

dehydrators, 

natural gas 

transmission and 

storage facilities) 

HAPs Glycol dehydrators 

Background Technical Support Document – Petroleum and Natural Gas Industry 11 
 

 

EPA 40 CFR Part 63, 

NESHAP1

, Subpart 

HH 

MACT3 Major and Area 

(petroleum and 

natural gas 

production, up to 

and including 

processing 

plants) 

HAPs Point Source - Glycol 

dehydrators and tanks in 

petroleum and natural gas 

production; equipment leaks 

at gas processing plants 

Area Source - Triethylene 

glycol (TEG) dehydrators in 

petroleum and natural gas 

production 

EPA 40 CFR Part 63, 

NESHAP1

, –Subpart 

YYYY 

MACT3 Major and Area 

(Stationary 

Combustion 

Turbine) 

HAPs All segments of the 

petroleum and natural gas 

industry 

EPA 40 CFR Part 63, 

NESHAP1

, Subpart 

ZZZZ 

MACT3 Major and Area 

(Reciprocating 

Internal 

Combustion 

Engines) 

HAPs All segments of the 

petroleum and natural gas 

industry 

Notes: 

1

National Emission Standards for Hazardous Air Pollutants 2

New Source Performance Standard 

3

Maximum Allowable Control Technology 

Table 3, indicates that only DOE 10 CFR Part 300 includes the monitoring or reporting of 

CH4 emissions from the petroleum and natural gas industry. However, this program is a 

voluntary reporting program and is not expected to have a comprehensive coverage of CH4 

emissions. Although some of the sources included in the other regulations lead to CH4 

emissions, these emissions are not reported. The MACT regulated sources are subject to Part 

70 permits which require the reporting of all major HAP emission sources, but not GHGs. 

GHG emissions from petroleum and natural gas operations are not systematically monitored 

and reported; therefore these regulations and programs cannot serve as the foundation for a 

GHG emissions reporting rule. 

b. Review of Existing Programs and Studies 

The second step was to review existing monitoring and reporting programs to identify all 

emissions sources that are already monitored under these programs. When the Mandatory 

Reporting Rule development process began, six reporting programs and six guidance 

documents were reviewed. Table 4 summarizes this review, highlighting monitoring points 

identified by the programs and guidance documents. 

Table 4 shows that the different monitoring programs and guidance documents reflect the 

points of monitoring identified in the U.S. GHG Inventory, which are consistent with the 

range of sources covered in the 2006 IPCC Guidelines. Therefore, the U.S. GHG Inventory 

was used to provide the initial list of emissions sources for determining the emissions sources 

that can be potentially included in the rule. 

The preliminary review provided a potential list of sources, but did not yield any definitive 

indication on the emissions sources that were most suitable for potential inclusion in a 

reporting program. A systematic assessment of emissions sources in the petroleum and 

Background Technical Support Document – Petroleum and Natural Gas Industry 12 
natural gas industry was then undertaken to identify the specific emissions sources (e.g., 

equipment or component) for inclusion in a GHG reporting rule. 

Background Technical Support Document – Petroleum and Natural Gas Industry 13 
Table 4: Summary of Program and Guidance Documents on GHG Emissions Monitoring and Reporting 

Reporting Program/Guidance 

Source Category (or Fuel) 

Coverage (Gases or Fuels) 

Points of Monitoring Monitoring Methods a

Methods* 

2006 IPCC Guidelines for National GHG Inventory, Volume 2, Chapter 4 

Petroleum and Gas – all segments 

CH4, non-combustion 

CO2 and other GHG gases 

Oil and natural gas systems fugitive equipment leaks, evaporation losses, venting, flaring, and accidental releases; and all other fugitive emissions at oil and natural gas production, transportation, processing, refining, and distribution facilities from equipment leaks, storage losses, pipeline breaks, well blowouts, land farms, gas migration to the surface around the outside of wellhead casing, surface casing vent bows, biogenic gas formation from tailings ponds and any other gas or vapor releases not specifically accounted for as venting or flaring 

Accounting/ reporting mCompanies choose a baemissions data are availare used as an historic ccompany's emissions arensures data consistency measurement of GHG econcentration and flow IPCC methodologies arfollowing categories: 

- Tier I calculation

estimating emissiemissions based oindustry segment 

- Tier II calculation

estimating emissiemissions based ospecific industry performing a masspecific oil and/o

Tier III calculation-baseemissions involve "rigoprimary type of source equipment leaks) at the appropriate accounting temporary and minor fieThe calculation of emisand facility-specific em

AGA - Greenhouse Gas Emissions Estimation Methodologies, Procedures, and Guidelines 

Gas – Distribution CH4, non-combustion 

CO2 and other GHG gases 

Segment-level counts, equipment discharges (i.e. valves, open-ended lines, vent stacks), and segment 

Equipment or segment ecalculations Tier I, II (IPCC) - facili

Background Technical Support Document – Petroleum and Natural Gas Industry 
for the Natural Gas 

Distribution Sector 

capacities, facility counts and capacities 

Tier III (IPCC) - equipmintentional emissions, pand process/equipment 

API - Compendium of GHG Emissions Estimation Methodologies for the Oil and Gas Industry 

Gas and Petroleum – all segments 

CH4, non-combustion 

CO2 

Equipment discharges (e.g. valves, open-ended lines, vent stacks), vent stacks for equipment types, tank PRV/vents, and facility input 

Equipment or segment ecalculations Tier II (IPCC) - facility Tier III (IPCC) - equipmintentional emissions, ptank level emissions ratemissions rate (BY SEG

California Climate Action All legal entities CH4, non-combustion All activities resulting in Provides references for 

Registry General Reporting (e.g. corporations, CO2 and other GHG indirect and direct emission of calculations Protocol, March 2007 institutions, and 

organizations) registered in California, including petroleum and gas – all segments 

gases GHG gases for the entity 

The CCAR does not spefugitive emissions 

California Mandatory GHG Petroleum – CH4, non-combustion All activities resulting in CH4 Continuous monitoring 

Reporting Program Refineries CO2 and other GHG 

gases 

and CO2 fugitive emissions for 

petroleum refineries 

or process emissions ratCO2 process emissions 

continuous emissions mcalculating fugitive emiflares and other control 

DOE Voluntary Reporting Petroleum and CH4, non-combustion All activities resulting in Direct, site-specific mea

of Greenhouse Gases Gas- All Segments CO2 and other GHG direct and indirect emissions mass balance factors Program (1605(b)) gases of GHG gases for the 

corporation or organization Mass-balance approach

and emission factors thawidely reviewed and adstandards-setting organiMass-balance approachand other emission facto

Background Technical Support Document – Petroleum and Natural Gas Industry 
Mass balance approach 

and default emissions fa

EU ETS 1st and 2nd 

Reporting Period 

Petroleum – Refining 

Non-combustion CO2 Hydrogen production Engineering calculation

Operators may calculate balance approach 

INGAA - GHG Emissions Gas - CH4, non-combustion Segment-level counts, Equipment or segment e

Estimation Guidelines for Transmission/Stora CO2 equipment discharges (i.e. 

Natural Gas Transmission ge valves, open-ended lines, vent Tier I (IPCC)- segment and Storage, Volume 1 stacks), and segment 

capacities, facility counts and capacities 

intentional and unintentTier II - equipment levereleases Tier II (IPCC) – facility rates for unintentional lEngineering calculation 

- Pig traps - Overhauls - Flaring 

IPIECA - Petroleum Petroleum and Gas CH4, non-combustion Refers to API Compendium Tiers I, II, and III (IPCC

Industry Guidelines for – all segments CO2 and other GHG points of monitoring: methods for all fugitive Reporting GHG Emissions gases Equipment discharges (e.g. 

valves, open-ended lines, vent stacks), vent stacks for equipment types, tank PRV/vents, and facility input 

the oil and gas industry 

New Mexico GHG Mandatory Emissions Inventory 

Petroleum refineries 

CO2 reporting starts 

2008 , CH4 reporting 

starts 2010 

Equipment discharges (e.g. valves, pump seals, connectors, and flanges) 

- 2009 reporting pr

in 10/2008 

Background Technical Support Document – Petroleum and Natural Gas Industry 
The Climate Registry All legal entities CH4, non-combustion All activities resulting in Continuous monitoring m

(General Reporting (e.g. CO2 and other GHG emission of GHG gases for the or process emissions rates Protocol for the Voluntary corporations, gases entity Reporting Program), 2007 institutions, and 

organizations) including petroleum and gas – all segments 

Measurement-based meth(continuous, flow meter) aconcentration in the flue gmethodologies involve the based on activity data and 

Western Regional Air Petroleum and CH4, non-combustion All activities resulting in Provides quantification m

Partnership (WRAP) Gas – all 

segments 

CO2 and other GHG gases 

emission of GHG gases for the entity 

sectors of the petroleum athe rule. Quantification mengineering equation; howequations in several cases rates, such as from well ve

World Resources Institute/ World Business Council for Sustainable Development GHG Protocol Corporate Standard, Revised Edition 2003 

Organizations with operations that result in GHG (GHG) emissions e.g. corporations (primarily), universities, NGOs, and government agencies. This includes the oil and gas industry 

CH4, non-combustion 

CO2 and other GHG gases 

All activities resulting in direct and indirect emission of GHG gases for the corporation or organization 

Provides continuous moniequipment or process emiCompanies need to choosverifiable emissions data areasons for choosing the yemissions are used as an hthe company's emissions aEmissions in the base yeareflect a change in the strureflect a change in the accThis ensures data consistemeasurement of GHG emconcentration and flow raCalculation-based methodemissions involve the calcon activity data and emiss

Background Technical Support Document – Petroleum and Natural Gas Industry 
i. EPA 2007 Cooperative Agreement with University of Texas (UT) Austin to Update GRI/ 

EPA Study Estimated Emission Factors 

In the past decade, there has been growing interest in better understanding CH4 emissions 

sources from the petroleum and natural gas industry. As mentioned above, the seminal 

study, upon which much of the current knowledge on CH4 emission factors is based, is 

Methane Emissions from the Natural Gas Industry (GRI/EPA 1996). In the United States, the 

GRI/EPA Study serves as the basis for most CH4 estimates from natural gas systems in 

EPA’s Inventory of U.S. GHG Emissions and Sinks, EPA’s Natural Gas STAR Program, 

Methane to Markets International Program, State Inventories, the American Petroleum 

Institute (API) Compendium, a transmission and distribution protocol by the Interstate 

Natural Gas Association of America (INGAA), as well as all of the organizations that 

reference these documents and programs in their individual work. The GRI/EPA Study was 

also evaluated for its relevance for a separate effort to develop a transmission and distribution 

GHG accounting protocol by the California Climate Action Registry. Internationally, the 

GRI/EPA Study is the source for many of the emission factors included in the 

Intergovernmental Panel on Climate Change Guidelines for National Greenhouse Gas 

Inventories. 

Although the GRI/EPA Study has been the cornerstone for estimating CH4 emissions from 

the natural gas industry to date, the data on which the study is based are now over a decade 

and a half old and in some cases (e.g., wells, compressors), not always reflective of current 

conditions in the United States. In recognition of the fact that existing methane emission 

factors were becoming quickly outdated, in 2007 EPA funded a 4-year cooperative 

agreement with UT Austin to support research and, as appropriate, measurement studies to 

update selected CH4 emission factors from the 1996 GRI study. The cooperative agreement 

identified a small set of 11 priority sources in different industry segments on which to focus 

emission factor development. With the limited budget available, as of mid-2010, the project 

has begun work on updating emission factors for reciprocating and centrifugal compressors 

only. Specifically, the project team has initiated preliminary measurement studies at 

compressor stations at natural gas transmission and storage facilities owned by two 

companies. Now approaching its final year, the project team is currently evaluating the most 

efficient use of the remaining resources; specifically whether to undertake additional 

measurements on transmission and storage facilities to gain the most robust data set possible, 

or to use remaining funds on another source of emissions in the production, processing, 

transmission, or distribution segments. 

The UT Austin cooperative agreement was initiated to develop representative national 

emission factors- it was not designed, like the GHG reporting rule, to comprehensively 

collect actual GHG emissions data to support a range of future climate policies. To meet the 

goals of the reporting rule, for larger sources, such as compressors, it is critical that EPA 

collect actual emissions data in order to understand trends and also connect emissions to 

specific equipment and types of operations. For example, if there is a trend regarding the 

maintenance of rod packing over time, this information would not be obtained through a 

static data set based on national compressor-level emission factors. . 

Background Technical Support Document – Petroleum and Natural Gas Industry 18 
 

Further, the limited budget available for the UT Austin study will not allow for emissions 

information from a large number of sources; the GHG reporting rule will be collecting 

comprehensive actual emissions data and other relevant information from major sources 

across the United States petroleum and natural gas industry for all U.S. facilities over 25,000 

mtCO2e. In addition, the GHG reporting rule will collect applicable information (e.g., 

equipment component counts and operational data) needed to verify the reported GHG data 

and support future climate policy analysis. 

c. Selection of Emissions Sources for Reporting 

When identifying emissions sources for inclusion in a GHG reporting rule, two questions 

need addressing. The first is defining a facility. In other words, what physically constitutes a 

facility? The second is determining which sources of emissions should a facility report? 

Including or excluding sources from a GHG reporting rule without knowing the definition of 

a facility is difficult. Therefore, both the facility definition and emissions source inclusion (or 

exclusion) were reviewed to arrive at a conclusion. 

i. Facility Definition Characterization 

Typically, the various regulations under the Clean Air Act (CAA) define a facility as a group 

of emissions sources all located in a contiguous area and under the common control of the 

same person (or persons). This definition can be easily applied to offshore petroleum and 

natural production, onshore natural gas processing, onshore natural gas transmission 

compression, underground natural gas storage, and LNG import and export equipment since 

the operations are all located in a clearly defined boundary. However, as discussed further 

below, this definition does not as directly lend itself to all industry segments, such as onshore 

petroleum and natural gas production, natural gas distribution, and petroleum transportation 

sectors. 

Onshore petroleum and natural gas production operations can be very diverse in 

arrangement. Sometimes crude oil and natural gas producing wellheads are far apart with 

individual equipment at each wellhead. Alternatively, several wells in close proximity may 

be connected to common pieces of equipment. Whether wells are connected to common 

equipment or individual equipment depends on factors such as distance between wells, 

production rate, and ownership and royalty payment. New well drilling techniques such as 

horizontal and directional drilling allow for multiple wellheads to be located at a single 

location (or pad) from where they are drilled to connect to different zones in the same 

reservoir. Therefore, the conventional facility definition of a “contiguous area” under a 

common owner/ operator cannot be easily applied to the onshore petroleum and natural gas 

production industry segment. Refer to Section 4(c)(iv) in the TSD for a more detailed 

discussion of the facility definition for onshore petroleum and natural gas production. 

An alternative to a physical facility definition is the use of a corporate level reporter 

definition. In such a case the corporation that owns or operates petroleum and natural gas 

production operations could be required to report. Here the threshold for reporting could 

require that an individual corporation sum up GHG emissions from all the fields it is 

Background Technical Support Document – Petroleum and Natural Gas Industry 19 
operating in and determine if its total emissions surpass the threshold. See Appendix D for 

further discussion of this issue. 

In the natural gas distribution segment the meters and regulators in the distribution segment 

are primarily located at small stations or underground vaults distributed over large urban or 

suburban regions. Individually defining each station or vault as a facility is impractical owing 

to the size and expected magnitude of emissions from single stations. However, a logical 

grouping of distribution equipment exists at the regulated local distribution company level. 

The precedent for reporting at this type of facility already exists under the Pipeline and 

Hazardous Materials Safety Administration (PHMSA) requirements under CFR Title 49 

Section 191.11. Refer to Section 4(c)(iv) of the TSD for a more detailed discussion of the 

definition for natural gas distribution. As explained in the Response to Comments, the 

PHMSA regulations primarily relate to pipeline safety provisions, and are unrelated to 

information EPA seeks to collect under this rule. 

ii. Selection of Potential Emissions Sources for Reporting 

Given that there are over 100 emissions sources1 in the petroleum and natural gas industry, it 

is important to target sources which contribute significantly to the total national emissions for 

the industry. This avoids an excessive reporting burden on the industry, but at the same time 

enables maximum coverage for emissions reporting. The selection of emissions sources for 

potential inclusion in the proposed rulemaking was conducted in three steps. 

Step 1: Characterize Emissions Sources 

The U.S. GHG Inventory was used as the complete list of sources under consideration for 

inclusion in a reporting rule. The U.S. GHG Inventory was also used to provide all relevant 

emissions source characteristics such as type, number of sources across industry segments, 

geographic location, emissions per unit of output, total national emissions from each 

emissions source, and frequency of emissions. Also, information included in the U.S. GHG 

Inventory and the Natural Gas STAR Program technical studies were used to identify the 

different monitoring methods that are considered the best for each emissions source. If there 

are several monitoring methods for the same source, with equivalent capabilities, then the 

one with lower economic burden was considered in the analysis. 

Step 2: Identify Selection Criteria and Develop Decision Tree for Selection 

There are several factors that impact the decision on whether an emissions source should be 

included for reporting. A discussion of the factors follows below. 

	 Significant Contribution to U.S. GHG Inventory – Emissions sources that contribute 

significant emissions can be considered for potential inclusion in the rule, since they 

increase the coverage of emissions reporting. Typically, in petroleum and natural gas 

facilities, 80 percent or more of the facility emissions are reported to be from 

approximately 10 percent of the emissions sources. This is a good benchmark to ensure 

the adequate coverage of emissions while reducing the number of emissions sources 

required for reporting thus, keeping the reporting burden to a minimum. Emissions 

sources in each segment of the natural gas and petroleum industry can be sorted into two 

Background Technical Support Document – Petroleum and Natural Gas Industry 20 
main categories: (1) top sources contributing to 80 percent of the emissions from the 

segment, and (2) the remaining sources contributing to the remaining 20 percent of the 

emissions from that particular segment. This can be easily achieved by determining the 

emissions contribution of each emissions source to the segment it belongs to, listing the 

emissions sources in a descending order, and identifying all the sources at the top that 

contribute to 80 percent of the emissions. Appendix A provides a listing of all emissions 

sources in the U.S. GHG Inventory and a breakdown of the top emissions sources by 

industry segment. 

	 Type of Emissions – The magnitude of emissions per unit or piece of equipment typically 

depends on the type of emissions. Vented emissions per unit source are usually much 

higher than equipment leak emissions from a unit source. For example, emissions from 

compressor blowdown venting for one compressor are much higher than equipment leak 

emissions from any one unit component source on the compressor. The burden from 

covering emissions reporting from each unit source (i.e. dollar per ton of emissions 

reported) is typically much lower in the case of venting sources in comparison to 

equipment leak emission sources when the same monitoring method is used. Therefore, 

vented sources could be treated separately from equipment leak sources for assessment of 

monitoring requirements. 

	 Best Practice Monitoring Method(s) – Depending on the types of monitoring methods 

typically used, a source may or may not be a potential for emissions reporting. There are 

four types of monitoring methods as follows: 

o	 Continuous monitoring – refers to cases where technologies are available that 

continuously monitor either the emissions from a source or a related parameter that 

can be used in estimating emissions. For example, continuous monitoring meters 

can determine the flow rate and in line analyzers can determine the composition of 

emissions from a process vent. 

o	 Periodic monitoring – refers to monitoring at periodic intervals to determine 

emissions from sources. For example, leak detection and measurement equipment 

can be used on a recurring basis to identify and measure an emissions rate from 

equipment. 

o	 Engineering calculations – refers to estimation of emissions using engineering 

parameters. For example, emissions from a vessel emergency release can be 

estimated by calculating the volume of the emitting vessel. 

o	 Emissions factors – refers to utilizing an existing emissions rate for a given source 

and multiplying it by the relevant activity data to estimate emissions. For example, 

emissions per equipment unit per year can be multiplied by the number of pieces of 

equipment in a facility to estimate annual emissions from that equipment for the 

facility. 

	 Accessibility of emissions sources – Not all emissions sources are directly accessible 

physically for emissions detection and/or measurement. For example, connectors on 

pipelines, pressure relief valves on equipment, and vents on storage tanks may be out of 

direct physical reach and could require the use of bucket trucks or scaffolding to access 

Background Technical Support Document – Petroleum and Natural Gas Industry 21 
them. In such cases requiring emissions detection and measurement may not always be 

feasible such as with leak detection equipment that requires the operator to be in close 

physical proximity to the equipment. Also, such requirements could pose health and 

safety hazards or lead to large cost burden. The accessibility of emissions sources was 

considered when addressing monitoring requirements and determining the type of leak 

detection equipment allowed under Subpart W. 

	 Geographical dispersion of emissions sources – The cost burden for detecting and 

measuring emissions will largely depend on the distance between various sources. 

Monitoring methods will have to be chosen considering the dispersion of emissions 

sources. 

	 Applicability of Population or Leaker Emission factors – When the total emissions from 

all leaking sources of the same type are divided by the total count of that source type then 

the resultant factor is referred to as population emissions factor. When the total emissions 

from all leaking sources of the same type are divided by the total count of leaking sources 

for that source type then the resultant factor is referred to as leaker emissions factor. For 

example, in an emissions detection and measurement study, if 10 out of 100 valves in the 

facility are found leaking then: 

o	 the total emissions from the 10 valves divided by 100 is referred to as 

population emissions factor 

o	 the total emissions from the 10 valves divided by 10 is referred to as leaker 

emissions factor 

Requiring emissions leak detection and application of a corresponding emissions factor 

results in lower reporting burden as compared to conducting actual measurements. 

Furthermore, the use of leaker emissions factors provides an estimate of “actual” 

emissions as opposed to the use of population emissions factor where the emissions from 

each facility can only be a "potential” of emissions. 

Based on the criteria outlined above, a decision process was developed to identify the 

potential sources that could be included in the reporting rule. Error! Reference source not 

found. shows the resulting decision tree that includes these criteria and supported the 

decision-making process. The decision process provided in Error! Reference source not 

found. was applied to each emissions source in the natural gas segment of the U.S. GHG 

Inventory. The onshore petroleum production segment has emissions sources that either are 

equivalent to their counterparts in the natural gas onshore production segment or fall in the 

20 percent exclusion category. Only CH4 emissions from the petroleum segment were taken 

into consideration for this exercise given that, for most sources, non-combustion CO2 

emissions from the petroleum segment are negligible in comparison to CH4 emissions from 

the same sources. The exception to these are flares and acid gas recovery units in EOR 

operations that have large CO2 emission, but EPA does not have any emissions estimates for 

these source (see Section 3 and (4)(c)(iv) of the TSD). Appendix A summarizes the results of 

this analysis and provides guidance on the feasibility of each of the monitoring options 

discussed previously. 

Background Technical Support Document – Petroleum and Natural Gas Industry 22 
 

 

 

Figure 1: Decision Process for Emissions Source Selection 

Is the emission source an equipment leak? 

Is source accessible for 

equipment leak detection? 

Use equipment leak 

detection and leaker 

emission factors to 

estimate emissions 

Use population 

emissions factor 

and source count 

to estimate 

emissions 

No 

No 

Yes 

No 

Is vented emissions 

source geographically 

dispersed? 

Does credible 

emission factor 

exist? Yes 

Use population 

emissions factor and 

source count to 

estimate emissions 

Yes 

Use 

Engineering 

Estimation 

method 

No 

Does engineering 

estimation methodology 

exist? 

No 

Use 

Engineering 

Estimation 

method 

Yes 

Use continuous 

or period 

monitoring 

No 

Is source contributing to top 80% of 

emissions from each segment? 

Yes 

No 

Potentially exclude 

Is the equipment leak 

emissions source 

geographically 

dispersed? 

Yes 

Yes 

Background Technical Support Document – Petroleum and Natural Gas Industry 23 
 

 

 

iii. Address Sources with Large Uncertainties 

As described in Section 3 of the TSD, the petroleum and natural gas industry inventories are 

primarily based on the EPA/GRI 1996 Study, however the emissions for several sources in 

the EPA/GRI study do not correctly reflect today’s operational practices. In some cases, 

comprehensive and sufficient information is not publicly available to revise the national 

Inventory estimates. In cases where public data are available, it is often incomplete and does 

not represent the industry at a national level. 

Over the years, new data and increased knowledge of industry operations and practices have 

highlighted the fact that emissions estimates for certain sources are understated in the US 

Inventory 

o Condensate and petroleum storage tanks 

o Natural gas well workovers 

o Natural gas well completions 

o Natural gas well liquid unloading 

o Centrifugal compressor wet seals 

o Flares 

o Scrubber dump valve emissions through tanks 

o Onshore combustion emissions 

The decision tree was not necessarily ideal for the sources listed above because they are 

known to be underestimated in current inventories. Therefore, after careful evaluation, EPA 

determined that these are significant emission sources that should be included in a 

comprehensive petroleum and natural gas systems GHG reporting rule. The following 

emissions sources are believed to be significantly underestimated in the U.S. GHG Inventory: 

well venting for liquids unloading; gas well venting during well completions; gas well 

venting during well workovers; crude oil and condensate storage tanks; centrifugal 

compressor wet seal degassing venting; scrubber dump valves; onshore combustion; and 

flaring. Refer to Appendix B for a detailed discussion on how new estimates were developed 

for each of the underestimated sources; natural gas well workovers, natural gas well 

completions, and natural gas well blowdowns. For centrifugal wet seals, EPA used an 

emission factor from a presentation given at the 24th World Gas Conference.5 

In addition, the U.S. GHG Inventory includes reasonable estimation of CH4 and CO2 

combustion emissions from natural gas engines and turbines (except in onshore production), 

as well as petroleum refineries. Emissions from these sources were not considered further 

here because methods for calculating and reporting emissions from these sources are 

addressed in the background technical support documents for Stationary Combustion 

5

 The Bylin, Carey (EPA) study reported wet seal degassing emission measurements from 48 centrifugal compressors. Five 

centrifugal compressors were found not emitting while, the remaining 43 emitted 14,860 thousand cubic meters per year. 

Twenty-three cubic feet per minute was determined by dividing the 14,860 by the 43 centrifugal compressors. Bylin, 

Carey (EPA), et. al (2009) Methane’s Role in Promoting Sustainable Development in Oil and Natural Gas 

Industry. <presented at 24th World Gas Conference> 

Background Technical Support Document – Petroleum and Natural Gas Industry 24 
described in Subpart C and Petroleum Refineries described in Subpart Y of the of the final 

GHG reporting rule (40 CFR Part 98) respectively. 

Onshore Combustion Emissions: 

The EPA estimates onshore production combustions emissions in its national GHG 

inventory. However, there are two challenges with the way these data are collected that make 

it difficult to use this data to support potential future climate policies. First, combustionrelated emissions are reported in the national inventory at a fairly high level of aggregation, 

making it difficult to discern facility-level emissions. Second, there are concerns that this 

aggregate estimate is underestimating the total emissions from this source. The National 

Inventory of U.S. GHG Emissions and Sinks uses the “lease and plant” fuel consumption 

data as reported by the Energy Information Administration (EIA) as activity data to apply an 

emissions factor to estimate emissions. However, EIA estimates the lease and plant volume 

using data available from individual petroleum and natural gas producing States. The States 

in turn require only the voluntary reporting of this data from petroleum and natural gas 

producing operators raising questions as to whether the national data are complete. In 

addition, this estimate may not include all of the combustion emissions resulting from 

contracted and/ or portable combustion equipment. Given the high level of aggregation of 

this data and the potential omissions of some fuel consumption in onshore production in the 

National Inventory, this source type would be valuable to include in the rule for a more 

complete picture of facility-related emissions from onshore production facilities. 

iv. Identify Industry Segments to be Included 

Based on the understanding of facility definitions for each segment of the petroleum and 

natural gas industry and the identification of potential sources for inclusion in a GHG 

reporting rule, the industry segments could be defined as follows: 

Onshore Petroleum and Natural Gas Production Segment – Onshore petroleum and 

natural gas production is an important segment for inclusion in a GHG reporting 

program, due to its relatively large share of emissions. However, in order to include 

this segment, it is important to clearly articulate how to define the facility and identify 

who is the reporter. Onshore production operations are a challenge for emissions 

reporting using the conventional facility definition of a “contiguous area” under a 

common owner/ operator. EPA evaluated possible options for defining a facility for 

onshore petroleum and natural gas production in order to ensure that the reporting 

delineation is clear, to avoid double counting, and ensure appropriate emissions 

coverage. One potential option considered was to define a facility for this segment as 

all petroleum or natural gas equipment on a well pad or associated with a well pad 

and CO2 EOR operations that are under common ownership or common control and 

that are located in a single hydrocarbon basin as defined in 40 CRF Part 98.238. This 

includes leased, rented, or contracted activities by an onshore petroleum and natural 

gas production owner or operator. 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. In this case, the operator would be the 

Background Technical Support Document – Petroleum and Natural Gas Industry 25 
company or corporation holding the required permit for drilling or operating. If the 

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 may also be 

considered the owner or operator. Operational boundaries and basin demarcations are 

clearly defined and are widely known, and reporting at this level would provide the 

necessary coverage of GHG emissions to inform policy. This facility definition for 

onshore petroleum and natural gas production will result in 85% GHG emissions 

coverage of this industry segment. 

EPA reviewed other possible alternatives to define a production facility such as at the 

field level. In such cases, the company (or corporation) operating in the field would 

report emissions. EPA analyzed this option and found that such a field level definition 

would result in a larger number of reporters and in lower emissions coverage than 

basin level reporting, since fields are typically a segment of a basin. 

In addition to basin and field level reporting, one additional alternative is identifying 

a facility as an individual well pad, including all stationary and portable equipment 

operating in conjunction with that well, including drilling rigs with their ancillary 

equipment, gas/liquid separators, compressors, gas dehydrators, crude petroleum 

heater-treaters, gas powered pneumatic instruments and pumps, electrical generators, 

steam boilers and crude oil and gas liquids stock tanks. In reviewing this option, EPA 

found that defining a facility as a single wellhead would significantly increase the 

number of reporters to a program, lower emissions coverage, and potentially raise 

implementation issues. For a complete discussion of the threshold analysis and 

estimated emissions coverage for each of the onshore petroleum and natural gas 

production facility options considered, refer to Section 5 of the TSD. 

 Offshore Petroleum and Natural Gas Production Segment – All of the production 

activities offshore take place on platforms. These platforms can be grouped into two 

main categories; wellhead platforms and processing platforms. Wellhead platforms 

consist of crude oil and/ or natural gas producing wellheads that are connected to 

processing platforms or send the hydrocarbons onshore. Processing platforms consist 

of wellheads as well as processing equipment such as separators and dehydrators, in 

addition to compressors. All platforms are within a confined area and can be 

distinctly identified as a facility. Since all sources are within a small area on and 

around the platform, all sources of emissions on or associated with offshore platforms 

could be monitored and reported. 

 Onshore Natural Gas Processing Segment –Processing plants process the gas 

received from production and/ or gathering or boosting segments to remove hydrogen 

sulfide (H2S) and/ or CO2 from the natural gas, if any, separate the higher molecular 

weight hydrocarbons (ethane, propane, butane, pentanes, etc.) from the natural gas 

and compress the natural gas to be injected into the onshore natural gas transmission 

segment. Natural gas processing facilities have a well defined boundary within which 

all processes take place. All emissions sources in processing facilities could be 

monitored and included in a GHG reporting rule. 

Background Technical Support Document – Petroleum and Natural Gas Industry 26 
 Onshore Natural Gas Transmission Compression – Transmission compressor stations 

are the largest source of emissions on transmission pipelines and meet the 

conventional definition of a facility. Given the relatively large share of emissions 

from the compressor station, as compared to the pipeline segments between 

transmission compressor stations, the station may be the most logical place to capture 

emissions from this segment. 

. 

 Underground Natural Gas Storage, LNG Storage, and LNG Import and Export 

Segments – All operations in an underground natural gas storage facility (except 

wellheads), LNG storage facility, and LNG import and export facilities are confined 

within defined boundaries. In the case of underground natural gas storage facilities, 

the wellheads are within short distances of the main compressor station such that it is 

feasible to monitor them along with the stations themselves. All three segments could 

be included in a GHG reporting rule. 

 Natural Gas Distribution Segment – The distribution segment metering and regulator 

above ground stations and below ground vaults are identifiable as facilities. However, 

the magnitude of emissions from a single station or vault may not be significant, 

which would result in minimal coverage of emissions from this segment. Multiple 

stations or vaults collectively contribute to a significant share of emissions from the 

natural gas industry nationally, but they may not be considered one facility because 

they are not contiguous and there is no logical grouping unless the entire system is 

considered. 

Another option for including distribution sector is adapting the facility definition 

from Subpart NN, Suppliers of Natural Gas and Natural Gas Liquids, of the MRR 

which defines a local distribution company (LDC) as a facility. In this case, the 

definition of natural gas distribution would be the distribution pipelines, metering and 

regulator stations and vaults that are operated by a Local Distribution Company 

(LDC) that is regulated as a separate operating company by a public utility 

commission or that are operated as an independent municipally-owned distribution 

system This facility definition provides clear reporting delineation because the 

equipment that they operate is clearly known, the ownership is clear to one company, 

and reporting at this level is consistent with the final MRR as well as other existing 

data reporting mechanisms. Additionally, this aggregation of equipment will include 

all the significant sources of emissions from the segment. 

 Petroleum Transportation Segment – All the sources in the petroleum transportation 

segment were excluded as a result of the decision process. Hence, this segment may 

not be amenable to inclusion in a reporting program. 

5. Options for Reporting Threshold 

For each segment in the petroleum and natural gas industry identified above as amenable to a 

reporting program, four thresholds were considered for emissions reporting as applicable to 

Background Technical Support Document – Petroleum and Natural Gas Industry 27 
an individual facility; 1,000 metric tons of CO2 equivalent (MtCO2e) per year, 10,000 

MtCO2e, 25,000 MtCO2e, and 100,000 MtCO2e. A threshold analysis was then conducted on 

each segment to determine which level of threshold was most suitable for each industry 

segment. CH4, CO2, and N2O emissions from each segment were included in the threshold 

analysis. 

a. Threshold Analysis 

For each segment, a threshold analysis was conducted to determine how many of the 

facilities in the segment exceed the various reporting thresholds, and the total emissions from 

these impacted facilities. This analysis was conducted considering equipment leak and vented 

CH4 and CO2 emissions, and incremental combustion CH4, CO2, and N2O emissions. 

Incremental combustion emissions are those combustion emissions from facilities not already 

reported under Subpart C of the 40 CFR Part 98, but are required to be reported because the 

combined process emissions from Subpar W plus combustion emissions exceed the 25,000 

metric tons CO2e reporting threshold. The equipment leak and vented emissions estimates 

available from the U.S. GHG Inventory were used in the analysis. However, the emissions 

estimates for four sources, well venting for liquids unloading, gas well venting during well 

completions, gas well venting during well workovers, and centrifugal compressor wet seal 

degassing venting from the U.S. GHG Inventory were replaced with revised estimates 

developed as described in Appendix B. Centrifugal compressor emissions were revised using 

centrifugal compressor activity data from the U.S. Inventory and an emission factor from the 

24th World Gas Conference5. Incremental combustion emissions were estimated using gas 

engine methane emissions factors available from the GRI study, back calculating the natural 

gas consumptions in engines, and finally applying a CO2 emissions factor to the natural gas 

consumed as fuel. Nitrous Oxide emissions were also calculated similarly. In the case of 

offshore petroleum and natural gas production platforms combustion emissions are already 

available from the GOADS 2000 study analysis and hence were directly used for the 

threshold analysis. It must be noted that the threshold analysis for 40 CFR Part 98, Subpart 

W includes all equipment leak and vented emissions, but only incremental combustion 

emissions. Due to these reasons the total emissions from the threshold analysis does not 

necessarily match the U.S. GHG Inventory for all segments of the petroleum and natural gas 

industry. A detailed discussion on the threshold analysis is available in Appendix C. 

The general rationale for selecting a reporting threshold could be to identify a level at which 

the incremental emissions reporting between thresholds is the highest for the lowest 

incremental increase in number of facilities reporting between the same thresholds. This 

would ensure maximum emissions reporting coverage with minimal burden on the industry. 

For example, for onshore production the emissions reporting coverage is 74 percent and the 

corresponding reporting facilities coverage is 2 percent for a threshold of 100,000 MtCO2e 

per year. The incremental emissions and facilities coverage is 11 and 2 percent (85 percent 

minus 74 percent and 4 percent minus 2 percent), respectively, for a 25,000 MtCO2e per year 

threshold. However, at the next reporting threshold level of 10,000 MtCO2e per year the 

incremental emissions and entities coverage is 6 and 5 percent, respectively. It can be seen 

that the incremental coverage of emissions decreases but the coverage of facilities increases. 

Background Technical Support Document – Petroleum and Natural Gas Industry 28 
Table 5 provides the details of the threshold analysis at all threshold levels for the different 

segments in the petroleum and gas industry. It must be noted that the threshold analysis 

estimates of emissions in this table are slightly different from the estimate of emissions in the 

April 2010 proposal. The slight decrease in reported emissions of 4 percent for the entire oil 

and gas sector resulted from data and calculation corrections in the transmission and LNG 

storage segments and use of different well property databases in onshore production (HPDI® 

in the final, as opposed to LASSER® in the April 2010 proposal). The same note applies to 

Table 7 below. 

Background Technical Support Document – Petroleum and Natural Gas Industry 29 
10,000 

Table 5: Threshold Analysis for the Petroleum and Gas Industry Segments 

Emissions Covered 

Source Category 

Threshold Level 

Total National Emissions 

Number of Facilities 

Process Emissions (MtCO2e/year) 

Combustion CO2 Emissions (Mt/year) 

Total Emissions (tons mtCO2e/yr) Percent 

100,000 265,349,383 22,510 136,547,535 60,732,073 197,279,608 74% 25,000 265,349,383 22,510 152,395,746 73,695,453 226,091,199 85% 10,000 265,349,383 22,510 158,499,897 82,061,519 240,561,416 91% 

Onshore Natural Gas Production Facilities (Basin) 

1,000 265,349,383 22,510 165,212,244 96,180,842 261,393,085 99% 

100,000 11,261,305 3,235 3,217,228 25,161 3,242,389 29% 25,000 11,261,305 3,235 4,619,175 500,229 5,119,405 45% 10,000 11,261,305 3,235 5,515,419 1,596,144 7,111,563 63% 

Offshore Petroleum and Natural Gas Production Facilities 

1,000 11,261,305 3,235 6,907,812 3,646,076 10,553,889 94% 100,000 33,984,015 566 24,846,992 27,792 24,874,783 73% 25,000 33,984,015 566 29,551,689 1,677,382 31,229,071 92% 10,000 33,984,015 566 30,725,532 2,257,443 32,982,975 97% 

Onshore Natural Gas Processing Facilities 

1,000 33,984,015 566 31,652,484 2,331,531 33,984,015 100% 

100,000 47,935,158 1,944 24,197,401 7,834 24,205,235 50% 25,000 47,935,158 1,944 36,154,061 6,155,313 42,309,374 88% 10,000 47,935,158 1,944 37,593,627 9,118,603 46,712,230 97% 

Onshore Natural Gas Transmission Facilities 

1,000 47,935,158 1,944 37,993,603 9,934,474 47,928,077 100% 100,000 9,730,625 397 3,557,040 0 3,557,040 37% 25,000 9,730,625 397 6,585,276 1,276,239 7,861,516 81% 10,000 9,730,625 397 7,299,582 1,685,936 8,985,518 92% 

Underground Natural Gas Storage Facilities 

1,000 9,730,625 397 7,762,600 1,951,505 9,714,105 100% 

100,000 2,113,601 157 596,154 25,956 622,110 29% 25,000 2,113,601 157 1,524,652 188,552 1,713,205 81% 

2,113,601 157 1,626,435 204,297 1,830,731 87% 

LNG Storage Facilities 

1,000 2,113,601 157 1,862,200 252,895 2,115,095 100% 100,000 315,888 5 314,803 0 314,803 100% 25,000 315,888 5 314,803 0 314,803 100% 10,000 315,888 5 314,803 0 314,803 100% 

LNG Import Facilities1 

1,000 315,888 5 315,048 840 315,888 100% 

100,000 25,258,347 1,427 18,470,457 0 18,470,457 73% 25,000 25,258,347 1,427 22,741,042 0 22,741,042 90% 10,000 25,258,347 1,427 23,733,488 0 23,733,488 94% 

Natural Gas Distribution Facilities 

1,000 25,258,347 1,427 24,983,115 0 24,983,115 99% 

1. The only LNG export facility in Alaska has not been included in this analysis. 

Background Technical Support Document – Petroleum and Natural Gas Industry 
Note: Totals may not add exactly due to rounding. Equipment leak and vented emissions in the threshold 

analysis are a sum of facility level emissions for each segment. Hence the total equipment leak and vented 

emissions from each segment may not match the U.S. GHG Inventory. 

As discussed above, alternative definitions of facility for onshore petroleum and natural gas 

production could be considered. One alternative option is applying the threshold at the field 

level. Table 7 provides the results of the threshold analysis for a field level facility 

definition. The results of this analysis show that at a 25,000 metric ton CO2e threshold, 1,157 

facilities would be covered and only 57 percent of national emissions. If the threshold were 

decreased to 1,000 metric tons CO2e, over 80 percent of national emissions would be covered 

but the number of reporters would increase to over 22,000. 

Table 7. Emissions coverage and number of reporting entities for field level facility 

definition 

Threshold 

Level2 

Emissions Covered Facilities Covered 

Metric tons 

CO2e/year Percent Number Percent 

100,000 110,437,470 42% 306 0% 

25,000 150,297,681 57% 1,157 2% 

10,000 171,902,688 65% 2,549 4% 

1,000 219,121,375 83% 22,459 33% 

A third alternative for a facility definition was individual well pads as facilities for onshore 

petroleum and natural gas production segment. Four different scenarios were also considered 

below for applying thresholds at individual well pads. 

 Case 1 (highest well pad emissions): Drilling and completion of an 

unconventional gas well early in the year with the well producing the remainder of 

the year with a full complement of common, higher process emissions equipment on 

the well pad including a compressor, glycol dehydrator, gas pneumatic controllers, 

and condensate tank without vapor recovery. We assumed that unconventional well 

completion does not employ "Reduced Emissions Completion" practices. 

 Case 2 (second highest well pad emissions): Drilling and completion of a 

conventional gas well early in the year with the well producing the remainder of the 

year with a full complement of common, higher process emissions equipment on the 

well pad including a compressor, glycol dehydrator, gas pneumatic controllers, and 

condensate tank without vapor recovery. 

 Case 3 (third highest well pad emissions): Drilling and completion of a 

conventional oil well early in the year with the well producing the remainder of the 

year with a full complement of common, higher process emissions equipment on the 

well pad including an associated gas compressor, glycol dehydrator, gas pneumatic 

Background Technical Support Document – Petroleum and Natural Gas Industry 31 
controllers, chemical injection pump, an oil heater-treater, and a crude oil stock tank 

without vapor recovery. 

 Case 4 (fourth highest well pad emissions): Production at an associate gas 

and oil well (no drilling) with a compressor, dehydrator, gas pneumatics, oil 

heater/treater and oil stock tank without vapor recovery. 

Table 8 below illustrates the average emissions for each scenario and the number of facilities 

that have emissions equal to or greater than that average. For example, in case 1, average 

emissions are 4,927 tons CO2e/well pad. A threshold would have to be set as low as 

appropriately 5,000 tons CO2e/well pad to capture even 6% of emissions from onshore 

petroleum and gas production. For the other cases, the threshold would have to be set lower 

than the thresholds considered for other sectors of the GHG reporting rule to capture even 

relatively small percentages of total emissions. In all cases, the number of reporters is higher 

than would be affected under the field or basin level options. 

Table 8: Alternate Well-head Facility Definitions 

Case 1 Case 2 Case 3 Case 4 

Average emissions (tons CO2e / well pad) 

Number of Reporters 

Covered Emissions (metric tons CO2e) 

Percent Coverage 

4,927 

3,349 

16,498,228 

6% 

700 

38,949 

40,943,092 

16% 

700 

66,762 

50,572,248 

19% 

370 

166,690 

87,516,080 

33% 

Background Technical Support Document – Petroleum and Natural Gas Industry 32 
The petroleum and natural gas industry may be somewhat unique when calculating facility 

emissions to be applied against a threshold for reporting. Subpart C in the GHG reporting 

rule excluded the calculation and reporting of emissions from portable equipment. This was 

one option considered for the petroleum and natural gas industry. However, given that 

portable equipment is so central to many of the operations in the petroleum and natural gas 

industry and such a large contributor to emissions for the industry, particularly for onshore 

petroleum and natural gas production, portable equipment emissions are an important source 

of emissions for inclusion a reporting rule. If these emissions were excluded from the 

threshold calculation, EPA estimates that a large number of facilities would fall below the 

threshold, preventing the collection of significant data from the industry that would be 

beneficial to the development of future climate policies and programs. Please see “Portable 

Combustion Emissions” memo under rulemaking docket EPA-HQ-OAR-2009-0923. 

Another issue that concerns onshore petroleum and natural gas production is the number of 

equipment operating contractors that support the well operators. It is typical to find 

production well operators contracting out the majority of their process equipment from 

separation, dehydration, and tanks, up to gathering and boosting and transport. Hence 

requiring well operators to report only emissions from equipment they own or directly 

operate could lead to a significant reduction in emissions coverage. Accordingly, the final 

rule provides that emissions from such equipment must be reported whether from equipment 

contracted to, leased from, owned or run by a third party. For a more full discussion of this 

issue, see Vol. 9, Response to Legal Issues on Mandatory Greenhouse Gas Reporting Rule 

Subpart W – Petroleum and Natural Gas. 

6. Monitoring Method Options 

a. Review of Existing Relevant Reporting Programs/ Methodologies 

To determine applicability of the different monitoring methods available, existing programs 

and guidance documents were reviewed. Table 4 shows a listing of the existing programs 

and guidance documents that were reviewed. All of the program and guidance documents 

provide direction on estimating CH4 and/ or CO2 emissions. All documents, in general, 

provide emissions rate (emissions factors) that can be used to estimate emissions and in some 

cases refer to continuous emissions monitoring. 

b. Potential Monitoring Methods 

Depending on the particular source to be monitored in a facility, several of the currently 

available monitoring methods for estimating emissions could be used. 

i. Equipment Leak Detection 

Traditional equipment leak detection technologies like the Toxic Vapor Analyzer (TVA) and 

the Organic Vapor Analyzer (OVA) are appropriate for use in small facilities with few pieces 

of equipment. However, comprehensive leak detection in large facilities can be cumbersome, 

time consuming, and in many cases costly. But new infrared remote equipment leak detection 

technologies are currently being used in the United States and internationally to efficiently 

Background Technical Support Document – Petroleum and Natural Gas Industry 33 
 

detect leaks across large facilities. Considering these factors, one of the following two 

technologies can be used to detect leaks in facilities depending on suitability; 

Infrared Remote Equipment Leak Detectors 

Hydrocarbons in natural gas emissions absorb infrared light. The infrared remote equipment 

leak detectors use this property to detect leakages in systems. There are two main types of 

detectors; a) those that scan the an area to produce images of equipment leaks from a source 

(passive instruments), and b) those that point or aim an IR beam towards a potential source to 

indicate presence of equipment leaks (active instruments). 

An IR camera scans a given area and converts it into a moving image of the area while 

distinctly identifying the location where infrared light has been absorbed, i.e. the equipment 

leak source. The camera can actually “see” equipment leaks. The advantages of IR cameras 

are that they are easy to use, very efficient in that they can detect multiple leaks at the same 

time, and can be used to do a comprehensive survey of a facility. The main disadvantage of 

an IR camera is that it may involve substantial upfront capital investment depending on the 

features that are made available. Therefore, these cameras are most applicable in facilities 

with large number of equipment and multiple potential leak sources or when purchased at the 

corporate level, and then shared among the facilities, thereby lowering costs. 

Aiming devices are based on infrared laser reflection, which is tuned to detect the interaction 

of CH4 and other organic compounds with infrared light in a wavelength range where CH4 

has strong absorption bands, but do not visually display an image of the equipment leaks. 

Such devices do not have screens to view equipment leaks, but pin point the location of the 

emissions with a visual guide (such as a visible pointer laser) combined with an audible 

alarm when CH4 is detected. These devices are considerably less expensive than the camera 

and also can detect equipment leaks from a distance (i.e. the instrument need not be in close 

proximity to the emissions). More time is required for screening, however, since each 

equipment (or component) has to be pointed at to determine if it is leaking. Also, if there are 

multiple leaks in the pathway of the IR beam then it may not accurately detect the right 

source of emissions. 

Method For IR instruments that visually display an image of equipment leaks, the 

background of the emissions has to be appropriate for emissions to be detectable. Therefore, 

the operator should inspect the emissions source from multiple angles or locations until the 

entire source has been viewed without visual obstructions to identify all emissions. For other 

IR detection instruments, such as those based on IR laser reflection, instruments would have 

to monitor potential emissions sources along all joints and connection points where a 

potential path to the atmosphere exists. For example, a flange can potentially have leaks 

along its circumference and such surfaces will have to be monitored completely by tracing 

the instrument along each surface. 

Calibration The minimum detectable quantity of equipment leaks using an IR instrument 

depends on a number of factors including manufacturer, viewing distance, wind speed, gas 

composition, ambient temperature, gas temperature, and type of background behind the 

equipment leaks. For best survey results, equipment leak detection can be performed under 

Background Technical Support Document – Petroleum and Natural Gas Industry 34 
favorable conditions, such as during daylight hours, in the absence of precipitation, in the 

absence of high wind, and, for active laser devices, in front of appropriate reflective 

backgrounds within the detection range of the instrument. The EPA Alternative Work 

Practice (AWP) requires optical imaging devices to detect a minimum flow rate, specified in 

Title 40 CFR Part 65 Section 7, before each use. The AWP specifies instructions for 

determining the minimum detectable flow rate, the purity of the calibration gas, and the 

allowed viewing distance. Equipment leak detection and measurement instrument manuals 

can also be used to determine optimal operating conditions to help ensure best results. 

Toxic Vapor Analyzer (or Organic Vapor Analyzer) 

TVAs and OVAs consist of a flame ionization detector that is used to detect the presence of 

hydrocarbons and measure the concentration of equipment leaks. It consists of a probe that is 

moved close to and around the potential emissions source and an emissions detection results 

in a positive reading on the instrument monitoring scale. The concentration can be used in 

conjunction with correlation equations to determine the leak rate. However, concentration is 

not a true measure of an emission’s magnitude. Therefore concentration data from TVAs and 

OVAs, for the purposes of the rule, may be best suited for screening purposes only. The 

advantage of these instruments is that they have lower costs than IR cameras and several 

facilities conducting Leak Detection and Repair (LDAR) programs might already have these 

instruments, thereby reducing capital investment burden. But these instruments screen very 

slowly given that each potential emissions source has to be individually and thoroughly 

circumscribed less than 1 centimeter from the potentially leaking joints or seals. 

Method TVAs and OVAs can be used for all equipment leak detection that is safely 

accessible at close-range. For each potential emissions source, all joints, connections, and 

other potential paths to the atmosphere would be monitored for emissions. Due to residence 

time of a sample in the probe, there is a lag between when an emission is captured and the 

operator is alerted. To pinpoint the source of the equipment leak, upon alert the instrument 

can be slowly retraced over the source until the exact location is found. 

Calibration Method 21 guidance can be used to calibrate the TVA or OVA using guidelines 

from Determination of Volatile Organic Compound Leaks Sections 3, 6, and 7. 

Acoustic Leak Detectors 

Acoustic leak detectors are simple devices that filter out the low frequency vibrations and 

noise of heavy machinery operating and sense and measure the decibel reading of high 

frequency vibrations and noise of fluids leaking through small cracks or openings. Fluid flow 

through open valves has little difference in sonic generated noise between the inlet and outlet 

of a valve, or the valve body itself. Similarly tightly closed valves have little difference in 

sonic noise measured on the inlet, outlet or valve body. Valves which are not tightly closed 

(i.e. a crevice or deformation of the valve plug and seat) will generate a high frequency noise 

depending on the valve type and size, the pressure drop across the closed valve, and the fluid 

density. This frequency can be measured in decibels and correlated with through valve 

leakage rate. 

Background Technical Support Document – Petroleum and Natural Gas Industry 35 
Method 

The instrument operator places the “stethoscope” like probe on the valve body or valve 

flange in one or more of the recommended locations, and observes the decibel reading 

displayed on the instrument digital signal indicator. This reading is documented in the field, 

along with the valve identification (valve number or location descriptor). The type of fluid, 

its density, and the system pressure upstream and downstream of the closed valve are also 

recorded to be entered along with the valve type (ball, plug, gate, pressure relief, etc) and 

nominal size) into an Excel spreadsheet supplied by the valve manufacturer. The through 

valve leakage rate is calculated by correlation algorithms developed by the instrument 

manufacturer. 

Calibration 

Calibration requirements are as provided by the manufacturer, depending on the type of 

acoustic detector. 

ii. Emissions Measurement 

A. Direct Measurement 

Three types of technologies can be used where appropriate to measure or quantify the 

magnitude of emissions. 

High Volume Sampler 

A high volume sampler consists of a simple fixed rate induced flow sampling system to 

capture the emissions and measure its volume. The emissions and the air surrounding the 

emissions source are drawn into the instrument using a sampling hose. The instrument 

measures the flow rate of the captured volume of air and emissions mixture. A separate 

sample of the ambient air is taken by the instrument to correct for the volume of ambient air 

that is captured along with the emissions. 

High volume samplers have moderate costs and have a potential capacity for measuring up to 

30 leaking components per hour with high precision at 0.02 percent methane. This allows for 

reduced labor costs and survey times while maintaining precise results. For this reason, high 

volume samplers are considered the preferred and most cost-effective direct measurement 

option for emissions within their maximum range. However, large component emissions and 

many vent emissions are above the high volume sampler capacity and therefore warrant the 

use of other measurement instruments. 

Method A high volume sampler is typically used to measure only emissions for which the 

instrument can intake the entire emissions from a single source. To ensure proper use of the 

instrument, a trained technician can conduct the measurements. The technician will have to 

be conversant with all operating procedures and measurement methodologies relevant to 

using a high volume sampler, such as positioning the instrument for complete capture of the 

emissions without creating backpressure on the source. If the high volume sampler, along 

with all attachments available from the manufacturer, is not able to capture all the emissions 

Background Technical Support Document – Petroleum and Natural Gas Industry 36 
from the source then anti-static wraps or other aids can be used to capture all emissions 

without violating operating requirements as provided in the instrument manufacturer’s 

manual. The attachments help capture the emissions from different points on the source 

allowing the measurement of the emission by the high volume sampler. 

Calibration The instrument can be calibrated at 2.5% and 100% CH4 by using calibrated 

gas samples and by following the manufacturer’s instructions for calibration. 

Meters 

Several types of meters measure natural gas flows and can be used for measurement of 

emissions from sources where the volume of emissions are large like in vent stacks. 

Rotameter – A rotameter consists of a tapered calibrated transparent tube and a 

floating bob inside to measure emissions. To measure emissions a rotameter is placed 

over an emissions source (typically vents and open ended lines) and the emissions 

pass through the tube. As the emissions move through the tube it raises the floating 

bob to indicate the magnitude of emissions on the calibrated scale. Rotameters are 

most advantageous to use in cases where the emissions are very large. The 

disadvantage though is that it can only be used on leaks where the entire emissions 

can be captured and directed through the rotameter. 

Turbine Meter –To measure emissions a turbine meter is placed over an emissions 

source and the emissions pass through the tube. As the emissions move through the 

tube it spins the turbine; the rate at which the turbine spins indicates the magnitude of 

emissions. Like rotameters, turbine meters are most advantageous to use in cases 

where emissions are very large. The disadvantage is that it can only be used on 

emissions that can be entirely captured and directed through the meter. 

Hotwire Anemometer – Hotwire anemometers measure emissions velocity by noting 

the heat conducted away by the emissions. The core of the anemometer is an exposed 

hot wire either heated up by a constant current or maintained at a constant 

temperature. In either case, the heat lost to emissions by convection is a function of 

the emissions velocity. Hotwire anemometers are best for measuring vents and open 

ended lines of known cross-sectional area and do not require complete capture of 

emissions. Hot wire anemometers have low levels of accuracy since they measure 

velocity that is converted into mass emissions rate. 

Pitot Tube Flow Meter – A simple pitot tube is a right angled tube open at one end 

and closed at the other. The closed end is connected to a transducer to measure 

pressure of the inflowing emissions. The open end is aligned parallel to the direction 

of emissions flow. Emissions are directed into the tube so that the pressure required to 

bring the air inside the tube to stagnation is measured. The difference in pressure 

between the interior of the pitot tube and the surrounding air is measured and 

converted to an emissions rate. Pitot tube flow meters can be used when the crosssectional area of an emitting vent or open ended line is known, or when the entire 

emission can be directed into the tube. The pitot tube flow meter measures pressure 

Background Technical Support Document – Petroleum and Natural Gas Industry 37 
 

 

 

differential that is converted to mass emissions rate. The pitot tube detects the flow 

velocity at only one point along the flowstream, hence the placement of the pitot tube 

inside the pipe where the flow is to be measured is critical to determine a 

representative flow volume, and not a location-specific flow volume, which can give 

erroneous results. It has relatively low accuracy compared to most flow meters, due 

to the low pressure drop measured. This also makes it vulnerable to fluctuations from 

turbulence changes in the flow stream. Although inaccurate compared to most 

meters, the pitot tube is one of the least expensive flow meters available. 

Vane Anemometer – A vane anemometer channels the emissions over a rotating vane 

that in turn rotates a fan to measure the velocity of emissions. The number of 

revolutions of the fan are detected and measured and converted to a flow velocity. 

Using the cross section of flow of the emissions, the volumetric flow rate of 

emissions can be estimated. A vane anemometer is best used for lines that have 

known cross-sectional areas. The disadvantage is if the flow direction of the 

emissions changes with respect to the axis of rotation of the vanes, it can result in 

errors in velocity and flow rate estimation. 

Method To ensure accurate measurements when using metering (e.g. rotameters, turbine 

meters, and others), all emissions from a single source will have to be channeled directly 

through the meter. An appropriately sized meter can be used to prevent the flow from 

exceeding the full range of the meter and conversely to have sufficient momentum for the 

meter to register continuously in the course of measurement. 

Calibration The meters can be calibrated using either one of the two methods provided 

below: 

(A)	 Develop calibration curves by following the manufacturer’s instruction. 

(B)	 Weigh the amount of gas that flows through the meter into or out of a container 

during the calibration procedure using a master weigh scale (approved by the 

National Institute of Standards and Technology (NIST) or calibrated using 

standards traceable by NIST) that has a very high degree of accuracy. Determine 

correction factors for the flow meter according to the manufacturer’s instructions, 

record deviations from the correct reading at several flow rates, plot the data 

points, compare the flow meter output to the actual flow rate as determined by the 

master weigh scale and use the difference as a correction factor. 

(C)	 The Final GHG Reporting Program provides guidance on calibration for meters in 

section §98.3(i). 

Calibrated Bagging 

A calibrated bag (also known as a vent bag) made of anti-static material is used to enclose an 

emissions source to completely capture all the leaking gas. The time required to fill the bag 

with emissions is measured using a stop watch. The volume of the bag and time required to 

Background Technical Support Document – Petroleum and Natural Gas Industry 38 
 

fill it is used to determine the mass rate of emissions. Calibrated bags have a very high 

accuracy, since all the emissions are captured in the measurement. 

Calibrated bags are the lowest cost measurement technique, and can measure up to 30 

leaking components in an hour, but may require two operators (one to deploy the bag, the 

other to measure time inflation). It is a suitable technique for emission sources that are 

within a safe temperature range and can be safely accessed. The speed of measurement is 

highly dependent on the emissions rate and the results are susceptible to human error in 

enclosing the emission source and taking the measurement data, leading to lower precision 

and accuracy. For those sources outside the capacity of high volume samplers and within the 

limitations of bagging, this would be a second best choice for quantification. 

Method Calibrated bags can be used only where the emissions are at near-atmospheric 

pressures and the entire emissions volume can be captured for measurement. Using these 

bags on high pressure vent stacks can be dangerous. For conducting measurement the bag is 

physically held in place by a trained technician, enclosing the emissions source, to capture 

the entire emissions and record the time required to completely fill the bag. Three 

measurements of the time required to fill the bag can be conducted to estimate the emissions 

rates. The average of the three rates will provide a more accurate measurement than a single 

measurement. 

Calibration To ensure accurate results, a technician can be trained to obtain consistent 

results when measuring the time it takes to fill the bag with emissions. 

All of the emissions measurement instruments discussed above measure the flow rate of the 

natural gas emissions. In order to convert the natural gas emissions into CO2 and CH4 

emissions, speciation factors determined from natural gas composition analysis must be 

applied. Another key issue is that all measurement technologies discussed require physical 

access to the emissions source in order to quantify emissions. 

B. Engineering Estimation and Emission Factors 

For several emissions sources, there are viable alternatives to physical measurement for 

calculating emissions. For example, emissions to the atmosphere due to emergency 

conditions from vessels or other equipment and engineered emissions from equipment like 

pneumatic devices can be estimated or quantified using engineering calculations. This is 

referred to as engineering estimation. Emission factors can be considered for nearly every 

source where emissions data is available, however, they usually have high uncertainties. 

Emissions factors may be appropriate for frequent, geographically sparse emission sources 

such as pneumatic devices. Several sources are outlined below along with relevant 

engineering estimation methods that can be used to estimate GHG gas emissions from each 

source. 

1. Natural Gas Driven Pneumatic Pumps 

Background Technical Support Document – Petroleum and Natural Gas Industry 39 
 

 

 

 

Leaks from natural gas driven pneumatic pumps can be calculated using data obtained from 

the manufacturer for natural gas emissions per unit volume of liquid pumped at operating 

pressures. This information is available from the pump manufacturer in their manuals. 

Operators can maintain a log of the amount of liquids pumped annually for individual 

pneumatic pumps and use Equation 1 below for calculating emissions: 

Es,n  Fs * V	 Equation 1 

where, 

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

per year 

Fs = Natural gas driven pneumatic pump gas emission in “emission per 

volume of liquid pumped at operating pressure” in scf/gallon at 

standard conditions, as provided by the manufacturer 

V = Volume of liquid pumped annually in gallons/year 

If manufacturer data for a specific pump is not available, then data for a similar pump model 

of the same size and operational characteristics can be used to estimate emissions. As an 

alternative to manufacturer data on pneumatic pump natural gas emissions, the operator can 

conduct a one-time measurement to determine natural gas emissions per unit volume of 

liquid pumped using a calibrated bag for each pneumatic pump, when it is pumping liquids. 

Due to the geographically isolated nature of pneumatic pumps, if manufacturer data is not 

readily available or would result in high burden to obtain the data, pneumatic pump 

emissions can also be quantified using published emission factors. The use of emission 

factors is less burdensome than collecting manufacturer data from each pneumatic pump but 

can be inaccurate due to limited data and variable pump design. However, the resulting 

information can still be useful for the purposes of informing policy because it will provide 

updated activity data on the number and type of pneumatic pumps in operation. See 

Appendix G for a discussion of population emission factors for pneumatic pumps and see 

Section (6)(d) of the TSD for how to calculate emissions from population factors. Emissions 

from natural gas driven pneumatic pumps can be calculated using an emissions factor as 

follows; 

Mass s,i	  Count * EF * GHG i*Conv i * 24*365	 Equation 2

where, 

Masss,i = Annual total mass GHG emissions in metric tons per year at standard 

conditions from all natural gas driven pneumatic pumps at the facility, 

for GHGi 

Count = Total number of natural gas driven pneumatic pumps at the facility 

Background Technical Support Document – Petroleum and Natural Gas Industry 40 
 

 

 

 

 

 

EF = Population emission factors for natural gas driven pneumatic pumps 

listed in Appendix G for onshore petroleum and natural gas production, 

onshore natural gas transmission, and underground natural gas storage 

facilities, respectively 

GHGi = for onshore petroleum and natural gas production facilities, 

concentration of GHGi, CH4 or CO2, in produced natural gas; for other 

facilities GHGi equals 1 

Convi = conversion from standard cubic feet to metric tons CO2e; 0.000410 for 

CH4, and 0.00005357 for CO2 

24 * 365 = conversion to yearly emissions estimate 

2. Natural Gas Driven Pneumatic Manual Valve Actuators 

Emissions from natural gas driven pneumatic manual valve actuators can be calculated using 

data obtained from the manufacturer for natural gas emissions per actuation. Operators can 

maintain a log of the number of manual actuations annually for individual pneumatic devices 

and use Equation 3 below: 

Es,n  As *N	 Equation 3 

where, 

Es,n = natural gas emissions at standard conditions 

As = natural gas driven pneumatic valve actuator natural gas emissions 

in “emissions per actuation” units at standard conditions, as 

provided by the manufacturer. 

N = Number of times the pneumatic device was actuated through the 

reporting period 

As an alternative to manufacturer data, the operator could conduct a one-time measurement 

to determine natural gas emissions per actuation using a calibrated bag for each pneumatic 

device. 

3. Natural Gas Driven Pneumatic Bleed Devices 

Pneumatic devices typically fall in three categories; low bleed devices, high bleed devices, 

and intermittent bleed devices. Low bleed devices are devices that bleed less than 6 scf of 

natural gas per hour. High bleed devices are devices that bleed more than 6 scf of natural gas 

per hour.6,7 Intermittent bleed devices are snap-acting or throttling devices that discharge the 

full volume of the actuator intermittently when control action is necessary, but do not bleed 

continuously. Given the vast difference in bleed rates, low bleed devices contribute to a 

6

 "Opportunities to Reduce Anthropogenic Methane Emissions in the United States," EPA 430-R-93-012, October 1993 7

 PG&E (Pacific Gas and Electric). 1990. Unaccounted for Gas Project Summary Volume, PG&E Research and 

Development; San Ramon, CA: GRI-90/0067.1 

Background Technical Support Document – Petroleum and Natural Gas Industry 41 
 

 

 

 

 

 

 

small portion of the total emissions from pneumatic devices nationally. Therefore, it may be 

feasible to provide an emissions factor approach for low bleed pneumatic devices to reduce 

burden. The following are two different options for determining emissions from low bleed, 

high bleed, and intermittent pneumatic devices. 

Emissions from a natural gas pneumatic high bleed device venting can be calculated using a 

specific pneumatic device model natural gas bleed rate during normal operation as available 

from the manufacturer. If manufacturer data for a specific device is not available then data 

for a similar size and operation device can potentially be used to estimate emissions. The 

natural gas emissions for each bleed device can be calculated as follows; 

Es,n  Bs * T Equation 4 

where, 

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

Bs = Natural gas driven pneumatic device bleed rate volume at standard 

conditions in cubic feet per minute, as provided by the manufacturer 

T = Amount of time in minutes that the pneumatic device has been operational 

through the reporting period 

Due to the geographically isolated nature of pneumatic devices, if manufacturer data is not 

readily available or would result in high burden to obtain the data, pneumatic device 

emissions can also be quantified using published emission factors. The use of emission 

factors is less burdensome than collecting manufacturer data from each device, but can be 

inaccurate due to limited data and variable design. However, the resulting information can 

still be useful for the purposes of informing policy because it will provide updated activity 

data on the number and type of pneumatic pumps in operation. See Appendix G for a 

discussion of population emission factors for pneumatic devices and see Section (6)(d) of the 

TSD for how to calculate emissions from population factors. Emissions from natural gas 

pneumatic low bleed device venting can be calculated using emissions factor as follows; 

Masss,i  Count * EF * GHGi *Convi * 24*365 Equation 5 

where, 

Masss,i = Annual total mass GHG emissions in metric tons per year at standard 

conditions from all natural gas pneumatic low bleed device venting at 

the facility, for GHG i 

Count = Total number of natural gas pneumatic low bleed devices at the facility 

EF = Population emission factors for natural gas pneumatic low bleed device 

venting listed in Appendix G for onshore petroleum and natural gas 

Background Technical Support Document – Petroleum and Natural Gas Industry 42 
 

production, onshore natural gas transmission, and underground natural 

gas storage facilities, respectively 

GHGi = for onshore petroleum and natural gas production facilities, 

concentration of GHGi, CH4 or CO2, in produced natural gas; for other 

facilities GHGi equals 1 

Convi = conversion from standard cubic feet to metric tons CO2e; 0.000410 for 

CH4, and 0.00005357 for CO2 

24 * 365 = conversion to yearly emissions estimate 

4. Acid Gas Removal (AGR) Vent Stacks 

AGR vents consist of both CO2 and CH4 emissions. CO2 emissions from AGR units can be 

reliably estimated using continuous emissions monitoring (CEMS) systems, mass balance 

approach, or one of the standard simulation software packages. CH4 emissions can only be 

estimated using simulation software packages. It must be noted, however, that CH4 emissions 

from AGR vents are insignificant, 0.06 percent of the total volume of CO2 and CH4 

emissions. The mass balance approach has the advantage of being usable in systems that use 

membrane, molecular sieves, or absorbents other than amines; simulation software packages 

currently do not provide an option for these types of technologies. 

Some facilities may have CEMS installed on their AGR unit vent stacks. In such a case, if 

the CEMS can reliably measure CO2 volumes then the measurements from CEMS can 

sufficiently inform on the CO2 emissions from AGR units. Alternatively, if the vent stack has 

a meter on it then the CO2 emissions can be estimated using this metered vent stack gas 

volume and the percent CO2 in the vent stack gas. 

Operators can calculate emissions from acid gas removal vent stacks using simulation 

software packages, such as ASPENTM or AMINECalcTM. Different software packages might 

use different calculations and input parameters to determine emissions from an acid gas 

removal unit. However, there are some parameters that directly impact the accuracy of 

emissions calculation. Therefore, any standard simulation software could be used assuming it 

accounts for the following operational parameters: 

 Natural gas feed temperature, pressure, and flow rate; 

 Acid gas content of feed natural gas; 

 Acid gas content of outlet natural gas; 

 Unit operating hours, excluding downtime for maintenance or standby; 

 Emissions control method(s), if any, and associated reduction of emissions; 

 Exit temperature of natural gas; and 

 Solvent pressure, temperature, circulation rate, and weight. 

CO2 emissions from AGR unit vent stacks can also be calculated using mass balance 

approach from the throughput of the AGR unit and gas composition as follows; 

Background Technical Support Document – Petroleum and Natural Gas Industry 43 
 

 

 

Ea,CO2  V   * V * VolI VolO * VolI VolO  Equation 6 

where, 

Ea,CO2 = Annual volumetric CO2 emissions at actual condition, in cubic feet per 

year. 

V = Total annual volume of natural gas flow into or out of the AGR unit in 

cubic feet per year at actual condition as determined using methods 

specified in paragraph (d)(5) of this section of the TSD. 

α = Factor is 1 if the outlet stream flow is measured. Factor is 0 if the inlet 

stream flow is measured. 

VolI = Volume fraction of CO2 content in natural gas into the AGR unit as 

determined in paragraph (d)(7) of this section. 

VolO = Volume fraction of CO2 content in natural gas out of the AGR unit as 

determined in paragraph (d)(8) of this section of the TSD. 

Sometimes AGR units have a continuous gas analyzer in which case they can be used to 

determine VolI and VolO. 

There are gas processing plants that capture CO2 for EOR or carbon sequestration projects. 

In such cases, the emissions ECO2 can be adjusted downward to account for the percentage of 

total emissions captured. 

5. Blowdown Vent Stacks 

Emissions from blowdown vent stacks can be calculated using the total physical volume 

between isolation valves (including all natural gas-containing pipelines and vessels) and logs 

of the number of blowdowns for each piece of equipment using Equation 7 below: 

 459.67  Ts Pa  

E  N *Vv 

  s,n  V v *C  Equation 7    459.67  Ta Ps  

where, 

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

blowdowns in cubic feet. 

N = Number of repetitive blowdowns for each equipment type of a unique 

volume in calendar year. 

Vv = Total volume of blowdown equipment chambers (including pipelines, 

compressors and vessels) between isolation valves in cubic feet. 

C = Purge factor that is 1 if the equipment is not purged or zero if the 

equipment is purged using non-GHG gases. 

Background Technical Support Document – Petroleum and Natural Gas Industry 44 
 

Ts = Temperature at standard conditions (o

F). 

Ta = Temperature at actual conditions in the blowdown equipment chamber 

(

o

F). 

Ps = Absolute pressure at standard conditions (psia). 

Pa = Absolute pressure at actual conditions in the blowdown equipment 

chamber (psia). 

6. Dehydrator Vent 

There are two predominant types of technologies that are used to dehydrate natural gas. The 

first type is the most prevalent and uses liquid tri-ethylene glycol for dehydration, typically 

referred to as glycol dehydrators. The second type of dehydrators use solid desiccants to 

extract water from natural gas. For glycol dehydrators, when contacted with natural gas for 

dehydration, the glycol absorbs some amount of natural gas, which is released as emissions 

during its regeneration. Standard simulation software packages that use some form of 

equilibrium analysis can estimate emissions from such liquid glycol type dehydrators. On the 

other hand, in desiccant dehydrators the solid desiccant itself does not absorb any significant 

quantities of natural gas. But emissions result when the desiccant dehydrator is opened to the 

atmosphere for the regeneration of the desiccant, which results in the release of natural gas 

trapped in the desiccant dehydrator vessel. Hence, for desiccant dehydrators standard 

simulation software packages cannot be used. However, calculative methods can be used to 

determine emissions from solid desiccant type dehydrators. The two monitoring methods for 

the two different types for dehydrators are as below. 

Emissions from a dehydrator vents can be calculated using a simulation software package, 

such as GLYCalcTM. There may be several other simulation packages, such as Aspen 

HYSYS, that can also estimate emissions from glycol dehydrators. However, GLYCalcTM is 

the most widely used software and referenced by several State and Federal agencies in their 

programs and regulations. Different software packages might use different calculations and 

input parameters to determine emissions from dehydration systems. However, there are some 

parameters that directly impact the accuracy of emissions calculation. Therefore, any 

standard simulation software could be used provided it accounts for the following operational 

parameters: 

 Feed natural gas flow rate; 

 Feed natural gas water content; 

 Outlet natural gas water content; 

 Absorbent circulation pump type(natural gas pneumatic/ air pneumatic/ electric); 

 Absorbent circulation rate; 

 Absorbent type: including, but not limited to, triethylene glycol (TEG), diethylene 

glycol (DEG) or ethylene glycol (EG); 

 Use of stripping natural gas; 

 Use of flash tank separator (and disposition of recovered gas); 

 Hours operated; and 

 Wet natural gas temperature, pressure, and composition. 

Background Technical Support Document – Petroleum and Natural Gas Industry 45 
 

 

 

 

 

 

For dehydrators that use desiccant emissions can be calculated from the amount of gas vented 

from the vessel every time it is depressurized for the desiccant refilling process using 

Equation 8 below: 

(H * D2 * P * P2 * %G *365days / yr) Es,n  Equation 8 (4 * P1

*T *1,000cf / Mcf *100) 

where, 

Es,n = Annual natural gas emissions at standard conditions 

H = Height of the dehydrator vessel (ft) 

Dv = Inside diameter of the vessel (ft) 

P1 = Atmospheric pressure (psia) 

P2 = Pressure of the gas (psia) 

P = pi (3.14) 

G% = Percent of packed vessel volume that is gas 

T = Time between refilling (days) 

100 = Conversion of %G to fraction. 

Some dehydrator vented emissions are sent to a flare. Annual emissions from dehydrator 

vents sent to flares can be calculated using the methodology under Section 8 of the TSD for 

flares. Alternatively, a simple combustion efficiency factors, such as 98 percent, can be used 

in conjunction with a CO2 emissions factor for natural gas to estimate emissions from glycol 

dehydrator vents to flare stack. 

7. EOR injection pump blowdown. 

EOR operations use pumps to inject supercritical phase CO2 into reservoirs. For 

maintenance, these pumps may be blown down to release all the supercritical phase CO2. The 

volume of CO2 released to during such blow down practices can be calculated using the total 

volume between isolation valves (including, but not limited to, pipelines, compressors and 

vessels).The emissions can be calculated using Equation 9 below. 

Mass  N *V * R *GHG *103 

c,i v c i Equation 9

where, 

Massc,i = Annual EOR injection gas venting emissions in metric tons at critical 

conditions “c” from blowdowns. 

Background Technical Support Document – Petroleum and Natural Gas Industry 46 
 

 

 

N = Number of blowdowns for the equipment in calendar year. 

Vv = Total volume in cubic meters of blowdown equipment chambers 

(including, but not limited to, pipelines, compressors and vessels 

between isolation valves. 

Rc = Density of critical phase EOR injection gas in kg/m3

. Use an appropriate 

standard method published by a consensus-based standards organization 

to determine density of super critical EOR injection gas. 

GHGi = mass fraction of GHGi in critical phase injection gas 

C. Emission Factors 

The EPA/ GRI and EPA/Radian studies provide emissions factors for almost all the 

emissions sources in the petroleum and natural gas industry. These can potentially be used to 

estimate emissions for reporting under the rule. However, the emissions factors are not 

appropriate for all the emissions sources. The emissions factors were developed more than a 

decade ago when the industry practices were much different from now. In some cases, the 

emissions factors were developed using limited sample data and knowledge about the 

industry’s operations (e.g., wells, compressors). While the available emission factors alone 

may not be appropriate for GHG reporting, certain emission factors may be sufficient, under 

certain circumstances, to calculate and characterize GHG emissions. Also, the introduction 

of many emissions reduction technologies are not reflected in the emissions factor estimates. 

However, the two studies provide raw emission data that in conjunction with newer 

publically available data (e.g., Clearstone 2006 study) could be used for developing emission 

factors for certain sources. Refer to Section 4(c)(ii), 6(c), and Appendix F and G of the TSD 

for a complete discussion of the use of emission factors in the reporting rule. 

D. Combination of Direct Measurement and Engineering Estimation 

Emissions from several sources can be estimated using a combination of direct measurement 

and engineering estimation. Direct measurement can provide either a snapshot of the 

emissions in time or information on parameters that can be used for using a calculative 

method to estimate emissions. Following are options for using such a combination of 

monitoring methods to estimate emissions. 

8. Flare stacks 

Flares typically burn two types of hydrocarbon streams; continuous and intermittent. 

Continuous streams result from vented emissions from equipment such as glycol dehydrators 

and storage tanks. Intermittent streams result from such sources as emergency releases from 

equipment blowdown. It must be noted that most of these streams, continuous or intermittent, 

can be covered using monitoring methods already provided on an individual emissions 

source level. 

Background Technical Support Document – Petroleum and Natural Gas Industry 47 
 

Flare emissions whether from continuous or intermittent streams can be monitored using one 

of the following monitoring methods 

Method 1: 

Many facilities, such as in the processing sector, may already have a continuous flow monitor 

on the flare. In such cases, the measured flow rates can be used when the monitor is 

operational, to calculate the total flare volumes for the calendar year. 

Method 2: 

Another option is to require the estimation of all streams of hydrocarbons going to the flare at 

an individual emissions source level. Here engineering calculation and other methods 

described for different sources in this Section of the TSD can be used to estimates of volume 

flare gas 

Method 3: 

When the flare stream is mostly continuous, a flow velocity measuring device (such as hot 

wire anemometer, pitot tube, or vane anemometer) can be inserted directly upstream of the 

flare stack to determine the velocity of gas sent to flare. The GHG volumetric emissions at 

actual conditions can then be calculated as follows. 

E a,CH 4	 un  combusted   V a *(1) * X	 CH 4 Equation 10

Ea ,CO 2 un  combusted   Va * X CO 2	 Equation 11 

E , 2 a CO (combusted)  *Va *Yj *Rj

j	 Equation 12 

Ea,i  Ea,CO 2 (combusted )  Ea,i (un  combusted ) Equation 13 

where, 

Ea,i(un-combusted) = Contribution of annual un-combusted emissions from 

flare stack in cubic feet, under ambient conditions, for 

both CH4 and CO2 as described in Equation 10 and 

Equation 11. 

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

combustion from flare stack, in cubic feet, under ambient 

conditions 

Ea,i(total) = Total annual emissions from flare stack in cubic feet, 

under ambient conditions 

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

the year 

Background Technical Support Document – Petroleum and Natural Gas Industry 48 
 

 

 

 

 

η = Percent of natural gas combusted by flare (default is 98 

percent) 

Xi = Concentration of GHGi in gas to the flare; where i = CO2 

or CH4. 

Yj = Concentration of natural gas hydrocarbon constituents j 

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

plus). 

Rj = Number of carbon atoms in the natural gas hydrocarbon 

constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 

for butane, and 5 for pentanes plus) 

In some cases the facility may have a continuous gas composition analyzer on the flare. Here 

the compositions from the analyzer can be used in calculating emissions. If an analyzer is not 

present then a sample of the gas to the flare stack can be taken every quarter to evaluate the 

composition of GHGs present in the stream. The natural gas composition analyses can be 

conducted using ASTM D1945-03. It must be noted that for processing plants there are two 

distinct streams of natural gas with significant differences in composition. The natural gas 

stream upstream of the de-methanizer can be expected to have higher C2+ components as 

opposed to the residue stream downstream of the de-methanizer. In addition, the CO2 content 

in natural gas can change significantly after acid gas removal. Finally, processing plants may 

send pure streams of separated hydrocarbons such as ethane, propane, butane, iso-butane, or 

pentanes plus to the flare during an emergency shutdown of any particular equipment. Such 

variations in hydrocarbon streams being sent to the flare would have to be accounted for in 

the monitoring methodology. 

9. Compressor wet seal degassing vents 

In several compressors, the wet seal degassing vents emit flash gas from degassed oil straight 

into or close to the compressor engine exhaust vent stack. The temperatures at the degassing 

vent exit are very high due to the proximity to the engine exhaust vent stack. In such cases, 

emissions can be estimated using a flow velocity measuring device (such as hot wire 

anemometer, pitot tube) or a flow rate measurement device such as vane anemometer, which 

can be inserted directly upstream of the degassing unit vent exit to determine the velocity or 

flow rate of gas sent to the vent. If a velocity measuring device is used then the volume of 

natural gas sent to vent can be calculated from the velocity measurement using the 

manufacturer manual for conversion. Annual emissions can be estimated using meter flow 

measurement as follows: 

Ea,i  MT * T * Mi * (1 B)	 Equation 14 

where, 

Ea,i = Annual GHGi (either CH4 or CO2) volumetric emissions at ambient 

conditions 

Background Technical Support Document – Petroleum and Natural Gas Industry 49 
MT = Meter reading of gas emissions per unit time 

T = Total time the compressor associated with the wet seal(s) is operational in 

the calendar year 

Mi = Mole percent of GHGi in the degassing vent gas 

B = percentage of centrifugal compressor wet seal degassing vent gas sent to 

vapor recovery or fuel gas or other beneficial use as determined by keeping 

logs of the number of operating hours for the vapor recovery system or 

recycle to fuel gas system 

A sample representative of the gas to the degassing vent can be taken every quarter to 

evaluate the composition of GHGs present in the stream using ASTM D1945-03. Some 

facilities may send their degassing vent vapors to a flare or to fuel use. The monitoring 

method will have to account for this. 

10. Reciprocating compressor rod packing venting 

There are three primary considerations for emissions from rod packing on reciprocating 

compressors. First, the rod packing case may or may not be connected to an open ended line 

or vent. Second, the rod packing may leak through the nose gasket in addition to the 

emissions directed to the vent. And third, the emissions from rod packing will vary 

depending on the mode of operation of the reciprocating compressor – running, standby and 

pressurized, or standby and de-pressurized. 

If the rod packing case is connected to an open ended line or vent then emissions from the 

rod packing case can be estimated using bagging or high volume sampler. Alternatively, a 

temporary meter such as vane anemometer or permanent meter such as orifice meter can be 

used to measure emissions from rod packing vents. 

If the rod packing case is open to the atmosphere then the emissions from the rod packing 

case will be mingled with the emissions from the nose gasket. The emissions from an open 

rod packing case usually will migrate to the distance piece (dog house), and if the distance 

piece is enclosed then this emissions will migrate to the engine crank case, before being 

emitted to the atmosphere. There are two possible options to monitor these emissions. The 

first option is to use an emissions factor for rod packing along with a population count. The 

second option is to require equipment leak detection and measurement to determine the exact 

location and volume of emission. 

Typically, rod packing emissions vary with the mode of operation of the compressor. The 

emissions are highest when the compressor is operating and lower when they are in standby 

pressurized mode. When the compressor is standby de-pressurized there might be some 

migration of natural gas from the unit isolation valve through the rod packing. But rod 

packing emissions from leaking unit isolation valves is for the most part negligible because 

unit isolation valves leak primarily through the blowdown vent stack. Hence to correctly 

Background Technical Support Document – Petroleum and Natural Gas Industry 50 
 

characterize annual emissions from rod packing, estimation of emissions at two compressor 

modes, operating and standby pressurized, may be required. 

11. Compressor isolation valve and blowdown valve 

Blowdown valves on a compressor are used to depressurize and release all of the natural gas 

in the compressor chambers when the compressor is taken offline. These blowdown valves, 

however, can leak in some cases when the compressor is in operating or standby pressurized 

modes. Isolation valves are used to isolate the compressor chambers from the pipeline that 

connects the natural gas flow into and out of the compressor. These isolation valves can leak 

when the compressor is take offline. Both the blowndown valve and isolation valve are 

typically connected to the blowdown vent system. The emissions from leaks in an isolation 

valve or blowdown valve can be detected and measured using detection and measurement 

methods as discussed in Sections (6)(b)(i) and (6)(b)(ii)(A) of the TSD. 

12. Storage tanks 

Emissions from storage tanks can be estimated using one of the following four methods. 

Method 1: 

In the case of storage tanks, emissions rates are not constant; and thus, a one-time 

measurement may not provide accurate emissions rates for the entire reporting period. To 

accurately estimate emissions from storage tanks, it is necessary to conduct multiple 

measurements during a cycle of operation that is representative of the tank operations 

through the year. Equation 15 below can be used to calculate GHG emissions: 

Ea,h  Q  ER	 Equation 15 

where, 

Ea,h = hydrocarbon vapor emissions at ambient conditions, in cubic meters 

Q = storage tank total annual throughput, in barrels 

ER = measured hydrocarbon vapor emissions rate per throughput (e.g. 

meter/barrel) 

ER can be estimating using the following procedure: 

	 The hydrocarbon vapor emissions from storage tanks can be measured using a 

flow meter for a test period that is representative of the normal operating 

conditions of the storage tank throughout the year and which includes a complete 

cycle of accumulation of hydrocarbon liquids and pumping out of hydrocarbon 

liquids from the storage tank. 

	 The throughput of the storage tank during the test period can be recorded. 

Background Technical Support Document – Petroleum and Natural Gas Industry 51 
	 The temperature and pressure of hydrocarbon vapors emitted during the test 

period can be recorded. 

	 A sample of hydrocarbon vapors can be collected for composition analysis. 

Method 2: 

A second method is to use simulation software such as E&P Tank (GEO-RVP) to estimate 

vented emissions from storage tanks. Therefore, any standard simulation software could be 

used assuming it accounts for the following operational parameters: 

	 Feed liquid flow rate to tank; 

	 Feed liquid API gravity; 

	 Feed liquid composition or characteristics; 

	 Upstream (typically a separator) pressure; 

	 Upstream (typically a separator) temperature; 

	 Tank or ambient pressure; and 

	 Tank or ambient temperature; 

	 Sales oil API gravity; 

	 Sales oil production rate; 

	 Sales oil Reid vapor pressure; 

Method 3: 

A third method to estimating emissions from storage tanks is to use the Peng-Robinson 

equation directly instead of using a simulation software. The Peng-Robinson equation is the 

basis behind most of the simulation softwares and therefore will result in estimates similar to 

Method 2 above. 

p 

where: 

p 

R 

T 

Vm

‘ 

α

where: 

Ω

Tc 

RT a   2 2 Equation 16 V	 m  b V m m  2bV  b

= Absolute pressure
 

= Universal gas constant
 

= Absolute temperature 

0.45724R2

T 2 0.7780RT 

= Molar volume = c = c
 

pc pc
 



2

  2 T 

= 1   0.37464 1.54226  0.26992 1    T    c 

= Acentric factor of the species 

= Critical temperature 

Background Technical Support Document – Petroleum and Natural Gas Industry 52 
Pc = Critical pressure 

Method 4: 

A conservative method to estimate GHG emissions from flashing in storage tanks is to take a 

sample of liquids at the low pressure separator (i.e. the last separator before the liquids enter 

the storage tank) and then assume that all the CH4 and CO2 dissolved in this sample is 

released to the atmosphere. 

Method 5: 

A fifth method for storage tank vented emissions quantification is use of the Vasquez-Beggs 

equation. This correlation equation provides an estimate of the gas-to-oil ratio for flashing 

tank vapors; however, it does not provide the GHG of the vapors, so composition analysis of 

tank vapors is still required. Equation 17 demonstrates the use of this correlation equation: 

 

GOR  A G fg  Psep 14.7 exp C  Goil  Equation 17  T   460  sep 

where, 

GOR = ratio of flash gas production to standard stock tank barrels of oil produced, 

in standard cubic feet/barrel (barrels corrected to 60°F) 

Gfg = Specific gravity of the tank flash gas, where air = 1. A suggested default 

value for Gfg is 1.22 

Goil = API gravity of stock tank oil at 60°F 

Psep = Pressure in separator (or other vessel directly upstream), in pounds per 

square inch gauge 

Tsep = Temperature in separator (or other vessel directly upstream of the tank), °F 

A = 0.0362 for Goil </= 30°API, or 0.0178 for Goil > 30°API 

B = 1.0937 for Goil </= 30°API, or 1.187 for Goil > 30°API 

C = 25.724 for Goil </= 30°API, or 23.931 for Goil > 30°API 

Sometimes one or more emissions source vents may be connected to the storage tank. In such 

cases the emissions from these sources will be commingled with the emissions from the 

storage tank. In addition, two phase separators directly upstream of the storage tank may not 

have a vortex breaker. This can lead to channeling of natural gas from the separator to the 

storage tank. All these multiple scenarios mean that only Method 1 could potentially capture 

such miscellaneous sources connected to the storage tank. If, however, Method 1 is 

performed at a time when say the separator is not vortexing then even Method 1 may not 

capture the emissions from the miscellaneous emissions sources connected to the storage 

tank. Hence there is no single method that can identify these variations in storage tank 

emissions that represent multiple sources. These data are available from two recent studies 

provided by the Texas Commission on Environmental Quality (2009) and the Texas 

Environment Research Consortium (2009) that highlight this fact. A potential option to 

correct such scenarios where other emissions sources are connected to the storage tank or if 

the separator is vortexing is to use multipliers on emissions estimated from Methods 1 and 2 

above. Two such potential multipliers are as below, 

Background Technical Support Document – Petroleum and Natural Gas Industry 53 
 

(i) The emissions for sales oil less than 45 API gravity can be multiplied by 3.87 

(ii) The emissions for sales oil equal to or greater than 45 API gravity can be 

multiplied by 5.37 

Details on the development of these multipliers are available in Appendix E. 

Dump Valve Emissions Estimation 

Storage tank vented emissions quantification could include the emissions that result from a 

gas-liquids separator liquid dump valve malfunction. Liquid dump or scrubber dump valves 

open periodically to reduce the accumulation of liquids in the separator. Scrubber dump 

valves can get stuck open due to debris preventing it from closing properly. In such a case, 

natural gas from the separator is lost through the dump valve ultimately passing through the 

storage tank’s atmospheric vent. Equation 18, below, can be used to account for storage tank 

emissions with improperly closed scrubber dump valves. 

Es,i  CFn  En Tn   En  8760 Tn  Equation 18 

where, 

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

storage tank in cubic feet. 

En = Storage tank emissions as determined in calculation methods 1, 2, or 5 

(with wellhead separators) of this section of the TSD during time Tn in 

cubic feet per hour. 

Tn = Total time the dump valve is not closing properly in the calendar year in 

hours. Tn is estimated by maintenance or operations records (records) such 

that when a record shows the valve to be open improperly, it is assumed 

the valve was open for the entire time period preceding the record starting 

at either the beginning of the calendar year or the previous record showing 

it closed properly within the calendar year. If a subsequent record shows it 

is closing properly, then assume from that time forward the valve closed 

properly until either the next record of it not closing properly or, if there is 

no subsequent record, the end of the calendar year. 

CFn = Correction factor for tank emissions for time period Tn is 3.87 for sales oil 

less than 45 API gravity. Correction factor for tank emissions for time 

period Tn is 5.37 for sales oil equal to or greater than 45 API gravity. 

Correction factor for tank emissions for time period Tn is 1.0 for periods 

when the dump valve is closed. 

Et = Storage tank emissions as determined in calculation methods 1, 2, or 3 of 

this section of the TSD at maintenance or operations during the time the 

dump valve is closing properly (ie.8760-Tn) in cubic feet per hour. 

Transmission Storage Tanks: 

Background Technical Support Document – Petroleum and Natural Gas Industry 54 
 

Storage tanks in the onshore natural gas transmission segment typically store the condensate 

from the scrubbing of pipeline quality gas. The volume of condensate is typically low in 

comparison to the volumes of hydrocarbon liquids stored in the upstream segments of the 

industry. Hence the emissions from condensate itself in the transmission segment are 

insignificant. However, scrubber dump valves often get stuck due to debris in the condensate 

and can remain open resulting in natural gas loss via the open dump valve. If the scrubber 

dump valve is stuck and leaking natural gas to the tank then the emissions will be visibly 

significant and will not subside to inconspicuous volumes. If the scrubber dump valve 

functions normally and shuts completely after the condensate has been dumped then the 

storage tank emissions should subside and taper off to insignificant quantities; this will 

happen because once the condensate has flashed the dissolved natural gas there will not be 

significant emissions from the storage tank. If persistent and significant emissions are 

detected then a measurement of those emissions may be required using a temporary meter or 

ultrasonic devices that can detect and measure the emissions in a non-invasive way. 

Storage tank vapors captured using vapor recovery systems or sent to flares will have to be 

accounted for in the above methods. 

13. Well testing venting and flaring 

During well testing the well usually is flowing freely and the produced hydrocarbons are 

typically vented and/ or flared. A gas to oil ratio is often determined when conducting well 

testing. This information can be reliably used to estimate emissions from well testing 

venting using Equation 19 below: 

Es,n  GOR * FR * D Equation 19

where, 

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

under actual conditions 

GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to 

hydrocarbon liquids produced of all API gravities 

FR = Flow rate in barrels of oil per day for the well being tested 

D = Number of days during the year the well is tested
 

When well testing emissions are sent to a flare then the emissions estimated above should be 

adjusted to reflect the combustion emissions. 

14. Associated gas venting and flaring 

Often times when onshore petroleum production fields are located in a remote location, the 

associated gas produced is sent to a vent or flare. This is because the associated natural gas 

is stranded gas, meaning that it is not economical to send the usually low volumes to the 

market via a pipeline system. Also, gas from producing wells may sometimes be routed to a 

Background Technical Support Document – Petroleum and Natural Gas Industry 55 
 

 

 

vent or a flare due to system upset conditions or for maintenance of field equipment. In such 

cases the emissions can be estimated using the volume of oil produced and the corresponding 

gas to oil ratio as following; 

Vented associated natural gas emissions can be estimated using Equation 20 below: 

Ea,n  GOR *V Equation 20 

where, 

Ea,n = Annual volumetric natural gas emissions from associated gas venting 

under actual conditions, in cubic feet 

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 

V = Total volume of oil produced in barrels in the calendar year. 

When well testing emissions are sent to a flare then the emissions estimated above will have 

to be adjusted to reflect the combustion emissions. 

15. Hydrocarbon liquids dissolved CO2 

Onshore petroleum production that uses EOR with CO2 injection results in the production of 

petroleum that has significant amounts of CO2 dissolved in it. This CO2 is usually separated 

from the liquid petroleum component, and re-injected in a closed loop system (although this 

CO2 might be eventually recovered when the EOR operation at the site is closed). However, 

the liquid portion of petroleum still contains dissolved CO2, since separation usually takes 

place at higher than ambient pressure. Most of this CO2 is then released in a storage tank 

where the CO2 flashes out of the liquid hydrocarbons. But even after this stage some amount 

of CO2 remains entrapped in the liquid hydrocarbons and is lost to the atmosphere during the 

transportation and processing phases. 

The amount of CO2 retained in hydrocarbon liquids after flashing in tanks can be determined 

by taking quarterly samples to account for retention of CO2 in hydrocarbon liquids 

immediately downstream of the storage tank. The emissions from this hydrocarbon 

dissolved CO2 can be estimated using Equation 21 below: 

Masss, CO2 = Shl * Vhl Equation 21 

where, 

Masss, CO2 = Annual CO2 emissions from CO2 retained in hydrocarbon liquids 

beyond tankage, in metric tons. 

Shl = Amount of CO2 retained in hydrocarbon liquids in metric tons per 

barrel, under standard conditions. 

Background Technical Support Document – Petroleum and Natural Gas Industry 56 
Vhl = Total volume of hydrocarbon liquids produced in barrels in the 

calendar year. 

16. Produced water dissolved CO2 

EOR operations may use water injection techniques to pressurize the reservoir and drive the 

hydrocarbons containing CO2 through the reservoir and up the production well. This water, 

like the liquid petroleum, contains dissolved CO2, since CO2 readily dissolves in water. This 

produced water is re-circulated for injection into the reservoir. However, often it may be sent 

through tankage to avoid a two phase flow of CO2 and water through the injection pumps. In 

such cases the CO2 dissolved in the water is flashed to the atmosphere in the storage tank. 

These emissions can be determined similar to hydrocarbon dissolved CO2 by sampling the 

water on a periodic basis. To determine retention of CO2 in produced water immediately 

downstream of the separator where hydrocarbon liquids and produced water are separated the 

following equation can be used. 

Masss, CO2 = Spw * Vpw	 Equation 22 

where, 

Masss, CO2 = Annual CO2 emissions from CO2 retained in produced water beyond 

tankage, metric tons. 

Spw = Amount of CO2 retained in produced water in metric tons per barrel, under 

standard conditions. 

Vpw = Total volume of produced water produced in barrels in the calendar year. 

EOR operations that route produced water from separation directly to re-injection into the 

hydrocarbon reservoir in a closed loop system without any leakage to the atmosphere could 

be exempted from reporting. 

17. Well venting for liquids unloading 

There are three potential methods to estimate well venting emissions from liquids unloading. 

Method 1 requires installation of a flow meter temporarily for developing an emissions 

factor. Method 2 requires a transient pressure spike engineering analysis across the vent pipe 

during one well unloading event. Method 3 uses an engineering calculation method that uses 

the well’s physical parameters to estimate emissions. Each of the three options is discussed 

below. 

Method 1: 

For each unique well tubing diameter and producing horizon/formation combination in each 

gas producing field where gas wells are vented to the atmosphere to expel liquids 

Background Technical Support Document – Petroleum and Natural Gas Industry 57 
 

 

accumulated in the tubing, a recording flow meter can be installed on the vent line used to 

vent gas from the well (e.g. on the vent line off the separator or a storage tank). An 

emissions factor can be estimated as an average flow rate per minute of venting calculated 

for each unique tubing diameter and producing horizon/formation combination in each 

producing field. The emission factor can be applied to all wells in the field that have the 

same tubing diameter and producing horizon/formation combination, multiplied by the 

number of minutes of venting of all wells of the same tubing diameter and producing 

horizon/formation combination in that field. A new factor can be determined periodically to 

track field declining formation pressure and flow potential. 

Method 2: 

For each unique well tubing diameter and producing horizon/formation combination in each 

gas producing field where gas wells are vented to the atmosphere to expel liquids 

accumulated in the tubing, an engineering analysis of the transient pressure spike across the 

vent line for well unloading events can be conducted. An emissions factor as an average 

flow rate per minute of venting can then be calculated through such an analysis. This 

emissions factor can be applied to all wells in the field that have the same tubing diameter 

and producing horizon/formation combination, multiplied by the number of minutes of 

venting all wells of the same tubing diameter and producing horizon/formation combination 

in that field. A new emission factor can be determined periodically to track field declining 

formation pressure and flow potential. Emissions from well venting for liquids unloading 

can be calculated using Equation 23 below: 

Es,n = T * X * EF Equation 23 

where, 

Es,n = Annual natural gas emissions at standard conditions 

T = Amount of time of well venting 

X = Concentration of GHG i in gas vented. 

EF = Emission factor developed using the transient pressure spike 

For wells that have a plunger lift installed on a timer or programmable logic controller that 

vent to the atmosphere and automatically closes the vent valve when the plunger is received 

at the well head, an equation calculating the volume of gas in the tubing string calculated at 

sales pipeline pressure can be used. This equation is unique for each category of wells with 

the same well depth and tubing size. The emissions factor can be estimated by multiplying 

the tubing cross-sectional area by the tubing string length from wellhead to the bottom 

resting location of the plunger, corrected for sales line pressure and average gas flowing 

temperature. 

Background Technical Support Document – Petroleum and Natural Gas Industry 58 
 

 

Method 3: 

The Natural Gas STAR Lessons Learned – Installing Plunger Lift Systems in Gas Wells 

(available at <http://epa.gov/gasstar/documents/ll_plungerlift.pdf>) provides an engineering 

estimation method in its Appendix. This method uses physical characteristics of the well that 

are usually well known. Using this method, emissions from well venting for liquids 

unloading can be calculated using Equation 24 below: 

Ea,n = {(0.37×10-3) * CD2 * WD * SP * V} + Equation 24 {SFR*(HR-T)*Z} 

where, 

Es,n = Annual natural gas emissions at actual conditions, in cubic feet/year 

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

CD = Casing diameter (inches) 

WD = Well depth (feet) 

SP = Shut-in pressure (psig) 

V = Number of vents per year 

SFR = Average sales flow rate of gas well in cubic feet per hour 

HR = Hours that the well was left open to the atmosphere during unloading 

T = 1 hour for average well to blowdown casing volume at shut-in 

pressure for wells without plunger lift assist; 0.5 hour for average 

well to blowdown tubing volume at sales line pressure when using 

plunger lift assist. 

Z = If HR is less than 1.0 then Z is equal to 0. If HR is greater than or 

equal to 1.0 then Z is equal to 1. 

For details on the time taken to blowdown a casing and tubing to unload a well, see “Change 

to Rule Equation W-7: Time to Vent the Casing Gas from Well Liquids Unloading” in the 

rulemaking docket (EPA-HQ-OAR-2009-0923) 

18. Gas well venting during well completions and workovers 

There are two methods to estimate emissions from gas well venting during well completions 

and workovers. Method 1 requires the installation of a recording flow meter on the vent line 

to the atmosphere or to a flare. Method 2 is an engineering calculation for flow based on the 

pressure drop across the well choke for subsonic and sonic flow. Method 3 uses the 

production of the well to determine emissions. 

Method 1: 

A recording flow meter can be installed on the vent line to the atmosphere or to a flare during 

each well completion or workover event. This one time reading can be extrapolated to yearly 

emissions based on the time taken for completion or workover and the number of times the 

Background Technical Support Document – Petroleum and Natural Gas Industry 59 
 

well is worked over (if more than once per year). Such emissions factors can be developed 

for representative wells in a field on a yearly basis. During periods when gas is combusted in 

a flare, the carbon dioxide quantity can be determined from the gas composition with an 

adjustment for combustion efficiency. This method can also be used when phase separation 

equipment is used and requires the installation of a recording flow meter on the vent line to 

the atmosphere or to a flare. 

Emissions from gas well venting during well completions and workovers can be calculated 

using Equation 25 below: 

Ea,n = T * FR – EnF - SG Equation 25 

where, 

Ea,n = Annual natural gas vented emissions at ambient conditions in cubic feet 

T = Cumulative amount of time in hours of well venting during the reporting 

period 

FR = Flow rate in cubic feet per hour, under ambient conditions 

EnF = Volume of CO2 or N2 injected gas in cubic feet at standard conditions that 

was injected into the reservoir during an energized fracture job. If the 

fracture process did not inject gas into the reservoir, then EnF is 0. If 

injected gas is CO2 then EnF is 0. 

SG = Volume of natural gas in cubic feet at standard conditions that was 

recovered into a sales pipeline. If no gas was recovered for sales, SG is 0. 

Method 2: 

Using pressures measured upstream and downstream of the well choke, the average flow rate 

across the choke can be calculated. Using engineering judgment and the total time that flow 

across the choke is occurring, the total volume to the atmosphere or a flare during the backflow period can be estimated. This one time reading can be extrapolated to yearly emissions 

based on the time taken for completion or workover and the number of times the well is 

worked over (if more than once per year). Such emissions factors can be developed for 

representative wells in a field on a yearly basis. 

Emissions from gas well venting during well completions and workovers can be calculated 

using Equation 26 for subsonic flow and Equation 27 for sonic flow below: 

1.515 1.758    P   P  5 2 2 FR  1.27 10 * A* 3430*Tu * 

      Equation 26  P1   P1    

where, 

Background Technical Support Document – Petroleum and Natural Gas Industry 60 
 

 

 

 

 

 

FR = Average flow rate in cubic feet per hour, under subsonic flow 

conditions. 

A = Cross sectional area of orifice (m2). 

P1 = Upstream pressure (psia). 

Tu = Upstream temperature (degrees Kelvin). 

P2 = Downstream pressure (psia). 

3430 = Constant with units of m2

/(sec2 * K). 

1.27*105

 = Conversion from m3/second to ft3/hour. 

FR 1.27 105 * A* 187.08*Tu Equation 27 

where, 

FR = Average flow rate in cubic feet per hour, under sonic flow conditions.
 

A = Cross sectional area of orifice (m2

). 

Tu = Upstream temperature (degrees Kelvin). 

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

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

Method 3: 

A quick and least burdensome method to determine emissions from well venting during 

completions and workovers is to use the daily gas production rate to estimate emissions using 

Equation 28 below: 

E V a,n  f f * T Equation 28 f 

where, 

Ea,n = Annual natural gas emissions in cubic feet at actual conditions from gas 

well venting during well completions and workovers without hydraulic 

fracturing. 

f = Total number of well completions without hydraulic fracturing in a field. 

Vf = Average daily gas production rate in cubic feet per hour of each well 

completion without hydraulic fracturing. This is the total annual gas 

production volume divided by total number of hours the wells produced 

to the sales 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. 

Background Technical Support Document – Petroleum and Natural Gas Industry 61 
Tf = Time each well completion without hydraulic fracturing was venting in 

hours during the year. 

19. Onshore production combustion emissions 

The combustion process is well understood in terms of GHG emissions. The use of emissions 

factors is reliable if the quantity and type of fuel combustion is known. The alternative is to 

use combustion emissions stack monitors, which are cost prohibitive and may not be 

considered appropriate for onshore production. Onshore production segment does not meter 

its fuel, since most of the equipment in the field is located upstream of the lease meter. 

However, requiring meters at every single well site to measure fuel volume is not feasible in 

terms of cost. Hence, the use of heat rating of the equipment along with the hours of 

operations is the most feasible approach to estimate the amount of fuel consumed. Using the 

emissions factors approach, GHG emissions from combustion equipment can be estimated 

using broadly two methods; fuel specific emissions factors and equipment specific fuel 

factors. Fuel specific emissions factors are related to a particular type of fuel in use and do 

not take into account the type of equipment (e.g. whether internal or external combustion 

equipment). The advantage of this type of approach is that if the fuel volume for a facility is 

known then there is no need to identify the particular equipment that is combusting it. The 

disadvantage in this method though is that it does not take into account the differing levels of 

efficiency between different types of equipment. On the other hand, equipment specific 

emissions factors take into account the efficiency levels of each equipment type 

corresponding with the type of fuel it combusts. However, the disadvantage of using 

equipment specific emissions factors is that fuel consumption has to be known at an 

equipment level. Both fuel specific and equipment specific emissions factors are available 

form the API Compendium and EPA AP-42 documents. 

20. Natural gas distribution combustion emissions 

The combustion emissions from natural gas distribution result mainly from inline gas heaters, 

small compressors, etc. Heaters are used to prevent natural gas dropping below the dew point 

(where liquids, mainly water, might condense) or to maintain the temperature of gas let-down 

in pressure from high pressure transmission pipelines to low pressure distribution gate station 

metering systems. The Joule-Thompson effect causes gas temperature to drop when the gas is 

suddenly expanded across a valve or orifice. Thus, transmission pressure gas at, for example 

1000 psig and ambient temperature of 70°F can drop well below freezing when depressurized 

to 100 psig. This gas may be heated to a temperature above so-called “dry” gas dew point or 

a range consistent with distribution gate station meter calibrations. These are usually small 

sources of emissions and may not contribute significantly to the total emissions from the 

distribution segment. However, some natural gas distribution systems operate compressor 

stations that are similar in size and operations to the natural gas transmission or gas storage 

systems. These compressor stations may have significant emissions and could be captured 

under combustion emissions reporting. 

Background Technical Support Document – Petroleum and Natural Gas Industry 62 
 

c. Leak detection and leaker emission factors 

For leaks from standard components such as connectors, valves, meters, etc. emissions can 

be estimated by conducting an equipment leak detection program and applying a leaker 

emissions factor to those sources found to be emitting. This option may be considered over 

direct measurement (e.g., high flow sampler) to avoid the capital cost in measurement 

equipment and labor hours to conduct measurement. Estimating emissions using leaker 

emission factors is more accurate than population factors because leaker factors are applied 

to leaks once they are identified. Since equipment leaks occur randomly within a population 

of components, determining the number of actual leaking component improves the emissions 

estimate. Equation 29, below, can be used for this purpose. 

Es,i  GHGi *EFX *Tx Equation 29 x 

where, 

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

each equipment leak source in cubic feet. 

x = Total number of this type of emissions source found to be leaking during 

Tx. 

EFE = Leaker emission factor for specific sources 

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

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

the total hydrocarbon of the feed natural gas; other segments GHGi 

equals 1 for CH4 and 1.1 × 10-2 for CO2. 

Tx = The total time the component was found leaking and operational, in 

hours. If one leak detection survey is conducted, assume the component 

was leaking for the entire calendar year. If multiple leak detection 

surveys are conducted, assume that the component found to be leaking 

has been leaking since the previous survey or the beginning of the 

calendar year. 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. 

Leaker emissions factors are available for specific sources for onshore natural gas 

processing facilities, onshore natural gas transmission compression facilities, 

underground natural gas storage facilities, liquefied natural gas storage facilities, 

liquefied natural gas import and export facilities, and natural gas distribution 

facilities. These leaker emissions factors and a discussion on their development are 

available in Appendix F. 

d. Population Count and Emission Factors. 

For equipment leaks that are geographically dispersed or where the cost burden is an issue, 

emissions can be estimated using the population count of emissions sources and a 

Background Technical Support Document – Petroleum and Natural Gas Industry 63 
 

corresponding population emissions factor. This option may be considered over direct 

measurement to avoid the cost of purchasing a high volume sampler, screening device, and 

the labor hours to use both. Such an option may be most feasible for emissions sources with 

gas content greater than 10 percent CH4 plus CO2 by weight since otherwise the emissions 

factors may overestimate overall GHG emissions. The disadvantage of using population 

factors is that it will only provide an estimate of potential emissions, not actual emissions. It 

will also not provide any trends in changes in emissions over time, since the only variable is 

equipment/ component count, which in most operations does not change significantly. Hence, 

petroleum and natural gas operators who are voluntarily reducing emissions by conducting 

periodic leak detection and repair will end up reporting more emissions than is actually 

occurring in their operations. Emissions from all sources listed in this paragraph of this 

section can be calculated using Equation 30. 

Es,i  Count * EF * GHGi *T	 Equation 30 

where, 

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

each equipment leak source category 

Count = Total number of this type of emission source at the facility 

EF = Population emission factor for specific sources listed in Appendix F. 

GHGi = for onshore petroleum and natural gas production facilities and onshore 

natural gas processing facilities, concentration of GHG i, CH4 or CO2, in 

produced natural gas or feed natural gas; for other facilities GHGi equals 

1 

T = Total time the specific source associated with the equipment leak was 

operational in the reporting period, in hours 

Population emissions factors are available for specific sources for onshore petroleum and 

natural gas production facilities, onshore natural gas processing facilities, onshore natural 

gas transmission compression facilities, underground natural gas storage facilities, 

liquefied natural gas storage facilities, liquefied natural gas import and export facilities, 

and natural gas distribution facilities. These population emissions factors and a 

discussion on their references are available in Appendix G. 

e. Method 21 

This is the authorized method for detecting volatile organic carbon (VOC) emissions under 

Title 40 CFR. The method specifies the performance of a portable VOC emission detection 

instrument with a probe not exceeding one fourth inch outside diameter, used to slowly 

circumscribe the entire component interface where a leak could occur. The probe must be 

maintained in close proximity to (but not touching) the interface; otherwise it could be 

damaged by rotating shafts or plugged with ingested lubricants or greases. In most cases, it 

can be no more than 1 centimeter away from the leak interface. Method 21 does not specify 

Background Technical Support Document – Petroleum and Natural Gas Industry 64 
 

leak definitions; they are defined within specific subparts of the Title 40 CFR. Method 21 

also allows certain alternative equipment leak detection methods, such as soap solutions 

(where the leaking source is below the boiling point and above the freezing point of the soap 

solution, does not have areas open to the atmosphere that the soap solution cannot bridge, 

and does not have signs of liquid leakage). Method 21 does not specify any emissions mass 

or volumetric quantification methods, but only specifies an emissions concentration 

expressed in parts per million of combustible hydrocarbons in the air stream of the 

instrument probe. This leak detection data has been used by state emission inventories with 

“leaker” factors developed by the Synthetic Organic Chemicals Manufacturing Industry 

(SOCMI)8 to estimate the quantity of VOC emissions. SOCMI factors were developed from 

petroleum refinery and petrochemical plant data using Method 21. 

Method 21 instrumentation technology has been used for over 30 years to detect leaks. The 

approach uses gas concentration measurement of air and combustible gas drawn into the tip 

of a probe manually circumscribed on or within one centimeter along the entire potential seal 

surface or center of a vent to detect equipment leaks. This original practice is required for 

certain regulated components that are reachable with the hand-held leak detection instrument 

used while standing on the ground or fixed platform accessible by stairs (i.e. does not require 

climbing ladders, standing on stools or use of bucket-lift trucks to access components). In a 

study conducted by API at seven California refineries9 with over five years of measured data 

(11.5 million data points), it was found that 0.13 percent of the components contributed over 

90 percent of the controllable emissions (i.e. equipment leaks or vented emissions that can be 

mitigated once detected). Given the fact that only a small number of sources contribute to 

the majority of emissions, it is important for this final rule to detect and quantify leaking 

sources beyond the scope of Method 21. 

Performance standards for remote leak sensing devices, such as those based on infrared (IR) 

light imaging, or laser beams in a narrow wavelength absorbed by hydrocarbon gases, were 

promulgated in the general provisions of EPA 40 CFR Part 60. This alternate work practice 

(AWP) permits leak detection using an instrument which can image both the equipment and 

leaking gas for all 40 CFR 60 subparts that require monitoring under LDAR. 

In a typical Method 21 program, the costs of conducting emissions detection remain the same 

during each recurring study period. This is because the determination of whether a potential 

source is emitting or not is made only after every regulated source is screened for emissions 

as described above. The OVA/TVA requires the operator to physically access the emissions 

source with the probe and thus is much more time intensive than using the optical gas 

imaging instrument. Optical gas imaging instruments were found to be more cost effective 

for leak detection for this reporting rule as these instruments are able to scan hundreds of 

source components quickly, including components out of reach for an OVA/TVA. 

8

 EPA (1995). Protocol for Equipment Leak Emission Estimates. Research Triangle Park, NC. Publication No. 

EPA-453/R-95-017. Online at: http://www.epa.gov/ttnchie1/efdocs/equiplks.pdf 9

 Hal Taback Company Analysis of Refinery Screening Data, American Petroleum Institute, Publication
 

Number 310, November 1997. 

Background Technical Support Document – Petroleum and Natural Gas Industry 65 
Although leak detection with Method 21 or the AWP in their current form in conjunction 

with leaking component emission factors may not be the best suited for all mandatory 

reporting, the principle could potentially be adopted for estimating emissions from minor 

sources such as equipment leaks from components. Emissions can be detected from sources 

(including those not required under Method 21, i.e. not within arm’s reach) using AWP 

procedures for the optical gas imaging instrument, and applying leaker emissions factors 

available from studies conducted specifically with methane emissions in its scope. This will 

be easier for industry to adapt to and also avoid the use of Synthetic Organic Chemical 

Manufacturing Industry correlation equations or leak factors developed specifically for 

different industry segments (i.e. petroleum refineries and chemical plants). This method will 

also result in the estimation of real emissions, as opposed to potential emissions from 

population emissions factor calculations. 

f. Portable VOC Detection Instruments for Leak Measurement 

As discussed above under Method 21, portable VOC detection instruments do not quantify 

the volumetric or mass emissions. They quantify the concentration of combustible 

hydrocarbon in the air stream induced through the maximum one fourth inch outside 

diameter probe. Since these small size probes rarely ingest all of the emissions from a 

component leak, they are used primarily for equipment leak detection. EPA provides 

emissions quantification guidelines, derived from emissions detection data, for using portable 

VOC detection devices. One choice of instrument emissions detection data is referred to as 

“leak/no-leak,” where equipment is determined to be leaking when the portable instrument 

indicates the provided leak definition. Different leak definitions are specified within the 

subparts of the Clean Air Act. Subpart KKK of 40 CFR Part 60 defines “leakers” for natural 

gas processing facilities as components with a concentration of 10,000 ppm or more when 

measured by a portable leak detection instrument. Components that are measured to be less 

than 10,000 ppm are considered “not leaking.” Hence, these quantification tables have a “noleak” emission factor for all components found to have emissions rates below the leak 

definition, and “pegged” emission factors for all components above the leak definition. 

Alternatively, the “stratified” method has emission factors based on ranges of actual leak 

concentrations below, at and above the leak definition. Portable leak detection instruments 

normally peg at 10,000 ppm, and so are unsuitable for use with the “stratified” quantification 

factors. 

g. Mass Balance for Quantification 

There are mass balance methods that could be considered to calculate emissions for a 

reporting program. This approach would take into account the volume of gas entering a 

facility and the amount exiting the facility, with the difference assumed to be emitted to the 

atmosphere. This is most often discussed for emissions estimation from the transportation 

segment of the industry. For transportation, the mass balance is often not recommended 

because of the uncertainties surrounding meter readings and the large volumes of throughput 

relative to equipment leaks. The mass balance approach may, however, be feasible in cases 

where the volume of emissions is significantly large and recognizable as meter readings. One 

such source is an acid gas recovery unit where the volume of CO2 extracted from natural gas 

Background Technical Support Document – Petroleum and Natural Gas Industry 66 
is significant enough to be registered in a compositional difference of the natural gas and can 

be determined using mass balance. 

h. Gulf Offshore Activity Data System program (GOADS) 

The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) 

conducts a comprehensive activity data collection effort under its Gulf Offshore Activity 

Data System program (GOADS) in compliance with 30 CFR 250.302 through 304. This 

requires all petroleum and natural gas production platforms located in the Federal Gulf of 

Mexico (GoM) to report their activities to BOEMRE once in every three to four years. The 

activity data reported includes counts of emissions sources, volumes of throughputs from 

several pieces of equipment, fuel consumption by combustion devices, and parametric data 

related to certain emissions sources such as glycol dehydrators. This activity data is then 

converted into emissions estimates by BOEMRE and reported subsequently by BOEMRE. 

The BOEMRE summary report provides estimates of GHG emissions in the GoM as well as 

a detailed database of emissions from each source on platform in the GoM. The EPA could 

potentially use this data reported by the GOADS program. However, since the data has 

historically been collected once every three to four years, EPA will not receive new 

emissions information for every reporting period. This means that between BOEMRE 

reporting periods if a new platform is commissioned, an old platform is de-commissioned, 

new equipment is installed on existing platforms, or operating levels of platforms change 

then this information will not get recorded and reported for periods when BOEMRE GOADS 

is not being conducted. This issue however, can be resolved by requiring new platforms to 

use the most recent GOADS methods to estimate emissions and other reporters to adjust their 

emissions annually based on the time each platform was operating in comparison to the 

GOADS reporting year. Finally, the BOEMRE GOADS program does not collect 

information from platforms in the GoM under State jurisdiction, as well as platforms in the 

Pacific and Alaskan coasts. These platforms not under GOADS purview will not have 

existing data to report if GOADS reporting were to be adopted by EPA. Nevertheless, a 

reporting rule can potentially require non-GOADS platforms to adopt the GOADS 

methodology to calculate emissions. If BOEMRE discontinues or delays their GOADS, then 

platform operators under a reporting rule using GOADS may refer to the most recently 

published version of the GOADS program instructions to continue reporting. 

i. Additional Questions Regarding Potential Monitoring Methods 

There are several additional issues regarding the potential monitoring methods relevant to 

estimating equipment leak and vented emissions from the petroleum and natural gas industry. 

i. Source Level Equipment Leak Detection Threshold 

This document does not indicate a particular equipment leak definition or detection threshold 

requiring emissions measurement. This is because different equipment leak detection 

instruments have different levels and types of detection capabilities, i.e. some instruments 

provide a visual image while others provide a digital value on a scale (not necessarily 

Background Technical Support Document – Petroleum and Natural Gas Industry 67 
directly related to mass emissions). Hence the magnitude of actual emissions can only be 

determined after measurement. This, however, may not serve the purpose of a reporting rule, 

which is to limit the burden by focusing only on significant sources of emissions. A facility 

can have hundreds of small emissions (as low as 3 grams per hour) and it might not be 

practical to measure all of them for reporting. 

There are, however, two possible approaches to overcome this issue, as follows; provide an 

instrument performance standard such that any source determined to be emitting per the 

instrument is considered an emissions source, or provide a threshold value for the emitter 

such that any source below the threshold magnitude is not considered an emitter. 

Instrument Performance Standards 

Performance standards can be provided for equipment leak detection instruments and usage 

such that all instruments follow a minimum common detection threshold. Alternatively, the 

AWP to Detect Leaks from Equipment standards for optical gas imaging instruments recently 

adopted by EPA can potentially be proposed. In such a case, all detected emissions from 

components subject to the final rule may require measurement and reporting. This avoids the 

necessity of specifying performance standards. 

The EPA Alternative Work Practice (AWP) promulgated the use of optical gas imaging 

instruments that can detect in some cases emissions as small as 1 gram per hour. The AWP 

requires technology effectiveness of emissions statistically equivalent to 60 grams/hour on a 

bi-monthly screening frequency, i.e. the technology should be able to routinely detect all 

emissions equal to or greater than 60 grams/hour. EPA determined by Monte Carlo 

simulation that 60 grams/hour leak rate threshold and bi-monthly monitoring are equivalent 

to existing work practices (Method 21). To implement the technology effectiveness, the 

AWP requires that the detection instrument meet a minimum detection sensitivity mass flow 

rate. For the purposes of the proposed supplemental rule, such a performance standard could 

be adapted for the detection of natural gas emissions with methane as the predominant 

component (it should be noted that Method 21 is specifically meant for VOCs and HAPs and 

not for methane). 

Equipment Leak Threshold 

One alternative to determining an emission source is to provide a mass emissions threshold 

for the emitter. In such a case, any source that emits above the threshold value would be 

considered an emitter. For portable VOC monitoring instruments that measure emission 

concentrations a concentration threshold equivalent to a mass threshold can be provided. 

However, the concentration measurement is converted to an equivalent mass value using 

SOCMI correlation equations, which were developed from petroleum refinery and 

petrochemical plant data. In the case of an optical imaging instrument, which does not 

provide the magnitude of emissions, either concentration or mass emissions, quantification 

would be required using a separate measurement instrument to determine whether a source is 

an emitter or not. This could be very cost prohibitive for the purposes of this rule. 

Background Technical Support Document – Petroleum and Natural Gas Industry 68 
 

ii. Duration of Equipment Leaks 

Equipment leaks by nature occur randomly within the facility. Therefore, there is no way of 

knowing when a particular source started emitting. If the potential monitoring method 

requires a one time equipment leak detection and measurement, then assumptions will have 

to be made regarding the duration of the emissions. There are several potential options for 

calculating the duration of emissions. If a component leak is detected, total emissions from 

each source could be quantified under one of the following three scenarios: 1) if a facility 

conducts one comprehensive leak survey each reporting period, applicable component leaker 

emissions factors could be applied to all specific component emissions sources and emissions 

quantified based on emissions occurring for an entire reporting period; 2) if a facility 

conducts two comprehensive leak surveys during a single reporting period, applicable 

component leaker emissions factors could be applied to all component emissions sources. If 

a specific emission source is found not leaking in the first survey but leaking in the second 

survey, emissions could be quantified from the date of the first leak survey conducted in the 

same reporting period forward through the remainder of the reporting period. If a specific 

emissions source is found leaking in the first survey but is repaired and found not leaking in 

the second survey, emissions could be quantified from the first day of the reporting period to 

the date of the second survey. If a component is found leaking in both surveys, emissions 

could be quantified based on an emission occurring for an entire reporting period; 3) if a 

facility conducts multiple comprehensive leak surveys during the same reporting period, 

applicable component leaker emissions factors could be applied to component emissions 

sources. Each specific source found leaking in one or more surveys is quantified for the 

period from a prior finding of no leak (or beginning of the reporting period) to a subsequent 

finding of no leak (or end of the reporting period). If a component is found leaking in all 

surveys, emissions could be quantified based on an emissions occurring for an entire 

reporting period. 

iii. Equipment Leak and Vented Emissions at Different Operational Modes 

If a reporting program relies on a one time or periodic measurement, the measured emissions 

may not account for the different modes in which a particular technology operates throughout 

the reporting period. This may be particularly true for measurements taken at compressors. 

Compressor leaks are a function of the mode in which the compressor is operating: i.e. 

offline pressurized, or offline de-pressurized. Typically, a compressor station consists of 

several compressors with one (or more) of them on standby based on system redundancy 

requirements and peak delivery capacity. When a compressor is taken offline it may be kept 

pressurized with natural gas or de-pressurized. When the compressor is offline and kept 

pressurized, equipment leaks and vented emissions result from closed blowdown valves and 

reciprocating compressor rod packing leaks, respectively. When the compressor is offline 

and depressurized, emissions result from leaking isolation valves. When operating, 

compressor vented emissions result from compressor seals or rod packing and other 

components in the compressor system. In each of the compressor modes, the resultant 

equipment leak and vented emissions are significantly different. One potential approach to 

account for these varying levels of equipment leak and vented emissions is to have operators 

measure all compressors in each operating mode once a reporting period. Operators would 

Background Technical Support Document – Petroleum and Natural Gas Industry 69 
 

also need to report the time for which the compressor is in the different modes. The 

disadvantages to this approach is that it will increase the reporting burden because 

measurements will have to be taken at each mode of compressor operation in each reporting 

period and the time that the equipment is in various operational modes would also have to be 

tracked. In addition, it is not feasible to require operators to take compressors off-line every 

year to conduct measurements in offline pressurized and depressurized modes. One 

alternative approach is to report compressor emissions in the mode the compressors are 

found, also known as reporting compressor emissions “as-is”. The reporters could then 

determine emission factors for each mode and apply them to the period of time each 

compressor was not in the mode it was measured in for the reporting period. Since most 

compressors would be found in the, pressurized, operating mode, reporters could be required 

to measure each compressor in an offline mode less frequently (e.g. every three reporting 

periods) to ensure sufficient data points are collected in the less common offline modes. 

A similar issue exists with tanks where the operating conditions change more often than for 

compressors. The amount of throughput through tanks varies continuously as new 

hydrocarbon liquids are introduced and stored liquids are withdrawn for transportation. 

Unlike other equipment, the operational level of tanks cannot be categorized into a fixed and 

limited number of modes. This makes it all the more challenging to characterize emissions 

from storage tanks. One option is to require operators to use best judgment and characterize a 

few different modes for the storage tanks and make adjustments to the monitored emissions 

accordingly. 

iv. Natural Gas Composition 

When measuring equipment leaks and vented emissions using the various measurement 

instruments (high volume sampler, calibrated bags, and meters) or using engineering 

estimation for vented emissions, only flow rate is measured or calculated and the individual 

CH4 and CO2 emissions are estimated from the natural gas mass emissions using natural gas 

composition appropriate for each facility. For this purpose, the monitoring methodologies 

discussed above would require that facilities use existing gas composition estimates to 

determine CH4 and CO2 components of the natural gas emissions (acid gas recovery units, 

flare stacks, and storage tank vented emissions are an exception to this general rule). These 

gas composition estimates are assumed to be available at facilities. But this may or may not 

be a practical assumption for reporting. In the absence of gas composition, periodic 

measurement of the required gas composition for speciation of the natural gas mass 

emissions into CH4 and CO2 mass emissions could be a potential option. 

In addition, GHG components of natural gas may change significantly in the facilities during 

the reporting period and different sources in the same facility may be emitting different 

compositions of natural gas. This is most prevalent in onshore production, offshore 

production and natural gas processing facilities. One potential option is to apply an average 

composition across all emissions sources for the reporting facility. Another option is to apply 

specific composition estimates across similar streams in the same facility. For example, in 

processing, the natural gas composition is similar for all streams upstream of the demethanizer. The same is true of all equipment downstream of the de-methanizer overhead. 

Background Technical Support Document – Petroleum and Natural Gas Industry 70 
For onshore production and offshore production monthly or quarterly samples can be taken 

to account for the variation in natural gas being produced from different combinations of 

production wells throughout the reporting period. 

v. Physical Access for Leak Measurement 

All emissions measurement techniques require physical access to the leaking source. The 

introduction of remote leak detection technologies based on infrared (IR) light absorption by 

hydrocarbon gas clouds from atmospheric leaks makes leak detection quicker and possible 

for sources outside of arms reach from the ground or fixed platforms. Leaks from flanges, 

valve stems, equipment covers, etc. are generally smaller than emissions from vents. 

Component leaks are expensive to measure where they are not accessible within arms reach 

from the ground or a fixed platform. For these inaccessible sources, the use of emission 

factors for emissions quantification may be appropriate. Vent stacks are often located out of 

access by operators for safety purposes, but may represent large emission sources. Where 

emissions are detected by optical gas imaging instruments, emissions measurement may be 

cost-effective using the following source access techniques: 

 Short length ladders positioned on the ground or a fixed platform where OSHA 

regulations do not require personnel enclosure and the measurement technique can be 

performed with one hand; 

 Bucket trucks can safely position an operator within a full surround basket allowing 

both hands to be used above the range of ladders or for measurement techniques 

requiring both hands; 

 Relatively flat, sturdy roofs of equipment buildings and some tanks allow safe access 

to roof vents that are not normally accessible from fixed platforms or bucket trucks; 

 Scaffolding is sometimes installed for operational or maintenance purposes that allow 

access to emission sources not normally accessible from the ground, fixed platforms 

and out of reach of bucket trucks. 

7. Procedures for Estimating Missing Data 

It is possible that some companies would be missing data necessary to quantify annual 

emissions. In the event that data are missing, potential procedures to fill the data gap are 

outlined below and are organized by data type. 

In general, although there is always the possibility of using a previous periods’ data point to 

replace missing data in the current reporting period, this is not ideal since varying operating 

conditions can dramatically impact emissions estimates. Where using previous reporting 

periods’ data are not desirable, then a reporting rule might require 100% data availability. In 

other words, there would be no missing data procedures provided. If any data were identified 

as missing, then there would be an opportunity to recollect the emissions data over the course 

of the current reporting period. 

Background Technical Support Document – Petroleum and Natural Gas Industry 71 
a. Emissions Measurement Data 

Measured data can be collected by trained engineers using a high volume sampler, meter, or 

calibrated bag. Over the course of the data collection effort, some of the measured emissions 

rates could get lost temporarily or permanently due to human error, or storage errors such as 

lost hard-drives and records. If measured data is missing then the field measurement process 

may have to be repeated within the reporting period. If this proves to be impossible and the 

company clearly certifies that they lost the data and can justify not repeating the survey 

within the given reporting period, then the previous reporting period’s data could be used to 

estimate equipment leaks from the current reporting period. 

b. Engineering Estimation Data 

Engineering estimations rely on the collection of input data to the simulation software or 

calculations. A potential procedure for missing input data is outlined below for each type of 

input parameter. 

 Operations logs. If operating logs are lost or damaged for a current reporting period, 

previous reporting period’s data could be used to estimate emissions. Again, using 

previous reporting periods’ data are not as desirable as there could be significant 

differences from period to period based on operating conditions. 

 Process conditions data. Estimating vented emissions from acid gas removal vent 

stacks, blowdown vent stacks, dehydrator vents, natural gas driven pneumatic valve 

bleed devices, natural gas driven pneumatic pumps, and storage tanks requires data on 

the process conditions (e.g., process temperature, pressure, throughputs, and vessel 

volumes). If, for any reason, these data are incomplete or not available for the current 

reporting period, field operators or engineers could recollect data wherever possible. 

If this data cannot be collected, then relevant parameters for estimation of emissions 

can be used from previous reporting period. However, where possible current 

reporting period parameters should be used for emissions estimation due to the 

reasons listed above. 

c. Emissions Estimation Data for Storage Tanks and Flares 

Emissions from storage tanks and flares might require a combination of both direct 

measurement and engineering estimation to quantify emissions. In such cases the storage 

tank emissions calculation requires the measurement of “emissions per throughput” data. If 

this data is missing then the previous reporting periods’ estimate of “emissions per 

throughput” measured data could be used with current period throughput of the storage tank 

to calculate emissions. 

Calculating emissions from flares requires the volume of flare gas measured using a meter. If 

these data are missing then the flare gas in the current reporting period could be estimated by 

scaling the flare gas volume from previous reporting period by adjusting it for current period 

throughput of the facility. 

Background Technical Support Document – Petroleum and Natural Gas Industry 72 
d. Emissions Estimation Data Using Emissions Factors 

If population emissions factors are used then the only data required is activity data. In such a 

case missing data should be easily replaceable by undertaking a counting exercise for 

locations from which the data is missing. Alternatively, previous reporting period activity 

data can be used to fill in missing data. However, if facility and/ or equipment modifications 

have resulted in increase or decrease in activity data count then this may not be a feasible 

approach. 

If leaker emissions factors are used then activity data will have to be collected using some 

form of equipment leak detection. In such case, missing data may not be easily replaceable. 

Previous period reported activity data may be used but it may not be representative of current 

period emissions. A detection survey to replace missing data may be warranted. 

8. QA/QC Requirements 

a. Equipment Maintenance 

Equipment used for monitoring, both emissions detection and measurement, should be 

calibrated on a scheduled basis in accordance with equipment manufacturer specifications 

and standards. Generally, such calibration is required prior to each monitoring cycle for each 

facility. A written record of procedures needed to maintain the monitoring equipment in 

proper operating condition and a schedule for those procedures could be part of the QA/QC 

plan for the facility. 

An equipment maintenance plan could be developed as part of the QA/QC plan. Elements of 

a maintenance plan for equipment could include the following: 

	 Conduct regular maintenance of monitoring equipment. 

o	 Keep a written record of procedures needed to maintain the monitoring system 

in proper operating condition and a schedule for those procedures; 

o	 Keep a record of all testing, maintenance, or repair activities performed on 

any monitoring instrument in a location and format suitable for inspection. A 

maintenance log may be used for this purpose. The following records should 

be maintained: date, time, and description of any testing, adjustment, repair, 

replacement, or preventive maintenance action performed on any monitoring 

instrument and records of any corrective actions associated with a monitor’s 

outage period. 

b. Data Management 

Data management procedures could be included in the QA/QC Plan. Elements of the data 

management procedures plan are as follows: 

	 Check for temporal consistency in production data and emission estimate. If outliers 

exist, can they be explained by changes in the facility’s operations, etc.? 

Background Technical Support Document – Petroleum and Natural Gas Industry 73 
 

o	 A monitoring error is probable if differences between annual data cannot be 

explained by: 

 Changes in activity levels, 

 Changes concerning monitoring methodology, 

 Changes concerning change in equipment, 

 Changes concerning the emitting process (e.g. energy efficiency 

improvements).10 

	 Determine the “reasonableness” of the emission estimate by comparing it to previous 

year’s estimates and relative to national emission estimate for the industry: 

o	 Comparison of emissions by specific sources with correction for throughput, 

if required, 

o	 Comparison of emissions at facility level with correction for throughput, if 

required, 

o	 Comparison of emissions at source level or facility level to national or 

international reference emissions from comparable source or facility, adjusted 

for size and throughput, 

o	 Comparison of measured and calculated emissions.10 

	 Maintain data documentation, including comprehensive documentation of data 

received through personal communication: 

o	 Check that changes in data or methodology are documented 

c. Calculation checks 

Calculation checks could be performed for all reported calculations. Elements of calculation 

checks could include: 

	 Perform calculation checks by reproducing a representative sample of emissions 

calculations or building in automated checks such as computational checks for 

calculations: 

o	 Check whether emission units, parameters, and conversion factors are 

appropriately labeled, 

o	 Check if units are properly labeled and correctly carried through from 

beginning to end of calculations, 

o	 Check that conversion factors are correct, 

o	 Check the data processing steps (e.g., equations) in the spreadsheets, 

o	 Check that spreadsheet input data and calculated data are clearly differentiated 

o	 Check a representative sample of calculations, by hand or electronically, 

o	 Check some calculations with abbreviated calculations (i.e., back of the 

envelope checks), 

10 Official Journal of the European Union, August 31, 2007. Commission Decision of 18 July 2007, 

“Establishing guidelines for the monitoring and reporting of GHG emissions pursuant to Directive 2003/87/EC 

of the European Parliament and of the Council. Available at http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2007:229:0001:0085:EN:PDF. 

Background Technical Support Document – Petroleum and Natural Gas Industry 74 
 

o	 Check the aggregation of data across source categories, business units, etc., 

o	 When methods or data have changed, check consistency of time series inputs 

and calculations.11 

9. Reporting Procedure 

(a) The facilities that cross the potential threshold for reporting could report the following 

information to EPA: 

(1) Emissions monitored at an aggregate source level for each facility, separately identifying 

those emissions that are from standby sources. In several onshore natural gas processing 

plants CO2 is being capture for Enhanced Oil Recovery operations. Therefore, these CO2 

emissions may have to be separately accounted for in the reporting. 

(2) Activity data, such as the number of sources monitored, for each aggregated source type 

level for which emissions will be reported. 

(3) The parameters required for calculating emissions when using engineering estimation 

methods. 

In addition, the following reporting requirements could be considered for a reporting rule; 

(b) Equipment leaks by nature occur randomly within the facility, therefore, where emissions 

are reported on an annual basis, it may not be possible to determine when the equipment 

leaks began. As discussed in more detail in Section (I)(ii) of the TSD, under these 

circumstances, annual emissions could be determined assuming that the equipment leaks 

were continuous from the beginning of the reporting period or from the last recorded not 

leaking in the current reporting period and until the equipment leak is repaired or the end of 

the reporting period. 

(c) Due to the point-in-time nature of direct measurements, reports of annual emissions levels 

should take into account equipment operating hours according to standard operating 

conditions and any significant operational interruptions and shutdowns, to convert direct 

measurement to an annual figure. 

10. Verification of Reported Emissions 

As part of the data verification requirements, the owner or operator could submit a detailed 

explanation of how company records of measurements are used to quantify equipment leaks 

and vented emissions measurement within 7 days of receipt of a written request from EPA or 

from the applicable State or local air pollution control agency (the use of electronic mail can 

be made acceptable). 

11 U.S. EPA 2007. Climate Leaders, Inventory Guidance, Design Principles Guidance, Chapter 7 “Managing 

Inventory Quality”. Available at 

http://www.epa.gov/climateleaders/documents/resources/design_princ_ch7.pdf. 

Background Technical Support Document – Petroleum and Natural Gas Industry 75 
 

 

 

Appendix A: Segregation of Emissions Sources using the Decision Process 

The tables provided in this appendix represent the outcome of the decision process used to 

identify a starting list of potential sources that were evaluated for inclusion in the final rule. 

The decision process was applied to each emission source in the natural gas segment of the 

U.S. GHG Inventory. The petroleum onshore production segment has emission sources that 

either are equivalent to their counter-parts in the natural gas onshore production segment or 

fall in the exclusion category. Petroleum transportation was not analyzed further due to the 

level of emissions and refineries are treated separately in Subpart Y. 

 Sources Contributing to 80% of Equipment Leaks and Vented Emissions from Each Industry 

Segment 

Source 

Offshore 

Production 

Onshore 

Production Processing Transmission Storage LNG Storage 

LNG Import and 

Export Distribution 

Separators 4% 

Meters/Piping 4% 

Small Gathering Reciprocating Comp. 2% 

Pipeline Leaks 7% 

CBM Powder River 2% 

Pneumatic Device Vents 43% 0.26% 12% 13% 

Gas Pneumatic Pumps 9% 0.49% 

Dehydrator Vents 2% 3% 3% 

Well Clean Ups (LP Gas Wells)/ Blowdowns 7% 

Plant/Station/ Platform Fugitives 4% 5% 16% 14% 3% 

Reciprocating Compressors 48% 40% 45% 54% 14% 

Centrifugal Compressors 22% 16% 8% 6% 19% 4% 

Acid Gas Removal Vents 2% 

Vessel Blowdowns/Venting 6% 

Routine Maintenance/Upsets - Pipeline venting 10% 

Station venting 8% 2% 

M&R (Trans. Co. Interconnect) 4% 

Pipeline Leaks Mains 36% 

Services 16% 

Meter/Regulator (City Gates) 37% 

Residential Customer Meters 

Flare stacks 1% 

Non-pneumatic pumps 0.03% 

Open ended lines 0.005% 

Pump seals 0.41% 

Storage tanks 50% 

Wellhead fugitive emissions 4% 

Well completions 0.0004% 

Well workovers 0.04% 

NOTE: Pink cells represent sources that were included over riding the decision tree process. Blue cells represent 

sources that are not present in the respective segments. Green cells represent sources that are not explicitly 

identified in the U.S. GHG Inventory; however, these sources may potentially be found in the respective segments. 

Blank cells are sources in the U.S. GHG Inventory. 

Background Technical Support Document – Petroleum and Natural Gas Industry 76 
Inventory of Methane Emissions from Natural Gas Systems 

PRODUCTION OFFSHORE 

Total Emissions 

Nationally 

(MMcf/year) 

Tonnes 

CO2e/ Year 

% of Sector 

Emissions 

% of total 

Inventory 

Emissions 

Activity 

Factors 

Leak 

Detection 

Mea

Amine gas sweetening unit 0.2 80 0.01% 0.0001% NE c 

Boiler/heater/burner 0.8 332 0.05% 0.0002% c 

Diesel or gasoline engine 0.01 6 0.001% 0.000004% c 

Drilling rig 3 1,134 0.17% 0.001% c 

Flare 24 9,583 1.47% 0.01% c 

Centrifugal Seals 358 144,547 22% 0.10% a 

Connectors 0.8 309 0.05% 0.0002% b 

Flanges 2.38 960 0.15% 0.001% b 

OEL 0.1 32 0.005% 0.00002% b Other 44 17,576 2.70% 0.01% b 

Pump Fugitive 0.5 191 0.03% 0.0001% b 

Valves 19 7,758 1% 0.01% b 

Glycol dehydrator 25 9,914 2% 0.01% c 

Loading operation 0.1 51 0.01% 0.00004% c 

Separator 796 321,566 49% 0.23% c 

Mud degassing 8 3,071 0.47% 0.002% c 

Natural gas engines 191 77,000 12% 0.05% Natural gas turbines 3 1,399 0.22% 0.001% 

Pneumatic pumps 7 2,682 0.41% 0.002% c 

Pressure/level controllers 2 636 0.10% 0.0005% c Storage tanks 7 2,933 0.45% 0.002% c 

VEN exhaust gas 121 48,814 8% 0.03% c 

NOTES: Leak Detection: a – Yes and cost effective; b – Yes but cost burden c - No. Cost effectiveness based on expert judgment. 

Direct Measurement: a – Accurate and cost effective; b – Accurate but cost burden; c – Questionable; d – No direct measu

Engineering Estimate: a – Exists; b – does not exist. 

Accessible Source: y – Yes; n – No; b – Both. 

Background Technical Support Document – Petroleum and Natural Gas Industry 
PRODUCTION ONSHORE 

Total Emissions 

Nationally 

(MMcf/year) 

Tonnes 

CO2e/ Year 

% of Sector 

Emissions 

% of total 

Inventory 

Emissions 

Activity 

Factors 

Leak 

Detection 

Direct 

Measurement 

Normal Fugitives 

Gas Wells Non-associated Gas Wells (less Unconventional) 2,682 1,083,539 2% 0.77% 376784 b b 

Unconventional Gas Wells 69 27,690 0.06% 0.02% 35440 a b 

Field Separation Equipment 0 Heaters 1,463 591,023 1% 0.42% 89720 a b 

Separators 4,718 1,906,206 4% 1% 247919 b b 

Dehydrators 1,297 524,154 1% 0.37% 37925 a b 

Meters/Piping 4,556 1,840,683 4% 1% 315487 b b Gathering Compressors 0 Small Reciprocating Comp. 2,926 1,182,062 2% 1% 28490 a a 

Large Reciprocating Comp. 664 268,133 0.54% 0.19% 112 a a 

Large Reciprocating Stations 45 18,178 0.04% 0.01% 14 a a 

Pipeline Leaks 8,087 3,267,306 7% 2% 392624 b b 

Vented and Combusted 

Drilling and Well Completion Completion Flaring 0 188 0.00% 0.00% 597 c c Well Drilling 96 38,946 0.08% 0.03% 35600 c c 

Coal Bed Methane

 Powder River 2,924 1,181,246 2% 1% 396920 c c 

 Black Warrior 543 219,249 0.44% 0.16% c c 

Normal Operations Pneumatic Device Vents 52,421 21,178,268 43% 15% c b 

Chemical Injection Pumps 2,814 1,136,867 2% 0.81% c b 

Kimray Pumps 11,572 4,674,913 9% 3% c b 

Dehydrator Vents 3,608 1,457,684 3% 1% c c 

Condensate Tank Vents Condensate Tanks without Control Devices 1,225 494,787 1% 0.35% c c 

Condensate Tanks with Control Devices 245 98,957 0.20% 0.07% c d Compressor Exhaust Vented Gas Engines 11,680 4,718,728 9% 3% Well Workovers Gas Wells 47 18,930 0.04% 0.01% c d 

Well Clean Ups (LP Gas Wells) 9,008 3,639,271 7% 3% c d 

Blowdowns Vessel BD 31 12,563 0.03% 0.01% c d 

Pipeline BD 129 52,040 0.10% 0.04% c d Compressor BD 113 45,648 0.09% 0.03% c d 

Compressor Starts 253 102,121 0.20% 0.07% c d 

Upsets Pressure Relief Valves 29 11,566 0.02% 0.01% c d 

Mishaps 70 28,168 0.06% 0.02% c d 

Notes: Leak Detection: a – Yes and cost effective; b – Yes but cost burden; c - No. Cost effectiveness based on expert j

Direct Measurement: a – Accurate and cost effective; b – Accurate but cost burden; c – Questionable; d – No dir

Engineering Estimate: a – Exists; b – does not exist. 

Accessible Source: y – Yes; n – No; b – Both. 

Background Technical Support Document – Petroleum and Natural Gas Industry 
GAS PROCESSING PLANTS 

Total Emissions 

Nationally 

(MMcf/year) 

Tonnes 

CO2e/ Year 

% of Sector 

Emissions 

% of total 

Inventory 

Emissions 

Activity 

Factors 

Leak 

Detection 

D

Meas

Normal Fugitives 

Plants 1,634 660,226 5% 0.47% a 

Recip. Compressors 17,351 7,009,755 48% 5% a 

Centrifugal Compressors 5,837 2,358,256 16% 2% a 

Vented and Combusted 

Normal Operations

 Compressor Exhaust 

Gas Engines 6,913 2,792,815 19% 2% Gas Turbines 195 78,635 1% 0.06%

 AGR Vents 643 259,592 2% 0.18% c 

 Kimray Pumps 177 71,374 0.49% 0.05% c 

 Dehydrator Vents 1,088 439,721 3% 0.31% c 

 Pneumatic Devices 93 37,687 0.3% 0.03% c 

Routine Maintenance 

Blowdowns/Venting 2,299 928,900 6% 1% c 

Notes: Leak Detection: a – Yes and cost effective; b – Yes but cost burden; c - No. Cost effectiveness based on expert judg

Direct Measurement: a – Accurate and cost effective; b – Accurate but cost burden; c – Questionable; d – No direct m

Engineering Estimate: a – Exists; b – does not exist. 

Accessible Source: y – Yes; n – No; b – Both. 

Background Technical Support Document – Petroleum and Natural Gas Industry 
TRANSMISSION 

Total Emissions 

Nationally 

(MMcf/year) 

Tonnes 

CO2e/ Year 

% of Sector 

Emissions 

% of total 

Inventory 

Emissions 

Activity 

Factors 

Leak 

Detection 

Dire

Measur

Fugitives 

Pipeline Leaks 166 67,238 0.17% 0.05% a c 

Compressor Stations (Transmission) Station 5,619 2,270,177 6% 2% a a 

 Recip Compressor 38,918 15,722,907 40% 11% a a 

 Centrifugal Compressor 7,769 3,138,795 8% 2% a a 

M&R (Trans. Co. Interconnect) 3,798 1,534,238 4% 1% a a 

M&R (Farm Taps + Direct Sales) 853 344,646 1% 0.25% b b 

Vented and Combusted 

Normal Operation Dehydrator vents (Transmission) 105 42,329 0.11% 0.03% c c 

 Compressor Exhaust

 Engines (Transmission) 10,820 4,371,314 11% 3% Turbines (Transmission) 61 24,772 0.06% 0.02% Generators (Engines) 529 213,911 0.55% 0.15% Generators (Turbines) 0 60 0.0002% 0.00004%

 Pneumatic Devices Trans + Stor

 Pneumatic Devices Trans 11,393 4,602,742 12% 3% c b 

Routine Maintenance/Upsets Pipeline venting 9,287 3,752,013 10% 3% c d  Station venting Trans + Storage

 Station Venting Transmission 7,645 3,088,575 8% 2% c d 

Notes: Leak Detection: a – Yes and cost effective; b – Yes but cost burden; c - No. Cost effectiveness based on expert judgment. 

Direct Measurement: a – Accurate and cost effective; b – Accurate but cost burden; c – Questionable; d – No direct measurem

Engineering Estimate: a – Exists; b – does not exist. 

Accessible Source: y – Yes; n – No; b – Both. 

Background Technical Support Document – Petroleum and Natural Gas Industry 
STORAGE 

Total Emissions 

Nationally 

(MMcf/year) 

Tonnes 

CO2e/ Year 

% of Sector 

Emissions 

% of total 

Inventory 

Emissions 

Activity 

Factors 

Leak 

Detection 

Direc

Measurem

Fugitives 

Compressor Stations (Storage) 

Station 2,801 1,131,492 16% 1% a a 

Recip Compressor 8,093 3,269,454 45% 2% a a 

Centrifugal Compressor 1,149 464,354 6% 0.33% a a 

Wells (Storage) 695 280,891 4% 0.20% a a 

Vented and Combusted 

Normal Operation 

Dehydrator vents (Storage) 217 87,514 1% 0.06% c c 

 Compressor Exhaust

 Engines (Storage) 1,092 441,108 6% 0.31% 

Turbines (Storage) 9 3,680 0.05% 0.003%

 Pneumatic Devices Trans + Stor

 Pneumatic Devices Storage 2,318 936,324 13% 1% c b 

 Station venting Trans + Storage

 Station Venting Storage 1,555 628,298 9% 0.45% c d 

Notes: Leak Detection: a – Yes and cost effective; b – Yes but cost burden; c - No. Cost effectiveness based on expert judgment. 

Direct Measurement: a – Accurate and cost effective; b – Accurate but cost burden; c – Questionable; d – No direct measure

Engineering Estimate: a – Exists; b – does not exist. 

Accessible Source: y – Yes; n – No; b – Both. 

Background Technical Support Document – Petroleum and Natural Gas Industry 
LNG STORAGE 

Total Emissions 

Nationally 

(MMcf/year) 

Tonnes 

CO2e/ Year 

% of Sector 

Emissions 

% of total 

Inventory 

Emissions 

Activity 

Factors 

Leak 

Detection 

Me

LNG Storage 

LNG Stations 552 222,824 14% 0.16% b 

LNG Reciprocating Compressors 2,084 842,118 54% 1% b 

LNG Centrifugal Compressors 715 288,756 19% 0.21% b 

LNG Compressor Exhaust LNG Engines 172 69,632 5% 0.05% LNG Turbines 1 261 0.02% 0.0002% LNG Station venting 306 123,730 8% 0.09% c 

Total Emissions 

Nationally 

(MMcf/year) 

Tonnes 

CO2e/ Year 

% of Sector 

Emissions 

% of total 

Inventory 

Emissions 

Activity 

Factors 

Leak 

Detection 

Me

LNG Import Terminals 

LNG Stations 22 8,880 3% 0.01% b LNG Reciprocating Compressors 105 42,347 14% 0.03% b 

LNG Centrifugal Compressors 27 10,820 4% 0.01% b 

LNG Compressor Exhaust LNG Engines 586 236,647 78% 0.17% LNG Turbines 3 1,370 0.45% 0.001% LNG Station venting 12 4,931 2% 0.004% c 

LNG IMPORT AND EXPORT TERMINALS 

Notes: Leak Detection: a – Yes and cost effective; b – Yes but cost burden; c - No. 

Direct Measurement: a – Accurate and cost effective; b – Accurate but cost burden; c – Questionable; d – No direct measurem

Engineering Estimate: a – Exists; b – does not exist. 

Accessible Source: y – Yes; n – No; b – Both. 

Export Terminals are not currently included in the U.S. GHG Inventory, therefore they were not included in this analysis. The

terminal, located in Alaska. 

Background Technical Support Document – Petroleum and Natural Gas Industry 
DISTRIBUTION 

Total Emissions 

Nationally 

(MMcf/year) 

Tonnes 

CO2e/ 

Year 

% of Sector 

Emissions 

% of total 

Inventory 

Emissions 

Activity 

Factors 

Leak 

Detection 

Direct 

Measurement 

E

Normal Fugitives 

Pipeline Leaks 

Mains - Cast Iron 9,222 3,725,675 14% 3% a b 

Mains - Unprotected steel 6,515 2,632,209 10% 2% a b 

Mains - Protected steel 1,422 574,529 2% 0.41% a b 

Mains - Plastic 6,871 2,775,759 10% 2% a b 

Total Pipeline Miles 36% 7% 

Services - Unprotected steel 7,322 2,957,970 11% 2% a b 

Services Protected steel 2,863 1,156,473 4% 1% a b 

Services - Plastic 315 127,210 0.47% 0.09% a b Services - Copper 47 19,076 0.07% 0.01% a b 

Total Services 16% 3% Meter/Regulator (City Gates) 37% 7%

 M&R >300 5,037 2,034,986 7% 1% 3,198 a a 

 M&R 100-300 10,322 4,170,101 15% 3% 12,325 b b 

 M&R <100 249 100,480 0.37% 0.07% 6,587 a c 

Reg >300 5,237 2,115,726 8% 2% 3,693 a a 

 R-Vault >300 25 9,976 0.04% 0.01% 2,168 a a 

Reg 100-300 4,025 1,625,929 6% 1% 11,344 b b 

 R-Vault 100-300 8 3,247 0.01% 0.002% 5,097 a c 

Reg 40-100 306 123,586 0.45% 0.09% 33,578 b b 

 R-Vault 40-100 23 9,115 0.03% 0.01% 29,776 b b 

Reg <40 17 6,690 0.02% 0.005% 14,213 b b 

Customer Meters 

Residential 5,304 2,142,615 8% 2% 37017342 b b 

Commercial/Industry 203 81,880 0.30% 0.06% 4231191 b b 

Vented 

Rountine Maintenance

 Pressure Relief Valve Releases 63 25,346 0.09% 0.02% c d 

 Pipeline Blowdown 122 49,422 0.18% 0.04% c d 

Upsets 

Mishaps (Dig-ins) 1,907 770,405 3% 1% c d 

NOTES: Leak Detection: a – Yes and cost effective; b – Yes but cost burden; c - No. Cost effectiveness based on expert judgment. 

Direct Measurement: a – Accurate and cost effective; b – Accurate but cost burden; c – Questionable; d – No direct measurem

Engineering Estimate: a – Exists; b – does not exist. 

Accessible Source: y – Yes; n – No; b – Both. 

Background Technical Support Document – Petroleum and Natural Gas Industry 
 

Appendix B: Development of revised estimates for four U.G. GHG 

Inventory emissions sources 

Well Completion and Workover Venting 

This discussion describes the methods used to estimate total U.S. methane emissions from 

well completion and workover venting. For the purposes of this estimate, it is assumed that 

all unconventional wells are completed with hydraulic fracturing of tight sand, shale or coal 

bed methane formations (i.e. completions involving high rate, extended back-flow to expel 

fracture fluids and sand proppant, which also leads to greater gas venting or flaring emissions 

than conventional well completions). It is understood that not all unconventional wells 

involve hydraulic fracturing, but some conventional wells are hydraulically fractured, which 

is assumed to balance the over-estimate. 

►Estimate the Number of Gas Wells Completed 

The data in Exhibit B-1 was extracted from EPA (2008)12. The unconventional well column 

only includes CBM wells and shale gas wells, but does not include tight sands formations 

because that data is not readily available either publically or in the U.S. Inventory. Thus, this 

analysis underestimates the activity associated with unconventional well completions and 

workovers. 

Exhibit B-1. 2007 Natural Gas Wells 

Year 

Approximate Number of 

Onshore Unconventional 

Gas Wells 

Approximate Number of 

Onshore Conventional Gas 

Wells 

Total Number of Gas Wells 

(both conventional and 

unconventional) 

2006 35,440 375,601 411,041 

2007 41,790 389,245 431,035 

Exhibit B-1 was used to calculate that there was a net increase of 19,994 wells (both 

conventional and unconventional) between 2006 and 2007. Each of these wells is assumed 

to have been completed over the course of 2006. EPA (2008) also estimates that 35,600 gas 

wells were drilled in 2006. This includes exploratory wells, dry holes, and completed wells. 

EPA (2008) also indicates that 19,994 of those natural gas wells were drilled and completed. 

The difference between the 35,600 drilled and 19,994 new wells is 15,606 wells, which we 

assume are replaced for shut-in or dry holes. This analysis assumed that 50% of those 

remaining 15,606 wells were completed. Thus, the total number of gas well completions, 

both conventional and unconventional, was estimated to be 27,797 wells in 2006. 

19,994wells  50%  35,600wells 19,994wells   27,797wells 

That is 78% of the total gas wells drilled in 2006. We assumed this same percentage of 

completed wells applies to the year 2007. EPA (2008) estimates 37,196 gas wells were 

12 EPA.. (2008) U.S. Inventory of Greenhouse Gas Emissions and Sinks: 1990 – 2007. Available online at: 

<http://epa.gov/climatechange/emissions/usgginv_archive.html>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 84 
 

 

 

drilled in 2007, so applying this completion factor, 78% of 37,196 wells equals 29,043 gas 

wells completed in 2007. 

►Estimate the Number of Conventional and Unconventional Well Completions 

Exhibit B-1 shows a net increase of 6,350 unconventional wells from 2006 to 2007. This is 

32% of the 19,994 net increase in all wells over that period. It was assumed that 32% of the 

estimated 29,043 well completions in 2007 (see previous section) were unconventional wells. 

The remaining gas well completions were assumed to be conventional wells. These results 

are summarized in Exhibit B-2. This analysis also assumed that all unconventional wells 

require hydraulic fracture upon completion. Because these completions and workovers only 

account for CBM wells and shale gas wells, it is a significant underestimate since tight sands 

formations are omitted. 

Exhibit B-2. 2007 Completions Activity Factors 

2007 Conventional 

Well Completions 19,819 

2007 Unconventional 

Well Completions 9,224 

►Estimate the Number of Conventional and Unconventional Well Workovers 

GRI (1996)13 provides activity data for 1992 on conventional workovers. It reported that 

9,324 workovers were performed with 276,014 producing gas wells. This activity data was 

projected to 2007 using the ratio of 2007 producing gas wells to 1992 producing gas wells; as 

shown in Exhibit 3: 

Exhibit B-3. Calculation of 2007 Conventional Workover Activity Factor 

2007GasWells 2007ConventionalWorkovers  1992ConventionalWorkovers 

1992GasWells 

431,035wells 2007ConventionalWorkovers  9,324workovers 

276,014wells 

Unconventional gas wells were assumed to be re-fractured once every 10 years. Thus, the 

number of unconventional gas well workovers was 10% of the existing unconventional well 

count in 2007. 

The resulting activity factors for conventional and unconventional gas well workovers are 

summarized in Exhibit B-4. 

Exhibit B-4. Summary of 2007 Workover Activity Factors 

13 GRI. Methane Emissions from the Natural Gas Industry. 1996. Available online at: 

<http://epa.gov/gasstar/tools/related.html>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 85 
 

 

 

2007 Conventional 

Well Workovers   wells 

wells workovers 

276,014 

431,035 9,324 14,569 

2007 Unconventional 

Well Workovers 10% 41,790wells  4,179 

►Estimate the Emission Factor for Conventional Well Completions 

GRI (1996) estimated that conventional well completions emit 0.733 Mcf of methane each. 

GRI (1996) assumed that all completion flowback was flared at 98% combustion efficiency 

and the produced gas was 78.8% methane by volume. This analysis estimated the amount of 

gas sent to the flare by dividing the reported GRI factor by the 2% un-combusted gas. The 

resulting emission factor for conventional well completions was 36.65 Mcf of 

methane/completion. 

►Estimate the Emission Factor for Conventional Well Workovers 

The GRI (1996) emission factor for well workovers was accepted for this analysis. That 

emission factor is 2.454 Mcf of methane/workover for conventional wells. 

►Estimate the Emission Factor for Unconventional Well Completions 

The emission factor for unconventional well completions was derived using several 

experiences presented at Natural Gas STAR technology transfer workshops. 

One presentation14 reported that the emissions from all unconventional well completions 

were approximately 45 Bcf using 2002 data. The emission rate per completion can be backcalculated using 2002 activity data. API Basic Petroleum Handbook15 lists that there were 

25,520 wells completed in 2002. Assuming Illinois, Indiana, Kansas, Kentucky, Michigan, 

Missouri, Nebraska, New York, Ohio, Pennsylvania, Virginia, and West Virginia produced 

from low-pressure wells that year, 17,769 of those wells can be attributed to onshore, nonlow-pressure formations. The Handbook also estimated that 73% (or 12,971 of the 17,769 

drilled wells) were gas wells, but are still from regions that are not entirely low-pressure 

formations. The analysis assumed that 60% of those wells are high pressure, tight formations 

(and 40% were low-pressure wells). Therefore, by applying the inventory emission factor for 

low-pressure well cleanups (49,570 scf/well-year1

) approximately 5,188 low-pressure wells 

emitted 0.3 Bcf . 

49,570scf 1Bcf 40% 12,971wells  

9  0.3Bcf well 10 scf 

The remaining high pressure, tight-formation wells emitted 45 Bcf less the low-pressure 0.3 

Bcf, which equals 44.7 Bcf. Since there is great variability in the natural gas sector and the 

resulting emission rates have high uncertainty; the emission rate per unconventional (highpressure tight formation) wells were rounded to the nearest thousand Mcf. 

14 EPA. Green Completions. Natural Gas STAR Producer’s Technology Transfer Workshop. September 21, 

2004. Available online at: <http://epa.gov/gasstar/workshops/techtransfer/2004/houston-02.html>. 15 API. Basic Petroleum Data Handbook. Volume XXIV, Number 1. February, 2004. 

Background Technical Support Document – Petroleum and Natural Gas Industry 86 
 

 

44.7Bcf 106 Mcf   6,000Mcf / completion 60% 12,971wells Bcf 

The same Natural Gas STAR presentation14 provides a Partner experience which shares its 

recovered volume of methane per well. This analysis assumes that the Partner recovers 90% 

of the flowback. Again, because of the high variability and uncertainty associated with 

different completion flowbacks in the gas industry, this was estimated only to the nearest 

thousand Mcf – 10,000 Mcf/completion. 

A vendor/service provider of “reduced emission completions” shared its experience later in 

that same presentation14 for the total recovered volume of gas for 3 completions. Assuming 

that 90% of the gas was recovered, the total otherwise-emitted gas was back-calculated. 

Again, because of the high variability and uncertainty associated with different completion 

flowbacks in the gas industry, this was rounded to the nearest hundred Mcf – 700 

Mcf/completion. 

The final Natural Gas STAR presentation16 with adequate data to determine an average 

emission rate also presented the total flowback and total completions and re-completions. 

Because of the high variability and uncertainty associated with different completion 

flowbacks in the gas industry, this was rounded to the nearest 10,000 Mcf – 20,000 

Mcf/completion. 

This analysis takes the simple average of these completion flowbacks for the unconventional 

well completion emission factor: 9,175 Mcf/completion. 

►Estimate the Emission Factor for Unconventional Well Workovers (“re-completions”) 

The emission factor for unconventional well workovers involving hydraulic re-fracture (“recompletions”) was assumed to be the same as unconventional well completions; calculated in 

the previous section. 

►Estimate the Total National Emissions (disregarding reductions) 

The estimated activity factors were multiplied by the associated emission factors to estimate 

the total emissions from well completions and workovers in the U.S. for 2007. This does not 

reflect reductions due to control technologies such as flares or bringing portable treatment 

units onsite to perform a practice called “reduced emission completions.” The results are 

displayed in Exhibit B-5 below. 

Exhibit B-5. Summary of Flowback: U.S. Completion and Workover Venting 2007 

Activity Activity Factor Emission Factor Total U.S. Emissions 

Conventional Gas Well 

Completions 19,819 completions 36.65 Mcf/completion ~0.7 Bcf 

Conventional Gas Well 

Workovers 14,569 workovers 2.454 Mcf/workover << 1 Bcf 

16 EPA. Reducing Methane Emissions During Completion Operations. Natural Gas STAR Producer’s 

Technology Transfer Workshop. September 11, 2007. Available online at: 

<http://epa.gov/gasstar/documents/workshops/glenwood-2007/04_recs.pdf>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 87 
 

Unconventional Gas 

Well Completions 9,224 completions 9,175 Mcf/completion ~85 Bcf 

Unconventional Gas 

Well Workovers 4,179 workovers 9,175 Mcf/workover ~38. Bcf 

Note: The emission factors and calculated emissions 

as presented in this table were rounded independently. TOTAL: ~120 Bcf 

►Estimate the Volume of Emissions That Are Not Flared 

Some states regulate that completion and re-completion (workover) flowbacks must be flared 

or recovered. Industry representatives have shared with EPA that flaring of completions and 

workovers is required in Wyoming; however, it is not required in Texas, New Mexico, and 

Oklahoma. EPA assumed that no completions were flared in the Texas, New Mexico, and 

Oklahoma, then took the ratio of unconventional wells in Wyoming to the unconventional 

wells in all four sample states to estimate the percentage of well completions and workovers 

that are flared. EPA assumed that this sample was indicative of the rest of the U.S. This 

ratio was estimated to be approximately 51%. 

The portion of flared natural gas was deducted from the results of Exhibit B-5 so that only 

the vented portion of natural gas from well completions and workovers was estimated. It 

then converted these natural gas emissions to methane emissions using an average methane 

content in produced natural gas of 78.8% by volume. The results are in Exhibit B-6, below. 

Exhibit B-6. Summary of Methane Emissions: U.S. Completion and Workover Venting 

2007 

Activity Unmitigated Flowback Natural Gas Vented Methane Vented 

Conventional Gas Well 

Completions ~0.7 Bcf ~0.37 Bcf ~0.29 Bcf 

Conventional Gas Well 

Workovers << 1 Bcf << 1 Bcf << 1 Bcf 

Unconventional Gas 

Well Completions ~85 Bcf ~43 Bcf ~34 Bcf 

Unconventional Gas 

Well Workovers ~38. Bcf ~19 Bcf ~14 Bcf 

Note: The emission factors and calculated emissions 

as presented in this table were rounded independently. TOTAL: ~48 Bcf 

The final resulting methane emissions from well completions and workovers is 48 Bcf. This 

estimate does not include hydraulic fracturing due to completions and workovers of gas wells 

in tight sands formations. Tight sands wells are not tracked by the U.S. Inventory and may 

substantially increase this estimate of unconventional well completions and workovers. A 

2008 INGAA study17 estimated that, in fact, approximately twice as many unconventional 

wells were completed than this analysis and approximately twice as many unconventional 

wells exist, 10% of which may require workover. This increase in activity is due to the 

inclusion of tight sands formations. If this analysis were to account for that activity level, not 

only would the number of hydraulic fractures increase substantially, but also the distribution 

of wells that are required to flare by law would be shifted such that only 15% of hydraulic 

17 INGAA Foundation Inc.. Availability, Economics, And Production Potential of North American 

Unconventional Natural Gas Supplies. November 2008. 

Background Technical Support Document – Petroleum and Natural Gas Industry 88 
 

 

 

 

 

fracture flowbacks would be estimated to be flared. Using INGAA’s estimates of activity, 

emissions would increase to 141 Bcf. 

Well Blowdown Venting for Liquid Unloading 

This discussion describes the methods used to estimate total U.S. methane emissions from 

low-pressure well blowdowns for liquid unloading. 

►Estimate the Fraction of Conventional Wells that Require Liquid Unloading 

This analysis assumed that the survey of 25 well sites conducted by GRI (1996) for the base 

year 1992 provides representative data for the fraction of conventional wells requiring 

unloading. That is, 41.3% of conventional wells required liquid unloading. 

►Calculate Emissions per Blowdown 

This analysis used a fluid equilibrium calculation to determine the volume of gas necessary 

to blow out a column of liquid for a given well pressure, depth, and casing diameter. The 

equation for this calculation is available in an EPA, Natural Gas STAR technical study18. 

The equation is displayed in Exhibit B-7. 

Exhibit B-7. Well Blowdown Emissions for Liquid Unloading 

 2 Vv = 0.37 10 6  D  h  P 

where, 

Vv = Vent volume (Mcf/blowdown) 

D = casing diameter (inches) 

h = well depth (feet) 

P = shut-in pressure (psig) 

A combination of GASIS19 and LASSER20 databases provided well depth and shut-in 

pressures for a sample of 35 natural gas basins. The analysis assumed an average casing 

diameter of 10-inches for all wells in all basins. 

►Estimate the Annual Number of Blowdowns per Well that Require Unloading 

For wells that require liquid unloading, multiple blowdowns per year are typically necessary. 

A calibration using the equation in the previous section was performed using public data for 

the shared experiences of two Natural Gas STAR Partners. 

One Partner reported that it recovered 4 Bcf of emissions using plunger lifts with “smart” 

automation (to optimize plunger cycles) on 2,200 wells in the San Juan basin21. Using the 

18 EPA. Installing Plunger Lift Systems in Gas Wells: Lessons Learned from Natural Gas STAR Partners. 

October, 2003. Available online at: <http://epa.gov/gasstar/documents/ll_plungerlift.pdf>. 

19 DOE. GASIS, Gas Information System. Release 2 – June 1999.
 20 LASSERTM database. 

21 EPA. Natural Gas STAR Partner Update: Spring 2004. Available online at: 

<http://epa.gov/gasstar/documents/partner-updates/spring2004.pdf>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 89 
 

 

data for San Juan basin in the equation in Exhibit B-6 required approximately 51 blowdowns 

per well to match the 4 Bcf of emissions. 

Another Partner reported that it recovered 12 MMcf of emissions using plunger lifts on 19 

wells in Big Piney18. Using information for the nearest basin in the equation in Exhibit B-6 

required approximately 11 blowdowns per well to match the 12 MMcf of emission. 

The simple average of 31 blowdowns per well requiring liquid unloading was used in the 

analysis to determine the number of well blowdowns per year by basin. 

►Estimate the Percentage of Wells in Each Basin that are Conventional 

GASIS and LASSER provided approximate well counts for each basin and GRI provided the 

percentage of conventional wells requiring liquid unloading for 35 sample basins. However, 

many of those basins contain unconventional wells which will not require liquid unloading. 

EIA posts maps that display the concentration of conventional gas wells in each basin22, the 

concentration of gas wells in tight formations by basin23, and the concentration of coal bed 

methane gas wells by basin24. These maps were used to estimate the approximate percentage 

of wells that are conventional in each basin. These percentages ranged from 50% to 100%. 

►Estimate Emissions from 35 Sample Basins 

The total well counts for each basin were multiplied by the percentage of wells estimated to 

be conventional for that basin to estimate the approximate number of conventional wells in 

each of the basins. The resulting conventional well counts were multiplied by the percentage 

of wells requiring liquid unloading, as estimated by the GRI survey (41.3%). The number of 

wells in each basin that require liquid unloading were multiplied by an average of 31 

blowdowns/well to determine the number of well blowdowns for each basin. The emissions 

per blowdown, as calculated using the equation in Exhibit B-6, were then multiplied by the 

number of blowdowns for each basin to estimate the total well venting emissions from each 

of the 35 sample basins due to liquid unloading. Using the GRI estimate that the average 

methane content of production segment gas is 78.8% methane by volume, the total methane 

emissions from the sample of 35 basins were calculated to be 149 Bcf. 

►Extrapolate Sample Data to Entire U.S. 

The sample of 35 gas well basins represented only 260,694 conventional gas wells. EPA’s 

national inventory25 estimated that there were 389,245 conventional gas wells in 2007. The 

emission estimates were extrapolated to the entire nation by the ratio of the conventional gas 

wells. The final resulting emissions from gas well venting due to liquid unloading were 

estimated to be 223 Bcf. 

22 EIA. Gas Production in Conventional Fields, Lower 48 States. Available online at: 

<http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm>. 23 EIA. Major Tight Gas Plays, Lower 48 States. Available online at: 

<http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm>. 24 EIA. Coal Bed Methane Fields, Lower 48 States. Available online at: 

<http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm>. 25 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2006. 2007. Available online at 

http://www.epa.gov/climatechange/emissions/usinventoryreport.html. 

Background Technical Support Document – Petroleum and Natural Gas Industry 90 
This estimate does not include emission reductions from control methods such as plunger 

lifts, plunger lifts with “smart” automation, or other artificial lift techniques. 

Background Technical Support Document – Petroleum and Natural Gas Industry 91 
 

Appendix C: Development of threshold analysis 

As the main text has pointed out the petroleum and natural gas sector includes hundreds, and 

in some cases thousands, of operators, many of them with few emission sources as well as 

ones with over 100 emission sources. Requiring all operators to report would impose a large 

burden on the industry and also on EPA. A rule-of-thumb, substantiated by survey work, is 

that 80 percent of the emissions come from 10 percent of the analysis. Therefore, a threshold 

analysis was performed so that the large emitters would be identified and small insignificant 

emitters could be excluded from the reporting requirement. 

Threshold Analysis for Onshore Production 

The following points lay out the methodology for the threshold analysis for the onshore 

petroleum and natural gas production segment 

	 The threshold analysis for onshore (including EOR) production sector estimated the 

equipment leaks, vented emissions, and combustion emissions per unique operator 

per basin. 

	 The oil and gas production volumes per operator per basin were obtained from the 

HPDITM database 2006. The total onshore oil and gas production process and 

combustion (CH4 and CO2) emissions estimated in the U.S. GHG Inventory 2006 

were apportioned to each operator based on the oil or gas production volumes. 

	 The U.S. GHG Inventory emissions estimates for the following sources were revised: 

gas well hydraulic fracture completion venting, gas well liquids unloading venting, 

and gas well workover venting following hydraulic fracture. Natural Gas STAR 

emission reductions reported by partners from these sources are higher than the 

current inventory emission estimates. As a result emissions from these sources are 

currently under-estimated in the inventory. The methodology used to revise these 

emissions estimates can be found in Appendix B. In addition, emissions from storage 

tanks vented and flared emissions are believed to be under estimated in the U.S. GHG 

Inventory. EPA independently estimated the storage tank emissions using publicly 

available data described in docket memo “Analysis of Tank Emissions” (EPA-HQOAR-2009-0923-0002). EPA’s estimated emissions from onshore production storage 

tanks may be as high as 75 billion cubic feet (Bcf) as compared with the 12 Bcf 

estimate provided in the 2006 inventory. In addition, the threshold analysis does not 

account for several sources that are not represented in the U.S. GHG Inventory such 

as associated gas venting and flaring, well testing venting and flaring and gas well 

hydraulic fracture completion venting in tight sands, the latter because these wells are 

not included in state data (See Appendix B). For all of these sources which are 

believed to be under estimated in the U.S. GHG Inventory, there are Natural Gas 

STAR reductions reported by production partners for year 2006 of 67 Bcf. However, 

Natural Gas STAR reports generally do not state exactly where the reported 

reductions were made, and in the case of production, whether they were onshore or 

offshore or included oil and gas gathering equipment. Therefore, EPA has concluded 

that the increase in emissions not accounted for in the U.S. GHG Inventory 

approximately offset the reductions reported by Natural Gas STAR production 

Background Technical Support Document – Petroleum and Natural Gas Industry 92 
 

 

 

partners. Because it is not feasible to map the emissions reductions reported by 

Natural Gas STAR Partners to their respective facilities, apportioning reductions 

equally would distort the threshold analysis. Hence, the threshold analysis does not 

include both the revised estimates from storage tanks (and other missing sources) and 

reductions from Natural Gas STAR because they cancel out.26 

	 The combustion emissions from the following sources were estimated separately as 

they are not included in the U.S GHG Inventory: heater-treater, well drilling (oil and 

gas), dehydrator reboiler, and acid gas removal (AGR) units. 

o	 Heater-Treaters Combustion: The total national combustion emissions 

from heater-treaters were calculated by estimating the total fuel required to 

increase the temperature by 10oC of total oil produced in 2006. CO2 and N2O 

combustion emission factor for natural gas from the API compendium 2004 

was used to estimate the total national CO2 and N2O emissions. The total 

emissions were apportioned to the operators based on their oil production 

volumes. 

o	 Dehydrator and AGR Combustion: The total national combustion 

emissions from dehydrators and AGR units were estimated by applying the 

fuel consumption factor of 17 Mcf of natural gas/ MMcf of gas throughput, 

obtained from the EPA’s Lesson Learned 2006, Replacing Glycol 

Dehydrators with Desiccant Dehydrator. The total national throughput was 

assumed to be equal to the total national gas produced obtained from the EIA. 

CO2 and N2O combustion emission factor for natural gas from the API 

compendium 2004 was used to estimate the total national CO2 and N2O 

emissions. The total emissions were apportioned to the operators based on 

their gas production volumes. 

o	 Well Drilling Combustion: The total national combustion emissions from 

well drilling was estimated by multiplying the emissions per well drilled with 

the national number of oil and gas wells drilled in the year 2006. The 

emissions per well was estimated by assuming the use of two 1500 hp diesel 

engines over a period of 90 days to drill each well. CO2 and N2O combustion 

emission factor for diesel from the API compendium 2004 was used to 

estimate the total national CO2 and N2O emissions. The total emissions were 

apportioned to different states based on the percentage of rigs present in the 

state. The number of rigs per state was obtained from Baker Hughes. The total 

oil and gas well drilling combustion emissions per state was apportioned to 

each operator in the state based on their oil and gas volumes respectively. 

	 The total barrels of oil produced per field and operator using EOR operations was 

obtained from the OGJ (2006) EOR/Heavy Oil Survey. 

26 A similar issue occurs with the other segments of the industry. For processing facilities, emissions from 

flares are not included in the threshold analysis. For transmission segment, emissions from scrubber dump 

valves and compressor unit isolation valves are not included in the threshold analysis. For the distribution 

segment, the emission from combustion sources are not included in the threshold analysis. The missing and 

under accounted emissions estimates roughly offset the Natural Gas STAR reductions reported. Hence, EPA 

has assumed that the missing and under-accounted cancel out the Natural Gas STAR Reductions and therefore 

did not include them in the threshold analyses. 

Background Technical Support Document – Petroleum and Natural Gas Industry 93 
 

 

	 The total make-up CO2 volume required for EOR operations was estimated using 

0.29 metric tons CO2/ bbl oil produced from EOR operations obtained from DOE, 

Storing CO2 with Enhanced Oil Recovery. The total recycled CO2 volumes per 

operator was estimated using a factor of 0.39 metric tons CO2/bbl estimated from 

DOE, Storing CO2 with Enhanced Oil Recovery. 

	 The equipment count for EOR operations was estimated by apportioning the U.S. 

GHG Inventory activity factors for onshore petroleum production to each field using 

the producing well count or throughput (bbl) based on judgment. E.g. the total 

number of compressors in the US used in EOR onshore production operations per 

field was estimated by using the ratio of the throughput per field to the national 

throughput and multiplying it by the total number of national compressors in onshore 

operations. 

	 The emission factors in the U.S. GHG Inventory and the re-estimated activity factors 

for EOR operations were used to estimate total methane emissions by volume for 

EOR operations. This volume was adjusted for methane composition (assumed to be 

78.8% from GRI) to estimate the natural gas emissions from EOR operations. The 

composition of 97% CO2 and 1.7% CH4 was applied to the total natural gas emissions 

to estimate CO2 and CH4 emissions from leaking, vented, and combustion sources 

covered in the U.S. GHG Inventory 97% CO2 and 1.7% CH4 composition was 

obtained from Summary of Carbon Dioxide Enhanced Oil Recovery (CO2 EOR) 

Injection Well Technology. 

	 The following EOR emissions sources are not covered in the U.S. GHG Inventory 

and therefore were estimated separately: 

o	 Recycled injection CO2 dehydrator vented emissions 

o	 Recycled injection CO2 compressor - vented and combustion emissions 

o	 CO2 injection pumps - combustion and vented emissions 

o	 Water injection pumps – combustion emissions 

o	 Orifice meter - vented emissions from calibration 

Emissions from the above mentioned sources were calculated in the following manner: 

 Recycled CO2 Dehydrator: The number of dehydrators per EOR field was estimated 

by using the ratio of gas throughput to the number of dehydrators indicated in the 

GRI report and multiplying it by the recycled CO2 volumes. The recycled dehydrator 

vented emissions were estimated using readjusted U.S. GHG Inventory emission 

factor. The GRI methane emission factor was divided by 78.8% methane composition 

to calculate the natural gas emission factor. The natural gas emission factor was 

adjusted to EOR operation using the critical density of CO2. 97% CO2 and 1.7% CH4 

composition obtained from Summary of Carbon Dioxide Enhanced Oil Recovery 

(CO2EOR) Injection Well Technology was used to estimate emissions. 

 Recycled CO2 Injection compressor: The recycled CO2 injection compressor fuel 

gas requirement was estimated using an assumed value of 65 kWhr/metric ton CO2 

injected. The assumption was based on the DOE study, Electricity use of EOR with 

Carbon dioxide. It is assumed that only 50% of the injected CO2 requires natural gas 

powered compressors. CH4 and CO2 combustion emissions were estimated by 

applying API compendium relevant combustion emission factors to the fuel gas used 

by each operator. The fuel gas consumption was estimated using the horsepower 

Background Technical Support Document – Petroleum and Natural Gas Industry 94 
requirements of engines per operator. N2O (CO2e) combustion emissions were 

estimated by applying API compendium N2O combustion emission factors to the fuel 

gas used by each plant. The number of compressor per field was estimated using an 

assumed number of 12 hp/ bbl of EOR produced oil. This number was obtained from 

Enhanced Recovery Scoping Study conducted by the state of California. It is assumed 

that a typical compressor used in EOR operations is 3000 hp. This number is obtained 

from DOE study, Electricity use of EOR with Carbon dioxide. The compressor 

blowdown emissions was estimated assuming one blowdown event per year, the 

estimated number of compressors per field, and compressor blowdown emission 

factor obtained from the U.S GHG inventory. The compressor blowdown emission 

factor was adjusted for critical CO2 density, CO2 and CH4 gas composition. 97% CO2 

and 1.7% CH4 composition obtained from Summary of Carbon Dioxide Enhanced Oil 

Recovery (CO2EOR) Injection Well Technology was used to estimate emissions. . 

	 CO2 Injection pumps: The supercritical CO2 injection pumps are assumed to be 

electrically driven and therefore have no combustion emissions. 97% CO2 and 1.7% 

CH4 composition obtained from Summary of Carbon Dioxide Enhanced Oil Recovery 

(CO2EOR) Injection Well Technology was used to estimate emissions. The pump 

blowdown emissions were estimated assuming an internal diameter of 12 inches and 

length of 30 feet with a 50% void volume. The pipe length between the blowdown 

valve and unit valve was assumed to be 10 feet with a diameter of 5.38 inches. It is 

assumed that the pump and pipeline vent gas equivalent to their volume once a year 

during blowdown operations. The number of supercritical pumps required per field 

was estimated by assuming that the EOR operations use pumps with 600 hp with a 

throughput of 40 Mcf/day. These pump specifications were obtained from an 

unnamed Natural Gas STAR Partner. 

	 Water injection pumps: The injection pump fuel gas requirement was estimated 

using an assumed value of 6 kWhr/bbl of oil produced. The assumption was based on 

the DOE study, Electricity use of EOR with Carbon dioxide. It is assumed that only 

50% of the injection pumps are natural gas powered. CH4 and CO2 combustion 

emissions were estimated by applying API compendium (2004) relevant combustion 

emission factors to the fuel gas used by each operator. The fuel gas consumption was 

estimated using the horsepower requirements of engines per operator. N2O (CO2e) 

combustion emissions were estimated by applying API compendium N2O combustion 

emission factors to the fuel gas used by each plant. 

	 Orifice Meter Vented Emissions: It is assumed that there are 5 orifice meters for 

each field based on data provided by an unnamed Natural Gas STAR Partner. The 

orifice meters are assumed to be calibrated once per year during which the volume of 

meter is vented to the atmosphere. The orifice meters are assumed to be 8 inches in 

diameter and 12 feet in length. 97% CO2 and 1.7% CH4 composition obtained from 

Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well 

Technology was used to estimate emissions. 

	 The total emissions per operator were calculated by summing up all the process and 

combustion emissions for EOR operations and onshore production. 

	 Each operator was assigned a “1” if it crossed a threshold and a “0” otherwise, by 

running the following logic checks: 

o	 IF(operator total emissions > 1000) then reporting 

Background Technical Support Document – Petroleum and Natural Gas Industry 95 
 

 

 

o	 IF(operator total emissions > 10000) then reporting 

o	 IF(operator total emissions > 25000) then reporting 

o	 IF(operator total emissions >100000) then reporting 

Threshold Analysis for Offshore Production 

	 Federal GOM offshore platforms, by their complex ID, and their corresponding CO2 

combustion and equipment leak emissions (CO2e), CH4 equipment leaks (CO2e), CH4 

vented emissions (CO2e), and N2O combusted emissions (CO2e) for the year 2000 

was obtained from the BOEMRE Goads Summary Access File "Final GOADS 

Emissions Summaries” 

 The ratio of 2006 to 2000 Gulf of Mexico offshore productions was calculated and 

applied to the emissions from each platform to estimate emissions for the year 2006. 

 The total number of GOM offshore production platforms was obtained from the 

BOEMRE website. 

 Each platform was assigned a “1” or “0” based on if it crossed an emissions threshold 

by running the following logic checks: 

o	 IF(operator total emissions > 1000) then reporting 

o	 IF(operator total emissions > 10000) then reporting 

o	 IF(operator total emissions > 25000) then reporting 

o	 IF(operator total emissions >100000) then reporting 

	 The total number of state platforms (Alaska and Pacific) was obtained from the 

Alaska Division of Oil and Gas and Emery et al27 respectively. The number of state 

and federal offshore oil and gas wells for GOM, Pacific, and Alaska was obtained 

from the LASSERTM database. The ratio of federal GOM oil and gas wells to federal 

platforms and the number of state offshore oil and gas wells were used to estimate the 

state GOM platform count. 

	 The ratio of gas to oil platforms was obtained from the U.S GHG Inventory 2006. All 

the state offshore platforms were assumed to be shallow water platforms. 

	 The state offshore equipment leak, vented, and combustion emissions were estimated 

by applying the ratio of state to federal platforms and multiplying it by the federal 

offshore equipment leak, vented, and combustion emissions. 

	 The percentage of platforms that fall within each emissions threshold (1000, 10,000, 

25,000 and 100,000 metric tons CO2e) for the federal GOM offshore was calculated 

and applied to the estimated state equipment leak, vented, and combustion emissions 

to calculate the volume of state offshore emissions that fall within each threshold. 

	 The number of state platforms that fall within each category was estimated by taking 

the ratio of federal emissions to platform count within each threshold and multiplying 

it by the state emissions covered by each threshold. 

	 The emissions from state and federal offshore platforms were summed up to estimate 

the total emissions from offshore operations 

27 Emery, Brian M. et al. Do oil and gas platforms off California reduce recruitment of bocaccio (Sebastes 

paucispinis) to natural habitat? An analysis based on trajectories derived from high 

frequency radar. http://www.icess.ucsb.edu/iog/pubs/DrifterSimulationsFinal_v5.pdf 

Background Technical Support Document – Petroleum and Natural Gas Industry 96 
Threshold Analysis for Processing 

	 US gas processing plants, plant throughputs, and equipment count per plant were 

obtained from the OGJ (2006). 2005 and 2006 emissions are assumed to be the same 

on a plant basis as the total national throughput from 2005 to 2006 did not change 

significantly and were 45,685 MMcf/d and 45,537.4 MMcf/d respectively as 

indicated by the U.S. GHG Inventory 

	 CH4 and CO2 process emissions (CO2e) per facility were estimated by multiplying the 

equipment count per plant (activity factor) obtained from the Gas Processing Survey 

with their corresponding emission factors obtained from GRI/ EPA 1996 reports. The 

national processing sector average composition (CH4 and CO2 content) of natural gas 

was obtained from GTI and applied to the GRI emission factors. Emission factor for 

centrifugal compressor wet seals was obtained from Bylin et al5 

. Due to the 

uncertainty in centrifugal compressor wet seal emissions, the point that it is not 

possible to ascribe Natural Gas STAR processing partner emission reductions to a 

particular processing plant or even to processing plants in general as opposed to gas 

gathering equipment, the Natural Gas STAR reported processing reductions of 6 

Bcf/year were not incorporated into this analysis26. 

	 CH4, CO2 and N2O combustion emissions (CO2e) were estimated by applying CH4, 

CO2 and N2O API compendium relevant combustion emission factors to the fuel gas 

used by each plant. The fuel gas consumption was estimated using the horsepower 

requirements of engines and turbines per plant. 

	 N2O combustion emissions (CO2e) were estimated by applying API compendium 

N2O combustion emission factors to the fuel gas used by each plant. 

 The different emissions per plant was summed up to provide total emissions (CO2e) 

 Each facility was assigned a “1” or “0” based on if it crossed a threshold by running 

the following logic checks: 

o	 IF(operator total emissions > 1000) then reporting 

o	 IF(operator total emissions > 10000) then reporting 

o	 IF(operator total emissions > 25000) then reporting 

o IF(operator total emissions >100000) then reporting 

 Summing the results of the above logic checks for each threshold provided the 

number of facilities exceeding that threshold. 

 Multiplying the logic checks above by the total emissions for each facility, then 

summing the results yielded the total emissions covered at each threshold. 

	 The resulting O&M and capital costs from the cost burden analyses were entered for 

each facility in the spreadsheet. The sum of the product of O&M or capital costs and 

the logic checks described above provides the total cost burdens for each reporting 

threshold. Dividing the total cost burdens by the number of reporting facilities 

(calculated above) provides the average facility cost burdens at each reporting 

threshold. 

Threshold Analysis for Transmission 

	 “Facility” in the natural gas transmission segment is defined as a compressor station. 

Data for individual compressor stations on interstate transmission pipelines are 

Background Technical Support Document – Petroleum and Natural Gas Industry 97 
 

reported to FERC Form 228, and data for compressor stations on intrastate pipelines 

were obtained from EIA through personal contact. However, the data collected for 

intrastate pipelines were incomplete. 

	 For intrastate pipeline facilities that did not have the number of compressor stations 

listed, it was assumed that each facility has one compressor. The compressor 

horsepower per intrastate pipeline was estimated by multiplying design throughput 

per intrastate pipeline with the ratio of total interstate pipeline compressor 

horsepower (engine and turbine) to the total interstate design throughput. 

	 The FERC data, supplemented with intrastate data and assumptions, list pipeline 

states, names, designed throughput capacity, and in some cases the type of 

compressor (centrifugal, reciprocating, and/or electric), and the installed horsepower 

for each station. 

	 In cases where the installed reciprocating horsepower is provided, it was used for 

installed engine capacity (Hp). In cases where the installed capacity was provided, 

but the type of compressor was not specified, the analysis assumes that 81% of the 

installed capacity is reciprocating. In cases where the provided installed capacity is 

both centrifugal and reciprocating, it is assumed that 81% is for engines. The 81% 

assumption is the ratio of reciprocating compressor engine capacity in the 

transmission sector to centrifugal turbine drivers for 2006 taken from the U.S. GHG 

Inventory 

	 The ratio of reciprocating compressor engine driver energy use (MMHphr, EPA1

) to 

interstate station design throughput capacity (MMcfd, FERC28) was calculated. Then, 

the reciprocating compressor energy use for each station was assigned by multiplying 

the installed station throughput capacity by the ratio calculated previously in this 

bullet. 

	 In cases where the installed centrifugal horsepower is provided, it was used directly 

for installed turbine capacity (Hp). In cases where the installed capacity was 

provided, but the type of compressor was not specified, the analysis assumes that 

19% of the installed capacity is centrifugal. In cases where the provided installed 

capacity is both centrifugal and reciprocating, it is assumed that 19% is for turbines. 

The 19% assumption is the ratio of centrifugal compressor turbine capacity in the 

transmission sector to reciprocating engine drivers taken from the U.S. GHG 

Inventory. 

	 The ratio of centrifugal compressor engine driver energy use (MMHphr, EPA1

) to 

interstate station design throughput capacity (MMcfd, FERC28) was calculated. Then, 

the reciprocating compressor energy use for each station was assigned by multiplying 

the installed station throughput capacity by the ratio calculated previously in this 

bullet. 

	 The total emissions for 2006, both vented and equipment leak methane and nonenergy CO2, were estimated in the U.S. GHG Inventory. Emission factor for 

centrifugal compressor wet seals was obtained from Bylin et al5 . Due to the 

uncertainty in centrifugal compressor wet seal emissions, the point that it is not 

possible to ascribe Natural Gas STAR transmission partner emission reductions to a 

28 FERC. Form 2 Major and Non-major Natural Gas Pipeline Annual Report. Available online at: 

<http://www.ferc.gov/docs-filing/eforms/form-2/data.asp#skipnavsub>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 98 
 

particular compressor station or even to transmission in general as opposed to gas 

storage equipment, the Natural Gas STAR reported transmission reductions of 25 

Bcf/year were not incorporated into this analysis26. The total emissions were 

allocated to each facility based on its portion of the segment’s total station throughput 

capacity, as shown in the following equation: 

StationCapacityi Station “i” process emissions = TotalInventoryEmissions StationCapacity 

i 

	 Combustion CO2 and N2O emissions were estimated for each facility by applying the 

following emission factors: 

EFCO2 = 719 metric tons CO2e/MMHphr 

EFN20 = 5.81 metric tons CO2e/MMHphr 

EmissionsCO2 or N20 = EFCO2 or N20 × Compressor energyi (MMHphr) 

 The total emissions for each facility were calculated by summing the calculated 

process and the combustion emissions. 

 Each facility was assigned a “1” or “0” based on if it crossed a threshold by running 

the following logic checks: 

o	 IF(operator total emissions > 1000) then reporting 

o	 IF(operator total emissions > 10000) then reporting 

o	 IF(operator total emissions > 25000) then reporting 

o IF(operator total emissions >100000) then reporting 

 Summing the results of the above logic checks for each threshold provided the 

number of facilities exceeding that threshold. 

	 Multiplying the logic checks above by the total emissions for each facility, then 

summing the results yielded the total emissions covered at each threshold. 

Threshold Analysis for Underground Storage 

	 “Facility” in the underground natural gas storage segment is defined as storage 

stations and the connected storage wellheads. Underground storage data by operator 

are collected in form EIA-17629. 

	 The data collected in EIA-176 contained each underground storage operator, field, 

and location as well as the storage capacity and maximum daily delivery. 

	 The total compressor energy use in 2006 for the underground storage segment was 

estimated in the U.S. GHG Inventory. This total energy use, in millions of 

horsepower hours (MMHphr), is allocated to each facility based on its portion of the 

segment’s total maximum daily delivery capacity; as described in the following 

equation: 

29 EIA. EIA-176 Query System. Available online at: 

<http://www.eia.doe.gov/oil_gas/natural_gas/applications/eia176query_historical.html>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 99 
MaximumDailyDelivery Compressor energyi (MMHphr) = i TotalSegmentMMHphr  MaximumDailyDelivery 

i 

Where, index “i” denotes an individual facility 

	 The total process emissions for 2006, both vented and equipment leak methane and 

non-energy CO2, were estimated in the U.S. GHG Inventory. These total process 

emissions were allocated to each facility based on its portion of the segment’s total 

maximum daily delivery capacity, using the same methods as compressor energy use. 

	 Combustion CO2 and N2O emissions were estimated for each facility by applying the 

following emission factors: 

EFCO2 = 719 metric tons CO2e/MMHphr 

EFN20 = 5.81 metric tons CO2e/MMHphr 

EmissionsCO2 or N20 = EFCO2 or N20 × Compressor energyi (MMHphr) 

 The total emissions for each facility were calculated by summing the calculated 

process and the combustion emissions. 

 Each facility was assigned a “1” or “0” based on if it crossed a threshold by running 

the following logic checks: 

o	 IF(operator total emissions > 1000) then reporting 

o	 IF(operator total emissions > 10000) then reporting 

o	 IF(operator total emissions > 25000) then reporting 

o IF(operator total emissions >100000) then reporting 

 Summing the results of the above logic checks for each threshold provided the 

number of facilities exceeding that threshold. 

	 Multiplying the logic checks above by the total emissions for each facility, then 

summing the results yielded the total emissions covered at each threshold. 

Threshold Analysis for LNG Storage 

	 “Facility” in LNG storage segment is defined as LNG storage plants (peak shaving or 

satellite). Data for each peak shaving facility is provided in The World LNG Source 

Book – An Encyclopedia of the World LNG Industry. Summary data for all satellite 

facilities is estimated in the Additional Changes to Activity Factors for Portions of the 

Gas Industry background memo for EPA’s U.S. GHG Inventory. 

	 The data reported in The World LNG Source Book – An Encyclopedia of the World 

LNG Industry includes the operator, liquefaction capacity, storage capacity, 

vaporization design capacity for each individual peak shaving plant. 

	 U.S GHG Inventory reports that in addition to peak shaving plants there are 

approximately 100 satellite facilities with a total storage capacity of 8.7 Bcf. The ICF 

memo also provides several key assumptions that will be discussed at the appropriate 

locations below. 

	 The total liquefaction compressor energy use for the segment was estimated using the 

methods and assumptions detailed in the background memo for EPA’s U.S. GHG 

Inventory. LNG company contacts provided the memo’s assumption that 750 

MMHphr are required for liquefaction for each million cubic feet per day of 

liquefaction capacity. It assumes the liquefaction takes place over a 200-day “fill” 

Background Technical Support Document – Petroleum and Natural Gas Industry 100 
 

 

season. It assumes that approximately 50% of compressors are driven by gas-fired 

engines or turbines. EIA provides the LNG storage additions for 2006 on its website, 

totaling 38,706 MMcf. Thus, the total liquefaction energy use for the segment was 

calculated using the following formula: 

38,706MMcf 750Hp 24hours	 1MMHphr LEU =    200days 50% 

200days 1MMcfd day 1,000,000Hphr 

where, 

LEU = total liquefaction energy use for the segment, gas fired (MMHphr) 

	 The total calculated liquefaction compressor energy use was apportioned to individual 

facilities based on their share of the total liquefaction capacity for the segment, as 

shown in the following equation: 

LCi Facility “i” liquefaction MMHphr = TotalSegmentMMHphr LC 

i 

Where “i” indexes facilities and LC = liquefaction capacity. 

	 Storage capacity, provided in gallons by The World LNG Source Book – An 

Encyclopedia of the World LNG Industry, was converted to million cubic feet with a 

conversion factor of 1 gallon of LNG = 81.5 standard cubic feet of natural gas. 

	 Boil-off liquefaction compressor energy use was calculated using assumptions 

outlined in the U.S GHG Inventory. The memo assumes that 0.05% of storage 

capacity boils off and is recovered by vapor recovery compressors and liquefied. 

These compressors must operate all year and require the same 750 Hp per 1 MMcfd 

liquefied. The boil-off liquefaction compressor energy use was thus estimated for 

each facility using the following equation: 

SCi  0.05% 750Hp  24hours  MMHphr FBEUi =  

365days  

365days MMcfd  day  1,000,000Hphr 

where, 

FBEUi = Facility “i” boil-off liquefaction compressor energy use 

(MMHphr) 

SC = Facility “i” storage capacity (MMcf) 

	 Vaporization and send-out compressor energy use was also calculated based on 

assumptions from the U.S GHG Inventory. It estimates that with an average send-out 

pressure of 300 psia and inlet pressure of 15 psia, using 2-stage compression, a 

satellite facility requires 1.86 MMHphr for each MMcfd of send-out. The send-out 

period lasts all year, unlike the “fill” season. The memo also estimates that 75 Bcf of 

gas were sent out from peak shaving facilities compared to 8.7 Bcf from satellite 

facilities in 2003. This equates to 89.6% of send-out coming from peak shaving 

plants in 2003; the analysis assumes the same is true for 2006. EIA30 provides that in 

2006, total LNG withdrawals were 33,743 MMcf. The send-out compressor energy 

30 EIA. Liquefied Natural Gas Additions to and Withdrawals from Storage. Available online at: 

<http://tonto.eia.doe.gov/dnav/ng/ng_stor_lng_dcu_nus_a.htm>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 101 
use by all peak shaving plants in the segment was calculated using the following 

equation: 

33,743MMcf 1.86MMHphr Total send-out energy use =  89.6% 

365days MMcfd 

	 Send-out compressor energy use was apportioned to each peak shaving facility by its 

share of the total peak shaving segment’s send-out capacity; using the same method 

as apportioning liquefaction energy use. (See liquefaction bullet). 

	 The 100 satellite facilities were assumed to be equal size and capacity. That is, 8.7 

Bcf storage capacity, all of which is sent out each year. It was assumed that satellite 

facilities have no liquefaction, except for that which is necessary for boil-off. We 

performed the above analysis on the “average” satellite facility to estimate its energy 

use and emissions. The only difference was that 10.4% of EIA reported LNG 

withdrawals was attributed to the satellite facilities. 

	 The total process emissions for 2006, both vented and equipment leak methane and 

non-energy CO2, were estimated in the U.S. GHG Inventory. These total emissions 

were allocated to each facility based on its portion of the segment’s total storage 

capacity, using the same methods as apportioning liquefaction and send-out 

compressor energy use. 

 Combustion CO2 and N2O emissions were estimated for each facility by applying the 

following emission factors: 

EFCO2 = 719 metric tons CO2e/MMHphr 

EFN20 = 5.81 metric tons CO2e/MMHphr 

EmissionsCO2 or N20 = EFCO2 or N20 × Compressor energyi (MMHphr) 

	 The total emissions for each facility were calculated by summing the calculated 

equipment leak, vented, and combustion emissions. 

	 Each facility was assigned a “1” or “0” based on if it crossed a threshold by running 

the following logic checks: 

o	 IF(operator total emissions > 1000) then reporting 

o	 IF(operator total emissions > 10000) then reporting 

o	 IF(operator total emissions > 25000) then reporting 

o IF(operator total emissions >100000) then reporting 

 Summing the results of the above logic checks for each threshold provided the 

number of facilities exceeding that threshold. 

 Multiplying the logic checks above by the total emissions for each facility, then 

summing the results yielded the total emissions covered by each threshold. 

	 Satellite facilities crossed the 1,000 and 10,000-metric ton reporting threshold, but 

fell well short of the 25,000-metric ton threshold. 

Threshold Analysis for LNG Import Terminals 

Background Technical Support Document – Petroleum and Natural Gas Industry 102 
 

 

 

 

 

 

	 “Facility” in the LNG import segment is defined as the import terminals. Data is 

available for this on the FERC website31. It provides the owner, location, capacity, 

and 2006 import volumes for each LNG terminal. 

	 ICF Additional Changes to Activity Factors for Portions of the Gas Industry 

background memo for EPA’s U.S. Inventory assumptions were used to estimate 

liquefaction, boil-off liquefaction, and send-out compressor energy use for each of the 

LNG import terminals. 

	 It was assumed that import terminals do not have liquefaction capacity. 

	 Boil-off liquefaction compressor energy use was calculated using assumptions 

outlined in ICF Additional Changes to Activity Factors for Portions of the Gas 

Industry background memo for EPA’s U.S. Inventory. The memo assumes that 

0.05% of capacity boils off and is recovered by vapor recovery compressors and 

liquefied. These compressors must operate all year and require the same 750 Hp per 

1 MMcfd liquefied. The boil-off liquefaction compressor energy use was thus 

estimated for each facility using the following equation: 

IVi  0.05% 750Hp  24hours  MMHphr FBEUi =  

365days  

365days MMcfd  day  1,000,000Hphr 

where, 

FBEUi = Facility “i” boil-off liquefaction compressor energy use 

(MMHphr) 

IVi = Facility “i” import volume (MMcf) 

	 Vaporization and send-out compressor energy use was also calculated based on 

assumptions from ICF Additional Changes to Activity Factors for Portions of the Gas 

Industry background memo for EPA’s U.S. GHG Inventory. It estimates that with an 

average send-out pressure of 300 psia and inlet pressure of 15 psia, using 2-stage 

compression, satellite facilities require 1.86 MMHphr for each MMcfd of send-out. 

The following equation estimates the energy use at each facility: 

IVi 1.86MMHphr Facility “i” send-out energy use = 

365days MMcfd 

 The total process emissions for 2006, both vented and equipment leak methane and 

non-energy CO2, were estimated in the U.S. GHG Inventory. These total process 

emissions were allocated to each facility based on its portion of the segment’s total 

import volume, using the following equation: 

IVi Facility “i” process emissions =  InventorySegmentEmissions IV 

i 

where, 

IVi = import volume and “i” represents individual facilities 

 Combustion CO2 and N2O emissions were estimated for each facility by applying the 

following emission factors: 

EFCO2 = 719 metric tons CO2e/MMHphr 

31 FERC. Import Terminals. Available online at: <http://www.ferc.gov/industries/lng.asp>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 103 
 

EFN20 = 5.81 metric tons CO2e/MMHphr 

EmissionsCO2 or N20 = EFCO2 or N20 × Compressor energyi (MMHphr) 

 The total emissions for each facility were calculated by summing the calculated 

process and the combustion emissions. 

 Since there were only 5 active import terminals, all were assumed to be “medium” in 

size. 

 Each facility was assigned a “1” or “0” based on if it crossed a threshold by running 

the following logic checks: 

o	 IF(operator total emissions > 1000) then reporting 

o	 IF(operator total emissions > 10000) then reporting 

o	 IF(operator total emissions > 25000) then reporting 

o IF(operator total emissions >100000) then reporting 

 Summing the results of the above logic checks for each threshold provided the 

number of facilities exceeding that threshold. 

	 Multiplying the logic checks above by the total emissions for each facility, then 

summing the results yielded the total emissions covered by each threshold. 

Threshold Analysis for Distribution 

	 “Facility” in the natural gas distribution segment is defined as the local distribution 

company (LDC). The Department of Transportation (DOT)32 provides a set of data 

that contains distribution main pipelines miles by pipeline materials and distribution 

service counts by pipeline material for each LDC. 

	 CO2 and CH4 equipment leaks from distribution mains were evaluated for each 

facility by multiplying its pipeline data by the appropriate emission factor, 

summarized in the table below, from the U.S GHG Inventory1 . 

Exhibit C-8: LDC’s Equipment Leak Emission Factors 

Pipeline Type/Material Equipment Leak Emission 

Factor 

Mains – Unprotected Steel 110 Mcf/mile/year 

Mains – Protected Steel 3.07 Mcf/mile/year 

Mains – Plastic 9.91 Mcf/mile/year 

Mains – Cast Iron 239 Mcf/mile/year 

Services – Unprotected 

Steel 1.70 Mcf/service/year 

Services – Protected Steel 0.18 Mcf/service/year 

Services – Plastic 0.01 Mcf/service/year 

Services – Copper 0.25 Mcf/service/year 

 The total miles of mains pipelines of all materials were summed for each LDC. 

 The total emissions from metering and regulating (M&R) stations for 2006, both 

vented and equipment leak methane and non-energy CO2, were estimated by EPA 

32 DOT. 2006 Distribution Annuals Data. Available online at: 

<http://www.phmsa.dot.gov/pipeline/library/data-stats>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 104 
U.S GHG Inventory. These total emissions were allocated to each facility based on 

its portion of the segment’s total import volume, using the following equation: 

MM i Facility “i” M&R emissions =  InventorySegmentEmissions  MM 

i 

where, 

MM = total miles of mains pipeline, and “i” represents individual 

facilities 

	 The total emissions for each facility were calculated by summing the calculated 

pipeline leaks and M&R station emissions26. 

	 Each facility was assigned a “1” or “0” based on if it crossed a threshold by running 

the following logic checks: 

o	 IF(operator total emissions > 1000) then reporting 

o	 IF(operator total emissions > 10000) then reporting 

o	 IF(operator total emissions > 25000) then reporting 

o IF(operator total emissions >100000) then reporting 

 Summing the results of the above logic checks for each threshold provided the 

number of facilities exceeding that threshold. 

	 Multiplying the logic checks above by the total emissions for each facility, then 

summing the results yielded the total emissions covered at each threshold. 

Background Technical Support Document – Petroleum and Natural Gas Industry 105 
 

Appendix D: Analysis of potential facility definitions for onshore 

petroleum and natural gas production 

The purpose of this appendix is to determine the barriers in using a physical definition of a 

facility for the onshore petroleum and natural gas production segment. The paper also 

discusses a potential alternative to a physical definition by using a corporate level reporter 

definition. 

A. Facility Definition: Any production sector reporting configuration will need specific 

definitions on what constitutes a facility. 

i.	 Field level – A field may be defined by either physically aggregating certain 

surface equipment, referred to as physical field definition. Or the field may be 

defined by demarcation of geographical boundaries, referred to as Geographic 

field definition. 

Physical field definition: 

The challenge in defining a field as a facility is to recognize a common structure 

through the oil and gas production operations. Such a definition can be achieved 

by identifying a point in the system upstream of which all equipment can be 

collectively referred to as a field level facility. All oil and gas production 

operators are required by law to meter their oil and gas production for paying 

royalties to the owner of the gas and taxes to the state, referred to as the lease 

meter. All equipment upstream of this meter can be collectively referred to as a 

facility. 

There is no precedence for such a definition in the CAA. It must be noted, 

however, that the facility definitions commonly used in the CAA pertain 

specifically to pollutants whose concentration in the ambient atmosphere is the 

deciding factor on its impact. This is not necessarily true of GHGs that have the 

same overall impact on climate forcing irrespective of how and where they occur. 

Geographic field definition: 

An alternative to the lease meter field level definition is to use the EIA Oil and 

Gas Field Code Master33 to identify each geological field as a facility. This 

definition is structurally similar to the corporate basin level definition, i.e. it uses 

geological demarcations to identify a facility rather than the above ground 

operational demarcation. 

ii.	 Basin level – The American Association of Petroleum Geologists (AAPG) 

provides a geologic definition of hydrocarbon production basins which are 

referenced to County boundaries. The United States Geological Survey (USGS) 

33 EIA Oil and Gas Field Master – 2007, 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/field_code_master_list/current/pdf/fcml_all. 

pdf 

Background Technical Support Document – Petroleum and Natural Gas Industry 106 
also provides such a definition, which is different than the AAPG definition. The 

AAPG definition identified by the “geologic province code” is most commonly 

used by the industry and can be used to report emissions from each basin. The 

individual counties in each state are allocated to different geologic province codes 

and therefore there is no ambiguity in associating an operation with the relevant 

basin (geologic province code). An operation physically located on a basin as 

defined by the AAPG can be identified with that particular basin, irrespective of 

which basins the wells are producing from. (Well pads may have multiple wells 

producing from different fields and zones in a reservoir, and possibly different 

basins as well). 

B. Level of Reporting: It is important to clearly distinguish the level of reporting- i.e., the 

facility level or the corporate level. The level of reporting is where the threshold level is 

applied and thus determination on whether reporting is required. In some cases, the 

owner or operator of the facility itself is the reporter and in other cases it is the overall 

company that is the reporter. For example, in subpart NN of the MRR published on 

September 22, 2009, reporting for natural gas sent to the end use customers is at the local 

distribution company, and not the individual physical locations (or facilities) that send the 

natural gas into the economy. Alternatively, in subpart MM of the initial rule proposal, 

the owner or operator of the individual refinery is the reporter as opposed to the company 

owning multiple refineries. 

For the purposes of onshore petroleum and natural gas production reporting can be at 

either the facility level or the corporate level. If the level of reporting is at the corporate 

level, it could still be required that data be reported for individual facilities. 

C. Qualitative Analysis of Facility Options 

The following qualitative evaluation provides a discussion on the advantages and 

disadvantages of using any of the three reporting level definitions, based on expert opinion. 

i. Ease of practical application of reporter and facility definitions 

1) Field level facility definition – In this case the physical demarcation of field 

level by aggregating field equipment is difficult to implement. On the other 

hand, field level definition based on boundaries identified by the EIA Oil and 

Gas Field Code Master should be easy to implement, since the classification if 

widely used in the industry. 

Physical Field Definition: 

There are no standard guidelines or operational practices on how many wells 

can be connected to one lease meter. The choice of whether multiple wells are 

connected to the same lease meter depends on; the well spacing, number of 

owners of leases, volume of hydrocarbons produced per well, geographical 

Background Technical Support Document – Petroleum and Natural Gas Industry 107 
 

boundaries, and ease of operation. Therefore, such a definition will lead to 

facilities of all kinds of sizes; at one extreme several well pads with multiple 

wells could be connected to one lease meter, while at the other extreme where 

situation demands only one well with no equipment could directly be
 

connected to a lease meter. In addition there will be thousands of facilities that 

will be under purview. 

 Any lease meters located upstream of a compression system will exclude
 

compressors from the facility definition. This means that the required 

threshold for emissions reporting may not be reached due to exclusion of the 

equipment leaks as well as the combustion emissions from compressors. 

Alternatively, the threshold will have to be set very low to capture any 

reasonable amount of emissions from field level definition. 

Geographic field definition: 

The EIA publishes its Field Code Master on a yearly basis. Also, the 

classification system is widely used in the industry. Hence such a definition 

should be easy to implement. 

2) Basin level facility definition - Basin level definition is more practical to 

implement given that operational boundaries and basin demarcations are 

clearly defined. Furthermore, more emissions will be captured under this 

facility definition than the field level or well level definitions. 

3) Corporate reporting - 

It can be difficult to identify who the corporation is that would be responsible 

for reporting. If the corporation can be readily identified and defined then 

applying a field level facility definition using the EIA field classification or 

basin level facility definition using AAPG classification becomes practical. 

ii. Coverage that can be expected from each definition type 

1)	 Field level facility definition – This definition (both physical and 

geographical) provides the highest level of detail possible on emissions 

sources. However, any field level definition along with a 25,000 metric tons 

CO2e/year threshold for reporting could potentially exclude a large portion of 

the U.S. oil and gas operations. Hence only a portion of the entire emissions 

from the U.S. oil and gas operations will get reported. 

2)	 Basin level facility definition - Basin level information will throw light on the 

difference in patterns of emissions from sources both as a result of being 

located in different basins and as a result of different operational practices in 

different companies. This definition will result in the reporting of a significant 

portion of the emissions for the identified sources from the entire U.S. onshore 

oil and gas operations. 

Background Technical Support Document – Petroleum and Natural Gas Industry 108 
3) Corporate reporting - This definition will result in reporting of a significant 

portion of the emissions for the identified sources from the entire US onshore 

oil and gas operations. Since the reporting will be at a company level, 

variations in emissions from sources due to location on different basins may 

not be evident. However, if corporate national level reporter definition is used 

in addition to field and/or basin level reporting then all possible patterns in 

emissions will be evident. 

D. Data Sources for Research and Analysis 

i. Clean Air Act 

ii. United States Geological Survey 

iii. Natural Gas STAR Technical Documents 

iv. EPA National GHG Inventory 

v. DOE GASIS database 

vi. Lasser® database 

vii. Energy Information Administration 

viii. Oil & Gas Journal 

ix. HARC - VOC Emissions from Oil and Condensate Storage Tanks 

x. State Oil and Gas Commissions 

xi. American Association of Petroleum Geologists 

Background Technical Support Document – Petroleum and Natural Gas Industry 109 
 

 

Appendix E: Development of multipliers to scale emissions or 

miscellaneous sources connected to storage tanks 

This method of quantifying tank emissions assumes that thermodynamically based models 

such as E&P Tank can accurately predict the effect of flashing emissions from hydrocarbons 

in fixed roof storage; but are unable to predict or account for emissions from vortexing or 

dump valves. Either direct measurement or a correction factor is required to represent the 

total emissions from hydrocarbon storage tanks. 

This appendix compares two methods of correcting E&P Tank (GEO-RVP) data to account 

for non-flashing emission effects on tanks. Actual measurement data from a Texas 

Commission on Environmental Quality (TCEQ) report34 were compared to E&P Tank 

(GEO-RVP) data runs on the same tanks to develop a correction factor which can be applied 

to E&P Tank (GEO-RVP) results in which additional non-flashing emissions or vortexing are 

detected. 

Selected Data 

All data considered were presented in a TCEQ-funded report that compared tank emission 

predicting equations, charts, and models to actual measured data. Data from the E&P Tank 

2.0 GEO-RVP setting were compared against to direct measurement results. The TCEQ 

study focused on comparing the various methods of predicting VOC portion of emissions; 

however, for the purposes of this analysis, the total gas-oil ratios were compared. 

Where direct measurement results were within ±100% of E&P Tank (GEO-RVP) results, 

those tanks were assumed to be exhibiting typical flashing emissions only. Direct 

measurement results greater or less than ±100% of E&P Tank (GEO-RVP) results were used 

to develop a correction factor for non-flashing effects on tank emissions. 

The data were separated into two regimes: 

 Hydrocarbon liquids with API gravities less than 45 ̊API were considered “oil” 

 Hydrocarbon liquids with API gravities greater than 45 ̊API were considered 

“condensate” 

Correction factors were developed for both ranges. 

Method 1 – Least Squares Analysis of Emission Difference 

The first method sorts qualifying tanks in ascending order of emission rates estimated by the 

E&P Tank (GEO-RVP) runs. The difference between the measured emission rate and E&P 

Tank (GEO-RVP) emission rates was plotted against the E&P Tank (GEO-RVP) emission 

rates and a trend line was fitted to the equation, as shown in Exhibits E-9 and E-10. 

Exhibit E-9. Oil Tank Correction Factors 

34 Texas Commission on Environmental Quality (TCEQ). Upstream Oil and Gas Storage Tank Project Flash 

Emissions Models Evaluation. July 16, 2009. 

Background Technical Support Document – Petroleum and Natural Gas Industry 110 
y = -1.5592x + 139.23 

R2

 = 0.0719 

(100) 

-

100 

200 

300 

400 

500 

10 20 30 40 50 60 70 80 90 100 

[Measurement] - [E&P Tank estimates]

E&P Tank Estimate (scf/bbl) 

(scf/bbl) 

Oil Tanks ( ̊API<45) 

Measurement - E&P Tank Linear (Measurement - E&P Tank) 

Exhibit E-10. Condensate Tank Correction Factors 

600 

[Measurement] - [E&P Tank estimates] 

(scf/bbl) 

500 

400 

300 

200 

100 

-

y = -0.6673x + 248.34 

R2

 = 0.0045 

E&P Tank Estimate (scf/bbl) 

Condensate Tanks ( ̊API>45) 

20 30 40 50 60 70 80 

Measurement - E&P Tank Linear (Measurement - E&P Tank) 

The equation for the line of best fit can be used on E&P Tank (GEO-RVP) results where 

non-flashing emission affects are detected to estimate the true tank emissions. The data used 

to derive this relationship range from oil gravities from 29.1 to 44.8 ̊API and separator 

pressures from 15 to 70 psig; and for condensate gravities from 45.3 to 82.2 ̊API and 

separator pressures from 30 to 231 psig. 

The E&P Tank (GEO-RVP) emission estimates can be corrected with the following 

equations: 

 For oil: CE = (-0.5592 × EE) + 139.23 

 For condensate: CE = (0.3327 × EE) + 248.34 

Where “EE” is the E&P Tank (GEO-RVP) emission estimate and “CE” is the corrected 

emission estimate. 

As demonstrated in Exhibits E-9 and E-10, the correlations for the correction factor are very 

weak, with R2

 values of 0.0719 for oil and 0.0045 for condensate. 

Background Technical Support Document – Petroleum and Natural Gas Industry 111 
Method 2 – Average Emissions Ratio Analysis 

This method takes the simple average of the ratio of qualifying measured emission rates to 

simulated emission rates generated by E&P Tank (GEO-RVP) for the oil and condensate 

ranges. 

Using this method, E&P Tank (GEO-RVP) emission estimates can be corrected with the 

following equations: 

 For oil: CE = 3.87 × EE 

 For condensate: CE = 5.37 × EE 

Where “EE” is the E&P Tank (GEO-RVP) emission estimate and “CE” is the corrected 

emission estimate. 

Summary 

Predicting and evaluating non-flashing effects on emissions (such as dump valves or 

vortexing) has not yet been thoroughly studied or quantified. The methods above have 

significant weaknesses as: 

1. The sample data set is limited 

2. Only weak correlations were observed for the available data. 

Method 1 naturally suggests that very low estimates are underestimating the tank emissions 

and very high estimates (over 89 scf/bbl for oil) are overestimating the emissions. This will 

tend to “even out” estimates so that none are extremely high or extremely low. It also 

suggests that if E&P Tank (GEO-RVP) estimates 0 scf/bbl flashing emissions, the emission 

rates are actually higher than if E&P Tank (GEO-RVP) estimates large (near 89 scf/bbl for 

oil) emission rates. 

Method 2 does not “even out” emission rates, and assumes that in all cases where nonflashing effects are present, each case is uniformly underestimated. 

Background Technical Support Document – Petroleum and Natural Gas Industry 112 
 

 

Appendix F: Development of leaker emission Factors 

Natural Gas Emission Factors for Onshore Production 

Leaker Emission Factors – All Components, Light Crude Service 

Methodology 

Average emission factors by facility type are taken from API’s Emission Factors for Oil and 

Gas Production Operations35. Hydrocarbon liquids greater than or equal to 20°API are 

considered “light crude.” The methane content of associated natural gas with onshore light 

crude is 61.3% is taken from the same API publication, Table ES-4, page ES-3. 

Component EF, scf/hour/component = ((Component EF, lb/day THC) * (A)) / ((B) * (C)) 

Component Name Component EF, 

scf/hour/comp 

Component EF, 

lb/day THC 

Valve 2.03 3.381 

Connector 0.90 1.497 

Open-Ended Line 0.96 1.6 

Pump 2.35 3.905 

Other 2.31 3.846 

EF: Emission Factor
 

THC: Total Hydrocarbons
 

Conversions: 

A: 0.613 – CH4 content of onshore light crude associated natural gas 

B: 0.04246 CH4 density lb/scf 

C: 24 hours/day 

Leaker Emission Factors – All Components, Heavy Crude Service 

Methodology 

Average emission factors by facility type are taken from API’s Emission Factors for Oil and 

Gas Production Operations35 . Hydrocarbon liquids less than 20°API are considered “heavy 

crude.” The methane content of associated natural gas with onshore heavy crude is 94.2% 

taken from the same API publication, Table ES-4, page ES-3. 

Component EF, scf/hour/component = ((Component EF, lb/day THC) * (D)) / ((B) * (C)) 

Component Name Component EF, 

scf/hour/component 

Component EF, 

lb/day THC 

Valve 3.13 3.381 

Flange 4.15 4.49 

Connector (other) 1.38 1.497 

Open-Ended Line 1.48 1.6 

Other 3.56 3.846 

35 API. Emission Factors for Oil and Gas Production Operations. Table 10, page 16. API Publication Number 

4615. January 1995. 

Background Technical Support Document – Petroleum and Natural Gas Industry 113 
 

 

EF: Emission Factor
 

THC: Total Hydrocarbons
 

Conversions: 

B: 0.04246 CH4 density lb/scf 

C: 24 hours/day 

D: 0.942 – CH4 content of onshore heavy crude associated natural gas 

Total Hydrocarbon Emission Factors for Processing 

Leaker Emissions Factors – Reciprocating Compressor Components, Centrifugal 

Compressor Components, and Other Components, Gas Service 

Methodology 

The leaker emissions factors are from Clearstone Engineering’s Identification and Evaluation 

of Opportunities to Reduce Methane Losses at Four Gas Processing Plants36 and 

Clearstone’s Cost-Effective Directed Inspection and Maintenance Control Opportunities at 

Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites37. 

The components were categorized into three groups: reciprocating compressor related, 

centrifugal compressor related and all other components. Furthermore, the components 

related to reciprocating and centrifugal compressor were segregated into components before 

and after the de-methanizer. Once categorized, the sum of the leak rates from components 

known to be leaking was divided by the sum of number of leaking components. 

Component EF, scf/hour/component = (Leak rate, Mscf/day/component) * (E) / (C) 

Component 

Name 

Reciprocating Compressor 

Component, (scf/hour/comp) 

Centrifugal Compressor 

Component, (scf/hour/comp) Other 

Components, 

Before De- (scf/hour/comp) 

Methanizer 

After DeMethanizer Before DeMethanizer After DeMethanizer 

Valve 15.88 18.09 0.67 2.51 6.42 

Connector 4.31 9.10 2.33 3.14 5.71 

Open-Ended 

Line 17.90 10.29 17.90 16.17 11.27 

Pressure 

Relief Valve 2.01 30.46 - - 2.01 

Meter 0.02 48.29 - - 2.93 

Conversions: 

C: 24 hours / day 

E: 1000 scf / Mscf 

36 EPA. Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas Processing 

Plants. Clearstone Engineering Ltd. June 20, 2002. <www.epa.gov/gasstar/documents/four_plants.pdf> 37 National Gas Machinery Laboratory, Kansas State University; Clearstone Engineering, Ltd; Innovative 

Environmental Solutions, Inc. Cost-Effective Directed Inspection and Maintenance Control Opportunities at 

Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites. For EPA Natural 

Gas STAR Program. March 2006. 

Background Technical Support Document – Petroleum and Natural Gas Industry 114 
 

 

 

Total Hydrocarbon Emission Factors for Transmission 

Leaker Emission Factors – All Components, Gas Service 

Methodology 

Gas transmission facility emissions are drawn from the Handbook for Estimating Methane 

Emissions from Canadian Natural Gas Systems38 and the Measurement of Natural Gas 

Emissions from the Canadian Natural Gas Transmission and Distribution Industry39 . All 

compressor related components were separated from the raw data and categorized into the 

component types. Once categorized, the sum of the leak rates from components known to be 

leaking was divided by the sum of number of leaking components. 

Component EF, scf/hour/component = (Gas Transmission Facility Emissions, kg/h/src) * (F) 

/ (B) 

Component Name Component EF, 

(scf/hour/comp) 

Connector 2.7 

Block Valve 10.4 

Control Valve 3.4 

Compressor Blowdown Valve 543.5 

Pressure Relief Valve 37.2 

Orifice Meter 14.3 

Other Meter 0.1 

Regulator 9.8 

Open-Ended Line 21.5 

Conversions: 

B: 0.04246 CH4 density lb/scf 

F: 2.20462262 lb/kg 

Methane Emission Factors for LNG Storage 

Leaker Emission Factors – LNG Storage Components, LNG Service 

Methodology 

38 Clearstone. Handbook for Estimating Methane Emissions from Canadian Natural Gas Systems. Clearstone 

Engineering Ltd., Enerco Engineering Ltd, and Radian International. May 25, 1998. 

39 Clearstone. Measurement of Natural Gas Emissions from the Canadian Natural Gas Transmission and 

Distribution Industry. Clearstone Engineering Ltd., Canadian Energy Partnership for Environmental Innovation 

(CEPEI). April 16, 2007. 

Background Technical Support Document – Petroleum and Natural Gas Industry 115 
 

 

The light liquid emission factors with leak concentrations greater than or equal to 10,000 

ppmv were taken from Protocol for Equipment Leak Emission Estimates40. The emissions 

are assumed to be 100% methane. 

Component EF, scf/hour/component = (Light Liquid >= 10,000 ppmv Emission Factor) * (F) 

/ (B) 

Component Name Component EF, 

scf/hour/comp 

† 

Light Liquid EF, 

kg/hr THC 

Valve 1.19 2.30E-02 

Pump Seal 4.00 7.70E-02 

Connector 0.34 6.50E-03 

Other 1.77 3.40E-02 † 

Greater or equal to 10,000 ppmv 

Conversions: 

B: 0.04246 CH4 density lb/scf 

F: 2.20462262 lb/kg 

Total Hydrocarbon Emission Factors for Processing, Transmission, and 

Underground Storage 

Leaker Emissions Factors –Compressor Components, Non-Compressor Components, 

Gas Service 

Methodology 

Several leaker emission factors for the processing segment, such as open-ended lines before 

the de-methanizer for reciprocating compressors, did not have sufficient data points to justify 

a representative emission factor. To eliminate this issue, the segregation of components into 

reciprocating versus centrifugal and before the de-methanizer versus after the de-methanizer 

was eliminated. 

In addition, the leaker emission factors from transmission were combined with those from 

processing. Equipment leak emissions from transmission compressors and processing 

compressors are similar because they are comparable in size and discharge pressure. 

Compressors in processing either inject residue gas into high pressure transmission pipelines 

or pressurize large volumes of production gas for processing facility processes. 

The same LEFs can also be used for compressor related components in underground natural 

gas storage because compressors in this sector have a large throughput and inject gas at high 

pressure into the ground or into transmission pipelines. The final emission factors were 

corrected to 68 ̊F and 14.7 psia per the definition of “standard conditions” set forth in subpart 

A of Title 40 CFR 98. 

40 EPA. Protocol for Equipment Leak Emission Estimates. Emission Standards Division. U.S. EPA. SOCMI 

Table 2-7. November 1995. 

Background Technical Support Document – Petroleum and Natural Gas Industry 116 
 

Component EF, scf/hour/component = (Leak rate, Mscf/day/component) * (E) / (C) 

Component Name Emission Factor (scf/hour/component) 

Leaker Emission Factors – Compressor Components, Gas Service 

Valve 15.07 

Connector 5.68 

Open-ended Line 17.54 

Pressure Relief Valve 40.27 

Meter 19.63 

Leaker Emission Factors – Non -Compressor Components, Gas Service 

Valve 6.52 

Connector 5.80 

Open-ended Line 11.44 

Pressure Relief Valve 2.04 

Meter 2.98 

Conversions: 

C: 24 hours / day 

E: 1000 scf / Mscf 

Methane Emission Factors for LNG Terminals 

Leaker Emission Factors – LNG Terminals Components, LNG Service 

Methodology 

See methodology for Leaker Emission Factors – LNG Storage Components, LNG Service for 

LNG Storage40. 

Methane Emission Factors for Distribution 

Leaker Emission Factors – Above Grade M&R Stations Components, Gas Service 

Methodology 

Gas distribution meter/regulator station emissions are drawn from: Handbook for Estimating 

Methane Emissions from Canadian Natural Gas Systems38 and Measurement of Natural Gas 

Emissions from the Canadian Natural Gas Transmission and Distribution Industry39. 

Component EF, scf/hour/component = (Gas Distribution Meter/Regulator Station Emissions, 

kg/h/src) * (F) / (B) 

Component Name Component EF, 

scf/hour/comp 

Gas Distribution Meter/Regulator 

Station Emissions, kg/h/src 

Connector 0.67 0.01292 

Background Technical Support Document – Petroleum and Natural Gas Industry 117 
 

 

Block Valve 1.49 0.02872 

Control Valve 3.94 0.07581 

Pressure Relief Valve 5.24 0.1009 

Orifice Meter 0.46 0.0088 

Other Meter 0.01 0.0002064 

Regulator 2.14 0.04129 

Open-Ended Line 6.01 0.1158 

Conversions: 

B: 0.04246 CH4 density lb/scf 

F: 2.20462262 lb/kg 

Leaker Emission Factors – Distribution Mains and Services, Gas Service 

Methodology 

Emission factors for pipeline leaks (mains and services) are drawn from GRI’s Methane 

Emissions from the Natural Gas Industry41 . 

Component EF, scf/hour/leak = (Pipeline Leak, scf/leak-year) / (G) 

Component Name 

Component EF 

(Mains), 

scf/hour/leak 

Pipeline Leak EF 

(Mains), 

scf/leak-yr 

Component EF, 

(Services) 

scf/hour/leak 

Pipeline Leak EF 

(Services), 

scf/leak-yr 

Unprotected Steel 6.02 52748 2.33 20433 

Protected Steel 2.38 20891 1.08 9438 

Plastic 11.63 101897 0.35 3026 

Copper 0.88 7684 

Conversions: 

G: 8,760 hours/year 

NATURAL GAS EMISSION FACTORS FOR ONSHORE PRODUCTION 

Emission Factor Onshore production (scf/hour/component) 

Leaker Emission Factors - All Components, Gas Service 

Valve 

Connector

Open-ended Line 

Pressure Relief Valve 

Low-Bleed Pneumatic Device Vents 

Gathering Pipelines

CBM Well Water Production 

Compressor Starter Gas Vent 

Conventional Gas Well Completion 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

41 GRI. Methane Emissions from the Natural Gas Industry. Volume 9. Tables 8-9 and 9-4. June 1996. 

<www.epa.gov/gasstar/documents/emissions_report/9_underground.pdf> 

Background Technical Support Document – Petroleum and Natural Gas Industry 118 
 

 

 

 

 

 

Conventional Gas Well Workover NA 

Leaker Emission Factors - All Components, Light Crude Service1 

Valve 

Connector
 

Open-ended Line 

Pump 

Other 

2.03 

0.90 

0.96 

2.35 

2.31 

Leaker Emission Factors - All Components, Heavy Crude Service2 

Valve 

Flange 

Connector (other)
 

Open-ended Line 

Other 1

 Hydrocarbon liquids greater than or equal to 20 ̊API are considered "light crude" 2

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

3.13 

4.15 

1.38 

1.48 

3.56 

TOTAL HYDROCARBON EMISSION FACTORS FOR PROCESSING
 

Processing1 

Before De-Methanizer 

Emission Factor 

(scf/hour/component) 

After De-Methanizer 

Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - Reciprocating Compressor Components, Gas Service 

Valve 15.88 18.09 

Connector 4.31 9.10 

Open-ended Line 17.90 10.29 

Pressure Relief Valve 2.01 30.46 

Meter 0.02 48.29 

Leaker Emission Factors - Centrifugal Compressor 

Components, Gas Service 

Valve 0.67 2.51 

Connector 2.33 3.14 

Open-ended Line 17.90 16.17 

Leaker Emission Factors - Other Components, Gas Service2 

Valve 

Connector
 

Open-ended Line 

Pressure Relief Valve 

Meter 

6.42 

5.71 

11.27 

2.01 

2.93 

METHANE EMISSION FACTORS FOR TRANSMISSION
 

Transmission Emission Factor (scf/hour/component) 

Leaker Emission Factors - All Components, Gas Service 

Connector 2.7 

Block Valve 10.4 

Background Technical Support Document – Petroleum and Natural Gas Industry 119 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Control Valve 

Compressor Blowdown Valve 

Pressure Relief Valve 

Orifice Meter 

Other Meter 

Regulator 

Open-ended Line 

Leaker Emission Factors - Other Components, Gas Service 

Low-Bleed Pneumatic Device Vents 

1

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

3.4 

543.5 

37.2 

14.3 

0.1 

9.8 

21.5 

NA
 

METHANE EMISSION FACTORS FOR UNDERGROUND STORAGE
 

Underground Storage Emission Factor (scf/hour/component) 

Leaker Emission Factors - Storage Station, Gas Service 

Connector 0.96 

Block Valve 2.02 

Control Valve 3.94 

Compressor Blowdown Valve 66.15 

Pressure Relief Valve 19.80 

Orifice Meter 0.46 

Other Meter 0.01 

Regulator 1.03 

Open-ended Line 6.01 

Leaker Emission Factors - Storage Wellheads, Gas Service 

Connector

Valve 

Pressure Relief Valve 

Open-ended Line 

Leaker Emission Factors - Other Components, Gas Service 

Low-Bleed Pneumatic Device Vents 

NA 

NA 

NA 

NA 

NA
 

TOTAL HYDROCARBON EMISSION FACTORS FOR PROCESSING, TRANSMISSION, AND, UNDERGROUND 

STORAGE 

Processing, Transmission, and Underground Storage Emission Factor (scf/hour/component) 

Leaker Emission Factors – Compressor Components, Gas Service 

Valve 

Connector
 

Open-Ended Line 

Pressure Relief Valve 

Meter 

15.07 

5.68 

17.54 

40.27 

19.63 

Leaker Emission Factors – Non-compressor Components , Gas Service 

Valve 6.52 

Connector 5.80 

Open-Ended Line 11.44 

Background Technical Support Document – Petroleum and Natural Gas Industry 120 
 

 

 

 

 

Pressure Relief Valve 2.04 

Meter 2.98 

1

Valves include control valves, block valves, and regulator valves. 

METHANE EMISSION FACTORS FOR LNG STORAGE 

Emission Factor LNG Storage (scf/hour/component) 

Leaker Emission Factors - LNG Storage Components, LNG Service 

Valve 

Pump Seal 

Connector 

Other 

1.19 

4.00 

0.34 

1.77 

Leaker Emission Factors - LNG Storage Compressor, Gas Service 

Vapor Recovery Compressor NA 

METHANE EMISSION FACTORS FOR LNG TERMINALS 

LNG Terminals Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - LNG Terminals Components, LNG Service 

Valve 

Pump Seal 

Connector 

Other 

1.19 

4.00 

0.34 

1.77 

Leaker Emission Factors - LNG Terminals Compressor, Gas Service 

Vapor Recovery Compressor NA 

METHANE EMISSION FACTORS FOR DISTRIBUTION 

Emission Factor Distribution (scf/hour/component) 

Leaker Emission Factors - Above Grade M&R Stations Components, Gas Service 

Connector 

Block Valve 

Control Valve 

Pressure Relief Valve 

Orifice Meter 

Regulator 

Open-ended Line 

1.69 

0.557 

9.34 

0.270 

0.212 

26.131 

1.69 

Leaker Emission Factors - Below Grade M&R Stations Components, Gas Service 

Below Grade M&R Station, Inlet Pressure > 300 psig NA 

Below Grade M&R Station, Inlet Pressure 100 to 300 psig NA 

Below Grade M&R Station, Inlet Pressure < 100 psig NA 

Leaker Emission Factors - Distribution Mains, Gas Service1 

Unprotected Steel 

Background Technical Support Document – Petroleum and Natural Gas Industry 121 

6.02 
 

Protected Steel 2.38 

Plastic 11.63 

Cast Iron NA 

Leaker Emission Factors - Distribution Services, Gas Service1 

Unprotected Steel 2.33 

Protected Steel 1.08 

Plastic 0.35 

Copper 1

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

0.88 

Summary 

This Appendix provides leaker emissions factors that can be applied to any individual 

emissions source which meets the leak detection definition in a leak detection survey. These 

emissions factors provide an estimate of real emissions as opposed to potential emissions 

since they are applied only to leaking emissions sources. However, it must be noted that 

these leaker emissions factors assume that any emissions source found leaking has been 

leaking for the duration of an entire year. 

Background Technical Support Document – Petroleum and Natural Gas Industry 122 
 

 

Appendix G: Development of population emission factors 

Natural Gas Emission Factors for Onshore Production 

Whole Gas Population Emission Factors – All Components, Gas Service 

Methodology 

The well counts and emission factors were taken from GRI’s Methane Emissions from the 

Natural Gas Industry42 . The emission factors for each source are calculated using gas 

production for the Eastern and Western United States. The average methane content of 

produced natural gas is assumed to be 78.8%. 

Eastern/Western U.S. Component EF, scf/hour/component = (EF Eastern/Western U.S., 

mscf/yr) * (A) * (B) / (C) / (D) 

Component Eastern U.S. EPA/GRI EF (mscf 

CH4/year) 

Eastern U.S. Subpart W EF (scf 

natural gas/hour) 

Valve 0.184 0.027 

Connector 0.024 0.004 

Open-Ended Line 0.420 0.062 

Pressure Relief Valve 0.279 0.041 

Component Western U.S. EPA/GRI EF (mscf 

CH4/year) 

Western U.S. Subpart W EF (scf 

natural gas/hour) 

Valve 0.835 0.123 

Connector 0.114 0.017 

Open-Ended Line 0.215 0.032 

Pressure Relief Valve 1.332 0.196 

Conversions: 

A: 1,000 scf/mscf 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

C: 8,760 hours/year 

D: 78.8% methane by volume in produced natural gas 

“High Continuous Bleed Pneumatic Device Vents” Methodology 

Methane emissions per pneumatic device are from API’s Compendium of Greenhouse Gas 

Emissions Methodologies for the Oil and Gas Industry 43. The average methane content of 

natural gas is assumed to be 78.8%. 

48.1 scf/hour/component EF = (896 [scfd CH4/pneumatic devises, high bleed]) * (B) / (D) / 

(E) 

42 GRI. Methane Emissions from the Natural Gas Industry. Volume 8. June 1996. 

<www.epa.gov/gasstar/documents/emissions_report/8_equipmentleaks.pdf> 43 API. Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry. American 

Petroleum Institute. Table 5-15, page 5-68. August 2009. 

Background Technical Support Document – Petroleum and Natural Gas Industry 123 
 

 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

D: 78.8% – production quality of natural gas (% methane) 44 

E: 24 hours/day 

“Low Continuous Bleed Pneumatic Device Vents” Methodology 

Methane emissions per pneumatic device are from API’s Compendium of Greenhouse Gas 

Emissions Methodologies for the Oil and Gas Industry43. The average methane content of 

natural gas is assumed to be 78.8%. 

1.80 scf/hour/component EF = (33.4 [scfd CH4/pneumatic devises, low bleed]) * (B) / (D) / 

(E) 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

D: 78.8% – production quality of natural gas (% methane) 

E: 24 hours/day 

“Intermittent Bleed Pneumatic Device Vents” Methodology 

Methane emissions per pneumatic device are from API’s Compendium of Greenhouse Gas 

Emissions Methodologies for the Oil and Gas Industry43. The average methane content of 

natural gas is assumed to be 78.8%. 

17.4 scf/hour/component EF = (323 [scfd CH4/pneumatic devises, low bleed]) * (B) / (D) / 

(E) 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

D: 78.8% – production quality of natural gas (% methane)44 

E: 24 hours/day 

“Pneumatic Pumps” Methodology 

Methane emissions per pneumatic pump are from GRI’s Methane Emissions from the 

Natural Gas Industry45. The average methane content of natural gas is assumed to be 78.8%. 

13.3 scf CH4/hour/component EF = (248 [scfd CH4/pneumatic devises, low bleed]) * (B) / 

(D) / (E) 

44 GRI. “Vented and Combustion Source Summary,” Methane Emissions from the Natural Gas Industry, U.S.
 

EPA, Volume 6, Appendix A, page A-2.

45 GRI. Methane Emissions from the Natural Gas Industry. Volume 13. Tables 4-4. June 1996.
 

<http://epa.gov/gasstar/documents/emissions_report/13_chemical.pdf>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 124 
 

 

 

 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

D: 78.8% – production quality of natural gas (% methane)46 

E: 24 hours/day 

Population Emission Factors – All Components, Light Crude Service 

Methodology 

Average emissions factors by facility type were taken from API’s Emission Factors for Oil 

and Gas Production Operations.47 Hydrocarbon liquids greater than or equal to 20°API are 

considered “light crude.” 

Component EF, scf/hour/component = (Average Emissions Factors by Facility Type, 

lb/component-day) * (B) / (E) / (F) 

Component Name Component EF, 

scf/hr/comp 

Average EF by Facility Type, 

lb/component-day 

Valve 0.04 7.00E-02 

Flange 0.002 4.07E-03 

Connector 0.005 8.66E-03 

Open-Ended Line 0.04 6.38E-02 

Pump 0.01 1.68E-02 

Other 0.23 3.97E-01 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

D: 24 hours/day 

F: 0.072 gas density lb/scf – assumes a gas composition of 61.2% methane, 20% ethane, 

10% propane, 5% butane, and 3.8% pentanes+ 

Population Emission Factors – All Components, Heavy Crude Service 

Methodology 

Average emissions factors by facility type were taken from API’s Emission Factors for Oil 

and Gas Production Operations48. Hydrocarbon liquids less than 20°API are considered 

“heavy crude.” The methane content of associated natural gas with onshore light crude is 

94.2% from the same study. 

46 GRI. “Vented and Combustion Source Summary,” Methane Emissions from the Natural Gas Industry, U.S.
 

EPA, Volume 6, Appendix A, page A-2.

47 API. Emission Factors for Oil and Gas Production Operations. Table 9, page 10. API Publication Number 

4615. January 1995. 

48 API. Emission Factors for Oil and Gas Production Operations. API Publication Number 4615. page ES-3,
 

Table ES-4, January 1995. 

Background Technical Support Document – Petroleum and Natural Gas Industry 125 
 

Component EF, scf/hour/component = (Average Emissions Factors by Facility Type, 

lb/component-day) * (B) / (D) / (F) 

Component Name Component EF, 

scf/hr/comp 

Average EF by Facility Type, 

lb/component-day 

Valve 0.0004 6.86E-04 

Flange 0.0002 1.16E-03 

Connector (Other) 0.0004 4.22E-04 

Open-Ended Line 0.004 8.18E-03 

Other 0.002 3.70E-03 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

D: 24 hours/day 

F: 0.072 gas density lb/scf – assumes a gas composition of 61.2% methane, 20% ethane, 

10% propane, 5% butane, and 3.8% pentanes+ 

Methane Emission Factors For Processing 

Population Emission Factors – All Components, Gas Service 

There are no population emission factors in subpart W for the onshore natural gas processing 

segment. 

Methane Emission Factors for Transmission 

Population Emission Factors – All Components, Gas Service 

Gas transmission facility emission factors were taken from the Handbook for Estimating 

Methane Emissions from Canadian Natural Gas Systems49. “Connector” includes flanges, 

threaded connections, and mechanical couplings. “Block Valve” accounts for emissions 

from the stem packing and the valve body, and it applies to all types of block valves (e.g., 

butterfly, ball, globe, gate, needle, orbit, and plug valves). Leakage past the valve seat is 

accounted for the Open-Ended Line emission category. Leakage from the end connections 

is accounted for by the connector category (i.e., one connector for each end). “Control 

Valve” accounts for leakage from the stem packing and the valve body. Emissions from the 

controller and actuator are accounted for by the Instrument Controller and Open-Ended Line 

categories respectively. This factor applies to all valves with automatic actuators (including 

fuel gas injection valves on the drivers of reciprocating compressors). “Orifice Meter” 

accounts for emissions from the orifice changer. Emissions from sources on pressure tap 

lines etc. are not included in the factor (i.e., these emissions must be calculated separately). 

49 CEPEI. Handbook for Estimating Methane Emissions from Canadian Natural Gas Systems. May 25, 1998. 

Background Technical Support Document – Petroleum and Natural Gas Industry 126 
“Other Meter” accounts for emissions from other types of gas flow meters (e.g., diaphragm, 

ultrasonic, roots, turbine, and vortex meters). 

Component EF, scf/hour/component = (Gas Transmission Facility Emissions, kg/h/src) * (B) 

* (I) / (F) 

Component Name Component EF, 

scf/hour/comp 

Gas Transmission Facility 

Avg. Emissions, kg/hr/src 

Connector 0.01 2.732E-04 

Block Valve 0.11 2.140E-03 

Control Valve 1.04 1.969E-02 

Pressure Relief Valve 14.74 2.795E-01 

Orifice Meter 0.18 3.333E-03 

Other Meter 0.0005 9.060E-06 

Regulator 0.17 3.304E-03 

Open-Ended Line 4.40 8.355E-02 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

F: 0.04246 CH4 density lb/scf 

I: 2.20462262 lb/kg 

Population Emission Factors – Other Components, Gas Service 

“Low Continuous Bleed Pneumatic Device Vents” Methodology 

Methane emissions per pneumatic device are from API’s Compendium of Greenhouse Gas 

Emissions Methodologies for the Oil and Gas Industry43. The average methane content of 

natural gas is assumed to be 78.8%. 

1.41 scf/hour/component EF = (33.4 [scfd CH4/pneumatic devises, low bleed]) * (B) * (J) / 

(D) / (E) 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

D: 78.8% – production quality of natural gas (% methane) from: “Vented and 

Combustion Source Summary,” Methane Emissions from the Natural Gas Industry, 

U.S. EPA, Volume 6, Appendix A, page A-2. 

E: 24 hours/day 

J: 93.4% – pipeline quality natural gas (% methane) from: “Vented and 

Combustion Source Summary,” Methane Emissions from the Natural Gas Industry, 

U.S. EPA, Volume 6, Appendix A, page A-2. 

“High Continuous Bleed Pneumatic Device Vents” Methodology 

Background Technical Support Document – Petroleum and Natural Gas Industry 127 
 

 

Methane emissions per pneumatic device are from GRI’s Methane Emissions from the 

Natural Gas Industry50. The average methane content of natural gas is assumed to be 78.8%. 

18.8 scf/hour/component EF = (162,197 [scfy CH4/pneumatic devises, low bleed]) * (B) / 

(C) 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

C: 8,760 hours/year 

“Intermittent Bleed Pneumatic Device Vents” Methodology 

Methane emissions per pneumatic device are from GRI’s Methane Emissions from the 

Natural Gas Industry50. The average methane content of natural gas is assumed to be 78.8%. 

18.8 scf/hour/component EF = (162,197 [scfy CH4/pneumatic devises, low bleed]) * (B) / 

(C) 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

C: 8,760 hours/year 

Methane Emission Factors for Underground Storage 

Population Emission Factors – Storage Station, Gas Service 

Methodology 

See methodology for “Population Emission Factors – All Components, Gas Service” for 

Transmission. 

Population Emission Factors – Storage Wellheads, Gas Service 

Methodology 

Emission factors for injection/withdrawal wellheads are from GRI’s Methane Emissions from 

the Natural Gas Industry42 . 

Component EF, scf/hour/component = (Injection/Withdrawal Wellhead) (A) * (B) / (C) 

Component Name Component EF, 

scf/hr/comp 

Injections/Withdrawal 

Wellhead, Mcf/yr 

Connector 0.01 0.125 

50 GRI. Methane Emissions from the Natural Gas Industry. Volume 12. Page 52. June 1996. 

<http://epa.gov/gasstar/documents/emissions_report/12_pneumatic.pdf>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 128 
 

Valve 0.10 0.918 

Pressure Relief Valve 0.17 1.464 

Open-Ended Line 0.03 0.237 

Conversions: 

A: 1,000 scf/mscf 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

C: 8,760 hours/year 

Population Emission Factors – Other Components, Gas Service 

Methodology 

“Low Continuous Bleed Pneumatic Device Vents” Methodology 

See “Low Continuous Bleed Pneumatic Device Vents” Methodology for Population 

Emission Factors – Other Components, Gas Service for Transmission. 

“High Continuous Bleed Pneumatic Device Vents” Methodology 

See “High Continuous Bleed Pneumatic Device Vents” Methodology for Population 

Emission Factors – Other Components, Gas Service for Transmission. 

“Intermittent Bleed Pneumatic Device Vents” Methodology 

See “Intermittent Bleed Pneumatic Device Vents” Methodology for Population Emission 

Factors – Other Components, Gas Service for Transmission. 

Methane Emission Factors for LNG Storage 

Population Emission Factors – LNG Storage Components, LNG Service 

Methodology 

Component emission factors are from EPA’s Inventory of U.S. Greenhouse Gas Emissions 

and Sinks51 . The emission factors were adjusted by an assumed average methane content of 

93.4% by volume. 

Component EF, scf/hour/component = (Component EF, Mscf/comp-yr) (B) * (I) / (F) 

Component Name Component EF, 

scf/hour/comp 

Component EF, 

Mscf/comp-yr 

Valve 0.10 0.867 

Open-ended Line 1.30 11.2 

Connector 0.02 0.147 

PRV 0.72 6.2 

Conversions: 

51 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2006. Available online at 

<http://www.epa.gov/climatechange/emissions/usinventoryreport.html>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 129 
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

F: 0.04246 CH4 density lb/scf 

I: 2.20462262 lb/kg 

Population Emission Factors – LNG Storage Compressor, Gas Service 

“Vapor Recovery Compressor” Methodology 

The methane emissions per compressor are from the Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-200751. 

4.23 scf/hour/component EF = (100 scfd CH4/compressor) * (B) / (D) 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

D: 24 hours/day 

Methane Emission Factors for LNG Terminals 

Population Emission Factors – LNG Terminals Components, LNG Service 

Methodology 

See methodology for Population Emission Factors – LNG Storage Components, LNG 

Service for LNG Storage. 

Population Emission Factors – LNG Terminals Compressor, Gas Service 

Methodology 

See “Vapor Recovery Compressor” Methodology for Population Emission Factors – LNG 

Storage Compressor, Gas Service for LNG Storage. 

Methane Emission Factors for Distribution 

Population Emission Factors – Above Grade M&R Stations Components, Gas Service 

Methodology 

Gas distribution meter/regulator station average emissions from: Gas transmission facility 

emissions are from the Handbook for Estimating Methane Emissions from Canadian Natural 

Gas Systems49. “Connector” includes flanges, threaded connections, and mechanical 

couplings. “Block Valve” accounts for emissions from the stem packing and the valve body, 

and it applies to all types of block valves (e.g., butterfly, ball, globe, gate, needle, orbit, and 

plug valves). Leakage past the valve seat is accounted for the Open-Ended Line emission 

category. Leakage from the end connections is accounted for by the connector category 

Background Technical Support Document – Petroleum and Natural Gas Industry 130 
 

 

(i.e., one connector for each end). “Control Valve” accounts for leakage from the stem 

packing and the valve body. Emissions from the controller and actuator are accounted for by 

the Instrument Controller and Open-Ended Line categories respectively. This factor applies 

to all valves with automatic actuators (including fuel gas injection valves on the drivers of 

reciprocating compressors). “Orifice Meter” accounts for emissions from the orifice 

changer. Emissions from sources on pressure tap lines etc. are not included in the factor (i.e., 

these emissions must be calculated separately). “Other Meter” accounts for emissions from 

other types of gas flow meters (e.g., diaphragm, ultrasonic, roots, turbine, and vortex meters). 

Component EF, scf/hour/component = (Gas Distribution Meter/Regulator Station Emissions, 

kg/h/src) * (B) * (I) / (F) 

Component Name Component EF, 

scf/hour/comp 

Gas Distribution Meter/Regulator 

Station Avg. Emissions, kg/h/src 

Connector 5.79E-03 1.098E-04 

Block Valve 5.85E-02 1.109E-03 

Control Valve 1.04E+00 1.969E-02 

Pressure Relief Valve 8.78E-01 1.665E-02 

Orifice Meter 1.76E-01 3.333E-03 

Other Meter 4.78E-04 9.060E-06 

Regulator 1.01E-01 1.915E-03 

Open-Ended Line 4.39E+00 8.355E-02 

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

F: 0.04246 CH4 density lb/scf 

I: 2.20462262 lb/kg 

Population Emission Factors – Below Grade M&R Stations Components, Gas Service 

Methodology 

Average emission factors are from GRI’s Metering and Pressure Regulating Stations in 

Natural Gas Transmission and Distribution52 . (Converted to 68 ̊F) 

Below Grade M&R Station, Inlet Pressure > 300 psig: 1.32 scf/hour/station EF 

Below Grade M&R Station, Inlet Pressure 100 to 300 psig: 0.20 scf/hour/station EF 

Below Grade M&R Station, Inlet Pressure < 100 psig: 0.10 scf/hour/station EF 

Population Emission Factors – Distribution Mains and Services, Gas Service 

Methodology 

52 GRI. Methane Emissions from the Natural Gas Industry. Volume 10. Table 7-1. June 1996. 

<www.epa.gov/gasstar/documents/emissions_report/10_metering.pdf>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 131 
 

 

Emission factors for pipeline leaks (mains and service) are from the Inventory of U.S. 

Greenhouse Gas Emissions and Sinks: 1990-200753 

Component EF, scf/hour/service = (Pipeline Leak mscf/mile/year) (A) * (B) / (C) 

Component Name 

Component EF 

(Mains), 

scf/hr/service 

Pipeline Leak EF 

(Mains), 

Mscf/mile-yr 

Component EF 

(Services), 

scf/hr/service 

Pipeline Leak EF 

(Services), 

Mscf/mile-yr 

Unprotected Steel 12.77 110.19 0.19 1.70 

Protected Steel 0.36 3.07 0.02 0.18 

Plastic 1.15 9.91 0.001 0.01 

Cast Iron 27.67 238.7 

Copper 0.03 0.25 

Conversions: 

A: 1,000 scf/mscf 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60 ̊F to 68 ̊F per subpart A 

definition of standard conditions 

C: 8,760 hours/year 

Nitrous Oxide Emission Factors for Gas Flaring 

Population Emission Factors – Gas Flaring 

Methodology 

Emission factors are from API’s Compendium of Greenhouse Gas Emissions Methodologies 

for the Oil and Gas Industry. 

Gas Production: 5.90E-07 metric tons/MMcf gas production or receipts EF 

Sweet Gas Processing: 7.10E-07 metric tons/MMcf gas production or receipts EF 

Sour Gas Processing: 1.50E-06 metric tons/MMcf gas production or receipts EF 

Conventional Oil Production: 1.00E-04 metric tons/barrel conventional oil production EF 

Heavy Oil Production: 7.30E-05 metric tons/barrel heavy oil production EF 

Summary 

This Appendix provides population emissions factors for potential emissions sources. These 

population emissions factors could be used in conjunction with population counts that make 

it more cost effective in estimating emissions. However, these population emissions factors 

estimate potential emissions as the percentage of emissions sources leaking may or may not 

53 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2007. Available online at 

<http://www.epa.gov/climatechange/emissions/usinventoryreport.html>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 132 
be the same as the assumption made when developing the emissions factors. Also, the 

population emissions factors assume that a subset of leaking emission sources is leaking 

continuously throughout the year. 

Background Technical Support Document – Petroleum and Natural Gas Industry 133 
Appendix H: Glossary 

The following definitions are based on common industry terminology for the respective 

equipment, technologies, and practices. 

Absorbent circulation pump means a pump commonly powered by natural gas 

pressure that circulates the absorbent liquid between the absorbent regenerator and natural 

gas contactor. 

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. 

Air injected flare means a flare in which air is blown into the base of a flare stack to 

induce complete combustion of gas. 

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). 

Blowdown vent stack emissions mean natural gas and/or CO2 released due to 

maintenance and/or blowdown operations including compressor blowdown and emergency 

shut-down (ESD) system testing. 

Calibrated bag means a flexible, non-elastic, anti-static bag of a calibrated volume 

that can be affixed to an emitting source such that the emissions inflate the bag to its 

calibrated volume. 

Centrifugal compressor means any equipment that increases the pressure of a process 

natural gas or CO2 by centrifugal action, employing rotating movement of the driven shaft. 

Centrifugal compressor dry seals mean a series of rings around the compressor shaft 

where it exits the compressor case that operates mechanically under the opposing forces to 

prevent natural gas or CO2 from escaping to the atmosphere. 

Background Technical Support Document – Petroleum and Natural Gas Industry 134 
Centrifugal compressor dry seal emissions mean natural gas or CO2 released from a 

dry seal vent pipe and/or the seal face around the rotating shaft where it exits one or both 

ends of the compressor case. 

Centrifugal compressor wet seal degassing vent emissions means emissions that occur 

when the high-pressure oil barriers for centrifugal compressors are depressurized to release 

absorbed natural gas or CO2. High-pressure oil is used as a barrier against escaping gas in 

centrifugal compressor shafts. Very little gas escapes through the oil barrier, but under high 

pressure, considerably more gas is absorbed by the oil. The seal oil is purged of the absorbed 

gas (using heaters, flash tanks, and degassing techniques) and recirculated. The separated 

gas is commonly vented to the atmosphere. 

Component means each metal to metal joint or seal of non-welded connection 

separated by a compression gasket, screwed thread (with or without thread sealing 

compound), metal to metal compression, or fluid barrier through which natural gas or liquid 

can escape to the atmosphere. 

Continuous bleed means a continuous flow of pneumatic supply gas to the process 

measurement device (e.g. level control, temperature control, pressure control) where the 

supply gas pressure is modulated by the process condition, and then flows to the valve 

controller where the signal is compared with the process set-point to adjust gas pressure in 

the valve actuator. 

Compressor means any machine for raising the pressure of a natural gas or CO2 by 

drawing in low pressure natural gas or CO2 and discharging significantly higher pressure 

natural gas or CO2. 

Condensate means hydrocarbon and other liquid, including both water and 

hydrocarbon liquids, separated from natural gas that condenses due to changes in the 

temperature, pressure, or both, and remains liquid at storage conditions. 

Dehydrator means a device in which a liquid absorbent (including desiccant, ethylene 

glycol, diethylene glycol, or triethylene glycol) directly contacts a natural gas stream to 

absorb water vapor. 

Dehydrator vent emissions means natural gas and CO2 released from a natural gas 

dehydrator system absorbent (typically glycol) reboiler or regenerator to the atmosphere or a 

flare, including stripping natural gas and motive natural gas used in absorbent circulation 

pumps. 

De-methanizer means the natural gas processing unit that separates methane rich 

residue gas from the heavier hydrocarbons (e.g., ethane, propane, butane, pentane-plus) in 

feed natural gas stream. 

Desiccant means a material used in solid-bed dehydrators to remove water from raw 

natural gas by adsorption or absorption. Desiccants include activated alumina, pelletized 

Background Technical Support Document – Petroleum and Natural Gas Industry 135 
calcium chloride, lithium chloride and granular silica gel material. Wet natural gas is passed 

through a bed of the granular or pelletized solid adsorbent or absorbent in these dehydrators. 

As the wet gas contacts the surface of the particles of desiccant material, water is adsorbed 

on the surface or absorbed and dissolves the surface of these desiccant particles. Passing 

through the entire desiccant bed, almost all of the water is adsorbed onto or absorbed into the 

desiccant material, leaving the dry gas to exit the contactor. 

Engineering estimation 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. 

Equipment leak means those emissions which could not reasonably pass through a 

stack, chimney, vent, or other functionally-equivalent opening. 

Equipment leak detection means the process of identifying emissions from 

equipment, components, and other point sources. 

External combustion means fired combustion in which the flame and products of 

combustion are separated from contact with the process fluid to which the energy is 

delivered. Process fluids may be air, hot water, or hydrocarbons. External combustion 

equipment may include fired heaters, industrial boilers, and commercial and domestic 

combustion units. 

Natural gas distribution facility means the collection of all distribution pipelines, 

metering stations, and regulating stations that are operated by a Local Distribution Company 

(LDC) that is regulated as a separate operating company by a public utility commission or 

that are operated as an independent municipally-owned distribution system. 

Onshore petroleum and natural gas production facility means all petroleum or natural 

gas equipment on a well pad or associated with a 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. The gas may or may not be metered, but always does 

not pass through a city gate station. In some cases a nearby LDC may handle the billing of 

the gas to the customer(s). 

Background Technical Support Document – Petroleum and Natural Gas Industry 136 
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 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. 

Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or 

mole basis, that is combusted at the flare burner tip. 

Gas conditions mean the actual temperature, volume, and pressure of a gas sample. 

Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature 

and pressure that is produced from a volume of oil when depressurized to standard 

temperature and pressure. 

Gas well means a well completed for production of natural gas from one or more gas 

zones or reservoirs. Such wells contain no completions for the production of crude oil. 

High-bleed pneumatic devices are automated, continuous bleed flow control devices 

powered by pressurized natural gas and used for maintaining a process condition such as 

liquid level, pressure, delta-pressure and temperature. Part of the gas power stream that is 

regulated by the process condition flows to a valve actuator controller where it vents 

continuously (bleeds) to the atmosphere at a rate in excess of 6 standard cubic feet per hour. 

Intermittent bleed pneumatic devices mean automated flow control devices powered 

by pressurized natural gas and used for maintaining a process condition such as liquid level, 

pressure, delta-pressure and temperature. These are snap-acting or throttling devices that 

discharge the full volume of the actuator intermittently when control action is necessary, but 

does not bleed continuously. 

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. 

Background Technical Support Document – Petroleum and Natural Gas Industry 137 
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. 

Low-bleed pneumatic devices mean automated flow control devices powered by 

pressurized natural gas and used for maintaining a process condition such as liquid level, 

pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by 

the process condition flows to a valve actuator controller where it vents continuously (bleeds) 

to the atmosphere at a rate equal to or less than six standard cubic feet per hour. 

Natural gas driven pneumatic pump means a pump that uses pressurized natural gas 

to move a piston or diaphragm, which pumps liquids on the opposite side of the piston or 

diaphragm. 

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. 

Oil well means a well completed for the production of crude oil from at least one oil 

zone or reservoir. 

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. 

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. 

Reciprocating compressor means a piece of equipment that increases the pressure of a 

process natural gas or CO2 by positive displacement, employing linear movement of a shaft 

driving a piston in a cylinder. 

Background Technical Support Document – Petroleum and Natural Gas Industry 138 
Reciprocating compressor rod packing means a series of flexible rings in machined 

metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the 

amount of compressed natural gas or CO2 that escapes to the atmosphere. 

Re-condenser means heat exchangers that cool compressed boil-off gas to a 

temperature that will condense natural gas to a liquid. 

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. 

Sales oil means produced crude oil or condensate measured at the production lease 

automatic custody transfer (LACT) meter or custody transfer tank gauge. 

Separator means a vessel in which streams of multiple phases are gravity separated 

into individual streams of single phase. 

Sour natural gas means natural gas that contains significant concentrations of 

hydrogen sulfide (H2S) and/or carbon dioxide (CO2) that exceed the concentrations specified 

for commercially saleable natural gas delivered from transmission and distribution pipelines. 

Sweet Gas is natural gas with low concentrations of hydrogen sulfide (H2S) and/or 

carbon dioxide (CO2) that does not require (or has already had) acid gas treatment to meet 

pipeline corrosion-prevention specifications for transmission and distribution. 

Transmission pipeline means high pressure cross country pipeline transporting 

saleable quality natural gas from production or natural gas processing to natural gas 

distribution pressure let-down, metering, regulating stations where the natural gas is typically 

odorized before delivery to customers. 

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. 

United States means the 50 States, the District of Columbia, the Commonwealth of 

Puerto Rico, American Samoa, the Virgin Islands, Guam, and any other Commonwealth, 

territory or possession of the United States, as well as the territorial sea as defined by 

Presidential Proclamation No. 5928. 

Background Technical Support Document – Petroleum and Natural Gas Industry 139 
Vapor recovery system means any equipment located at the source of potential gas 

emissions to the atmosphere or to a flare, that is composed of piping, connections, and, if 

necessary, flow-inducing devices, and that is used for routing the gas back into the process as 

a product and/or fuel. 

Vaporization unit means a process unit that performs controlled heat input to vaporize 

LNG to supply transmission and distribution pipelines or consumers with natural gas. 

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). 

Well completions means the process that allows for the flow of petroleum or natural 

gas from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow 

characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. 

Well completion also involves connecting the well bore to the reservoir, which may include 

treating the formation or installing tubing, packer(s), or lifting equipment, steps that do not 

significantly vent natural gas to the atmosphere. This process may also include high-rate 

flowback of injected gas, water, oil, and proppant used to fracture or re-fracture and prop 

open new fractures in existing lower permeability gas reservoirs, steps that may vent large 

quantities of produced gas to the atmosphere. 

Well workover means the process(es) of performing one or more of a variety of 

remedial operations on producing petroleum and natural gas wells to try to increase 

production. This process also includes high-rate flowback of injected gas, water, oil, and 

proppant used to re-fracture and prop-open new fractures in existing low permeability gas 

reservoirs, steps that may vent large quantities of produced gas to the atmosphere. 

Wellhead means the piping, casing, tubing and connected valves protruding above the 

earth’s surface for an oil and/or natural gas well. The wellhead ends where the flow line 

connects to a wellhead valve. Wellhead equipment includes all equipment, permanent and 

portable, located on the improved land area (i.e. well pad) surrounding one or multiple 

wellheads. 

Wet natural gas means natural gas in which water vapor exceeds the concentration 

specified for commercially saleable natural gas delivered from transmission and distribution 

pipelines. This input stream to a natural gas dehydrator is referred to as “wet gas.” 

Background Technical Support Document – Petroleum and Natural Gas Industry 140 
Appendix I: References 

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Guidelines for the Natural Gas Distribution Sector. 

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Technology. 

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Bacharach, Inc. (2005) HiFlow® Sampler Natural Gas Leak Rate Measurement: Instruction 

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DOE/ NETL (2008). Storing CO2 with Enhanced Oil Recovery. DOE/NETL-402/1312/02­

EIA (2006) Underground Storage Field Level Data From EIA-191A. 

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Background Technical Support Document – Petroleum and Natural Gas Industry 141 

07-08 
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GTI (1999), Gas Resource Database: Unconventional Natural Gas and Gas Composition 

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GTI(2007) The World Energy Source Book – Fourth Edition, An Encyclopedia of the World 

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INGAA (2008) Greenhouse Gas Emissions Estimation Guidelines for Natural Gas 

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Background Technical Support Document – Petroleum and Natural Gas Industry 142 
IPIECA (2003) Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions. 

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Lasser Production Data, Version 3.0.8 

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OGJ (2006) EOR/ Heavy Oil Survey. 

OGJ (2007) Worldwide Gas Processing Survey. <http://www.ogj.com> 

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Customized Tables 

U.S. EPA (2002) Analytical Support Branch, Environmental Analysis Division, Office of 

Environmental Information Wage Rates for Economic Analyses of the Toxics Release 

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Background Technical Support Document – Petroleum and Natural Gas Industry 143 
U.S. EPA (2007) Natural Gas STAR Emissions Reduction Quantification Reference Guide. 

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Background Technical Support Document – Petroleum and Natural Gas Industry 144