GREENHOUSE GAS EMISSIONS REPORTING FROM THE 

PETROLEUM AND NATURAL GAS INDUSTRY 

BACKGROUND TECHNICAL SUPPORT DOCUMENT 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

CLIMATE CHANGE DIVISION 

WASHINGTON DC 
TABLE OF CONTENTS 

1. Segments in the Petroleum and Natural Gas Industry ......................................................... 3 

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 Mandatory GHG Reporting Rule................................................................. 9 

a. Review of Existing Regulations...................................................................................... 10 

b. Review of Existing Programs ......................................................................................... 12 

c. Selection of Emissions Sources for Reporting................................................................ 17 

i. Facility Definition Characterization ............................................................................ 17 

ii. Selection of Potential Emissions Sources for Reporting ............................................ 18 

iii. Address Sources with Large Uncertainties................................................................ 23 

iv. Identify Sources to be Included ................................................................................. 23 

5. Options for Reporting Threshold....................................................................................... 30 

a. Threshold Analysis.......................................................................................................... 30 

6. Monitoring Method Options.............................................................................................. 34 

a. Review of Existing Relevant Reporting Programs/ Methodologies............................... 34 

b. Potential Monitoring Methods........................................................................................ 34 

i. Fugitive Emissions Detection ...................................................................................... 34 

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

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

B. Engineering Estimation.......................................................................................... 39 

C. Emission Factors.................................................................................................... 45 

D. Combination of Direct Measurement and Engineering Estimation....................... 46 

c. Leak detection and leaker emission factors .................................................................... 57 

d. Population Count and Emission Factors......................................................................... 58 

e. Method 21 ...................................................................................................................... 58 

f. Portable VOC Detection Instruments for Leak Measurement........................................ 59 

g. Mass Balance for Quantification ................................................................................... 60 

h. Gulf Offshore Activity Data System program (GOADS).............................................. 60 

i. Additional Questions Regarding Potential Monitoring Methods.................................... 61 

i. Source Level Fugitive Emissions Detection Threshold........................................... 61 

ii. Duration of Fugitive Emissions.............................................................................. 63 

iii. Fugitive and Vented Emissions at Different Operational Modes.......................... 63 

iv. Natural Gas Composition....................................................................................... 64 

v. Physical Access for Leak Measurement ................................................................. 65 

7. Procedures for Estimating Missing Data ............................................................................ 65 

a. Emissions Measurement Data......................................................................................... 65 

b. Engineering Estimation Data .......................................................................................... 66 

c. Emissions Estimation Data for Storage Tanks and Flares.............................................. 66 

d. Emissions Estimation Data Using Emissions Factors .................................................... 66 

8. QA/QC Requirements........................................................................................................ 67 

Background Technical Support Document – Petroleum and Natural Gas Industry 2
a. Equipment Maintenance.................................................................................................. 67 

b. Data Management ........................................................................................................... 67 

c. Calculation checks .......................................................................................................... 68 

9. Reporting Procedure ........................................................................................................... 69 

10. Verification of Reported Emissions.................................................................................. 70 

Appendix A: Segregation of Emissions Sources using the Decision Process ........................ 71 

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

sources............................................................................................................................... 79 

Appendix C: Development of threshold analysis................................................................... 86 

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

production ......................................................................................................................... 99 

Appendix E: Analysis of potential facility definitions for local distribution companies ..... 103 

Appendix F: Analysis of Definition Options for Natural Gas Production Gathering Pipelines 

for Emissions Reporting ................................................................................................. 106 

Appendix G: Accounting for Inaccessible Emissions Sources............................................. 109 

Appendix H: Review and assessment of potential alternatives to monitoring methods for 

emissions sources............................................................................................................ 124 

Appendix I: Flares................................................................................................................. 130 

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

connected to storage tanks.............................................................................................. 132 

Appendix K: Development of Leaker Emission Factors...................................................... 135 

Appendix L: Development of Population emission factors.................................................. 144 

Appendix M: Potential Solutions to Measure Greenhouse Gas Emissions in Various Modes 

of Equipment Operation.................................................................................................. 159 

Appendix N: Identifying gas compositions for emissions estimates.................................... 166 

Appendix O: Development of performance criteria and monitoring protocol for fugitive 

measurement techniques................................................................................................. 167 

Appendix P: Discussion on Methodologies in Emission References................................... 181 

Appendix Q: Glossary........................................................................................................... 185 

Appendix R: References....................................................................................................... 191 

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, and everything in between, 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 terminals, and 

• Natural Gas Industry –natural gas production, natural gas processing (including 

gathering and boosting), 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, all of which 

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

Background Technical Support Document – Petroleum and Natural Gas Industry 3
a. Petroleum Industry 

Petroleum Production. Petroleum or crude oil is produced from underground 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 fugitive 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 improve 

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 carbon dioxide 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 sources is a major 

source of emissions. 

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 practices and storage tanks 

release GHG emissions, as well as emissions from combustion. 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 Final Mandatory Reporting Rule (MRR) 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. 

Background Technical Support Document – Petroleum and Natural Gas Industry 4
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, 

fugitive, 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 (including Gathering/Boosting stations) In this segment of the 

supply chain, natural gas from the petroleum and natural gas production segment is 

compressed and injected into gathering lines that transport it to natural gas processing 

facilities. 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. All equipment and practices have associated GHG fugitive 

emissions, 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 

large reciprocating and turbine 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 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 LNG also requires transportation and storage. These processes are similar to above 

ground LNG storage and require compression and cooling processes. GHG emissions in this 

segment are related to the number of LNG import terminals and LNG storage facilities. 

Background Technical Support Document – Petroleum and Natural Gas Industry 5
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. Between the distribution mains and many off-shooting services are underground 

regulating vaults. 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), CO2, and nitrous oxide (N2O). This technical document will focus mainly on CH4 and 

CO2 emissions from fugitive and vented emissions. However, all three gases are 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 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 rarely 100 percent efficient, CH4 and N2O may also be 

emitted. For methodologies to quantify GHG emissions from combustion, please 

refer to Subpart C of the MRR. 

Fugitive emissions 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 

 

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 6
tear or damage to the equipment. For example, valves result in natural gas 

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. 

 However, defining fugitive emissions as unintentional and intentional led to a great 

deal of confusion in the initial rule proposal. Also, such a definition is not intuitive 

in that fugitive in itself means unintentional. Therefore, this document henceforth 

distinguishes fugitive emissions clearly from vented emissions. 

Fugitive emissions are emissions which are unintentional and could not reasonably 

pass through a stack, chimney, vent, or other functionally-equivalent opening. 

Vented emissions means intentional or designed releases of CH4 or CO2 containing 

natural gas or hydrocarbon gas (not including stationary combustion flue gas), 

including but not limited to 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). 

This document includes methodologies to quantify fugitive and vented emissions of 

CO2 and CH4. 

3. GHG Emissions from the Petroleum and Natural Gas Industry 

The U.S. GHG Inventory provides estimates of fugitive 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 

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. 

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; 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 7
The understatement of emissions in the U.S. GHG Inventory were revised using publicly 

available information for all sources, except crude oil and condensate storage tanks and 

flares, where no new reliable data are available4

. 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 

(CH4 – metric tons/year) 

Revised 

Emissions Factor 

(CH4 – metric tons/year) 

1) Well venting for liquids unloading 1.02 11 

2) Gas well venting during completions 

Conventional well completions 0.02 0.71 

Unconventional well completions 0.02 177 

3) Gas well venting during well workovers 

Conventional well workovers 0.05 0.05 

Unconventional well workovers 0.05 177 

4) Centrifugal compressor wet seal degassing venting 0 233 

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 8
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 90.2 186.4 

Processing 33.1 31.7 

Transmission and Storage 38.3 64.0 

Distribution 24.7 25.3 

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

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

After revising the U.S. GHG Inventory for the four updated sources, fugitive CH4 and CO2

emissions from the petroleum and natural gas industry were 307.4 million metric tons of CO2

equivalent (MMTCO2e) in 2006. Overall, the natural gas industry emitted 257.2 of CH4 and 

23.6 MMTCO2e of CO2 in 2006. Total CH4 and CO2 emissions from the petroleum industry 

in 2006 were 26.3 MMTCO2e and 0.3 MMTCO2e respectively. 

Petroleum Segment 

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 United States currently estimates CO2 emissions from crude oil 

production operations only in the U.S. GHG Inventory. 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 fugitive emissions from gate 

stations and pipelines. 

4. Methodology for Selection of Industry Segments and Emissions Sources 

Feasible for Inclusion in a Mandatory GHG Reporting Rule 

Background Technical Support Document – Petroleum and Natural Gas Industry 9
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 mandatory 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 mandatory 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. 

a. Review of Existing Regulations 

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

existing regulations to a mandatory reporting rule for GHG emissions. At this time, there are 

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 Mandatory Reporting 

Rule, which requires certain oil 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 Mandatory 

Reporting of 

Greenhouse Gases 

Rule 

Mandatory 

Emissions 

Reporting 

Point, Area, 

Biogenic 

CO2, CH4, 

N2O, HFCs, 

PFCs, , SF6, 

NF3, and HFE 

All facilities that emit 

25,000 metric tons or more 

per year of GHG. 

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 

Background Technical Support Document – Petroleum and Natural Gas Industry 10
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 

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 can not serve as the foundation for a 

mandatory GHG emissions reporting rule. 

Background Technical Support Document – Petroleum and Natural Gas Industry 11
Background Technical Support Document – Petroleum and Natural Gas Industry 12

b. Review of Existing Programs 

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

emissions sources that are already monitored under these programs. 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 proposed 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 oil and natural gas 

industry was then undertaken to identify the specific emissions sources (e.g., equipment or 

component for inclusion in a mandatory GHG reporting rule. 
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 Registry General Reporting Protocol, March 2007 

All legal entities (e.g. corporations, institutions, and organizations) registered in California, including petroleum and gas – all segments 

CH4, non-combustion 

CO2 and other GHG gases 

All activities resulting in indirect and direct emission of GHG gases for the entity 

Provides references for calculations The CCAR does not spefugitive emissions 

California Mandatory GHG Reporting Program 

Petroleum – Refineries 

CH4, non-combustion 

CO2 and other GHG gases 

All activities resulting in CH4

and CO2 fugitive emissions for 

petroleum refineries 

Continuous monitoring or process emissions ratCO2 process emissions 

continuous emissions mcalculating fugitive emiflares and other control 

DOE Voluntary Reporting of Greenhouse Gases Program (1605(b)) 

Petroleum and Gas- All Segments 

CH4, non-combustion 

CO2 and other GHG gases 

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

Direct, site-specific meamass balance factors Mass-balance approachand 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 Estimation Guidelines for Natural Gas Transmission and Storage, Volume 1 

Gas - Transmission/Storage 

CH4, non-combustion 

CO2

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

Equipment or segment eTier I (IPCC)- segment intentional and unintentTier II - equipment levereleases Tier II (IPCC) – facility rates for unintentional lEngineering calculation  - Pig traps  - Overhauls  - Flaring 

IPIECA - Petroleum Industry Guidelines for Reporting GHG Emissions 

Petroleum and Gas – all segments 

CH4, non-combustion 

CO2 and other GHG gases 

Refers to API Compendium points of monitoring: Equipment discharges (e.g. valves, open-ended lines, vent stacks), vent stacks for equipment types, tank PRV/vents, and facility input 

Tiers I, II, and III (IPCCmethods for all fugitive 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 
Background Technical Support Document – Petroleum and Natural Gas Industry 

The Climate Registry (General Reporting Protocol for the Voluntary Reporting Program), 2007 

All legal entities (e.g. corporations, institutions, and organizations) including petroleum and gas – all segments 

CH4, non-combustion 

CO2 and other GHG gases 

All activities resulting in emission of GHG gases for the entity 

Continuous monitoring mor process emissions rates Measurement-based meth(continuous, flow meter) aconcentration in the flue gmethodologies involve the based on activity data and 

Western Regional Air Partnership (WRAP) 

Petroleum and Gas – all segments 

CH4, non-combustion 

CO2 and other GHG gases 

All activities resulting in emission of GHG gases for the entity 

Provides quantification msectors of the petroleum athe rule. Quantification mengineering equation; howequations in several cases rates, such as from well v

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
c. Selection of Emissions Sources for Reporting 

When identifying emissions sources for inclusion in a mandatory 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 mandatory reporting rule without knowing 

the definition of a facility is difficult. Therefore, both the facility definition and emissions 

source inclusion (or exclusion) were studied independently and finally reviewed together 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 control of the same person 

(or persons under common control). This definition can be easily applied to onshore natural 

gas processing and petroleum refining facilities since the operations are all located in a 

clearly defined boundary. Onshore natural gas transmission compressor stations also can be 

clearly identified using this definition. However, this definition does not as directly lend 

itself to onshore petroleum and natural gas production, onshore natural gas transmission 

pipelines and natural gas distribution, and petroleum transportation sectors. 

Petroleum and natural gas production facilities can be very diverse in arrangement. 

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

equipment at each wellhead. At other times several wells in close proximity are connected to 

common pieces of equipment. The choice of whether multiple wells are connected to 

common 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, 

finding a single definition of a facility that can be applied to all of onshore petroleum and 

natural gas production can be challenging. In addition, there are several hydrocarbon 

resource ownership and operational equipment ownership issues relating to the onshore 

petroleum and natural gas production segment. In many cases, the mineral rights are not 

necessarily owned by the land owner. This is prevalent mostly in the western half of the 

United States where the Bureau of Land Management owns major portions of the minerals 

rights whereas the lands are held by private owners. Also, multiple operators commonly 

operate in a single production operation. For example, in the onshore production segment, 

multiple operators are responsible for different equipment in the same field under different 

ownership. 

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 

operating in and determine if its total emissions surpass the threshold. There is a precedent in 

subpart NN of the Final Mandatory Reporting Rule (MRR) for corporate reporting, where 

Background Technical Support Document – Petroleum and Natural Gas Industry 17
local distribution companies are required to report the volumes of natural gas that they sell to 

end customers. See Appendix E for further discussion of this issue. 

Natural gas transmission and petroleum transportation pipelines run over several hundred 

thousand miles in the United States. There are no identifiers (or markers) that can be used to 

readily assign a portion of the pipelines as a single facility. Moreover, emissions sources in 

pipelines are spread across large geographical areas making it difficult to use the common 

definition available from the CAA. The natural gas distribution segment has issues similar to 

the onshore natural gas transmission segment in defining facilities for the extensive pipeline 

network. The meters and regulators in the distribution segment are mainly in small 

underground vaults in urban areas. Individually defining each vault as a facility is again 

impractical owing to the size and expected magnitude of emissions from a single vault. It 

may also not be immediately obvious to include multiple vaults to define a facility, as they 

are not in a contiguous area. However, similar to the onshore production segment, local 

distribution companies could potentially report at a corporate level. The precedence for this 

type of reporting already exists under the Pipeline and Hazardous Materials Safety 

Administration (PHMSA) requirements under CFR Title 49 Section 191.11. See Appendix E 

for further discussion of this issue. 

Gathering pipelines collect produced natural gas from petroleum and natural gas fields and 

direct it to either processing plants, transmission systems, or in some cases directly to end use 

customers via distribution system. The definitional issue with gathering pipelines is similar to 

transmission and distribution systems in that pipelines cannot be physically demarcated into a 

facility. However, there is an additional issue in regard to gathering pipelines. Unlike other 

segments of the petroleum and natural gas industry, gathering systems may be owned by 

producers, processing plants, transmission companies, local distribution companies, or 

independent gathering companies. Therefore, it is difficult to assign this portion of onshore 

production to one particular segment. One option is to require gathering pipelines to be 

reported as an emissions source. The other option is to have a separate segment assigned to 

gathering pipelines. See Appendix F for further discussion on the options. 

ii. Selection of Potential Emissions Sources for Reporting 

Given that there are over 160 emissions sources 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 was used to identify the 

Background Technical Support Document – Petroleum and Natural Gas Industry 18
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 oil 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 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 and their 

contributions to their respective segment emissions. 

• 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 fugitive emissions from a unit source. For example, emissions from 

compressor blowdown venting for one compressor are much higher than fugitive 

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 fugitive 

emissions sources when the same monitoring method is used. Therefore, vented sources 

could be treated separately from fugitive 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. 

Background Technical Support Document – Petroleum and Natural Gas Industry 19
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 

them. In such cases requiring emissions detection and measurement may not always be 

feasible. Also, such requirements could pose health and safety hazards or lead to large 

cost burden. The accessibility of emissions sources has to be considered when addressing 

monitoring requirements. 

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

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

example, visiting individual onshore petroleum and natural gas production wells spread 

across large distances for emissions surveys will require excessive travel time and result 

in a large cost burden. Compressors at compressor stations on the other hand are located 

in close proximity. 

• 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 a 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 

The implication of these two types of emissions factor is as follows. The proposed rule 

could potentially ask for emissions detection only with the corresponding application of a 

leaker emissions factor. In such a case the burden for actual measurement is avoided. In 

addition, the use of leaker emissions factors will provide an estimate of “actual” 

Background Technical Support Document – Petroleum and Natural Gas Industry 20
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 a reporting rule. Figure 1 shows the resulting 

decision tree that includes these criteria and supported the decision-making process. The cost 

for monitoring from each emissions source varies greatly for oil and gas production and 

hence will have to be dealt with in addition to the decision tree. The decision process 

provided in Figure 1 was applied to each emissions source in the natural gas segment of the 

U.S. GHG Inventory. The petroleum onshore production segment has emissions sources that 

either are equivalent to their counterparts in the natural gas onshore segment or fall in the 20 

percent exclusion category. Only CH4 emissions were taken into consideration for this 

exercise given that, for most sources, fugitive CO2 emissions are negligible in comparison to 

CH4 emissions from the same sources. 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 21
Is emissions source a fugitive? 

Is source accessible for 

fugitive detection? 

Use fugitive detection 

and leaker emission 

factor 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 fugitive emissions 

source 

geographically 

dispersed? 

Yes 

Yes 

Figure 1: Decision Process for Emissions Source Selection 

Background Technical Support Document – Petroleum and Natural Gas Industry 22
iii. Address Sources with Large Uncertainties 

The natural gas and petroleum industry inventories are based on a U.S. EPA and Gas 

Research Institute Study5 published in 1996. There are several estimates of emissions factors 

for emissions sources that do not correctly reflect the operational practices of today. Hence in 

some cases the estimates either under or over count volume of emissions from these sources. 

From anecdotal evidence from the industry, it is believed that emissions from some sources 

may be much higher than currently reported in the U.S. GHG Inventory. In most cases 

sufficient information is not publicly available to make changes to the national Inventory 

estimates. In other cases where public data are available, it is often incomplete and does not 

represent the industry at a national level. The decision tree was not necessarily ideal for 

sources known to be over- or underestimated in current inventories, which use existing 

emission factors. Therefore, the decision tree was overridden for these sources. The sources 

for consideration under this exception are: 

 

o Condensate and oil storage tanks 

o Natural gas well workovers 

o Natural gas well completions 

o Natural gas well blowdowns 

o Centrifugal compressor wet seals 

o Flares 

In addition, the U.S. GHG Inventory includes CH4 and CO2 emissions from natural gas 

engines and turbines, 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 described in Subpart C of the Final Mandatory Reporting Rule (MRR) and 

Petroleum Refineries described in Subpart Y of the Final Mandatory Reporting Rule (MRR) 

respectively. 

iv. Identify Sources to be Included 

Based on the understanding of facility definitions for each segment of the oil and gas 

industry and the identification of potential sources for inclusion in a mandatory reporting 

rule, the potential segments and sources to be included were identified. A brief analysis for 

each segment is 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. For some segments of the industry, identifying a facility is 

straightforward since there are clear physical boundaries and ownership structures 

 

5

 U.S. Environmental Protection Agency/ Gas Research Institute, Methane Emissions from the Natural Gas 

Industry, June 1996. 

Background Technical Support Document – Petroleum and Natural Gas Industry 23
Onshore production operations are a challenge for emissions reporting using the 

conventional facility definition of a “contiguous area” under a common owner/ 

operator. EPA proposes to define a hydrocarbon producing basin as a facility and all 

operators report their emissions on a basin level. In such a case, the company (or 

corporation) operating in multiple fields in the same basin can report at the basin 

level. The operator could be the company or corporation holding the required state or 

federal permit for drilling or operating. Reporting emissions from all potential 

emissions sources at a basin level would substantially increase reporting burden but 

the complexity of reporting requirements would be substantially reduced. Another 

possible alternative is to define a production field as a facility. In such cases, the 

company (or corporation) operating in the field can report emissions. However, such 

field level definition can result in lower coverage than basin level reporting, since 

fields are typically a segment of a basin. 

In addition to basin and field level reporting, one alternative option 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 oil heatertreaters, gas powered pneumatic instruments and pumps, electrical generators, steam 

boilers and crude oil and gas liquids stock tanks. This definition was analyzed with 

available data including four cases to represent the full range of petroleum and natural 

gas well pad operations: 

• 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 24
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. 

Facility definitions identifying a single wellhead as a facility could significantly 

increase the number of reporters to a program, and potentially raise implementation 

issues. 

One way to reduce the reporting burden, due to the large number of sources, would be 

to focus on the largest contributors to GHG emissions. From the EPA Natural Gas 

STAR experience in mitigating methane emissions in the onshore petroleum and 

natural gas production segment, the major contributors to emissions from the onshore 

production segment are easily identifiable. These emissions sources are not reflected 

as major sources in the U.S. GHG Inventory as the inventory estimates are based on a 

1992 measurement study5

 that, in the case of these sources, was based on limited 

data. Based on current knowledge of the petroleum and natural gas industry, the 

following seven emissions sources are known to be the major contributors to the total 

petroleum and natural gas production segment emissions: natural gas driven 

pneumatic valve and pump devices, well completion releases and flaring, well 

blowdowns, well workovers, crude oil and condensate storage tanks, dehydrator vent 

stacks, and reciprocating compressor rod packing. With a basin level, field level, or 

well-head level facility definition, onshore production segment operators or 

companies could report emissions from the seven major emissions sources listed 

above. 

 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 – There are two types of operations in the 

processing segment of the natural gas industry; gathering/ boosting stations and 

processing facilities. Gathering/ boosting stations typically collect gas from several 

producing zones, dehydrate the natural gas and compress it for transportation to 

onshore natural gas processing plants. Processing facilities further process the gas to 

remove hydrogen sulfide (H2S) and/ or CO2 in the natural gas, if any, separate the 

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

Background Technical Support Document – Petroleum and Natural Gas Industry 25
and compress the natural gas to be injected into the onshore natural gas transmission 

segment. Both gathering/ boosting stations and natural gas processing facilities have a 

well defined boundary within which all processes take place. All emissions sources in 

a processing plant could be monitored and included in a mandatory GHG reporting 

rule, including associated gathering and boosting stations. 

 Onshore Natural Gas Transmission Segment – 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. Natural gas transmission also involves high pressure, large 

diameter pipelines that transport gas long distances from field production and natural 

gas processing facilities to natural gas distribution pipelines or large volume 

customers such as power plants or chemical plants. The magnitude of transmission 

pipeline emissions in the U.S. Inventory is 0.07% of the total national emissions. 

Also, the Department of Transportation in Title 49 CFR Part 192 Section 706 requires 

that all natural gas transmission lines perform leakage surveys at least two to four 

times every calendar year. Section 711 of the same regulation requires operators to 

make permanent repairs to discovered leaks when feasible. Therefore, EPA is not 

proposing to include reporting of fugitive emissions from natural gas pipeline 

segments between compressor stations, or crude oil pipelines and tank terminals in 

the supplemental rulemaking can potentially be excluded because of the dispersed 

nature of the fugitive emissions, and the fact that once fugitives are found, they are 

generally fixed quickly. One possible option is that each segment facility that 

operates gathering pipelines report emissions from their gathering lines. 

 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 mandatory reporting rule. 

 Natural Gas Distribution Segment – The distribution segment meter and regulation 

vaults are identifiable as a facility. However, the magnitude of emissions from a 

single vault is not significant. Although vaults collectively contribute to a significant 

share of emissions from the natural gas industry nationally, it may not be possible to 

group multiple vaults as a single facility as they are not in a contiguous area. Also, 

emissions from vaults and pipelines are usually quickly dealt with given the safety 

concerns in a gas distribution segment. This might not allow any time for monitoring 

of leaks. 

Another option for including distribution sector is adapting the facility definition 

from the fuels reporting regulation for natural gas reporting from distribution 

Background Technical Support Document – Petroleum and Natural Gas Industry 26
companies. This subpart of the MRR defines a local distribution company (LDC) as a 

facility and the threshold is applied at the company level. Using this definition will 

avoid all the issues discussed earlier since geographical demarcation of the facility 

will no more be an issue. 

 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. 

Table 5 provides a list of each segment and a corresponding facility definition. It also 

provides a listing of all sources that can be monitored and could be reported as part of a 

mandatory GHG reporting rule. 

Table 5: Segment Specific Facility Definition 

Segment Facility Definition Potential Emission 

Sources for Inclusion 

Onshore Petroleum 

and Natural Gas 

Onshore petroleum and natural gas production 

facility means all petroleum or natural gas 

equipment associated with all petroleum or 

natural gas production wells under common 

ownership or common control by an onshore 

petroleum and natural gas production owner 

or operator located in a single hydrocarbon 

basin as defined by the American Association 

of Petroleum Geologists which is assigned a 

three digit Geologic Province Code. Where an 

operating entity holds more than one permit in 

a basin, then all onshore petroleum and natural 

gas production equipment relating to all 

permits in their name in the basin is one 

onshore petroleum and natural gas production 

facility. 

Acid gas removal (AGR) vent 

stacks, centrifugal compressor dry 

seals, centrifugal compressor wet 

seals, compressor fugitive 

emissions, dehydrator vent stacks, 

flare stacks, natural gas driven 

pneumatic pumps, non-pneumatic 

pumps, open-ended lines (OELs), 

pump seals, pipeline fugitive 

emissions, natural gas driven 

pneumatic manual valve actuator 

devices, natural gas driven 

pneumatic valve bleed devices, 

reciprocating compressor rod 

packing, storage tanks, separators, 

well clean-ups/blowdowns, vessel 

blowdowns/venting, meters/piping, 

pipeline leaks, pipeline venting, 

wellhead fugitives, well 

completions, coal bed methane 

fugitives, heaters, separators. 

Offshore Petroleum 

and Natural Gas 

Production 

Offshore petroleum and natural gas 

production facility means any platform 

structure, either floating in the ocean or lake, 

or fixed on the ocean or lake bed, that houses 

equipment to extract hydrocarbons from the 

ocean or lake floor and transports it to storage 

or transport vessels or transports onshore. In 

addition, offshore production facilities include 

secondary platform structures and floating 

storage tanks connected to the platform 

structure by a pipeline. Production facilities 

connected to each other via causeways are one 

Acid gas removal (AGR) vent 

stacks, centrifugal compressor dry 

seals, centrifugal compressor wet 

seals, compressor fugitive 

emissions, dehydrator vent stacks, 

flare stacks, natural gas driven 

pneumatic pumps, non-pneumatic 

pumps, open-ended lines (OELs), 

pump seals, offshore platform 

pipeline fugitive emissions, 

platform fugitive emissions, 

natural gas driven pneumatic 

Background Technical Support Document – Petroleum and Natural Gas Industry 27
facility. manual valve actuator devices, 

natural gas driven pneumatic valve 

bleed devices, reciprocating 

compressor rod packing, storage 

tanks, separators, well cleanups/blowdowns, vessel 

blowdowns/venting, meters/piping, 

pipeline leaks, pipeline venting. 

Onshore Natural Gas 

Processing 

Natural gas processing facilities are plants 

designed to separate and recover natural gas 

liquids (NGLs)or other non-methane gases 

and liquids from a stream of produced natural 

gas to meet onshore natural gas transmission 

pipeline quality specifications through 

equipment performing one or more of the 

following processes: oil and condensate 

removal, water removal, separation of natural 

gas liquids, sulfur and carbon dioxide 

removal, fractionation of NGLs, or other 

processes, and also the capture of CO2 

separated from natural gas streams for 

Enhanced Oil Recovery (EOR), carbon 

sequestration projects or other commercial 

applications. In addition, field gathering 

and/or boosting stations that gather and 

process natural gas from multiple wellheads, 

and compress and transport natural gas 

(including but not limited to flow lines or 

intra-facility gathering lines or compressors) 

as feed to the natural gas processing facilities 

are considered a part of the processing facility. 

Gathering and boosting stations that send the 

natural gas to an onshore natural gas 

transmission facility, or natural gas 

distribution facility, or to an end user are 

considered stand alone natural gas processing 

facilities. All residue gas compression 

equipment operated by a processing plant, 

whether inside or outside the processing plant 

fence, are considered part of the natural gas 

processing facility. All petroleum and natural 

gas equipment associated with petroleum and 

natural gas wells are not considered a part of 

the natural gas processing 

AGR vent stacks, blowdown vent 

stacks, centrifugal compressor dry 

seals, centrifugal compressor wet 

seals, compressor fugitive 

emissions, dehydrator vent stacks, 

open-ended lines (OELs), natural 

gas driven pneumatic manual valve 

actuator devices, natural gas driven 

pneumatic valve bleed devices, 

processing facility fugitive 

emissions, reciprocating 

compressor rod packing, storage 

tanks, non-pneumatic pumps, 

meters/piping, pipeline leaks, 

station venting and M&R 

Onshore Natural Gas 

Transmission 

Onshore natural gas transmission compression 

facility means any permanent combination of 

compressors that move natural gas at elevated 

pressure from production fields or natural gas 

processing facilities, in transmission pipelines, 

to natural gas distribution pipelines, or into 

storage facilities. In addition, transmission 

compressor station includes equipment for 

liquids separation, natural gas dehydration, 

and tanks for the storage of water and 

hydrocarbon liquids. Each owner or operator 

Centrifugal compressor dry seals, 

centrifugal compressor wet seals, 

compressor fugitive emissions, 

dehydrator vent stacks, OELs, 

natural gas driven pneumatic 

manual valve actuator devices, 

natural gas driven pneumatic valve 

bleed devices, reciprocating 

compressor rod packing, storage 

tanks, transmission station fugitive 

emissions, meters/piping, pipeline 

Background Technical Support Document – Petroleum and Natural Gas Industry 28
engaged in gas transmission compression, 

who also operates gas gathering pipelines, 

shall report emissions for these pipelines. 

leaks, CBM Powder River, AGR 

vent stacks, vessel blowdown, 

station venting, and M&R. 

Underground Natural 

Gas Storage 

Underground natural gas storage facility 

means a subsurface facility, including but not 

limited to; depleted gas or oil reservoirs and 

salt dome caverns, utilized for storing natural 

gas that has been transferred from its original 

location for the primary purpose of load 

balancing, which is the process of equalizing 

the receipt and delivery of natural gas; 

processes and operations that may be located 

at a natural gas underground storage facility 

(including, but are not limited to, 

compression, dehydration and flow 

measurement); and all the wellheads 

connected to the compression units located at 

the facility. 

Centrifugal compressor dry seals, 

centrifugal compressor wet seals, 

compressor fugitive emissions, 

dehydrator vent stacks, OELs, 

pump seals, natural gas driven 

pneumatic manual valve actuator 

devices, natural gas driven 

pneumatic valve bleed devices, 

reciprocating compressor rod 

packing, storage tanks, storage 

station fugitive emissions, storage 

wellhead fugitive emissions, 

meters/piping, pipeline leaks, 

vessel blowdowns/venting, 

pipeline venting, station venting, 

and M&R. 

LNG Storage 

LNG storage facilities means an onshore 

facility that stores LNG in above ground 

storage vessels, equipment for liquefying 

natural gas, compressors to capture and reliquefy boil-off-gas, re-condensers, and 

vaporization units for re-gasification of the 

liquefied natural gas. 

Centrifugal compressor dry seals, 

centrifugal compressor wet seals, 

compressor fugitive emissions, 

OELs, LNG storage station 

fugitive emissions, reciprocating 

compressor rod packing, 

meters/piping, pipeline leaks, 

pneumatic device vents, vessel 

blowdowns/venting, pipeline 

venting, station venting, and 

M&R. 

LNG Import and 

Export 

LNG import facility means onshore or 

offshore facilities that receive imported LNG 

via ocean transport, store it in storage tanks, 

re-gasify it, and deliver re-gasified natural gas 

to a natural gas transmission or distribution 

system. LNG export facility means onshore or 

offshore facilities that receive natural gas, 

liquefy it, store it in storage tanks, and send 

out the LNG via ocean transportation, 

including to import facilities in the United 

States. 

Centrifugal compressor dry seals, 

centrifugal compressor wet seals, 

compressor fugitive emissions, 

OELs, LNG storage station 

fugitive emissions, reciprocating 

compressor rod packing, 

meters/piping, pipeline leaks, 

pneumatic device vents, vessel 

blowdowns/venting, pipeline 

venting, station venting, and 

M&R. 

Natural Gas 

Distribution 

A natural gas distribution facility is a Local 

Distribution Company (LDC) that owns or 

operates distribution pipelines, not interstate 

pipelines or intrastate pipelines, and metering 

and regulating stations, that physically deliver 

natural gas to end users and that are regulated 

as separate operating companies by State 

public utility commissions or that operate as 

independent municipally-owned distribution 

systems. 

Main cast iron pipeline fugitives, 

main unprotected steel pipeline 

fugitives, main protected steel 

pipeline fugitives, main plastic 

protected steel pipeline fugitives, 

service unprotected steel pipeline 

fugitives, service protected steel 

pipeline fugitives, service plastic 

pipeline fugitives, service copper 

pipeline fugitive, city gate station 

fugitives, customer meter fugitives, 

pressure relief valves, pipeline 

blowdowns, mishaps. 

Background Technical Support Document – Petroleum and Natural Gas Industry 29
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 

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 fugitive and vented CH4

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

combustion emissions are those combustion emissions not already reported under Subpart C 

of the MRR, but are required to be reported because their process emissions. The fugitive 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. 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. N2O 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 the rule includes all fugitive 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 is 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 67 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 14 and 2 percent (81 percent minus 67 

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 

Background Technical Support Document – Petroleum and Natural Gas Industry 30
Background Technical Support Document – Petroleum and Natural Gas Industry 31

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. 

Table 6 provides the details of the threshold analysis at all threshold levels for the different 

segments in the oil and gas industry. 
Table 6: Threshold Analysis for the Oil 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 

100,000 277,798,737 27,993 131,978,112 55,197,177 187,175,289 67% 25,000 277,798,737 27,993 154,932,641 69,294,918 224,227,559 81% 10,000 277,798,737 27,993 164,072,922 78,317,926 242,390,849 87% 

Onshore Natural Gas Production Facilities (Basin) 

1,000 277,798,737 27,993 174,457,309 94,391,220 268,848,529 97% 

100,000 11,261,305 3235 3,217,228 25,161 3,242,389 29% 25,000 11,261,305 3235 4,619,175 500,229 5,119,405 45% 10,000 11,261,305 3235 5,515,419 1,596,144 7,111,563 63% 

Offshore Petroleum and Natural Gas Production Facilities 

1000 11,261,305 3235 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 

1000 33,984,015 566 31,652,484 2,331,531 33,984,015 100% 

100,000 64,059,125 1,944 34,511,094 7,834 34,518,927 54% 25,000 64,059,125 1,944 51,527,832 6,155,313 57,683,144 90% 10,000 64,059,125 1,944 53,554,302 9,118,603 62,672,905 98% 

Onshore Natural Gas Transmission Facilities 

1,000 64,059,125 1,944 54,117,187 9,934,474 64,051,661 100% 100,000 9,713,029 397 3,548,988 0 3,548,988 37% 25,000 9,713,029 397 6,570,369 1,276,239 7,846,609 81% 10,000 9,713,029 397 7,283,058 1,685,936 8,968,994 92% 

Underground Natural Gas Storage Facilities 

1,000 9,713,029 397 7,745,028 1,951,505 9,696,532 100% 

100,000 2,113,601 157 669,503 25,956 695,459 33% 25,000 2,113,601 157 1,712,240 188,552 1,900,793 90% 10,000 2,113,601 157 1,826,546 204,297 2,030,842 96% 

LNG Storage Facilities 

1,000 2,113,601 157 1,859,880 237,094 2,096,974 99% 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. Fugitive and vented emissions in the threshold analysis are a 

sum of facility level emissions for each segment. Hence the total fugitive 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 

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

definition. 

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

Emissions Covered Facilities Covered Threshold 

Level2 Metric tons 

CO2e/year Percent Number Percent 

100,000 99,776,033 38% 305 0% 

25,000 144,547,282 55% 1,253 2% 

10,000 169,160,462 64% 2,846 3% 

1,000 242,621,431 92% 39,652 48% 

Four different scenarios were also considered above for applying thresholds at individual 

well pads. 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. So, 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 oil and gas production. For the other cases, the threshold would have to be set lower 

than the thresholds considered for other sectors of the mandatory 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) 4,927 700 700 370 

Number of Reporters 3,349 38,949 66,762 166,690 

Covered Emissions (metric tons CO2e) 16,498,228 40,943,092 50,572,248 87,516,080 

Percent Coverage 6% 16% 19% 33%

Background Technical Support Document – Petroleum and Natural Gas Industry 33
The petroleum and natural gas industry may be somewhat unique when calculating facility 

emissions to be applied against a threshold for reporting. Finalized source categories in the 

MRR 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 oil and natural gas industry 

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

and natural gas production, one might consider requiring reporting and calculation of 

portable equipment emissions from this source category. If these emissions were excluded 

from the threshold calculation, a large number of facilities may 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. Although lowering the threshold, but 

excluding portable equipment emissions could address this issue, data are not available to 

disaggregate stationary and portable combustion emissions from total combustion emissions 

in order to support an analysis to lower the threshold. 

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. 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. Table 4 provided a summary of the programs and 

guidance documents reviewed. 

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. Fugitive Emissions Detection 

Traditional fugitive emission 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 fugitive 

emissions detection technologies are currently being used in the United States and 

internationally to efficiently 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 Fugitive Emissions Detectors 

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

emissions 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 fugitive emissions from a 

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

presence of fugitive emissions. 

Background Technical Support Document – Petroleum and Natural Gas Industry 34
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 fugitive 

emissions source. The camera can actually “see” fugitive emissions. 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 involves 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 fugitive emissions. 

Such devices do not have screens to view the fugitive emissions, 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 fugitive emissions 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 fugitive emissions, 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 fugitive 

emissions 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 fugitive emissions depends on a number of 

factors including manufacturer, viewing distance, wind speed, gas composition, ambient 

temperature, gas temperature, and type of background behind the fugitive emissions. For best 

survey results, fugitive emissions detection can be performed under 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. Fugitive emissions detection and measurement instrument 

manuals can 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 

hydrocarbon and measure the concentration of the fugitive emissions. It consists of a probe 

Background Technical Support Document – Petroleum and Natural Gas Industry 35
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 fugitive emissions 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 fugitive emission, 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. 

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 maximum 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 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 

Background Technical Support Document – Petroleum and Natural Gas Industry 36
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 

from the source then anti-static wraps or other aids can to 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 connected 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 

Background Technical Support Document – Petroleum and Natural Gas Industry 37
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 

differential that is converted to mass emissions rate. 

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. 

Calibrated Bagging 

A calibrated 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 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 

Background Technical Support Document – Petroleum and Natural Gas Industry 38
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 (also known as vent 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 

Several emissions sources do not require physical measurement of the emissions using a 

measurement instrument. 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. These 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 

Fugitive emissions 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 the following equation for calculating emissions: 

, = sns *VFE Equation 1 

Background Technical Support Document – Petroleum and Natural Gas Industry 39
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. 

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 the following equation: 

, = sns *NAE Equation 2 

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 two categories; low bleed devices and high bleed devices. 

Low bleed devices are devices that bleed less than 6 scf of natural gas per hour. Given the 

vast difference in bleed rates, low bleed devices contribute to a small portion of the total 

emissions from pneumatic devices nationally. Therefore, it may be feasible to provide an 

Background Technical Support Document – Petroleum and Natural Gas Industry 40
emissions factor approach for low bleed pneumatic devices to reduce burden. Following are 

two different options for high and low bleed 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; 

, = sns * TBE Equation 3 

 

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 

Emissions from natural gas pneumatic low bleed device venting can be calculated using 

emissions factor as follows; 

Mass ,is = GHGEFCount i Convi 365*24**** Equation 4 

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 K 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; 0.000404 for 

CH4, and 0.00005189 for CO2

24 * 365 = conversion to yearly emissions estimate 

Background Technical Support Document – Petroleum and Natural Gas Industry 41
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 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. 

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 units. 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 be calculated as follows; 

 

Ea,CO2 = (V1 * %Vol1) - (V2 * %Vol2) Equation 5 

where, 

Ea,CO2 = Annual volumetric CO2 emissions at ambient condition, in cubic feet per 

year 

V1 = Metered total annual volume of natural gas flow into AGR unit in cubic 

feet per year at ambient condition 

%Vol1 = Volume weighted CO2 content of natural gas into the AGR unit 

V2 = Metered total annual volume of natural gas flow out of the AGR unit in 

cubic feet per year at ambient condition 

%Vol2 = Volume weighted CO2 content of natural gas out of the AGR unit 

Background Technical Support Document – Petroleum and Natural Gas Industry 42
Sometimes AGR units have a continuous gas analyzer in which case they can be used to 

determine %Vol1 and %Vol2. In addition, 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 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 the following equation: 

,na = *VNE v Equation 6 

 

where, 

Ea,n = Annual natural gas venting emissions at ambient conditions from 

blowdowns in cubic feet 

N = Number of blowdowns for the equipment in reporting year 

Vv = Total volume of blowdown equipment chambers (including, but not 

limited to, pipelines, compressors and vessels) between isolation valves in 

cubic feet 

6. Dehydrator Vent Stacks 

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 vent stack 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; see Appendix H for further details. Different 

software packages might use different calculations and input parameters to determine 

Background Technical Support Document – Petroleum and Natural Gas Industry 43
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. 

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 the 

following equation: 

)/000,1***4(

)/365*%****(

1

2

2

, McfcfTP

yrdaysGPPDH E ns = Equation 7 

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) 

Some dehydrator vented emissions are sent to a flare. Annual emissions from dehydrator vent 

stacks to flares can be calculated using the methodology under section 8 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. 

Background Technical Support Document – Petroleum and Natural Gas Industry 44
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 the following equation. 

3

, 10**** −

ic = cv GHGRVNMass i Equation 8 

 

where, 

Massc,i = Annual EOR injection gas venting emissions in metric tons at critical 

conditions “c” from blowdowns. 

N = Number of blowdowns for the equipment in reporting 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 

necessarily reliable 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 many cases 

the emissions factors were developed using limited sample data and knowledge about the 

industry’s operations. Also, the introduction of many emissions reduction technologies are 

not reflected in the emissions factor estimates. However, the two studies provide a wealth of 

raw data that can be potentially used to revise the estimate in conjunction with any new data 

that is now publicly available. 

Background Technical Support Document – Petroleum and Natural Gas Industry 45
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. 

Flare emissions in general 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 reporting year. 

Method 2: 

One 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 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 natural gas sent to flare. The GHG volumetric 

emissions at actual conditions can then be calculated as follows. 

ia Va Xi (unE combusted *)1(*) , − = −η Equation 9 

= ∑

j

COa RYV jja E (combusted ***) 2, η Equation 10 

( () ) ,, , =EE iaia combusted + ia unE − combusted Equation 11 

Background Technical Support Document – Petroleum and Natural Gas Industry 46
where, 

Ea,i(un-combusted) = Contribution of annual un-combusted emissions from 

flare stack in cubic feet, under ambient conditions

Ea,CO2(combusted) = Contribution of annual emissions 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 

η = Percent of natural gas combusted by flare (default is 98 

percent) 

Xi = Concentration of GHGi in gas to the flare 

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 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 

Background Technical Support Document – Petroleum and Natural Gas Industry 47
manufacturer manual for conversion. Annual emissions can be estimated using meter flow 

measurement as follows: 

,ia = i − BMTMTE )1(*** Equation 12 

 

where, 

Ea,i = Annual GHGi (either CH4 or CO2) volumetric emissions at ambient 

conditions 

MT = Meter reading of gas emissions per unit time 

T = Total time the compressor associated with the wet seal(s) is operational in 

the reporting 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 

Background Technical Support Document – Petroleum and Natural Gas Industry 48
first option is to use an emissions factor for rod packing along with a population count. The 

second option is to require fugitive emissions 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 this is for 

the most part, negligible. Hence to correctly characterize annual emissions from rod packing, 

estimation of emissions at two compressor modes, operating and standby pressurized, may be 

required. 

11. Storage tanks 

Emissions from storage tanks can be estimated using one of the following three 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 a one-time 

measurement during a cycle of operation that is representative of the tank operations through 

the year. The following equation can be used to calculate GHG emissions: 

,ha ×= ERQE Equation 13 

 

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. 

• 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. 

Background Technical Support Document – Petroleum and Natural Gas Industry 49
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 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 14 demonstrates the use of this correlation equation: 

( ) ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

+

×

×+××=

460 exp7.14

sep

oil

fg sep T

GC PGAGOR Equation 14 

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 

Background Technical Support Document – Petroleum and Natural Gas Industry 50
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, 

(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 J. 

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. This natural gas 

then flows through the storage tank. The only potential option to measuring emissions from 

scrubber dump valves is to monitor storage tank emissions to determine if the emissions do 

not subside and become negligible. 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 may be required using a 

temporary meter. 

Storage tank vapors captured using vapor recovery systems or sent to flares will have to be 

accounted for in the above method. 

12. 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 the equation below: 

,ns = ** DFRGORE Equation 15 

Background Technical Support Document – Petroleum and Natural Gas Industry 51
where, 

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

under ambient 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. 

13. 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. 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 the following equation, 

,na = *VGORE Equation 16

 

where, 

Ea,n = Annual volumetric natural gas emissions from associated gas venting 

under ambient 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 reporting 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. 

14. 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. 

Background Technical Support Document – Petroleum and Natural Gas Industry 52
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 the following equation, 

Masss, CO2 = Shl * Vhl Equation 17 

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. 

Vhl = Total volume of hydrocarbon liquids produced in barrels in the 

reporting year. 

15. Produced water dissolved CO2

EOR operations often use water injection techniques to push the CO2 soaked petroleum 

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 recirculated 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 18 

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 reporting year. 

Background Technical Support Document – Petroleum and Natural Gas Industry 53
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. 

16. 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 

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 the following equation, 

Es,n = T * X * EF Equation 19

where, 

Es,n = Annual natural gas emissions at standard conditions 

T = Amount of time of well venting 

Background Technical Support Document – Petroleum and Natural Gas Industry 54
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. 

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 the following equation: 

Es,n = {(0.37×10-3) * CD2

 * WD * SP * V} + 

{SFR*HR} Equation 20 

where, 

Es,n = Annual natural gas emissions at standard 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 = Sales flow rate of gas well in cubic feet per hour 

HR = Hours that the well was left open to the atmosphere during unloading 

17. 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 based on the pressure 

drop flow across the well choke. Method 3 uses the production of the well to determine 

emissions. 

Background Technical Support Document – Petroleum and Natural Gas Industry 55
Method 1: 

A recording flow meter can be installed on the vent line to the atmosphere or to a flare during 

each well unloading 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 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 from hydraulic 

fracturing can be calculated using equation 21 below; 

Es,n = T * FR Equation 21

where, 

Es,n = Annual natural gas vented emissions at ambient conditions in cubic feet 

T = Cumulative amount of time in hours of well venting during the year 

FR = Flow rate in cubic feet per hour, under ambient conditions 

Method 2: 

Using pressures measured before and after the well choke, an engineering calculation of the 

average flow rate across the choke can be done. 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 back-flow 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. 

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 

the following equation, 

,is = ** GHGTVE i Equation 22 

 

where, 

Es,i = Annual GHG emissions in cubic feet at standard conditions from gas 

well venting during conventional well completions or workovers 

Background Technical Support Document – Petroleum and Natural Gas Industry 56
V = Daily gas production rate, in cubic feet per minute 

T = Cumulative amount of time of well venting in minutes during the year 

GHGi = for onshore petroleum and natural gas production facilities, fraction of 

GHGi, CH4 or CO2, in produced natural gas 

c. Leak detection and leaker emission factors 

For fugitive emissions sources that are standard components such as connectors, valves, 

meters, etc. emissions can be estimated by conducting a fugitive emissions detection program 

and applying a leaker emissions factor to those sources found to be emitting. The following 

Equation 23 can be used for this purpose. 

E TGHGEFCount ,is = i

*** Equation 23 

 

where, 

Es,j = Annual total volumetric GHG emissions at standard conditions from a 

fugitive source 

Count = Total number of this type of emission source found to be leaking 

EF = Leaker emission factor for specific sources listed in Appendix J. 

GHGi = for onshore natural gas processing facilities, concentration of GHGi, 

CH4 or CO2, in feed natural gas; for other facilities GHGi equals 1 

T = Total time the specific source associated with the fugitive emission was 

operational in the reporting year, in hours 

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 K. 

Background Technical Support Document – Petroleum and Natural Gas Industry 57
d. Population Count and Emission Factors. 

For fugitive emissions 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 

corresponding population emissions factor. 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. Emissions from 

all sources listed in this paragraph of this section can be calculated using the following 

equation. 

,is = i

*** TGHGEFCountE Equation 24 

where, 

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

each fugitive source 

Count = Total number of this type of emission source at the facility 

EF = Population emission factor for specific sources listed in Appendix K. 

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 fugitive emission was 

operational in the reporting year, 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 L. 

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 fugitive emissions could occur. The probe 

must be maintained in close proximity to 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 leak 

Background Technical Support Document – Petroleum and Natural Gas Industry 58
definitions; they are defined within specific subparts of the Title 40 CFR. Method 21 also 

allows certain alternative fugitive emissions detection methods, such as soap solutions 

(where the fugitive emissions 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)6

 to estimate the quantity of VOC emissions. SOCMI factors were developed from 

petroleum refinery and petrochemical plant data using Method 21. SOCMI factors adjusted 

for methane content are considerably lower than the methane factors proposed in this rule, 

which were developed from more recent studies of gas processing plants and compressor 

stations. 

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 Method 21. 

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 fugitive emissions 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 fugitive emissions from 

a component leak, they are used primarily for fugitive emissions 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 

 

6

 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 

Background Technical Support Document – Petroleum and Natural Gas Industry 59
“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. For the proposed rule, fugitive emissions detection by more cost-effective screening 

technologies in conjunction with leaker emission factors are considered a better approach to 

emissions quantification than the labor intensive Method 21. 

g. Mass Balance for Quantification 

There are mass balance methods that could be considered to calculate emissions from 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 fugitive emissions. 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 

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 Mineral Management Service conducts a comprehensive activity data collection effort 

under its Gulf Offshore Activity Data System program (GOADS). This requires all 

petroleum and natural gas production platforms located in the Federal Gulf of Mexico (GoM) 

to report their activities to MMS once in every 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 

MMS and reported subsequently by MMS. The MMS 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 are only collected once every four years, EPA will not 

receive new emissions information for every reporting period. This means that between 

MMS reporting periods if a new platform is commissioned, an old platform is decommissioned, new equipment is installed on existing platforms, or operating levels of 

Background Technical Support Document – Petroleum and Natural Gas Industry 60
platforms change then this information will not get recorded and reported for periods when 

MMS GOADS is not being conducted. Finally, the MMS GOADS program does not collect 

information from platforms in the GoM under State jurisdiction, as well as platform 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. 

i. Additional Questions Regarding Potential Monitoring Methods 

There are several additional issues regarding the potential monitoring methods relevant to 

estimating fugitive and vented emissions from the petroleum and natural gas industry. 

i. Source Level Fugitive Emissions Detection Threshold 

This document does not indicate a particular fugitive emissions definition or detection 

threshold requiring emissions measurement. This is because different fugitive emissions 

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 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 fugitive emissions 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 proposed rule may require measurement and 

reporting. This avoids the necessity of specifying performance standards. 

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 fugitive emissions. 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 

Background Technical Support Document – Petroleum and Natural Gas Industry 61
study conducted by API at seven California refineries7

 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. fugitive 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 proposed supplemental rule to detect and 

quantify leaking sources beyond the scope of Method 21. 

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 the proposed supplemental rule as these instruments are able to scan 

hundreds of source components quickly, including components out of reach for an 

OVA/TVA. 

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). A detailed discussion on the available instruments and standards for 

methane emission detection and quantification are presented in Appendix O. 

Fugitive Emissions 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. As discussed above, these SOCMI factors are not proposed for this 

supplemental rule. 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. 

 

7

 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 62
ii. Duration of Fugitive Emissions 

 Fugitive emissions 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 fugitive emissions 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 fugitive emission 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. Fugitive 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. 

Fugitive emissions from a compressor 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, fugitive and vented emissions result from closed blowdown valves and 

reciprocating compressor rod packing leaks, respectively. When the compressor is offline 

and depressurized, fugitive 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 fugitive 

and vented emissions are significantly different. One potential approach to address this issue 

is that operators measure emissions for each mode the compressor is operated in and the 

period of time during the reporting period at which the compressor is in the different modes 

Background Technical Support Document – Petroleum and Natural Gas Industry 63
to account for the varying levels of fugitive and vented emissions. However, this will 

increase the reporting burden. Measurements will have to be taken at each mode of 

compressor operation and the time that the equipment is in various operational modes would 

also have to be tracked. 

A similar issue exists with tanks where the operational parameters change more dynamically 

than 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. A detailed discussion on the issue of operational modes, their impact on 

emissions monitoring, and potential options for monitoring emissions from emissions sources 

with varying modes of operation are can be found in Appendix M. 

iv. Natural Gas Composition 

When measuring fugitive and vented emissions using the various measurement instruments 

(high volume sampler, calibrated bags, and meters measure natural gas emissions) 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 (flare stack 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. 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. 

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. See Appendix N for a detailed discussion 

on this issue. 

Background Technical Support Document – Petroleum and Natural Gas Industry 64
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. Fugitive emissions 

from flanges, valve stems, equipment covers, etc. are generally smaller than emissions from 

vents. Fugitive emissions 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. 

Accessibility issues and these potential solutions are discussed in more detail in Appendix G. 

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 years’ data point to 

replace missing data in the current reporting year, this is not ideal since varying operating 

conditions can dramatically impact emissions estimates. Where using previous years’ 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. 

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 

Background Technical Support Document – Petroleum and Natural Gas Industry 65
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 fugitive emissions 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 years’ data are not as desirable as there could be significant differences from 

year to year based on operating conditions. 

• Process conditions data. Estimating vented emissions from acid gas removal vent 

stacks, blowdown vent stacks, dehydrator vent stacks, 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 year’s 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. 

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 

Background Technical Support Document – Petroleum and Natural Gas Industry 66
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 fugitive emissions 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.? 

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, 

Background Technical Support Document – Petroleum and Natural Gas Industry 67
 Changes concerning the emitting process (e.g. energy efficiency 

improvements).8

• 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.9

• 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), 

o Check the aggregation of data across source categories, business units, etc., 

 

8

 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. 

9

 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 68
o When methods or data have changed, check consistency of time series inputs 

and calculations.10

9. Reporting Procedure 

The following reporting requirements could be considered for a mandatory reporting rule; 

a) Some fugitive emissions 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 

fugitive emissions began. As discussed in more detail in Section I ii, under these 

circumstances, annual emissions could be determined assuming that the fugitive emissions 

were continuous from the beginning of the reporting period or from the last recorded not 

leaking in the current reporting period and until the fugitive emissions is repaired or the end 

of the reporting period. 

(b) There are potentially hundreds (and in some cases) thousands of emissions sources in a 

facility. Typically, from practical experience in the Natural Gas STAR Program 10 percent of 

the potential emissions sources have been found to be emitting the large majority of the 

emissions. Reporting of such large numbers of emissions estimates may not be practical. One 

way to minimize the reporting burden would be to have facilities report emissions at the 

individual source type level, i.e. emissions from each source type can be reported in the 

aggregate. For example, a facility with multiple reciprocating compressors may report 

emissions from all reciprocating compressors as an aggregate number. The disadvantage to 

this approach would be that there would not be a distinction in the reported data between 

vented emissions and fugitive emissions. Although such distinctions may be of interest to the 

reporter, as different mitigation opportunities may exist for intentional and unintentional 

releases, it may not be necessary for the integrity of a reporting program, and therefore 

aggregate reporting may be sufficient. 

(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. 

(d) 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. 

 

10 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 69
Background Technical Support Document – Petroleum and Natural Gas Industry 70

(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. 

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 fugitive 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). 
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 can be included in the proposed 

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 Fugitive and Vented Emissions from Each Sector 

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

Background Technical Support Document – Petroleum and Natural Gas Industry 71
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

Me

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 WellsNon-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 0Heaters 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 0Small 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 CompletionCompletion 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 OperationsPneumatic 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 VentsCondensate 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 VentedGas Engines 11,680 4,718,728 9% 3%

Well WorkoversGas 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 

BlowdownsVessel 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 UpsetsPressure 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

Dire

Measur

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 
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. 
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)11. 

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. 

994,19 wells + ( ) × ( 600,35%50 wells − 994,19 wells) = 797,27 wells

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 

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 

 

11 EPA. U.S. Inventory of Greenhouse Gas Emissions and Sinks: 1990 – 2007. Available online at: 

<http://epa.gov/climatechange/emissions/usgginv_archive.html>. 

79
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. 

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)12 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 

GasWells

GasWells ConventionalWorkovers ConventionalWorkovers

1992

2007 2007 = 1992 ×

wells

wells ConventionalWorkovers workovers

014,276

035,431 2007 = 324,9 ×

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 

2007 Conventional 

Well Workovers × = wells

wells workovers

014,276

035,431 324,9 14,569 

2007 Unconventional 

Well Workovers × 790,41%10 wells = 4,179 

►Estimate the Emission Factor for Conventional Well Completions 

 

12 GRI. Methane Emissions from the Natural Gas Industry. 1996. Available online at: 

<http://epa.gov/gasstar/tools/related.html>. 

80
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 completions 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 presentation13 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 Handbook14 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-year11)approximately 5,188 low-pressure wells 

emitted 0.3 Bcf . 

Bcf scf

Bcf

well

scf wells 3.0

10

1570,49 971,12%40 9 × × ≈×

 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. 

Mcf completion Bcf

Mcf

wells

Bcf /000,6 10

971,12%60

7.44 6

≈×

×

The same Natural Gas STAR presentation12 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 

 

13 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>. 

14 API. Basic Petroleum Data Handbook. Volume XXIV, Number 1. February, 2004. 

81
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 presentation12 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 presentation15 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 Results: 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 

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 

 

15 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>. 

82
The final U.S. emissions were rounded to 120 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 study16. 

The equation is displayed in Exhibit B-6. 

Exhibit B-6. Well Blowdown Emissions for Liquid Unloading 

Vv = ( ) ×××× PhD − 26 0 1037.

where, 

 Vv = Vent volume (Mcf/blowdown) 

D = casing diameter (inches) 

h = well depth (feet) 

P = shut-in pressure (psig) 

A combination of GASIS17 and LASSER18 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. 

 

16 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>. 17 DOE. GASIS, Gas Information System. Release 2 – June 1999. 18 LASSERTM database. 

83
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 basin19. Using the 

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 Piney16. 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 basin20, the 

concentration of gas wells in tight formations by basin21, and the concentration of coal bed 

methane gas wells by basin22. 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 inventory23. estimated that there were 389,245 conventional gas wells in 2007. The 

 

19 EPA. Natural Gas STAR Partner Update: Spring 2004. Available online at: 

<http://epa.gov/gasstar/documents/partner-updates/spring2004.pdf>. 20 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>. 

21 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>. 

22 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>. 

23 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2006. Available online at 

http://www.epa.gov/climatechange/emissions/usinventoryreport.html. 

84
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. 

This estimate does not include emission reductions from control methods such as plunger 

lifts, plunger lifts with “smart” automation, or other artificial lift techniques.

85
Appendix C: Development of threshold analysis 

As the main text has pointed out the oil and natural gas sector includes hundreds, and in 

some cases thousands, of players, many of them with few emission sources as well as 

ones with over 160 emission sources. Requiring all participants 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 

oil and natural gas production segment 

 

• Threshold analysis for onshore (including EOR) production sector was estimated per 

unique operator per basin. 

• The oil and gas production volumes per operator per basin were obtained from the 

LASSERTM 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: 

well completions, well unloading, and well clean-ups. 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 and 

flares as estimated in the U.S. GHG Inventory were included for the threshold 

analysis. These sources also have Natural Gas STAR reductions that are higher than 

the emissions estimates in the inventory. However, though these source emissions 

estimates were included, no new estimates were developed for lack of publicly 

available data. 

• 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 10o

F 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, 

86
obtained from the EPA’s Lesson Learned 2006, Replacing Gycol 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. 

• 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 vented, fugitive 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 

87
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 

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 

88
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 operators 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 

Threshold Analysis for Offshore Production

• Federal GOM offshore platforms, by their complex ID, and their corresponding CO2

combustion and fugitive emissions (CO2e), CH4 fugitive emissions (CO2e), CH4

vented emissions (CO2e), and N2O combusted emissions (CO2e) for the year 2000 

was obtained from the MMS 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 

MMS 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 al24 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 

 

24 http://www.icess.ucsb.edu/iog/pubs/DrifterSimulationsFinal_v5.pdf 

89
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 fugitive, vented and combustion emissions were estimated by 

applying the ratio of state to federal platforms and multiplying it by the federal 

offshore fugitive, 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 fugitive, 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 

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 degassing seals was obtained from Bylin et al25.

• 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 

 

25 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> 

90
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 

reported to FERC Form 226, 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, EPA28) to 

interstate station design throughput capacity (MMcfd, FERC27) 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 

 

26 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>. 

91
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, EPA28) to 

interstate station design throughput capacity (MMcfd, FERC27) 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 fugitive methane and non-energy CO2, 

were estimated in the U.S. GHG Inventory. These total fugitive and vented emissions 

were allocated to each facility based on its portion of the segment’s total station 

throughput capacity, as shown in the following equation: 

Station “i” process emissions = TotalInventoryEmissions

StationCapacity

StationCapacity

i

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-17627. 

 

27 EIA. EIA-176 Query System. Available online at: 

<http://www.eia.doe.gov/oil_gas/natural_gas/applications/eia176query_historical.html>. 

92
• 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: 

Compressor energyi (MMHphr) = TotalSegmentMMHphr MaximumDailyDelivery

MaximumDailyDelivery

i

i ×

∑

Where, index “i” denotes an individual facility 

• The total process emissions for 2006, both vented and fugitive methane and nonenergy 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. 

93
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 ICF 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 ICF 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” 

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: 

LEU = 

Hphr

MMHphr days dayhours

MMcfd

Hp

days

MMcf

000,000,1

1 200 %50 24

1

750

200

706,38 ×××××

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: 

Facility “i” liquefaction MMHphr = TotalSegmentMMHphr LC

LC

i

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: 

94
FBEUi = 

Hphr

MMHphr

day

hours days MMcfdHp

days

SCi

000,000,1

24 365 750

365

%05.0

×⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

×× ×

×

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. EIA28 provides that in 

2006, total LNG withdrawals were 33,743 MMcf. The send-out compressor energy 

use by all peak shaving plants in the segment was calculated using the following 

equation: 

Total send-out energy use = %6.89 86.1

365

743,33 × ×

MMcfd

MMHphr

days

MMcf

• 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 fugitive methane and nonenergy 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) 

 

28 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>. 

95
• The total emissions for each facility were calculated by summing the calculated 

fugitive, 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 

• “Facility” in the LNG import segment is defined as the import terminals. Data is 

available for this on the FERC website29. 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: 

FBEUi = 

Hphr

MMHphr

day

hours days MMcfdHp

days

IVi

000,000,1

24 365 750

365

%05.0

×⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

×× ×

×

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 

 

29 FERC. Import Terminals. Available online at: <http://www.ferc.gov/industries/lng.asp>. 

96
compression, satellite facilities require 1.86 MMHphr for each MMcfd of send-out. 

The following equation estimates the energy use at each facility: 

Facility “i” send-out energy use = MMcfd

MMHphr

days

IVi 86.1

365

×

• The total process emissions for 2006, both vented and fugitive methane and nonenergy 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: 

Facility “i” process emissions = InventorySegmentEmissions

IV

IV

i

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 

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)30 provides a set of data 

that contains distribution main pipelines miles by pipeline materials and distribution 

service counts by pipeline material for each LDC. 

• Fugitive CO2 and CH4 emissions 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 Inventory.

 

30 DOT. 2006 Distribution Annuals Data. Available online at: 

<http://www.phmsa.dot.gov/pipeline/library/data-stats>. 

97
Exhibit C-8: LDC’s Fugitive Emissions Emission Factor

Pipeline Type/Material Fugitive GHG 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 fugitive methane and non-energy CO2, were estimated by EPA 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: 

Facility “i” M&R emissions = InventorySegmentEmissions

MM

MM

i

i ×

∑

where, 

 MM = total miles of mains pipeline, and “i” represents individual 

facilities 

• There are no combustion emissions from the LDCs covered in the rule. 

• The total emissions for each facility were calculated by summing the calculated 

pipeline fugitives and M&R station 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. 

98
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. There are no definitions currently for the 

production sector in the initial rule proposal. 

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 Master31 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 

 

31 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 

99
referenced to County boundaries. The United States Geological Survey (USGS) 

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. 

Petroleum and natural gas production companies are identified uniquely by the Internal 

Revenue System (IRS). Also, the CAA defines the ‘‘owner or operator’’ as meaning any 

person who owns, leases, operates, controls, or supervises a stationary source. In general, 

operational control for a facility means the authority to introduce and implement 

operating, environmental, health and safety policies, and therefore would be the entity 

who potentially reports under the rule. In circumstances where this authority is shared 

among multiple entities, the entity holding the permit to operate from the local air 

pollution control district or air quality management district is considered to have 

operational control. 

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 

100
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 

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 

fugitive emissions as well as the combustion emissions from compressors. 

 

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. 

101
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. 

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 

102
Appendix E: Analysis of potential facility definitions for local distribution 

companies 

The purpose of this appendix is to investigate options for defining reporting facilities within 

the local distribution sector as well as discuss emissions sources to be reported and the 

associated coverage. 

A. Issue Identification and Clarification 

i. LDC Facility Definition: A potential parallel for defining the distribution sector 

for the GHG Reporting rule is adapting the definition available from Section NN 

of the Final Mandatory Reporting Rule (MRR) published on September 22, 2009.

The Clean Air Act (CAA) does not put forth any definition for a facility in the 

natural gas distribution sector. This is to be expected as there are few sources of 

hazardous air pollutants in the natural gas distribution sector; the primary 

stationary emissions from this sector are fugitive and vented methane emissions. 

Only Section 112 (n) (4) (A) mentions natural gas pipeline facilities within the 

CAA and it states that emissions from compressor or pump stations shall not be 

aggregated with other units to determine whether they are major sources. As there 

are no compressor stations or pump stations within local natural gas distribution 

systems, this would potentially not effect any facility definition. 

In developing an appropriate definition for a reporting entity within the local 

natural gas distribution sector, a number of sources were examined to determine if 

there are any existing facility definitions in use. The Pipeline and Hazardous 

Materials Safety Administration (PHMSA) in the Department of Transportation 

collects data from the distribution sector on pipeline incidents and mileage. CFR 

Title 49 Section 191.1132 requires that “each operator of a distribution pipeline 

system shall submit an annual report for that system”. Section 191.3 defines a 

pipeline system as: 

Pipeline or Pipeline System means all parts of those physical 

facilities through which gas moves in transportation, including, 

but not limited to, pipe, valves, and other appurtenance 

attached to pipe, compressor units, metering stations, regulator 

stations, delivery stations, holders, and fabricated assemblies. 

Data on pipeline mileage, number of services, leaks, and other incidents is 

reported to the PHMSA by individual LDCs. Larger holding companies that 

operate distribution systems in different areas do not report as one large entity; 

each system reports separate data to the PHMSA. 

 

32 Code of Federal Regulations Title 49. “Transportation of Natural and Other Gas By Pipeline; Annual Reports, 

Incident Reports, and Safety-Related Condition Reports.” Available online at 

http://www.access.gpo.gov/nara/cfr/waisidx_02/49cfr191_02.html 

103
The Climate Registry supports a voluntary GHG emissions reporting system in 

North America. The Climate Registry proposes that “For purposes of reporting, 

each pipeline, pipeline system, or electricity T&D system should be treated as a 

single facility”33. This definition indicates that an entire distribution system 

operated by an LDC would report GHG emissions as one entity to The Climate 

Registry. 

The final MRR requires that all LDCs report CO2 emissions which would result 

from the complete combustion of natural gas delivered to end users. The rule 

defines LDCs as: 

Local Distribution Companies are companies that own or 

operate distribution pipelines, not interstate pipelines or 

intrastate pipelines, that physically deliver natural gas to end 

users and that are regulated as separate operating companies 

by State public utility commissions or that operate as 

independent municipally-owned distribution systems. 

These various sources imply that LDCs are accustomed to reporting data from the 

pipeline systems that they operate. If GHG emissions from the natural gas 

distribution sector are required to be reported, it would be easiest to have 

emissions reported at the LDC level as this is consistent with the final MRR as 

well as other data reporting mechanisms. It is important to note that often one 

company may own several LDCs under different names. In such a case, it is 

important to determine at what level the company has to report. 

B. Evaluation Criteria and Approach 

i. Qualitative Analysis 

A qualitative evaluation below provides a discussion on the advantages and 

disadvantages of using a LDC reporting level definition, using the following 

criteria; 

1) Boundary limitations. 

As some holding companies operate multiple LDCs, often in close proximity, 

it may be difficult to define distinct boundaries between the systems that do 

not double-count or under-count GHG emissions. The data collected by the 

PHMSA appears to have addressed boundary issues for these large holding 

companies. The boundary specifications used by LDCs to report to the 

PHMSA can be potentially used to eliminate any confusion in the boundaries 

between LDCs owned by the same holding company. 

 

33 The Climate Registry. “General Reporting Protocol”. Page 38. Available online at 

http://www.theclimateregistry.org/downloads/GRP.pdf 

104
Another issue that needs to be addressed for the boundary definition is DOT’s 

definition of distribution pipelines versus transmission pipelines. In some 

cases, pipelines operated by LDCs are considered transmission pipelines 

rather than distribution pipelines. CFR Title 49 §192.5 provides the definition 

of a transmission line which can cover certain pipelines that are operated by 

an LDC. For example, a large company may operate a length of pipeline that 

delivers natural gas from an interstate transmission line to their distribution 

center. Along that length of pipeline there may be individual farm taps or 

industrial customers that pull gas directly from the transmission line with their 

own regulator to step down pressure. Because these end-users are not part of 

the distribution system, the initial rule proposal would need to clarify if any 

emissions from the equipment used to step down pressure and meter gas going 

to these customers would fall under the distribution sector or transmission 

sector. 

2) Ease of practical application of definition. 

Annual reports collected by the Pipeline and Hazardous Materials Safety 

Administration (PHMSA) demonstrate that the definition of a distribution 

pipeline system can be applied to the industry to achieve nationwide data 

reporting. 

3) Coverage that can be expected from LDC facility definition type. 

Defining a distribution pipeline system as a reporting entity in an equivalent 

fashion as in CFR Title 49 191.3 should include all distribution operations as 

tracked in the U.S. GHG Inventory. The number of entities that trigger the 

reporting threshold will depend largely upon the size of the system. A topdown estimate of fugitive emissions from LDCs based on both LDC data 

tracked by the PHMSA, as well as on emission factors from the Inventory of 

US Greenhouse Gas Emissions and Sinks34, indicates that 11% of LDCs 

would emit fugitive emissions in excess of the 25,000 metric tons CO2e 

threshold. Emissions from these LDCs would make up over 90% of fugitive 

emissions from all sources in the natural gas distribution sector. 

C. Data Sources for Research 

i. US Methane Emissions Inventory 

ii. CAA 

iii. NAICS definitions - 221210 Natural Gas Distribution 

iv. Office of Pipeline Safety 

v. Pipeline and Gas Journal 

 

34 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2006. Available online at 

http://www.epa.gov/climatechange/emissions/usinventoryreport.html. 

105
Appendix F: Analysis of Definition Options for Natural Gas Production 

Gathering Pipelines for Emissions Reporting 

The purpose of this appendix is to identify issues resulting from defining gathering pipelines 

as an independent reporting segment for the rule. 

A. Issue Identification and Clarification 

The initial rule proposal did not require emissions from natural gas production gathering 

pipelines to be reported. Natural gas production gathering pipelines cannot easily be 

classified into facilities as they are made up of a network of pipelines. The options for 

gathering pipelines are to include these facilities in either the Onshore Production sector, 

the Gas Processing sector, a new segment, or exclude them from reporting. 

i. Natural Gas Gathering Pipeline Facility Definition: 

From the wellhead, natural gas is transported to processing plants or natural gas 

transmission pipelines through a network of small-diameter, low-pressure 

gathering pipelines. A complex gathering system can consist of thousands of 

miles of pipes, interconnecting the processing plant to upwards of 100 wells in the 

area. The Department of Transportation (DOT), Pipeline and Hazardous 

Materials Safety Administration (PHMSA) statistics show that there were 

approximately 12,477 miles of onshore and 7095 miles of offshore gas gathering 

pipeline in the U. S. in 2007. This is a fraction of the total gathering pipeline 

mileage because only the mileage closest to human habitation that can pose a 

safety risk is reported to and regulated by PHMSA. Gathering pipelines may be 

owned by the producer or the processing plant, or the affiliate of a pipeline 

company or an independent gathering business. A fee is charged for the service 

and the fees are negotiated between the producer and the gathering pipeline. 

Gathering systems may report to federal land management agencies and state land 

use agencies primarily for safety and permitting purposes. They must file reports 

with the PHMSA, Office of Pipeline Safety (OPS). These reports are relative to 

silting, routing, and safety issues. 

The PHMSA collects data from the gathering pipeline sector on pipeline incidents 

and mileage under CFR Title 49 Section 191.171

 which requires each operator of 

a gathering pipeline system to submit an annual report: 

(a) Except as provided in paragraph (b) of this section, each 

operator of a transmission or a gathering pipeline system shall 

submit an annual report for that system on Department of 

 

1

 Code of Federal Regulations Title 49. “Transportation of Natural and Other Gas By Pipeline; Annual Reports, 

Incident Reports, and Safety-Related Condition Reports.” Available online at 

http://www.access.gpo.gov/nara/cfr/waisidx_02/49cfr191_02.html 

106
Transportation Form RSPA 7100.2–1. This report must be 

submitted each year, not later than March 15, for the preceding 

calendar year. 

Title 49CFR Part 192.3 defines a gathering pipeline as follows: 

Gathering line means a pipeline that transports gas from a current 

production facility to a transmission line or main. 

The PHMSA regulations for gas gathering pipelines incorporate an industry 

standard prepared by the American Petroleum Institute (API RP 80) to better 

define which portions of the natural gas pipeline network are considered 

“gathering” pipelines. This includes how a pipeline operator must determine 

which of its gas gathering pipelines are subject to regulation, i.e., which are 

“regulated gathering lines.” This is done using criteria that determine when a gas 

gathering pipeline is close enough to a number of homes, or to areas/buildings 

where people congregate, that an accident on the pipeline could impact them. 

Offshore gas gathering pipelines and high-pressure onshore lines meeting these 

criteria must meet all requirements of 49 CFR Part 192 applicable to gas 

transmission pipelines. Onshore gas gathering pipelines that operate at lower 

pressures must comply with a subset of these requirements specified in 49 CFR 

192.9. 

Title 49CFR Part 191.15 for transmission and gathering systems incident reports 

states: 

(a) Except as provided in paragraph (c) of this section, each 

operator of a transmission or a gathering pipeline system shall 

submit Department of Transportation Form RSPA F 7100.2 as 

soon as practicable but not more than 30 days after detection of an 

incident required to be reported under §191.5. 

Title 49CFR Part 191.3 defines an incident as follows: 

Incident means any of the following events:(1) An event that 

involves a release of gas from a pipeline or of liquefied natural gas 

or gas from an LNG facility and (i) A death, or personal injury 

necessitating in-patient hospitalization; or (ii) Estimated property 

damage, including cost of gas lost, of the operator or others, or 

both, of $50,000 or more. 

Under section 7 of the Natural Gas Act, FERC reviews applications for the 

construction and operation of natural gas pipelines. In its application review, 

FERC ensures that the applicant has certified that it will comply with Department 

of Transportation safety standards. FERC has no jurisdiction over pipeline safety 

or security, but actively works with other agencies with safety and security 

responsibilities. 

107
The Clean Air Act (CAA) does not put forth any definition for a facility in the 

natural gas gathering pipeline sector. This is to be expected as there are few 

sources of hazardous air pollutants in the natural gas gathering pipeline sector; the 

primary stationary emissions from this sector are fugitive and vented methane 

emissions. Only Section 112 (4) (A) mentions natural gas pipeline facilities within 

the CAA 

(4) OIL AND GAS WELLS; PIPELINE FACILITIES.— 

(A) Notwithstanding the provisions of subsection (a), emissions from any 

oil or gas exploration or production well (with its associated equipment) 

and emissions from any pipeline compressor or pump station shall not be 

aggregated with emissions from other similar units, whether or not such 

units are in a contiguous area or under common control, to determine 

whether such units or stations are major sources, and in the case of any 

oil or gas exploration or production well (with its associated equipment), 

such emissions shall not be aggregated for any purpose under this 

section. 

The Climate Registry supports a voluntary GHG emissions reporting system in 

North America. The Climate Registry proposes that “For purposes of reporting, 

each pipeline, pipeline system, or electricity T&D system should be treated as a 

single facility”35. This definition indicates that an entire gathering pipeline system 

operated by a company would report GHG emissions as one entity to The Climate 

Registry. 

These various sources imply that companies are accustomed to reporting data 

from the gathering pipeline systems that they operate. If GHG emissions from the 

natural gas gathering pipeline segment were included, it could be most 

straightforward to have emissions reported at the pipeline company level as this is 

consistent with the PHMSA reporting. 

B. Data Sources Referenced 

i. US Methane Emissions Inventory

ii. CAA

iii. Office of Pipeline Safety

iv. Energy Information Administration

v. Gas Research Institute (GRI) Well workover assumptions in the study Methane 

Emissions from the Natural Gas Industry.

 

35 The Climate Registry. “General Reporting Protocol”. Page 38. Available online at 

http://www.theclimateregistry.org/downloads/GRP.pdf 

108
Appendix G: Accounting for Inaccessible Emissions Sources 

The purpose of this appendix is to evaluate options for ensuring comprehensive fugitive and 

vented emissions detection and measurement of all potential sources, focusing on 

accessibility issues of potential sources of fugitive methane emissions. Part 1 identifies and 

discusses comprehensiveness issues. Part 2 discusses how to evaluate those issues. Part 3 

identifies other resources pertaining to the issue, and part 4 provides a summary. 

Inaccessible emission sources includes those potentially emitting components which are 

either unsafe to monitor, or physically out of reach, or visually hidden. Physically out of 

reach emission sources means those components which are not within arms reach when using 

a portable VOC detection instrument. Visually hidden emission sources are those that cannot 

be viewed with a optical imaging instrument due to blockage from other equipment or 

components. Unsafe-to-monitor emission sources are those described in the regulations 

discussed below. 

A. Review of Current Provisions Pertaining to Inaccessibility 

Inaccessible components and comprehensiveness of leak surveys are addressed in current 

EPA volatile organic compound (VOC) regulations. Method 21 provides general 

language about adhering to safety practices. 

i. 40 CFR 60 Appendices: Method 21 

5.0 Safety 

5.1 Disclaimer. This method may involve hazardous materials, 

operations, and equipment. This test method may not address all of 

the safety problems associated with its use. It is the responsibility 

of the user of this test method to establish appropriate safety and 

health practices and determine the applicability of regulatory 

limitations prior to performing this test method. 

40 CFR 60 Subpart VV covers leak inspections of components and is referenced 

by subpart KKK for onshore natural gas processing plants. Subpart VV does not 

discuss equipment as inaccessible but as difficult or unsafe-to-monitor. Unsafe-tomonitor equipment means that the equipment must expose monitoring personnel 

to immediate danger as a consequence of complying with performance standards. 

For equipment deemed as such, an explanation is required by the operator and a 

plan must be developed for future monitoring when the equipment is safe to 

monitor. Inaccessible equipment includes those that are unsafe-to-monitor; 

however, the provisions mentioned above only apply to pumps, valves, and 

connectors. 

ii. 40 CFR 63 Subpart UU 

109
(e) Special provisions for connectors —(1) Unsafe-to-monitor connectors. Any 

connector that is designated, as described in §63.1022(c)(1), as an unsafe-tomonitor connector is exempt from the requirements of paragraphs (a) and (b) of 

this section and the owner or operator shall monitor according to the written plan 

specified in §63.1022(c)(4). 

2) Inaccessible, ceramic, or ceramic-lined connectors. (i) Any connector that is 

inaccessible or that is ceramic or ceramic-lined (e.g., porcelain, glass, or glasslined), is exempt from the monitoring requirements of paragraphs (a) and (b) of 

this section, from the leak repair requirements of paragraph (d) of this section, 

and from the recordkeeping and reporting requirements of §§63.1038 and 

63.1039. An inaccessible connector is one that meets any of the provisions 

specified in paragraphs (e)(2)(i)(A) through (e)(2)(i)(F) of this section, as 

applicable. 

(A) Buried; 

(B) Insulated in a manner that prevents access to the connector by a monitor 

probe; 

(C) Obstructed by equipment or piping that prevents access to the connector by a 

monitor probe; 

(D) Unable to be reached from a wheeled scissor-lift or hydraulic-type scaffold 

that would allow access to connectors up to 7.6 meters (25 feet) above the 

ground. 

(E) Inaccessible because it would require elevating the monitoring personnel 

more than 2 meters (7 feet) above a permanent support surface or would require 

the erection of scaffold; 

(F) Not able to be accessed at any time in a safe manner to perform monitoring. 

Unsafe access includes, but is not limited to, the use of a wheeled scissor-lift on 

unstable or uneven terrain, the use of a motorized man-lift basket in areas where 

an ignition potential exists, or access would require near proximity to hazards 

such as electrical lines, or would risk damage to equipment. 

(ii) If any inaccessible, ceramic or ceramic-lined connector is observed by visual, 

audible, olfactory, or other means to be leaking, the visual, audible, olfactory, or 

other indications of a leak to the atmosphere shall be eliminated as soon as 

practical.

Based on a review of this existing HAP LDAR regulatory language, from 40 CFR 

Part 63 Subpart UU, many accessibility issues are addressed. Inaccessible 

connectors are described above as either buried, insulated in a manner that 

prevents access to the connector by a monitor probe, obstructed by equipment or 

110
piping that prevents access to the connector by a monitor probe, or unable to be 

reached from an permanent support surface. This definition of inaccessible can 

potentially be applied to all components for leak detection. 

The safety conditions outlined in the Clean Air Act and Method 21 may result in a 

portion of fugitive methane emissions to be excluded from required monitoring, 

due to safety and physical inaccessibility concerns in measurement. However, 

these conditions are most common within processing facilities where there are a 

large number of equipment in close proximity, as well as equipment that deal 

with hot and cold process streams that may be a safety concern. This is not 

necessarily the case for the other sectors in the oil and natural gas industry such as 

onshore production, transmission, and distribution where methane streams are not 

necessarily a safety concern. The number of emission sources excluded for safety 

reasons in the other oil and natural gas sectors are most likely less than that from 

processing because of the relative simplicity of their operations. Since the entire 

natural gas industry is within the scope of the rule, those leaks or measurements 

unaccounted for due to safety could be insignificant. 

B. Potential methods to account for inaccessible components 

i. Remote detection applicability – Distance, field of view, wind speed, and 

subjectivity of individual instrument technicians are among several factors that 

affect applicability to inaccessible components. A remote detection instrument is 

a device that can detect emissions without using a probe at a component’s surface. 

1) Distance. Fugitive methane emissions detection instruments of the remote 

sensing type can accommodate screening of many components that are 

inaccessible. Components must first be within the working distance of the 

remote sensing instrument. One study36 found that handheld remote sensing 

instruments can detect fugitive emissions from a 30-foot distance or closer. 

The study reports that the actual distance will depend, in part, on the specific 

instrument model: for example, a passive optical imaging instrument will have 

a maximum stated distance of “hundreds of feet”, while an active remote leak 

detection instrument will indicate a maximum distance of about 100 feet. The 

effective distance of a remote sensing instrument will vary depending on a 

number of parameters, many of which will be specific to the individual 

facility or even the individual component being surveyed. The parameters that 

affect leak detection performance include minimum detection limit, type of 

lens, wind speed, field of view, and the ambient and gas temperatures. For 

example, an instrument may detect a leak of a certain magnitude from a 

certain vantage point but not detect the same leak from a different vantage 

point where the view is obstructed or if sustained wind speeds increase. 

 

36 Implementing Directed Inspection & Maintenance with a Focus on Infrared Remote Screening. Draft 

document. EPA Natural Gas STAR 

111
The Alternative Work Practice (AWP) to Method 21 monitoring for 40 CFR 

Parts 60, 61, 63, and 65 in a VOC leak detection and repair program 

developed regulations to help ensure such standardization. Under the AWP, 

each monitoring session must begin with a “Daily Instrument Check”–a 

calibration test by releasing the known hydrocarbon of interest at the 

calculated mass flow rate and confirming detection is possible at the 

maximum distance from the component to the instrument that is to be tested 

during the monitoring session. 

40 CFR 60 Subpart A [60.18(i)(2)] 

(B) Set up the optical gas imaging instrument at a recorded 

distance from the outlet or leak orifice of the flow meter that will 

not be exceeded in the actual performance of the leak survey. 

(v) Repeat the procedures specified in paragraphs (i)(2)(ii) 

through (i)(2)(iv) of this section for each configuration of the 

optical gas imaging instrument used during the leak survey. 

This calibration test aims to control the parameters of performance and 

ensures that an inaccessible component can be screened successfully at a 

distance—except if the hydrocarbon cannot be detected during the calibration 

test. The practical effect of this test is that facilities with great distances 

between the feasible inspection point and the component may be at a 

disadvantage to those facilities with smaller distances for implementing 

remote sensing inspections if the greater distance is sufficiently large to 

prevent leak detection by the instrument. The AWP has provisions that can 

reduce this potential advantage/disadvantage scenario. The AWP reinforces 

the idea that monitoring has two components, 1) detection to determine mass 

flow rates that can be imaged, and 2) survey frequency. More frequent 

surveys could result in more opportunities to identify new occurrences of 

fugitives. Less frequent surveys could result in fewer opportunities to identify 

new occurring fugitives. Therefore, if a remote sensing instrument cannot 

detect emissions at a certain flow rate because of a large distance, there is the 

potential to increase the monitoring frequency and then monitor for a smaller 

size leak more frequently. 

2) Field of View. Another performance factor for remote sensing instruments 

that specifically affects monitoring of inaccessible components is the field of 

view. Either the background behind a component or any obstructions to view 

in front of the component can prohibit successful monitoring. The 

background is important for active remote sensing instruments that operate by 

generating a signal and then detecting emissions based on the reflected signal 

strength to determine if a hydrocarbon gas is within the signal path. These 

active instruments therefore require a suitable reflective background for any 

component being monitored. Facilities with inaccessible components already 

situated with such backgrounds may have a monitoring advantage with active 

112
instruments over facilities with elevated components and no such 

backgrounds. For a voluntary effort to detect, measure, and repair methane 

leaks, one natural gas transmission operator has affixed metal plates behind 

elevated open-ended lines (a minimal facility modification) to allow 

inspection from the ground with active remote sensing instruments. 

For the passive type of remote sensing instruments, background is a contrast 

issue to ensure that a gas plume can be detected by the instrument operator. A 

wall, vessel, or collection of piping often provides the necessary contrast. 

Inspecting the component against the sky may result in the ability to detect 

larger leaks. For this reason, the calibration test required by the AWP could 

be more prescriptive in matching the background requirements to the 

conditions to be encountered during monitoring to ensure consistent 

monitoring practices from facility to facility. 

Obstructions between the remote sensing instrument and the component will 

prevent leak inspection. For some components this may be remedied by 

inspecting the elevated component from a different vantage point, but for 

other components the obstruction of view may prevent an operator from using 

remote sensing for that component. Other components such as flanges on top 

of large vertical vessels may not offer a clear field of view for remote sensing, 

requiring a lift or other equipment to achieve a suitable viewing location for 

remote sensing. Applicability of remote sensing for inaccessible component 

inspection can therefore vary from facility to facility depending on the field of 

view. 

Use of an optical imaging instrument is also a field of view issue, and specific 

issues to consider are viewing for a sufficient length of time and ambient 

lighting conditions. Use of a camera by quickly panning through a large 

number of components is not sufficient to identify leaks or attribute leaks to a 

specific component. Since optical imaging instruments depend on the 

ambient IR radiation or IR radiation produced by indoor lighting, monitoring 

may not be possible during the night or without a light source, and the video 

image produced by a camera can be blank or difficult to interpret. The 

Method 21 AWP language appears to cover reasonable use of an IR camera 

by requiring video recordings and with instruments use specifications. 

The AWP requires that video recordings of monitoring be kept and that the 

video must clearly show the regulated components, which can help determine 

reasonable camera use. 

40 CFR 60 Subpart A [60.18(h)(3)] 

(vi) Recordkeeping requirements in the applicable subpart. A video 

record must be used to document the leak survey results. The video 

record must include a time and date stamp for each monitoring 

event. A video record can be used to meet the recordkeeping 

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requirements of the applicable subparts if each piece of regulated 

equipment selected for this work practice can be identified in the 

video record. The video record must be kept for 5 years. 

The AWP also specifies that the instrument must give the operator a clear 

view of each component, though the AWP does not otherwise specific a 

sufficient length of viewing time. 

40 CFR 63 Subpart A [60.18(i)]

(1) Instrument Specifications. The optical gas imaging instrument 

must comply with the requirements specified in paragraphs 

(e)(1)(i) and (e)(1)(ii) of this section. 

(i) Provide the operator with an image of the potential leak points 

for each piece of equipment at both the detection sensitivity level 

and within the distance used in the daily instrument check 

described in paragraph (e)(2) of this section. 

3) Wind Speed. Wind speed also affects applicability of remote sensing devices 

to inspecting inaccessible components. Increased wind speed will disperse a 

leak plume more quickly and make a leak more difficult to detect. Sustained 

wind speeds further decrease detection ability since intermittent wind allows 

leaks to accumulate before being dispersed by wind. Components at ground 

level or that are otherwise accessible may be shielded from components that 

are elevated above surrounding buildings or equipment. Remote sensing 

instruments may still be applicable in cases where components are subject to 

higher wind speeds, but this applicability may be incorporated into a more 

prescriptive calibration test for the instrument. Given the inaccessible nature 

of the elevated components, it may be difficult to ascertain or measure the 

wind conditions at the component, though measuring wind speed or 

conducting the calibration test in an open, nearby area may be a reasonable 

surrogate for wind conditions at the component. 

4) Subjectivity of Individual Instrument Technicians. Some remote sensing 

devices display a numerical value or audible alarm upon detection of fugitive 

emissions, while others display a video representation of the field of view and 

rely on the instrument technician to make the determination for if a 

component is leaking. The visual interpretation and judgment of an individual 

therefore introduces some subjectivity into monitoring elevated components 

with remote sensing. This subjectivity is an issue at the minimum detection 

level rather than for large leaks which are obvious due to plume size and 

motion of the plume. Subjectivity is also minimized with an AWP calibration 

test ensuring the technician can identify a specified minimum flow rate. A 

disadvantage of this calibration test is that in the test an individual would be 

viewing a specific component at a large distance to discern the presence of a 

leak, however, discerning leaks in the field amongst many components in the 

same frame of reference could be challenging. As a result, the individual may 

114
be able to discern a very small leak during the calibration test but not discern 

as small a leak during the actual survey. Though this subjectivity affects 

comprehensiveness of leak detection for elevated/inaccessible components, 

this is primarily a performance standard issue. If however, the survey was 

conducted in the same manner as Method 21 specifies for portable VOC 

monitoring devices, surveying each component individually, the subjectivity 

can be minimized. 

ii. Non-optical detection applicability – Leak detection instruments that require close 

proximity or contact with components (such as electronic screening, flame 

ionization detectors, toxic vapor analyzers, and organic vapor analyzers) are 

applicable to components that are inaccessible if resources are spent to gain 

access. Methods to gain access include: 

1) temporary use of a portable ladder, 

2) wearing harnesses or other applicable fall protection equipment to comply 

with safety regulations, 

3) temporary use of a bucket truck or other lift, 

4) facility modification to either create access to the component or relocate 

the component to an accessible area 

5) use of a self contained breathing apparatus, and 

6) excavation of buried components. 

A comprehensive leak survey covering all inaccessible components therefore 

would require additional labor costs and potentially additional capital or lease 

costs for specialized equipment. 

Hot-wire anemometers may be a niche solution for some inaccessible OELs. 

These quantification instruments operate by inserting a probe into a hole bored 

into a vent stack. Using such a device for leak inspections could eliminate the 

need for lifts to reach the top of some OELs. 

iii. Measurement applicability – all measurement instruments appropriate for a leak 

detection and measurement reporting rule require contact with or close proximity 

to the leaking component. 

1) High Volume Samplers capture a leak for measurement using a hose, 

requiring the hose to be in contact with or within several inches of the 

component. The instrument can typically be mounted on a backpack for use 

when standing on a ladder or other positions where the technician has limited 

mobility or requires the use of hands and arms for balance and for directing 

the leak into the instrument using the hose attachments. 

2) The enclosure method involves constructing a tent around a leaking 

component, passing a known volume of inert gas through the tent, and 

collecting the flow out to determine mass emissions. This method is timeconsuming, requiring about 30 minutes per enclosure and requiring ample 

115
access to the area surrounding the component to construct the enclosure. 

Inaccessible components such as elevated OELs are not suitable candidates 

for the enclosure method given that no other components are typically near the 

OEL which can support the enclosure. This method is time-consuming on the 

ground and will encounter construction difficulties when in an elevated, 

inaccessible position, and for these reasons it is unlikely that the enclosure 

method is practical for a large-scale monitoring program or applicable to 

inaccessible elevated components. 

3) The calibrated bag method uses a bag of a known volume constructed of antistatic materials plus a stopwatch to measure emissions. This measurement 

method involved some technique and training so that a technician places the 

bag over a leak source to capture all of the flow, ensures the bag unfurls 

correctly, and ensure that full inflation is achieved rather than bursting the bag 

or under-inflating it. The technique just described means that a technician 

requires both hands and arms to be free for the measurement rather than in use 

holding onto a ladder or railing. Calibrated bags are a measurement method 

applicable to inaccessibly high components, but additional resources such as a 

lift may be necessary. 

4) Correlation equations to estimate mass emissions based on parts per million 

readings taken from gas detectors are also applicable to an elevated 

component again but may require extra costs to gain access to that component. 

5) Turbine meters and rotameters are applicable to OELs and require access to 

and direct contact with the end of the stack. 

6) Hot wire anemometers operate by inserting a probe into a hole bored into a 

vent stack. Using such a device for leak inspections could eliminate the need 

for lifts to reach the top of some OELs but are not suitable for other types of 

component leaks. 

Emission factors or other calculation methods to quantify emissions volumes can 

limit or overcome the need to access components but sacrifice reporting accuracy. 

C. Evaluation Criteria and Approach 

Because each industry facility is constructed differently, each facility contains a different 

number of occurrences of these issues, resulting in different facility cost burdens. The 

exhibits below are examples of best case, low cost scenarios and a worst case, high cost 

scenarios as regards cost burdens. A key message for each accessibility issue is that 

remote sensing instruments require a higher initial capital cost.

i. Elevated Components: Components may be installed out of reach above ground 

level, above walkways, or beyond fixed platforms for a number of reasons. 

Pressure relief valves on large separators or other equipment divert the flow from 

overpressure situations in a safe manner which can warrant high elevations away 

116
from the walkways, ladders, and other access points. Similarly, open-ended lines 

may be elevated for safe venting. Pipe racks in larger facilities that may contain 

streams with a methane component may also be elevated beyond reach given the 

clearances needed for heavy maintenance vehicles. Stacks within buildings are 

typically routed beyond the roof which may be difficult to access since the stacks 

themselves require little maintenance and therefore do not need to be accessible.. 

The existing VOC LDAR rule states that pumps, valves, and connectors that 

cannot be monitored due to safety reasons are to be omitted from the survey work, 

meaning that a comprehensive report may not include those components. Those 

components deemed unsafe-to-monitor require an explanation as to why and a 

plan for future monitoring. Therefore, the inspection of some elevated 

components using the techniques that require close proximity such as portable 

VOC detection devices are excluded from the survey. 

Exhibit G-1: Survey and measurement of inaccessibly elevated components 

ii. Slanted Roofs: Emission sources may on roofs which are often not physically 

accessible. Vent stacks in particular are designed for safe venting and typically 

lead to rooftops away from personnel access points. A vent stack outlet above the 

roofline requires no routine maintenance, so access may not have been a facility 

design concern. The type of roof therefore affects accessibility of components on 

or above the roofline. Accessibility issues include: 

• whether the roof is flat or slanted; 

• whether the roof is accessible by a fixed ladder, by a portable ladder, by 

fixed stairs, or by portable lifts; 

117
• whether the roof can safely support the weight of a survey/measurement 

technician; and 

• component proximity to the edge of the roof which may require additional 

fall protection measures. 

These factors will vary for each building and for each facility, meaning that 

slanted roofs and other roof accessibility issues will be more burdensome to some 

facilities and less burdensome to others. 

Exhibit G-2: Survey and measurement of slanted roofs 

iii. Confined Spaces: Confined spaces require added safety measures such as use of 

a self contained breathing apparatus, so inclusion of components in confined 

spaces requires additional measures to access them. 

118
Exhibit G-3: Survey and measurement of confined spaces 

iv. Buried Components: The typical buried component is piping, ranging from 

small diameter flow lines to large diameter transmission lines. Fugitive emissions 

from such buried components can be detected by various means ranging from 

spotting dead vegetation above the lines to traversing the lines with various types 

of methane detection instruments. Quantification is more closely tied to the 

accessibility issue with buried components. Quantification may be possible 

without excavating the leaking component, and such quantification would require 

encasing the surrounding area with a tarp to capture all the methane flux from the 

ground and also accounting for the soil oxidizing rate. This method does not 

provide assurance that the entire magnitude is quantified since some of the 

methane may travel along the buried pipe corridor before moving towards the 

surface or may otherwise be dispersed over a larger ground area than the surface 

immediately above the component. 

Excavation is another quantification option, and it is labor intensive and has 

safety issues. Excavation of a line still in service around a leak is a safety issue, 

especially for high pressure lines. Excavation of the soil supporting the line may 

also risk a blowout. Quantification of an excavated line that is still in service 

poses additional safety and measurement issues such as approaching the leak 

source and routing all emissions into the measurement instrument. Lines can be 

taken out of service for safe excavation (and replacement), though this 

complicates the ability to quantify accurately the leak rate. 

119
Exhibit G-4: Survey and measurement of buried components 

v. Limited Accessibility Because of Safety: High flow rate fugitives or fugitives 

with high velocity or high pressure drop can be a safety issue. For example, 

compressor unit valves, when closed, isolate the compressor from the high 

pressure main line, and leaks across this valve can be large in magnitude and high 

in velocity. Another example is compressor or pump seal oil degassing vents that 

carry methane which has entrained oil mist or other liquids which may not be safe 

to approach for quantification or measurement without breathing protection. 

120
Exhibit G-5: Survey and measurement of no or limited accessibility due to safety 

vi. Scheduling Shutdowns, Startups, or Maintenance to Not Interfere with 

Measurement: Fugitive emission can vary depending on operating mode, and the 

availability of each operating mode for leak inspection and quantification is 

another accessibility issue. Compressors have a number of operating modes and 

best illustrate this accessibility issue. Some operators have compressors with high 

operating factors which limits the leak inspection and quantification of those 

compressors in the standby or shutdown mode. Conversely, compressors with a 

standby or peak loading role will have limited availability in the running 

operating mode for leak inspection and quantification.

vii. Internal Leaks through Open-Ended Lines: OELs can be manifolded into a 

single stack that leads to the atmosphere. A common example of this is valves 

around a compressor: two unit valves isolate the compressor from the main line, 

and a blowdown valve allows the volume of the compressor between the unit 

valves to be depressurized. All three of these valves typically lead to a single 

stack, and attributing leaks to a specific valve to target for quantification (or 

repair) can be difficult. In the case of the three compressor valves, a compressor 

can be cycled through different operating modes to isolate leak rate of the 

121
blowdown valve and leak rate of the two unit valves, but attributing leak rates to 

individual unit valves is difficult. If multiple compressors are connected to the 

same vent stack then it is difficult to identify the leak with a particular 

compressor. Hence, though a cumulative emissions reporting is possible in such 

cases, determining the number of leaking valves may not be possible.

A single fugitive emissions source can also reach the atmosphere through more 

than one path. An example of this is fugitives from pig trap valve which may 

reach the atmosphere either through the vent atop a pig trap or through the gasket 

on the pig trap hatch: both paths to the atmosphere must be measured and totaled 

to estimate the entire leak rate from the pig trap. 

D. Data Sources for Research 

Resources related to component accessibility are listed below. 

• Clean Air Act 

o 40 CFR 60 Appendices: EPA Method 21 

o 40 CFR 60 Subpart KKK: Standards of Performance of Performance for 

Equipment Leaks of VOC from Onshore Natural Gas Processing Plants. 

o AWP in 40 CFR General Provisions 

• OSHA Standards 

o The need to carry flammable gas detector (OSHA requires that the employer 

must provide personal protective equipment (PPE) for employees in a 

dangerous environment. If it is determined that a flammable gas detector is 

necessary PPE, then one must be provided and used.) 1910.132 - General 

requirements.

o The need to be aware of surroundings and watch where you walking (Requires 

employer to develop safe work practices and train employees on them) 

1910.119 - Process safety management of highly hazardous chemicals.

o Fall protection 1926.502 - Fall protection systems criteria and practices

o Confined spaces 1910.146 Confined Spaces - Amended Final Rule (1998) 

• Industry published standard operating procedures 

o API Leak Detection Standards API publishes many of these; each costs about 

$150. 

E. Summary 

• If the inaccessibility provisions for monitoring under the VOC LDAR regulation also 

apply to this reporting rule, the reporting rule may be able to require optical leak 

detection for components that are inaccessible, but may not be able to require direct 

emission measurement. 

• The enclosure method requires that a technician must first gain access to the 

component and remain in the inaccessible location for a relatively long period of time 

relative to other quantification methods to perform the measurement. 

• For vented methane emissions, significant emissions sources are often routed through 

OELs which are inaccessible, and exclusion of these OELs in particular would affect 

122
the comprehensiveness of a facility’s emissions reporting. Buried components are 

also potentially large fugitive emissions sources. 

• Remote sensing requires a) a capital investment by operators who lack suitable 

instruments already and b) rule language that ensures consistent and reasonable use of 

the instrument to detect methane leaks successfully. Method 21 monitoring of 

inaccessible components requires a capital investment by operators to obtain 

accessibility equipment such as lifts to gain physical proximity to each inaccessible 

component. Estimated cost impacts for either type of monitoring have been provided 

in the exhibits above for various types of inaccessible components. 

123
Appendix H: Review and assessment of potential alternatives to monitoring 

methods for emissions sources 

Pneumatic Pumps 

This appendix provides a brief overview of selected key comments (not all) representing 

initial thoughts to show why changes in the proposed supplemental rule were made. These 

are not meant to show every comment on an issue, or a response on every issue. First, it 

summarizes the comment(s) and then it summarizes research on pump curves, in this case, 

from pump vendors and how it can be used to estimate emissions from pumps. 

Comments 

A commenter proposes an alternate engineering emissions estimation methodology that 

employs the ideal gas law, different from direct measurement of emissions or using data from 

pump manufacturers and emission factors. The data required for this estimation methodology 

is provided by manufacturers in the form of “pump curves”. 

The volume of natural gas emissions from a pneumatic pump is a function of the amount of 

liquid pumped (displacement volume), the liquid outlet pressure from the pump, the gas pressure 

and temperature used as the pneumatic power gas, and the “mechanical efficiency loss” across 

the pump. In manufacturers’ information, this relationship is typically described using a set of 

“pump curves.” It can be described mathematically as follows: 37

Gas volume = [{(outlet pressure from the pump psig) + (atmospheric pressure psia)}/14.7 

psia] * (atmospheric temperature R/(460 R + gas temperature F ) * (volume of liquid pumped 

in cubic feet) * (1+pump inefficiency) 

Volume of liquid: 

Measured volume or calculated volume: (gals/stroke of pump/7.48 gal/scf * number of 

strokes/min) 

Pump inefficiency: 

Expressed as a fractional decimal (e.g. 0.30) provided by the manufacturer or an assumed 

default of 30% mechanical efficiency loss 

The gas temperature and pressure is assumed to be at atmospheric conditions in the equation 

above. To estimate the GHG emissions from the above equations: 

CO2 = (Volume of gas above) * (CO2 content of pneumatic power gas) 

CH4 = (Volume of gas above) * (CH4 content of pneumatic power gas) 

Comments 

 

37 The use of “fugitive” in quoted text from the initial proposed rule implies both fugitive and vented emissions 

as defined in this document. 

124
A commenter recommends using emission factors for pneumatic pumps provided in the API 

Compendium where emissions from pneumatic pumps are considered to be a small 

contributor to total facility emissions. 

Exhibit H-1 provides emission factors from API Compendium 2004 

Exhibit H-1: Emission factor for pneumatic pump seals. 

Component – Service a

Emission Factor 

original units b

(lb gas/day/component) 

Emission Factor 

converted to 

(tonne gas/hr/component) 

Pump Seals – gas 0.609 1.15E-05 

The engineering estimation method proposed by the first commenter is also supported by the 

second commenter. 

Measurement Methods 

A commenter lists the following methods as potential emissions measurement methods: 

• Direct measurement of gas consumption rate by pneumatic pump type using gas flow 

meters, and the measured or estimated CH4 content of gas. 

• Measured gas consumption rates by pneumatic pump type from vendor data, and the 

measured or estimated CH4 content of gas. 

• Emissions factor by pneumatic pump type (piston, diaphragm or average), and the 

measured or estimated CH4 content of gas. 

• Vented CH4 emissions from pneumatic pumps are estimated using the bleed rates of 

gas from the pumps, and the methane fraction of the vented gas, according to the 

following equation: 

2200

****

3.379

1

4 4

4

CH annual bleed

CH

MW QtfCH scf

molelb

E

−

=

where, 

ECH4 = total pneumatic pump CH4 venting emissions for a basin or region 

[tonne/yr] 

Qbleed = bleed rate of gas from a pneumatic pump [scf/hr] 

MWCH4 = molecular weight of methane (16 lb/lb-mole) [lb/lb-mole] 

f CH4 = molar fraction of methane in the gas 

tannual = annual usage of the pneumatic devices [hr/yr] 

Manufacturer’s Pump Curves: 

Pneumatic pump manufacturer Kimray was contacted regarding their manufacturer “pump 

curves”. Kimray provides pump curves for all its pneumatic pumps. Pump curves graphically 

represent the relationship between gas pump speed strokes per minute and gallons per hour of 

liquid pumped. Manufacturers also provide tables indicating the gas consumption or usage 

125
per gallon of liquid pumped at different operating pressures. This information can be used to 

estimate emissions from pneumatic pumps. Sample Kimray pump curve and gas 

consumption tables can be found at Kimray’s website.38

Summary 

Measurement of natural gas fugitive emissions either by direct measurement or using data 

provided by the pump manufacturer, along with appropriate emission factors may be used to 

estimate total emissions. The application of pump curves provided by manufacturers also 

seems feasible and a potentially cost-effective method to estimate emissions from pumps. If 

pump curves are not provided by the manufacturer, then the pump curves for pumps with 

similar operational capacity and manufacturer can be used for emissions estimation. 

 

Acid Gas Removal (AGR) Vents 

This appendix provides a brief overview of selected key comments (not all) representing 

initial thoughts to show why changes in the proposed supplemental rule were made. These 

are not meant to show every comment on an issue, or a response on every issue. First, it 

summarizes the comments, and then it provides quantification methods opted or reported by 

Natural Gas STAR partners, the API Compendium, and the EPA National GHG Inventory. 

Comments 

A commenter proposes the use of the following methods to estimate emissions from AGR 

vents: 

• Mass balance 

• Emission factor 

Comments 

Another commenter proposes the use of mass balance methods to estimate emissions from 

AGR vents. In cases where acid gas flow and composition are measured, this commenter 

recommends mass balance and in other cases proposes the following equation: 

)**21*(* ag ag CO2 CO2 CH 4 CH 4 = yQE ρ + y ρ

where, 

Eag = Mass of acid gas removed (tonnes CO2e) 

Qag = Volume of acid gas (1000 m3

) 

yCO2 = Mole fraction of CO2 in the acid gas

yCH4 = Mole fraction CH4 in the acid gas 

ρCO2 = Density of CO2 (1.87 kg/m3)

ρCH4 = Density of CH4 (0.717 kg/m3) 

21 = Global warming potential for CH4

 

38 Kimray. Available online at: <www.kimray.com.cn/pdf/G_10.17.pdf> 

126
API Compendium Measurement Method 

The API compendium lists the following methods to estimate methane emissions from amine 

ed on the methane composition in the 

units: 

• API’s AMINECalc is a software that provides a mass emission rate for VOCs that can 

be converted into methane emission rates bas

gas. Details on this software are available at: 

engineers.ihs.com/document/abstract/CKFJDBAAAAAAAAAA

• For uncontrolled AGR units, two CH4 emission factors for AGR vents were 

developed as part of the 1996 GRI/EPA CH4 emissions study (Volume 14, page A13) based on process simulation results for typical unit operations of a diet

39

hanol 

amine (DEA) unit (Myers, 1996). The factors are listed in Exhibit H-2 below : 

Exhibit H-2: Process Simulation Results for a Diethanol Amine Unit 

Methane Emission Factor Methane Emission Factor Un certainty Source original units converted to tonnes (+/- %) 

AGR vent 965 scf/106 scf treated gas 0

0.654 tonnes/106

 m3 treated gas 119 .0185 tonnes/106

 scf treated gas 

 6,083 scfd/AGR unit 0.1167 tonnes/day-AGR unit 126 

EPA National GHG Inventory: 

The U.S. GHG Inventory employs a mass balance approach to estimate methane emission 

from AGRs. The CO2 content acceptable in natural gas transmission pipelines varies from 

1% to 3% depending on the pipeline company. The national average of CO2 content in 

pipeline gas is 1%. As a result, natural gas processing companies are most likely aware of 

their outgoing natural gas CO2 composition. If the CO2 composition of the incoming natural 

gas can be identified, then estimation of emissions from AGR units is feasible using simple 

nd cost effective mass balance approach. 

other approach is using 

mulation software packages to estimate emissions CO2 emissions. 

s they are very small and would be difficult to assess via the mass balance 

pproach.

 

a

Summary 

If processing plants know the composition of their incoming and outgoing gas, the mass 

balance approach is reasonable for estimating CO2 emissions. An

si

The mass balance approach may not be reliable for methane emissions since feed gas and 

residue gas methane content are two very large numbers while the amount of methane going 

up the AGR vent is a very small number. For this source, methane losses may not be 

estimated a

a

39 API Compendium 2004, Appendix B-Additional Calculation Approaches, Page B-39.

127
 Glycol Dehydrator 

This appendix summarizes the input parameters to GTI’s GLYCalcTM software and how it is 

typically used. Below are 1) key GLYCalcTM inputs, 2) precedents for mandated use of 

GLYCalcTM specifically, and 3) a Summary of a quantification method. 

Required GLYCalcTM inputs include: 

Volume percent of the following components in the gas at the dehydrator inlet: 

CO2 

H2S 

N2 

C1 

C2 

C3 

C4s 

C5s

n-C6 

other C6 

C7s 

2,2,4 Trimethylpentane 

Benzene 

Toluene 

Xylenes 

C8+.

Other required information: 

o Is gas saturated (y/n) 

o Lean glycol 

recirculation ratio 

o Type of stripping gas (dry/wet) 

o Stripping gas flow rate 

o Is gas saturated (y/n) 

o Lean glycol 

recirculation ratio 

o Type of stripping gas 

(dry/wet) 

o Stripping gas flow 

rate 

o Dry gas dewpoint 

o Lean glycol 

concentration (%) 

o Flash tank 

temperature and 

pressure 

o Throughput 

o Operating hours per year 

o Glycol pump type 

o What controls are on the 

reboiler vent and flash 

gas vent? (i.e. is it 

vented, routed to fuel 

gas, etc). 

Precedents for GLYCalcTM use 

EPA AP-42 is the set of air emissions rate quantification methods for various pollutants 

(VOC, BTEX, HAPs). AP-42 gives GLYCalcTM as the only option for glycol dehydrators in 

gas processing40. The section on natural gas processing discusses glycol dehydration 

indicating that glycol dehydrator emissions are important from an air emissions standpoint 

and recommends using GLYCalcTM. 

MMS GOADS also uses GLYCalcTM to estimate all air emissions from glycol dehydrators41. 

State guidance documents for permitting show that GLYCalcTM is also specified by name and 

required for estimating air emissions rates. At least one state has specified an alternative if 

the operator does not wish to use GLYCALCTM42. The alternative is a mass balance 

calculation which requires taking samples of the rich glycol and the lean glycol and 

 

40EPA. AP-42. Section 5.3. January 1995. <www.epa.gov/ttn/chief/ap42/ch05/index.html> 41 Mineral Management Service (MMS). Gulfwide Emission Inventory Study for the Regional Haze and Ozone 

Modeling Effort. October 2004. MMS 2004-072. pg. 5-17 

<www.gomr.mms.gov/PI/PDFImages/ESPIS/2/3010.pdf > 

42 Oklahoma Department of Environmental Quality. Fact Sheet: Title V Oil & Gas Facilities. February 6, 1997. 

pg. 7 <www.deq.state.ok.us/factsheets/air/o&gfctst.pdf> 

128
calculating the difference for each pollutant species. This method is also applicable for 

methane and carbon dioxide. 

Summary

Given that GLYCalcTM is ubiquitous in industry and in regulatory entities both at the national 

and the state levels, GLYCalcTM could be used in the mandatory reporting rule: it is an 

industry standard and is not a cost burden at $140.00 per license43. Allowing for alternative 

estimation methods, either competing models, calculations, or measurement methods, would 

require additional resources for an EPA validation program since not all alternatives may be 

as rigorous or correct. Use of the same or similar inputs as GLYCalcTM does not guarantee 

an accurate emissions rate result as shown by the following two examples. 

1. The well-known 1996 EPA-GRI study in volume 1444 developed glycol dehydrator 

process simulations using ASPEN/SP® software that had relevant inputs as the basis 

for its results; however, the results have since been proven to have the unrealistic 

assumption of holding the glycol circulation rate constant for different runs. As a 

result, the results were developed assuming that reboiler stack methane emissions rate 

corresponds to the inlet gas flow rate (stack emissions actually correspond to glycol 

circulation rate). Though this study is an authority on methane emissions, and 

ASPEN is an established process simulator, the applied methodology for this 

particular source has become outdated as understanding of methane emissions has 

increased. This is an example of how application of different models for dehydrator 

emissions may cause inconsistent results from reporting entity to reporting entity and 

one advantage of stipulating a standardized software package. 

2. The 1996 EPA-GRI study also uses process simulation to estimate methane emissions 

from amine units which operate similar to glycol dehydrators in that they have a 

contactor and regenerator. The study used a process simulator, ASPEN PLUSTM, to 

model methane emissions by using 100 percent water as the solvent as a surrogate for 

aqueous amine solutions45. This may or may not be a valid assumption when using a 

process simulator for an individual unit, depending on the desired accuracy, and 

would require further resources to assess how this assumption compares to actual 

emission rates for specific units. Similar issues would arise for assessing assumptions 

when allowing other process simulation methods for glycol dehydrator methane 

emissions. 

Thus other glycol dehydrator emission modeling approaches are available but are primarily 

found in literature before GLYCalcTM became the norm and their use alongside GLYCalcTM 

may result in non-standard results across reporting entities. 

 

43 GTI. GRI-GLYCalc. Version 4.0. [CD-ROM]. GRI-00/0102. 

<www.gastechnology.org/webroot/app/xn/xd.aspx?it=enweb&xd=10abstractpage\12352.xml> 

44 GRI. Methane Emissions from the Natural Gas Industry. Volume 14. June 1996. 

<www.epa.gov/gasstar/documents/emissions_report/14_glycol.pdf> 

45 GRI. Methane Emissions from the Natural Gas Industry. Volume 6. June 1996. 

<www.epa.gov/gasstar/documents/emissions_report/6_vented.pdf> 

129
Appendix I: Flares 

This appendix provides results of additional research and general consensus on flare 

reporting that was conducted to support development of the supplemental proposed 

rulemaking. 

No data source was found that comprehensively reports data on vented and flared emissions 

from the production and processing sector of the oil and gas industry. The EIA does collect 

information from states on a voluntary basis. However, this data is not complete and 

moreover does not distinguish flare data from vent data. 

In 2004, the U.S. Government Accountability Office raised concerns on the lack of 

information on vented and flared data. EIA responded to this, but did not propose any 

concrete steps to collect accurate information. In summary, EIA proposed to rely on states, 

the Bureau of Land Management (BLM), and the Mineral Management Services to report, as 

best as possible, data on vented and flared emissions. In addition, EIA noted that BLM 

estimated the cost of meter vents and flares to be around $32 million in 2004 dollars.46

Flares in general can be categorized into two main types; continuous and intermittent. 

Continuous flares combust casing head gas, associated gas, well testing gas, and gas from 

equipment that generate a continuous waste gas stream (such as glycol dehydrators, storage 

tanks, and pneumatic devices). Intermittent flares combust releases that are not continuous in 

nature such as streams from equipment/ vessel/ site blowdowns and pressure relief valves. 

The emissions from continuous flares can be monitored using predominantly two techniques 

that are practical for the rule; (1) measurements using either a continuous flow meter or one 

time measurement meters, and (2) engineering methods. If most of the equipment emissions 

going to a flare get included in the rule, only associated gas and casing head gas flaring will 

have to be accounted for in this rule. 

Intermittent flare emissions can be measured only using continuous flow meters or 

engineering estimation methods. The volume of intermittent emissions is lower in magnitude 

in comparison to continuous emissions. Hence using continuous flow meters could be cost 

prohibitive for the purposes of the Rule. 

Summary 

Considering the various options and the magnitude of emissions from each type of flare 

(continuous and intermittent), the following monitoring options could be adopted for the 

Rule; 

Onshore and Offshore Production 

1) Continuous flaring: All major continuous equipment vents are covered in the initial 

rule proposal as individual sources. The only three major continuous sources not 

 

46 GAO. Natural Gas Flaring and Venting: Opportunities to Improve Data and Reduce Emissions. July 14, 

2004. GAO-04-809. <www.gao.gov/products/GAO-04-809> 

130
covered are casing head gas, associated gas, and well testing gas. Engineering 

estimation methods can be used for these sources. Companies can easily measure the 

gas-to-oil ratio for each of the sources and estimate emissions using calculation 

methods. 

2) Intermittent flaring: All equipment sending gas to the flare on an intermittent basis 

are covered as individual sources in the proposed rule. 

Onshore Processing 

There are potentially many sources that send their gas to a flare and are not covered in the 

proposed rule. For example, molecular sieves send gas to the flare intermittently and are not 

covered in the Rule. In addition, gas plants may send pure hydrocarbon products such as 

propane and butane to a flare when equipment shuts down (they may prefer to keep the plant 

running and losing some product as opposed to shutting down the plant). However, the 

possibility of using continuous meters on flares in processing plants can be cost prohibitive. 

One option is to provide for calculative methods based on the volume of pure hydrocarbons 

sent to flares during a disruption. 

131
 

Appendix J: 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) report47 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 J-1 and J-2. 

Exhibit J-1. Oil Tank Correction Factors 

 

47 Texas Commission on Environmental Quality (TCEQ). Upstream Oil and Gas Storage Tank Project Flash 

Emissions Models Evaluation. July 16, 2009. 

132
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)

Measurement - E&P Tank Linear (Measurement - E&P Tank)

Oil Tanks ( ̊API<45)

Exhibit J-2. Condensate Tank Correction Factors 

y = -0.6673x + 248.34

R2

 = 0.0045

-

100

200

300

400

500

600

20 30 40 50 60 70 80

E&P Tank Estimate (scf/bbl)

[Measurement] - [E&P Tank estimates] 

(scf/bbl)

Measurement - E&P Tank Linear (Measurement - E&P Tank)

Condensate Tanks ( ̊API>45)

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 J-1 and J-2, the correlations for the correction factor are very 

weak, with R2

 values of 0.0719 for oil and 0.0045 for condensate. 

133
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.

134
Appendix K: 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 Operations48. (A discussion on how this API study was conducted is 

provided in Appendix P.) 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 Operations48. (A discussion on how this API study was conducted is 

provided in Appendix P.) 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 

 

48 API. Emission Factors for Oil and Gas Production Operations. Table 10, page 16. API Publication Number 

4615. January 1995. 

135
Connector (other) 1.38 1.497 

Open-Ended Line 1.48 1.6 

Other 3.56 3.846 

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 Plants49 and 

Clearstone’s Cost-Effective Directed Inspection and Maintenance Control Opportunities at 

Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites50. 

(A discussion on how these studies were conducted is provided in Appendix P.) 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) 

Reciprocating Compressor 

Component, (scf/hour/comp) 

Centrifugal Compressor 

Component Component, (scf/hour/comp) 

Name Before DeMethanizer 

After DeMethanizer Before DeMethanizer After DeMethanizer 

Other 

Components, 

(scf/hour/comp) 

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 

 

49 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> 50 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. 

136
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 Systems51 and the Measurement of Natural Gas 

Emissions from the Canadian Natural Gas Transmission and Distribution Industry52.. (A 

discussion on how these studies were conducted is provided in Appendix P.) 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 

 

51 Clearstone. Handbook for Estimating Methane Emissions from Canadian Natural Gas Systems. Clearstone 

Engineering Ltd., Enerco Engineering Ltd, and Radian International. May 25, 1998. 

52 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. 

137
Methane Emission Factors for LNG Storage 

Leaker Emission Factors – LNG Storage Components, LNG Service

Methodology 

The light liquid emission factors with leak concentrations greater than or equal to 10,000 

ppmv were taken from Protocol for Equipment Leak Emission Estimates53. 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 

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 Storage53. 

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 Systems51 and Measurement of Natural Gas 

Emissions from the Canadian Natural Gas Transmission and Distribution Industry52. (A 

discussion on how these studies were conducted is provided in Appendix P.) 

 

53 EPA. Protocol for Equipment Leak Emission Estimates. Emission Standards Division. U.S. EPA. SOCMI 

Table 2-7. November 1995. 

138
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 

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 Industry54. 

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

Onshore production Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - All Components, Gas Service 

 

54 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> 

139
Valve NA 

Connector NA 

Open-ended Line NA 

Pressure Relief Valve NA 

Low-Bleed Pneumatic Device Vents NA 

Gathering Pipelines NA 

CBM Well Water Production NA 

Compressor Starter Gas Vent NA 

Conventional Gas Well Completion NA 

Conventional Gas Well Workover NA 

Leaker Emission Factors - All Components, Light Crude Service1 

Valve 2.03

Connector 0.90

Open-ended Line 0.96

Pump 2.35

Other 2.31

Leaker Emission Factors - All Components, Heavy Crude Service2 

Valve 3.13

Flange 4.15

Connector (other) 1.38

Open-ended Line 1.48

Other 3.56 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" 

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 6.42 

Connector 5.71 

Open-ended Line 11.27 

Pressure Relief Valve 2.01 

Meter 2.93 

Population Emission Factors - Other Components, Gas 

Service 

140
Gathering Pipelines3 2.81 

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

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

Leaker Emission Factors - Other Components, Gas Service 

Low-Bleed Pneumatic Device Vents NA

Gathering Pipelines1 NA 1

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

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 NA 

Valve NA

Pressure Relief Valve NA

Open-ended Line NA

Leaker Emission Factors - Other Components, Gas Service 

Low-Bleed Pneumatic Device Vents NA

METHANE EMISSION FACTORS FOR LNG STORAGE

LNG Storage Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - LNG Storage Components, LNG Service 

141
Valve 1.19

Pump Seal 4.00

Connector 0.34

Other 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 1.19

Pump Seal 4.00

Connector 0.34

Other 1.77

Leaker Emission Factors - LNG Terminals Compressor, Gas Service 

Vapor Recovery Compressor NA

METHANE EMISSION FACTORS FOR DISTRIBUTION

Distribution Emission Factor 

(scf/hour/component) 

Leaker Emission Factors - Above Grade M&R Stations Components, Gas Service 

Connector 1.69

Block Valve 0.557

Control Valve 9.34

Pressure Relief Valve 0.270

Orifice Meter 0.212

Regulator 26.131

Open-ended Line 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 - Gathering Pipelines, Gas Service 

Gathering Pipelines NA

Leaker Emission Factors - Distribution Mains, Gas Service1 

Unprotected Steel 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 0.88 1

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

142
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. 

143
Appendix L: Development of Population emission factors 

Natural Gas Emission Factors for Onshore Production 

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 Industry55. 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%. 

Component EF, scf/hour/component = (EF All U.S., mscf/yr) / (A) * (B) / (C) 

EF All U.S. Valve, mscf/yr = ((Eastern U.S. Gas Production Count) * (Eastern U.S. 

Gas Production EF, mscf/yr) + (Western U.S. Gas Production Count) * (Western U.S. 

Gas Production EF, mscf/yr)) / (Total U.S. Gas Production Count) 

Component 

Name 

Component 

EF, 

scf/hr/comp 

Eastern U.S. 

Component 

Count 

Eastern U.S. 

Component 

EF, Mcf/yr 

Western U.S. 

Component 

Count 

Western U.S. 

Component EF, 

Mcf/yr 

U.S. 

Component 

Count 

Valve 0.08 4,200 0.184 6,059 0.835 10,259 

Connector 0.01 18,639 0.024 32,513 0.114 51,152 

Open-Ended 

Line 0.04 260 0.42 1,051 0.215 1,311 

Pressure Relief 

Valve 0.17 92 0.279 448 1,332 540 

Conversions: 

A: 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. 

B: 1,000 scf/mscf 

C: 8,760 hours/year 

“Low-Bleed Pneumatic Device Vents” Methodology 

Methane emissions per pneumatic devise are from EPA’s Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-200756, The average methane content of natural gas is assumed 

to be 78.8%. 

2.75 scf/hour/component EF = (52 [scfd CH4/pneumatic devises, low bleed]) / (A) / (D) 

Conversions: 

 

55 GRI. Methane Emissions from the Natural Gas Industry. Volume 8. Tables 4-3, 4-6 and 4-24. June 1996. 

<www.epa.gov/gasstar/documents/emissions_report/8_equipmentleaks.pdf> 

56 EPA. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007. Annexes. Tables A-112 – A-125. 

U.S. EPA. April 2009. <epa.gov/climatechange/emissions/downloads09/Annexes.pdf> 

144
A: 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. 

D: 24 hours/day 

“Gathering Pipelines” Methodology 

Emissions and mileage of underground production pipelines are from GRI’s Methane 

Emissions from the Natural Gas Industry54. The average methane content of produced 

natural gas is assumed to be 78.8%. 

2.81 scf/hour/mile EF = (E) / (A) / (D) 

Conversions: 

A: 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. 

D: 24 hours/day 

E: 53.151651325 scfd/mile EF = (6.6 Bscf [Total Emissions Estimates from Underground 

Production Pipelines]) * (1,000,000,000 cf/bcf) / (365 days/year) / ((268,082 miles [Protected 

Steel Gathering Pipelines]) + (41,400 miles [Unprotected Steel Gathering Pipelines]) + 

(29,862 miles [Plastic Gathering Pipelines]) + (856 miles [Cast Iron Gathering Pipelines])) 

“CBM Well Water Production” Methodology 

Gg/gallon of water is from EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks: 

1990-200756. To calculate Gg/gallon water, 542.9 mg/l is assumed as the concentration of 

methane in the water, at a well depth of 700ft. 

0.11 scf methane/gallon EF = (51,922,341.5 [CH4 density, scf/Gg]) * (2.05216E-09

Gg/gallon water) 

2.05216E-09 Gg/gallon water EF = (542.9 mg/l) / (1,000 mg/g) * (3.78 l/gallon) * 

(gallons of water drainage/yr) / (1,000,000,000 g/Gg) 

 

“Compressor Starter Gas Vent” Methodology 

Annual emission factors for compressor starts are from GRI’s Methane Emissions from the 

Natural Gas Industry57. The average methane content of natural gas is assumed to be 

78.8%. 

1.22 scf/hour/component EF = (8,443 [Annual Emission Factor for Compressor Starts]) / (A) 

/ (C) 

Conversions: 

A: 78.8% – production quality of natural gas (% methane) from, “Vented and 

 

57 GRI. Methane Emissions from the Natural Gas Industry. Volume 6. Table 4-2 and Appendix A, page A-2. 

June 1996. <www.epa.gov/gasstar/documents/emissions_report/6_vented.pdf> 

145
Combustion Source Summary,” Methane Emissions from the Natural Gas Industry,

Volume 6, Appendix A, page A-2. 

C: 8,760 hours/year 

Flare Methodology 

Emissions and flaring efficiency are from GRI’s Methane Emissions from the Natural Gas 

Industry58. GRI assumed all gas is flared, that the duration is one day per completion, that the 

gas is 78.8% CH4, and the flare is 98% efficient. Results are adjusted to assume that no 

conventional gas well completions are flared. 

Conventional Gas Well Completion: 46,510 scf/completion EF = (0.733 scf/completion) / 

(0.02 [% Methane not Burned]) * (B) / (A) 

Conventional Gas Well Workover: 3,114 scf/workover EF = (2.454 mscf 

methane/workover) * (B) / (A) 

Conversions: 

A: 78.8% – production quality of natural gas (% methane) from: “Vented and 

Combustion Source Summary.” Methane Emissions from the Natural Gas 

Industry57.. 

B: 1,000 scf/mscf 

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.59 (A discussion on how this study was conducted is 

provided in Appendix P.) 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% from the same study. 

Component EF, scf/hour/component = (Average Emissions Factors by Facility Type, 

lb/component-day) / (D) / (F) * (G) 

Component Name Component EF, 

scf/hr/comp 

Average EF by Facility Type, 

lb/component-day 

Valve 0.04 7.00E-02 

Connector 0.01 8.66E-03 

Open-Ended Line 0.04 6.38E-02 

Pump 0.01 1.68E-02 

Other 0.24 3.97E-01 

 

58 GRI. Methane Emissions from the Natural Gas Industry. Volume 7, page B-9. June 1996. 

<www.epa.gov/gasstar/documents/emissions_report/7_blowandpurge.pdf> 59 API. Emission Factors for Oil and Gas Production Operations. Table 9, page 10. API Publication Number 

4615. January 1995. 

146
Conversions: 

D: 24 hours/day 

F: 0.04246 CH4 density lb/scf 

G: 0.613 – CH4 content of onshore light crude associated natural gas 

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 Operations59. (A discussion on how this study was conducted is 

provided in Appendix P.) 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. 

Component EF, scf/hour/component = (Average Emissions Factors by Facility Type, 

lb/component-day) / (D) / (F) * (H) 

Component Name Component EF, 

scf/hr/comp 

Average EF by Facility Type, 

lb/component-day 

Valve 0.001 6.86E-04 

Flange 0.001 1.16E-03 

Connector (Other) 0.0004 4.22E-04 

Open-Ended Line 0.01 8.18E-03 

Other 0.003 3.70E-03 

Conversions: 

D: 24 hours/day 

F: 0.04246 CH4 density lb/scf 

H: 0.942 – CH4 content of onshore heavy crude associated natural gas 

Methane Emission Factors For Processing 

Population Emission Factors – Other Components, Gas Service 

“Gathering Pipelines” Methodology 

Emissions and mileage of underground production pipelines from GRI’s Methane Emissions 

from the Natural Gas Industry54. The average methane content of produced natural gas is 

assumed to be 78.8%. 

2.81 scf/hour/mile EF = (E) / (A) / (D) 

Conversions: 

A: 78.8% – production quality of natural gas (% methane) from: “Vented and 

Combustion Source Summary.” Methane Emissions from the Natural Gas Industry57. 

D: 24 hours/day 

147
E: 53.151651325 scfd/mile EF = (6.6 Bscf [Total Emissions Estimates from Underground 

Production Pipelines]) * (1,000,000,000 cf/bcf) / (365 days/year) / ((268,082 miles [Protected 

Steel Gathering Pipelines]) + (41,400 miles [Unprotected Steel Gathering Pipelines]) + 

(29,862 miles [Plastic Gathering Pipelines]) + (856 miles [Cast Iron Gathering Pipelines])) 

Methane Emission Factors for Transmission 

Population Emission Factors – All Components, Gas Service 

Methodology 

Gas transmission facility emission factors were taken from the Handbook for Estimating 

Methane Emissions from Canadian Natural Gas Systems51. (A discussion on how this study 

was conducted is provided in Appendix P.) “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). “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) * (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 1.02 1.969E-02 

Pressure Relief Valve 14.51 2.795E-01 

Orifice Meter 0.17 3.333E-03 

Other Meter 0.0005 9.060E-06 

Regulator 0.17 3.304E-03 

Open-Ended Line 4.34 8.355E-02 

Conversions: 

F: 0.04246 CH4 density lb/scf 

I: 2.20462262 lb/kg 

148
Population Emission Factors – Other Components, Gas Service 

“Low-Bleed Pneumatic Device Vents” Methodology 

Methane emissions per pneumatic device are from EPA’s Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-2007.

56 The average methane content of produced natural gas is 

assumed to be 78.8%. Pipeline quality natural gas is assumed to be 93.4% methane. 

2.57 scf/hour/component EF = (52 [scfd CH4/pneumatic devises, low bleed]) / (A) / (D) * (J)

Conversions: 

A: 78.8% – production quality of natural gas (% methane) from: “Vented and 

Combustion Source Summary.” 57 

D: 24 hours/day 

J: 93.4% – pipeline quality of natural gas (% methane) from: “Vented and Combustion 

Source Summary.” 57 

“Gathering Pipelines” Methodology 

Emissions and mileage of underground production pipelines from GRI’s Methane Emissions 

from the Natural Gas Industry54. The average methane content of produced natural gas is 

assumed to be 78.8%. Pipeline quality natural gas is assumed to be 93.4% methane. 

2.62 scf/hour/mile EF = (E) / (A) / (D) * (J) 

Conversions: 

A: 78.8% – production quality of natural gas (% methane) from: “Vented and 

Combustion Source Summary.” 57 

D: 24 hours/day 

E: 53.151651325 scfd/mile EF = (6.6 Bscf [Total Emissions Estimates from Underground 

Production Pipelines]) * (1,000,000,000 cf/bcf) / (365 days/year) / ((268,082 miles [Protected 

Steel Gathering Pipelines]) + (41,400 miles [Unprotected Steel Gathering Pipelines]) + 

(29,862 miles [Plastic Gathering Pipelines]) + (856 miles [Cast Iron Gathering Pipelines])) 

J: 93.4% – pipeline quality of natural gas (% methane) from: “Vented and Combustion 

Source Summary.” Methane Emissions from the Natural Gas Industry57. 

149
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 Industry55. 

Component EF, scf/hour/component = (Injection/Withdrawal Wellhead) * (B) / (C) 

Component Name Component EF, 

scf/hr/comp 

Injections/Withdrawal 

Wellhead, Mcf/yr 

Connector 0.01 0.125 

Valve 0.10 0.918 

Pressure Relief Valve 0.17 1.464 

Open-Ended Line 0.03 0.237 

Conversions: 

B: 1,000 scf/mscf 

C: 8,760 hours/year 

Population Emission Factors – Other Components, Gas Service

Methodology 

See “Low-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 GRI’s Methane Emissions from the Natural Gas 

Industry55. 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) * (I) / (F) 

150
Component Name Component EF, 

scf/hour/comp 

Component EF, 

Mscf/comp-yr 

Valve 0.10 0.867 

Open-ended Line 1.28 11.2 

Connector 0.02 0.147 

PRV 0.71 6.2 

Conversions: 

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: 1990-200756. The methane content of associated natural gas with 

onshore light crude is 61.3%.60

6.81 scf/hour/component EF = (100 scfd CH4/compressor) / (D) / (G) 

Conversions: 

D: 24 hours/day 

G: 0.613 – CH4 content of onshore light crude associated natural gas 

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. 

 

60API. Emission Factors for Oil and Gas Production Operations. API Publication Number 4615. page ES-3, 

Table ES-4, January 1995. 

151
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 Systems51. (A discussion on how this study was conducted is provided in Appendix P.) 

“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). “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) * (I) / (F) 

Component Name Component EF, 

scf/hour/comp 

Gas Distribution Meter/Regulator 

Station Avg. Emissions, kg/h/src 

Connector 5.70E-03 1.098E-04 

Block Valve 5.76E-02 1.109E-03 

Control Valve 1.02E+00 1.969E-02 

Pressure Relief Valve 8.65E-01 1.665E-02 

Orifice Meter 1.73E-01 3.333E-03 

Other Meter 4.71E-04 9.060E-06 

Regulator 9.94E-02 1.915E-03 

Open-Ended Line 4.33E+00 8.355E-02 

Conversions: 

F: 0.04246 CH4 density lb/scf 

I: 2.20462262 lb/kg 

Population Emission Factors – Below Grade M&R Stations Components, Gas Service

Methodology 

152
Average emission factors are from GRI’s Metering and Pressure Regulating Stations in 

Natural Gas Transmission and Distribution61. 

Below Grade M&R Station, Inlet Pressure > 300 psig: 1.30 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 – Gathering Pipeline, Gas Service

Methodology 

See “Gathering Pipelines” Methodology for Population Emissions Factors – Other 

Components, Gas Service for Transmission. 

Population Emission Factors – Distribution Mains and Services, Gas Service

Methodology 

Emission factors for pipeline leaks (mains and service) are from the Inventory of U.S. 

Greenhouse Gas Emissions and Sinks: 1990-200756.

 

Component EF, scf/hour/service = (Pipeline Leak mscf/mile/year) * (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 12.58 110.19 0.19 1.70 

Protected Steel 0.35 3.07 0.02 0.18 

Plastic 1.13 9.91 0.001 0.01 

Cast Iron 27.25 238.7 

Copper 0.03 0.25 

Conversions: 

B: 1,000 scf/mscf 

C: 8,760 hours/year 

Nitrous Oxide Emission Factors for Gas Flaring 

Population Emission Factors – Gas Flaring 

Methodology 

 

61 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>. 

153
Emission factors are from API’s Compendium of Greenhouse Gas Emissions Methodologies 

for the Oil and Gas Industry62. 

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 

NATURAL GAS EMISSION FACTORS FOR ONSHORE PRODUCTION

Onshore production Emission Factor 

(scf/hour/component) 

Population Emission Factors - All Components, Gas Service 

Valve 0.08 

Connector 0.01 

Open-ended Line 0.04 

Pressure Relief Valve 0.17 

Low-Bleed Pneumatic Device Vents 2.75

Gathering Pipelines1 2.81

CBM Well Water Production2 0.11

Compressor Starter Gas Vent 1.22

Conventional Gas Well Completion3 46,510

Conventional Gas Well Workover4 3,114

Population Emission Factors - All Components, Light Crude Service5 

Valve 0.04

Connector 0.01

Open-ended Line 0.04

Pump 0.01

Other 0.24

Population Emission Factors - All Components, Heavy Crude Service6 

Valve 0.001

Flange 0.001

Connector (other) 0.000

Open-ended Line 0.01

Other 0.00 1

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

2

 Emission Factor is in units of "scf methane/gallon", in this case the operating factor is "gallons/year”. Therefore do not 

multiply by methane content 

3

 Emission Factor is in units of "scf/completion" 

4

 Emission Factor is in units of "scf/workover" 

5

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

 

62 API. Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry. American 

Petroleum Institute. Table 4-7, page 4-30. February 2004. 

154
6

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

155
METHANE EMISSION FACTORS FOR PROCESSING

Processing Emission Factor 

(scf/hour/component) 

Population Emission Factors - All Equipment Components, Gas Service 

Valve NA

Connector NA

Open-ended Line NA

Pressure Relief Valve NA

Meter NA

Population Emission Factors - Centrifugal Compressor Components, Gas Service 

Valve NA

Connector NA

Open-ended Line NA

Dry Seal NA

Population Emission Factors - Other Components, Gas Service 

Valve NA

Connector NA

Open-ended Line NA

Pressure Relief Valve NA

Meter NA

Population Emission Factors - Other Components, Gas Service 

Gathering Pipelines1 2.81 1

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

METHANE EMISSION FACTORS FOR TRANSMISSION

Transmission Emission Factor 

(scf/hour/component) 

Population Emission Factors - All Components, Gas Service 

Connector 1.42E-02

Block Valve 1.11E-01

Control Valve 1.02E+00

Compressor Blowdown Valve NA

Pressure Relief Valve 1.45E+01

Orifice Meter 1.73E-01

Other Meter 4.71E-04

Regulator 1.72E-01

Open-ended Line 4.34E+00

Population Emission Factors - Other Components, Gas Service 

Low-Bleed Pneumatic Device Vents 2.57

Gathering Pipelines1 2.62 1

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

156
METHANE EMISSION FACTORS FOR UNDERGROUND STORAGE

Underground Storage Emission Factor 

(scf/hour/component) 

Population Emission Factors - Storage Station, Gas Service 

Connector 1.42E-02

Block Valve 1.11E-01

Control Valve 1.02E+00

Compressor Blowdown Valve NA

Pressure Relief Valve 1.45E+01

Orifice Meter 1.73E-01

Other Meter 4.71E-04

Regulator 1.72E-01

Open-ended Line 4.34E+00

Population Emission Factors - Storage Wellheads, Gas Service 

Connector 0.01 

Valve 0.10

Pressure Relief Valve 0.17

Open-ended Line 0.03

Population Emission Factors - Other Components, Gas Service 

Low-Bleed Pneumatic Device Vents 2.57

METHANE EMISSION FACTORS FOR LNG STORAGE

LNG Storage Emission Factor 

(scf/hour/component) 

Population Emission Factors - LNG Storage Components, LNG Service 

Valve 0.87

Open-ended Line 11.20

Connector 0.15

PRV 6.20

Population Emission Factors - LNG Storage Compressor, Gas Service 

Vapor Recovery Compressor 6.81

METHANE EMISSION FACTORS FOR LNG TERMINALS

LNG Terminals Emission Factor 

(scf/hour/component) 

Population Emission Factors - LNG Terminals Components, LNG Service 

Valve 0.87

Open-ended Line 11.20

Connector 0.15

PRV 6.20

Population Emission Factors - LNG Terminals Compressor, Gas Service 

Vapor Recovery Compressor 6.81

157
METHANE EMISSION FACTORS FOR DISTRIBUTION

Distribution Emission Factor 

(scf/hour/component) 

Population Emission Factors - Above Grade M&R Stations Components, Gas Service 

Connector 5.70E-03

Block Valve 5.76E-02

Control Valve 1.02E+00

Pressure Relief Valve 8.65E-01

Orifice Meter 8.65E-01

Other Meter 4.71E-04

Regulator 1.92E-03

Open-ended Line 4.33E+00

Population Emission Factors - Below Grade M&R Stations Components, Gas Service1

Below Grade M&R Station, Inlet Pressure > 300 psig 1.30

Below Grade M&R Station, Inlet Pressure 100 to 300 psig 0.20

Below Grade M&R Station, Inlet Pressure < 100 psig 0.10

Population Emission Factors - Gathering Pipelines, Gas Service 

Gathering Pipelines2 2.62

Population Emission Factors - Distribution Mains, Gas Service3 

Unprotected Steel 12.58

Protected Steel 0.35

Plastic 1.13

Cast Iron 27.25

Population Emission Factors - Distribution Services, Gas Service3 

Unprotected Steel 0.19

Protected Steel 0.02

Plastic 0.001

Copper 0.03 1

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

2

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

3

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

Summary 

This Appendix provides population emissions factors for potential emissions sources. These 

population emissions factors can 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 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. 

158
159

 

Appendix M: Potential Solutions to Measure Greenhouse Gas Emissions in 

Various Modes of Equipment Operation 

The purpose of this appendix is to analyze the issues involved with and potential solutions to 

estimating emissions in the different modes of operation for equipment at oil and natural gas 

facilities. The scope includes fugitive and vented methane and carbon dioxide emissions. 

1. Evaluation Criteria and Approach 

A. Assessment on permutations of operating modes: startup, running, pressurized, 

shut down and depressurized to intermediate pressure shut down and 

depressurized to atmospheric pressure, shut down for major maintenance: 

Equipment will have variable vented and fugitive emissions depending on their 

modes of operation. The three equipment types discussed are i. compressors, ii. 

tanks, and iii. other components. The text below discusses how emissions differ and 

potential approaches for measurement and developing an inventory. 

i. Compressors – The table below shows each mode of operation in the rows and 

each emission type in the columns, forming a matrix of which emission types 

occur in each mode of operation. Different numbers denote when a different 

measurement is required, i.e. compressor seals will leak at different rates when 

pressurized and when depressurized, requiring separate measurements. For 

example, under normal operations seals on compressor piston rods have been 

documented to leak at approximately 75 cubic feet (scf)/hour. However, when a 

compressor is idle and fully pressurized (not blown down), this can increase to 

300 scf/hour. On the other hand, blowing a compressor down emits on average 

approximately 1,500 scf through the open blowdown valve and the upstream unit 

valve can leak an additional 1,400 scf/hour. However, when the compressor is left 

idle pressurized, the 1,400 scf/hour is eliminated from the unit valve and instead 

approximately 450 scf/hour emissions can leak through the closed blowdown 

valve. This clearly demonstrates how leak rates from different components can 

change between different operating modes63. 

63 EPA. Reducing Emissions when Taking Compressors Off-Line. EPA430-B-04-001. February 2004. 
Emission Type 

Operating Modes 

Starter 

OEL 

open 

Starter 

OEL 

closed 

Blowdown 

OEL open 

Blowdown 

OEL 

closed 

Unit 

Valves 

Seal or Rod 

Packing 

Face OEL 

Engine 

Crankcase 

(where 

applicable) 

Seal Oil 

Degassing 

OEL (where 

applicable) 

Engine or 

Turbine 

Exhaust 

(where 

applicable) 

Startup M1 M5 M8 M12 M14 M18 

Running (normal 

operation) M2 M5 M8 M12 M14 M19 

Shutdown (left 

pressurized) M3 M5 M9 M13 M15 

Shutdown (blown 

down to 

atmosphere) 

M3 M4 M7 M10 M13 M16 

Shutdown (blown 

down to 

intermediate 

pressure) 

M3 M6 M11 M13 M17 

Offline (major 

maintenance) 

Emergency/systems 

testing M4 M13 M16 

Emergency 

venting/shutdown M4 M13 M16 

In the chart above, the necessary components to monitor are displayed by the 

letter “M” and a number. The “M” stands for “monitor” to signify it is necessary, 

and the numbers differentiate measurements. For example, “M3” refers to starter 

OEL leaks in any of the shutdown operating modes. The leak rates should be the 

same for measurements sharing the same number; so no duplicate measurement 

would be necessary. While it is difficult to predict which components will have 

large leaks, cells highlighted in light blue signify which components are expected 

to have potentially large leaks for the modes. The table below displays a legend 

for all the necessary components under different conditions to monitor as derived 

from the matrix above. 

M1 Starter OEL Vents in Startup Mode 

M2 Starter OEL Leaks under Normal Operation 

M3 Starter OEL Leaks for All Shutdown Modes 

M4 OEL Blowdown Venting for All Modes 

M5 OEL Blowdown Vent Leaks for All Pressurized Modes 

M6 OEL Blowdown during Shutdown at Intermediate Pressure 

M7 Unit Valve Leaks during Shutdown Blowdowns to Atmosphere 

M8 Wet Seal or Rod Packing Face OEL during Startup and Normal Operation 

M9 Wet Seal or Rod Packing Face OEL during Pressurized Shutdown 

M10 Wet Seal or Rod Packing Face OEL during Shutdown Blowdown 

M11 Wet Seal or Rod Packing Face OEL during Shutdown at Intermediate Pressure 

M12 Engine Crankcase (where applicable) during Normal Operations 

M13 Engine Crankcase (where applicable) during All Shutdown modes 

M14 Wet Seal Oil Degassing OEL during Startup and Normal Operation 

M15 Wet Seal Oil Degassing OEL during a Pressurized Shutdown 

Background Technical Support Document – Petroleum and Natural Gas Industry 160
M16 Wet Seal Oil Degassing OEL during a Blowdown 

M17 Wet Seal Oil Degassing OEL during Shutdown at Intermediate Pressure 

M18 Engine or Turbine Exhaust during Startup 

M19 Engine or Turbine Exhaust during Normal Operation 

The 19 measurements, displayed above, are required to potentially cover all the 

possible compressor operating modes. 

ii. Tanks and Vapor Recovery Units (VRUs) – Emissions from storage tanks can 

potentially be estimated using one of the several options; standard simulation 

software, one time direct measurement of one cycle of tank operations, or using 

engineering methods such as Vasquez Beggs Equation. If no control device is 

present on the tank, then all tank vapors can be assumed to be vented. If control 

devices are present, then the “efficiency” of the control device will have to be 

evaluated by logging different operating modes. These events are displayed in the 

table below, where the owner/operator may have to use its best judgment to 

determine the recovery “efficiency” (percent of vapors recovered during each 

mode). By logging these situations, the overall efficiency for the reporting period 

can be determined. When a vapor recovery unit is operating properly, tank 

emissions are nearly zero. However, when a tank is able to vent freely, it has 

been documented to vent as much as 96 million cubic feet per year of gas64. The 

following table summarizes the situations in which a control device may be 

recovering vapors and when venting may occur. In some cases, both may be 

going on simultaneously. 

VRU Efficiency Considerations 

Control 

functions 

properly 

Valve or 

hatch pops 

open 

Significant leak 

in tank 

structure 

Large “slug” of 

fluids overloads 

device 

Control device 

malfunctions 

Control device 

down for 

maintenance 

Emitting gas × × × × × 

Capturing gas × × × × 

There may be an opportunity to utilize some of the provisions under 40 CFR part 

60 regulating petroleum tanks with liquids at a certain vapor pressure, which may 

require a VRU. 

40 CFR part 60, Subpart K 

(3) A vapor recovery system which collects all VOC vapors and gases 

discharged from the storage vessel, and a vapor return or disposal 

system which is designed to process such VOC vapors and gases so as 

to reduce their emission to the atmosphere by at least 95 percent by 

weight. 

 

64 EPA. Installing Vapor Recovery Units on Crude Oil Storage Tanks. EPA430-B-03-015. October 2003. 

Background Technical Support Document – Petroleum and Natural Gas Industry 161
iii. Other components – Most equipment have different operating modes that may 

affect its magnitude of emissions. Pneumatic actuation instruments will vary 

depending on whether the instrument is actuating or not. Chemical pumps will 

emit depending on the current throughput of chemical through the pump. Valves 

will emit at different rates depending on their configurations (e.g. closed, open, 

half-open). Wellheads may be producing to a production line or venting after 

completion or cleanup. 

There may be an opportunity to utilize some of the provisions under 40 CFR part 

60 regulating natural gas plants, however it may not lead to the “inventory” of 

emissions that the EPA is seeking. 

40 CFR part 60, Subpart KKK Standards of Performance for Equipment Leaks of 

VOC from Onshore Natural Gas Processing Plants. 

Equipment included 

Equipment means each pump, pressure relief device, openended valve or line, valve, compressor, and flange or other 

connector that is in VOC service or in wet gas service, and any 

device or system required by this subpart. 

B. Assessment of potential seasonal differences affecting emissions such as 

operating pressure or throughput: Seasonal changes typically occur in a 

changeover to winter operations but can occur based on any periodic yearly cycle. 

During winter months, throughput to end use may increase while throughput to 

storage may decrease. Remote wells and their facilities may also be shut in during 

winter. The result of these changes is that equipment may cycle between very low 

and very high operating factors through the year and that key operating parameters 

such as line pressure may vary with each season. Seasonal differences can therefore 

be tracked with a detailed prescription of operating modes. 

C. Assessment on other operating parameters that may vary such as gas 

composition, temperatures, and flow rates: Calculation of methane emissions 

depends greatly on gas composition (methane content). While downstream pipelines 

may require that strict composition specifications are met, upstream gas compositions 

can vary widely by well production rates and ages or the bringing of new wells/fields 

online or taking them offline. 

D. Discussion on non-continuous or non-steady emissions and how they may vary 

depending on different equipment modes of operation: Tanks are an example of 

non-steady and non-continuous emissions. Throughput rates and weather both affect 

the rate of emissions as well and control activity can affect the continuity. However, 

all the vapor that evolves from the tank contents will either be vented or collected by 

the control device and the monitoring methods for these have been discussed in 

section A. Pneumatic actuation devices and gas-driven pumps may have noncontinuous emissions as actuations occur or fluid is pumped more or less heavily. 

Background Technical Support Document – Petroleum and Natural Gas Industry 162
E. Potential methods to account for various operational modes in emissions 

monitoring: 

i. Compressors – Operators could log time spent in different operating modes. 

For compressors this may already be automated and recorded, though at 

remote sites operating hours may have to be determined by alternative means 

such as fuel consumption. Determining the resulting emissions can be done in 

several ways: 

1) Require that measurements of all operating modes for each reporting 

period be measured. This may require multiple days of measurement 

collection for each period if equipment modes are not cycled 

frequently. Alternatively, this may require scheduling cycling 

between all modes in a short time span to accommodate data 

collection.

• Advantages: This will provide the most accurate and precise 

emissions inventory data for each reporting period.

• Disadvantages: This increases the burden on companies to 

force all modes of operation for a compressor for each 

reporting period for monitoring purposes. 

2) One inspection and measurement survey can be performed per 

reporting period, but a different operating mode can be surveyed in 

each reporting period to complete collection of emissions from each 

operating mode.

• Advantages: This will decrease the burden of measurement 

and reporting on companies. For established and steady 

operations, the accuracy will likely not deteriorate, i.e. 

compressor blowdown volumes will remain constant.

• Disadvantages: Initially it may take several reporting periods 

before the companies have collected enough data to accurately 

report emissions for compressors when all operating modes are 

considered. Additionally, by the time emissions data for all 

modes of operation are collected, the originally measured mode 

may have changed substantially for facilities with changing 

process conditions.

3) Only normal operation and the most typical operating modes and 

parameters can be measured each reporting period, and previously 

collected measurements for other operating modes can be collected 

with less frequency.

• Advantages: EPA receives reliable data for at the most 

common modes of operation.

• Disadvantages: Burden on companies still increases.

ii. Tanks – Operators may have to track and log time spent in each mode of 

operation. The logs of these operating times can be provided to a junior 

engineer, who can perform the appropriate calculation based on the available 

data. Determining these emissions can be done in several ways: 

Background Technical Support Document – Petroleum and Natural Gas Industry 163
1) Use simulation software and require quarterly collection of key 

parameters such as: liquid hydrocarbon gravity and composition, 

tank vapor composition, tank conditions (temperature and pressure), 

hydrocarbon liquid condition immediately upstream of tank 

(temperature and pressure), average liquid hydrocarbon throughput. 

Perform the emissions simulation for each quarter using the collected 

data and apply the appropriately determined control device operating 

efficiency (if a control device is present) using data logs. 

• Advantages: The most reliable inventory data can be received 

for every reporting period. 

• Disadvantages: The labor and cost burden of performing this 

level of monitoring may increase for a company depending on 

its current internal monitoring practices. 

2) Use simulation software and require collection of key parameter data 

(as described above) once per reporting period. 

• Advantages: The burden of monitoring is diminished on the 

owner/operator for the reporting period. 

• Disadvantages: Less reliable data will be reported and does not 

capture changes in the process that may occur within a 

reporting period due to seasonal or operational changes. 

iii. Downstream (Transmission and Storage) Reporting Considerations – As 

discussed earlier, the increased demand in cooler months affects gas systems 

such that downstream pipeline throughput increases and operating pressures 

are increased, and that gas is withdrawn from storage. Alternatively, during 

warm months the pipeline throughput and pressures decrease while gas is 

injected into storage. Options for accounting for downstream emissions 

include: 

1) Potentially define warm and cool seasons by fixed months or by 

average temperature for each month. Entities can then perform 

monitoring twice annually (once at peak demand, once at low 

demand for normal operations) to estimate emissions for the warm 

and cool seasons; then extrapolate the measured/monitored 

emissions for the entire season and total for the reporting period. 

• Advantages: The most accurate emissions data for the 

represented reporting period can be obtained. 

• Disadvantages: Economic and labor burden could be 

significant, as would be required to monitor more than one 

time per year. Costs would be further impacted by the method 

required to monitor emissions. 

2) Potentially define warm and cool seasons, as discussed in the 

previous bullet. Companies can then monitor emissions once per 

period (year), but alternate measurements for peak demand (cold 

season) every other reporting period, and low demand (warm season) 

in the remaining seasons. After year 1, it will use the most current 

Background Technical Support Document – Petroleum and Natural Gas Industry 164
monitoring data for each season to estimate emissions from the 

reporting period. 

• Advantages: Data that represents both seasons can be received. 

• Disadvantages: The first reporting will be inaccurate since it 

will be estimated as if peak demand is reached for the entire 

period. Subsequent reporting periods will continue to have 

some level of uncertainty because it requires using data from 

the previous year. 

3) Potentially define an intermediate period between the peak demand 

and low demand that can be assumed to be representative of the 

average over the course of the year. 

• Advantages: This can be easier for the companies to track and 

plan for if the same monitoring time can be used each reporting 

period. It does not increase the burden of monitoring for 

reporting entities. 

• Disadvantages: It will be difficult to determine where the 

representative operating conditions are achieved. 

3. Data Sources for Research 

• Clean Air Act 

o EPA Method 21 

o EPA Method 21 AWP 

• Industry published standard operating procedures 

o API Leak Detection Standards 

o AGA Leak Detection Standards 

Background Technical Support Document – Petroleum and Natural Gas Industry 165
Appendix N: Identifying gas compositions for emissions estimates 

This appendix summarizes the research to identify gas composition sampling needed to 

quantify CH4 and CO2 emissions in estimates of natural gas emissions from direct 

measurements, engineering calculations, or the use of emissions factors. 

Sources that could be affected by gas composition changes

1. The initial proposed rule provided leeway on how gas composition could be estimated. A 

facility could estimate gas composition from continuous monitoring equipment, or a 

couple of samples per year. This could lead to GHG under or over reporting if the 

regulated entity selects samples that are not representative of the emissions source. 

2. The composition of produced gas varies widely from well to well, and over time the 

composition will change for the same well. The initial proposed rule language could be 

interpreted as a composite gas composition that represents all the wells. Again the issue 

of how the gas composition estimate is derived is not defined. This will impact GHG 

reporting for Offshore E&P and for Onshore E&P. 

3. The gas composition a processing plant receives will vary over the period of one year for 

example as wells are taken off-line for maintenance activities; new well volumes are sent 

to a gas plant; and as the composition and volumes of exiting wells change over time. 

Gas processing plants are not always owned and operated by the gas producer. This will 

result in different feed gas compositions as the gas plant starts and ends contracts for 

taking gas from different producers. 

4. For gas plants the initial proposed rule states that only two gas composition estimates are 

used for the “feed natural gas” upstream of the de-methanizer, and “residue gas” 

downstream of the de-methanizer. This can be clarified as “downstream of the demethanizer overhead”. 

Summary 

To minimize the cost burden and also achieve a more representative gas composition and 

therefore more accurate emissions estimation, quarterly samples could be made. In addition 

the following stream compositions could be used for estimating GHG emissions from natural 

gas; 

1. Gas Processing Facilities: “feed natural gas” can be used for all emissions sources 

upstream of the de-methanizer

2. Gas Processing Facilities: “residue gas” to transmission pipeline systems can be used 

for all related emissions sources downstream of the de-methanizer overhead

3. Gas Processing Facilities: gas i) entering and ii) exiting the acid gas removal unit 

which can be used to calculate the AGR vent emissions and for all emissions of 

related sources 

4. Offshore and Onshore Petroleum and Natural Gas Production: produced natural gas 

can be used to estimate GHG emissions from all emissions sources in the facility. 

Background Technical Support Document – Petroleum and Natural Gas Industry 166
Appendix O: Development of performance criteria and monitoring 

protocol for fugitive measurement techniques 

The purpose of this appendix is to outline relevant sources of documentation on fugitive and 

vented emissions detection and quantification technologies, including available standards of 

performance, use, and calibration. 

1. Issue Identification and Clarification 

A. Brief summary of the changes to LDAR under the newly passed AWP 

The recently promulgated alternative work practice (AWP) allows owners or operators to 

detect VOC or HAP leaking equipment using an optical gas imaging instrument if it is 

capable of imaging compounds in the streams that are regulated by the applicable rule. 

The imaging instrument must provide the operator with an image of both the leak and the 

leak source. Before using the instrument, owners and operators are required to determine 

the mass flow rate that the imaging instrument will be required to image. The mass flow 

rate can be determined using the method provided in sections (i)(2)(i)(A) and (i)(2)(i)(B) 

of the AWP. They are required to conduct a daily instrument check to confirm that the 

optical gas imaging instrument is able to detect leaks at the emission rate by using the 

instrument to view the mass flow rate required to be met exiting a gas cylinder. 

The AWP specifies that the imaging instrument is to be used as a direct replacement for 

other acceptable screening equipment; however, no measurement, record keeping, 

reporting, or other procedures can be replaced because of this. The company still must 

use the standard Method 21 screening equipment in one screening period per year. In 

addition to the record keeping practices already prescribed in the current work practice, 

companies must keep video records of the daily instrument check and leak survey results 

for at least 5 years. The company must document the equipment, process units, and 

facilities for which the optical gas imaging instrument will be/is used. 

The instrument must be used following the manufacturer’s instructions, ensuring that all 

appropriate settings conform to the instructions and parameters. All leaks that can be 

viewed with the instrument are regulated by the rule, so that they have to be fixed. 

“Optical gas imaging instrument” means an instrument that makes visible emissions that 

may otherwise be invisible to the naked eye. The AWP defines leaks as “any emissions 

imaged by the optical gas instrument; indications of liquids dripping; indications by a 

sensor that a seal or barrier fluid system has failed; or screening results using 40 CFR part 

60, Appendix A-7, Method 21 monitor that exceed the leak definition in the applicable 

subpart to which the equipment is subject.” 

B. Existing performance criteria and protocols for using fugitive emission detection

devices 

Background Technical Support Document – Petroleum and Natural Gas Industry 167
This section reviews existing performance criteria and protocols for using fugitive and 

emission devices. A discussion of current standards of performance follows. 

Method 21 

Section 6 defines equipment specifications and performance criteria for VOC monitoring 

instruments: 

6.1 The VOC instrument detector shall respond to the compounds 

being processed. Detector types that may meet this requirement 

include, but are not limited to, catalytic oxidation, flame ionization, 

infrared absorption, and photoionization. 

6.2 The instrument shall be capable of measuring the leak definition 

concentration specified in the regulation. 

6.3 The scale of the instrument meter shall be readable to ±2.5 

percent of the specified leak definition concentration. 

6.4 The instrument shall be equipped with an electrically driven pump 

to ensure that a sample is provided to the detector at a constant flow 

rate. The nominal sample flow rate, as measured at the sample probe 

tip, shall be 0.10 to 3.0 l/min (0.004 to 0.1 ft3

 /min) when the probe is 

fitted with a glass wool plug or filter that may be used to prevent 

plugging of the instrument. 

6.5 The instrument shall be equipped with a probe or probe extension 

or sampling not to exceed 6.4 mm (1/4in) in outside diameter, with a 

single end opening for admission of sample. 

6.6 The instrument shall be intrinsically safe for operation in 

explosive atmospheres as defined by the National Electrical Code by 

the National Fire Prevention Association or other applicable 

regulatory code for operation in any explosive atmospheres that may 

be encountered in its use. The instrument shall, at a minimum, be 

intrinsically safe for Class 1, Division 1 conditions, and/or Class 2, 

Division 1 conditions, as appropriate, as defined by the example code. 

The instrument shall not be operated with any safety device, such as 

an exhaust flame arrestor, removed. 

Section 6.1 is a performance criterion that defines which types of detection devices may be 

used (all of the devices proposed for use in the initial rule proposal are covered here) and 

specifies that the instrument must be responsive to the compounds being processed. Section 

6.2 indicates that the instrument shall be capable of accurately measuring the specified leak 

definition and section 6.3 defines the lower limit of instrument detection range or the highest 

concentration before there are no detectable emissions.

Sections 6.4 and 6.5 would not be applicable to portable monitoring devices that do not have 

probe extensions for sampling leaks. These specifications could still be applied specifically 

for portable VOC monitoring devices under the initial rule proposal. Section 6.6 is a 

reasonable performance criterion to adopt as it specifies that the detection device must 

conform to safe operating standards for use in explosive atmospheres. 

Background Technical Support Document – Petroleum and Natural Gas Industry 168
Section 7 of Method 21 covers leak detection device calibration and performance evaluation. 

It specifies the types of calibration gases that may be used as well as specifications for 

prepared gases and mixed compound gases that may be used for calibration. 

Section 8 details specifications for performance of the leak detection devices. The device 

must meet requirements for the response factor, calibration precision, and response time. 

These performance requirements are needed to ensure that the device will respond to the gas 

of interest, provide reasonably accurate measurements of leak concentration, and take an 

appropriate leak sample. Section 8 also describes leak detection procedures for individual 

components. Leak detection procedures are defined for the following sources within Method 

21: 

i. valves 

ii. flanges and other connectors 

iii. pumps and compressors 

iv. pressure relief devices 

v. process drains 

vi. open-ended lines or valves 

vii. seal system degassing vents and accumulator vents 

viii. access door seals 

Alternative Work Practice to Detect Leaks from Equipment

Performance criteria for optical gas imaging instruments are disclosed in the AWP 

document. 

(1)Instrument Specifications. The optical gas imaging instrument must 

comply with the requirements in (i)(1)(i) and (i)(1)(ii) of this section. 

(i)Provide the operator with an image of the potential leak points for 

each piece of equipment at both the detection sensitivity level and 

within the distance used in the daily instrument check described in 

paragraph (i)(2) of this section. The detection sensitivity level depends 

upon the frequency at which leak monitoring is to be performed. 

(ii)Provide a date and time stamp for video records of every 

monitoring event. 

(2)Daily Instrument Check. On a daily basis, and prior to beginning 

any leak monitoring work, test the optical gas imaging instrument at 

the mass flow rate determined in paragraph (i)(2)(i) of this section in 

accordance with the procedure specified in paragraphs (i)(2)(ii) 

through (i)(2)(iv) of this section for each camera configuration used 

during monitoring (for example, different lenses used), unless an 

alternative method to demonstrate daily instrument checks has been 

approved in accordance with paragraph (i)(2)(v) of this section. 

(i)Calculate the mass flow rate to be used in the daily instrument check 

by following the procedures in paragraphs (i)(2)(i)(A) and (i)(2)(i)(B) 

of this section. 

Background Technical Support Document – Petroleum and Natural Gas Industry 169
(ii) Start the optical gas imaging instrument according to the 

manufacturer’s instructions, ensuring that all appropriate settings 

conform to the manufacturer’s instructions. 

(iii) Use any gas chosen by the user that can be viewed by the optical 

gas imaging instrument and that has a purity of no less than 98 

percent. 

(iv) Establish a mass flow rate by using the following procedures: 

(A) Provide a source of gas where it will be in the field of view of the 

optical gas imaging instrument. 

(B) Set up the optical gas imaging instrument at a recorded distance 

from the outlet or leak orifice of the flow meter that will not be 

exceeded in the actual performance of the leak survey. Do not exceed 

the operating parameters of the flow meter. 

(C) Open the valve on the flow meter to set a flow rate that will create 

a mass emission rate equal to the mass rate specified in paragraph 

(i)(2)(i) of this section while observing the gas flow through the optical 

gas imaging instrument viewfinder. When an image of the gas 

emission is seen through the viewfinder at the required emission rate, 

make a record of the reading on the flow meter. 

(v)Repeat the procedures specified in paragraphs (i)(2)(ii) through 

(i)(2)(iv) of this section for each configuration of the optical gas 

imaging instrument used during the leak survey. 

(vi)To use an alternative method to demonstrate daily instrument 

checks, apply to the Administrator for approval of the alternative 

under § 60.13(i). 

(3)Leak Survey Procedure. Operate the optical gas imaging 

instrument to image every regulated piece of equipment selected for 

this work practice in accordance with the instrument manufacturer’s 

operating parameters. All emissions imaged by the optical gas 

imaging instrument are considered to be leaks and are subject to 

repair. All emissions visible to the naked eye are also considered to be 

leaks and are subject to repair. 

Additional Sources Investigated

Other sources of data were researched to find additional information on leak detection 

device performance criteria. The CDM AM0023 methodology for leak detection and 

repair at natural gas transmission compressor stations and distribution gate stations 

outlines a procedure for systematic leak detection. This procedure does not provide any 

detailed performance criteria for the leak detection devices themselves. However 

AM0023 specifies that portable monitoring instruments such as the OVA and TVA may 

be used for leak detection but not measurement. For leak measurement, AM0023 

specifies that one of five methods be used: rotameters, high volume sampler, flowthrough bagging, calibrated bagging and ultrasonic. The American Petroleum Institute 

and American Gas Association publish leak detection standards that may contain 

additional performance criteria for leak detection devices that may be applicable to the 

initial rule proposal. 

Background Technical Support Document – Petroleum and Natural Gas Industry 170
 

C. What information is available on existing performance criteria and protocols for 

using fugitive measurement detection devices and how can it be collected and 

modified for the EPA rule 

Method 21 was developed in the 70’s and 80’s to find and reduce emissions from leaks 

that were not easily detectable by other means. Although the method was not developed 

to quantify leak rates, EPA has published the “Protocol for Equipment Leak Emission 

Estimates.”65 This document covers quantification of leak rates through the use of 

SOCMI or petroleum industry correlations and Method 21 leak concentration 

measurements. This document also describes flow-through and vacuum bagging 

techniques for mass emission sampling. These quantification methods are not included as 

part of the initial rule proposal however, pieces of the flow-through bagging procedure 

may be applicable to emissions measurements using calibrated bags. Section 4.3 covers 

source enclosure of specific leaking components such as valves, pumps and agitators, 

compressors, connectors, and relief valves. 

Method 2C66 in Appendix A of CFR Title 40 Part 60 defines a procedure for measuring 

the stack gas velocity and volumetric flow rate. This method can be used for estimating 

fugitive and vented emissions from flare stacks and compressor wet seal degassing vents 

as discussed in the initial proposed rule. This method refers back to Method 2 for 

performance criteria of pitot tubes. This information could be adapted for use in the 

Fugitive GHG Reporting Rule. 

D. Performance criteria and past precedent for existing relevant regulations under the 

Clean Air Act. 

Performance criteria for fugitive detection devices include the following general aspects: 

i. The detection device should respond to the compounds being processed. Detector 

types that may meet this requirement include organic vapor analyzers, toxic vapor 

analyzers, infrared detection devices (imaging and pointing devices). 

(1) Both Method 21 and its AWP state this performance criterion first (as seen in 

Method 21 paragraph 6.1 and AWP instrument specifications (e)(1)(i)). This 

performance criterion ensures that leak detection surveys will be carried out 

using equipment that is able to detect the presence of the fugitive methane 

emissions and pinpoint the leak location. 

ii. The detection device shall be intrinsically safe for operation in explosive 

atmospheres. 

(1) Method 21 specifies this in paragraph 6.6. This performance criterion pertains 

to the safety of the operator performing the leak detection survey. Fugitive 

methane emissions have the potential to combine with air in a flammable 

 

65 US EPA. “Protocol for Equipment Leak Emission Estimates”. EPA-453/R-95-017 66 http://ecfr.gpoaccess.gov/cgi/t/text/textidx?c=ecfr&sid=75ed3a088a2e23401559636e29116342&rgn=div9&view=text&node=40:7.0.1.1.1.0.1.1.1&idno=40

Background Technical Support Document – Petroleum and Natural Gas Industry 171
mixture. It is necessary that a leak detection survey that is looking for methane 

releases into the atmosphere does not introduce any possible ignition source. 

(2) The AWP, however, does not reference the intrinsic safety issue of optical 

imaging devices. The onus of the safety of the device is on the reporter and 

manufacturer of the device. 

iii. Two gas mixtures are required for instrument calibration. A zero gas and a 

methane reference gas should be used to determine that the leak detection device 

is functioning correctly and will be able to pinpoint leak locations during a 

survey. 

iv. Calibration precision test must be completed prior to placing the detection device 

into service and at subsequent 3 month intervals or at the next use, whichever is 

later. 

(1) Method 21 and the infrared imaging AWP both prescribe methods for 

calibration of the instrument. These are potentially applicable to the 

monitoring rule. 

Additional performance criteria should be defined for the various types of detection 

devices. Performance Criteria specific to OVAs and TVAs has been well defined in 

Method 21. Information on performance criteria may be derived for infrared imaging 

devices from the recent AWP for Method 21. 

Very little information has been found relating to performance criteria for leak 

measurement devices. As with leak detection devices it is difficult to define performance 

criteria that will be applicable to all devices named as appropriate measurement tools in 

the initial rule proposal. Method 2C provides equipment specifications for pitot tubes. 

2. Evaluation Criteria and Approach 

A. Review of existing performance criteria in the CAA and if they are applicable to fugitive 

GHG emissions 

i. Method 21 provides performance criteria for portable VOC monitoring devices to 

detect equipment fugitives. These can be adapted so that references to VOCs are 

converted to methane and the frequency of confirmation of performance/ 

calibration is better aligned with the frequency of monitoring associated with this 

rule. 

ii. The AWP provides performance criteria for optical VOC imaging cameras to 

detect equipment fugitives. These can be adapted so that references to VOCs are 

converted to methane and the frequency of confirmation of performance/ 

calibration is better aligned with the frequency of monitoring associated with this 

rule. 

B. CARB Mandatory Greenhouse Gas Emissions Reporting 

(1) For reference, the CARB rule for fugitive methane emissions was reviewed. 

CARB relies on Method 21, screening values and correlations, and VOCs to 

methane conversion factor. 

Background Technical Support Document – Petroleum and Natural Gas Industry 172
Equipment fugitive methane emissions methods are based upon your local 

AQMD/APCD Leak Detection and Repair (LDAR) procedures. You will need to 

extend your LDAR monitoring to all gas service components. This includes all 

components carrying natural gas, refinery fuel gas, and low Btu gases. All 

components should be identified as one [of] the following six classification types: 

valve, pump seal, connector, flange, open-ended pipe, and other. For guidance 

you should consult and use the Component Identification and Counting 

Methodology found in the following CAPCOA (1999) document: 

California Implementation Guidelines for Estimating Mass Emissions of Fugitive 

Hydrocarbon Leaks at Petroleum Facilities, CAPCOA and CARB, 1999. 

www.arb.ca.gov/fugitive/fugitive.htm 

All gas service components should be screened using a monitoring instrument 

capable of detecting methane. Screenings should be conducted at the frequency 

interval required by your local air district. Specific screening procedures and 

instrument calibration requirements can be found in EPA Reference Method 21 

published in 40 CFR 60, Appendix A (EPA Method 21), 

www.epa.gov/ttn/emc/promgate/m-21.pdf. 

First identify and screen your gas service components. Component screening 

values will be used to calculate methane emissions. The CAPCOA document 

referenced above provides several methods by which VOC emissions may be 

calculated using component screening values. You will use Method 3: the 

Correlation Equation Method with modifications as required by the procedures 

that your local AQMD/APCD has put in place. You will calculate VOC emissions 

for three categories of components based on the component screening value: 

1. Zero components – where the screening value, corrected for background is 

indistinguishable from zero. 

2. Leaking components – components with screening values greater than zero but 

less than the screening value limit above which the local AQMD/APCD does not 

allow the use of correlation equations for the calculation of VOC emissions. 

This upper bound screening value is either 9,999 ppmv or 99,999 ppmv. 

3. Pegged components with SVs above the upper SV/correlation equation limit. 

After you have calculated VOC emissions for all your zero components, leaking 

components and pegged components, sum the three to obtain your fugitive 

equipment VOC emissions. The sum total of VOC emissions is then multiplied by 

CF, a VOC to CH4 conversion factor and a kg to metric tons conversion factor 

(0.001) to calculate total methane emissions. 

In most cases you should be able to determine a system specific VOC to methane 

conversion factor (CF) based on determinations of gas composition and methane 

content from fuel analysis. In cases where fuel analysis data is available, use the 

mass CH4/mass fuel ratio to calculate a system specific CF. In cases where 

representative data is not available you should use a default CF value of 0.6. 

Background Technical Support Document – Petroleum and Natural Gas Industry 173
B. In general, all screening devices do not quantify the mass or volumetric magnitude of 

leaks 

i. Wind can distort the size of a leak as seen through the camera. Point source 

suction devices that are screening leaks within touching distance (<1 cm from 

leak source) do not necessarily encompass an entire leak volume. Currently in the 

rule §98.234 (d)(4), weather is addressed such that monitoring using infrared 

imaging devices must be performed under favorable conditions (such as weather). 

ii. Evaluate existing screening protocols such as LDAR/Method21. 

Infrared Imaging Protocol, AWP to Method 21, Paragraph (g)(4)(i-vii)

(3) Leak survey procedure. Operate the optical gas imaging instrument to 

image every regulated piece of equipment selected for this work practice in 

accordance with the instrument manufacturer’s operating parameters. All 

emissions imaged by the optical gas imaging instrument are considered to be 

leaks and are subject to repair. All emissions visible to the naked eye are also 

considered to be leaks and are subject to repair. 

(4) Recordkeeping. Keep the records described in paragraphs (g)(4)(i) 

through (g)(4)(vii) of this section: 

(i) The equipment, processes, and facilities for which the owner or operator 

chooses to use the alternative work practice. 

(ii) The detection sensitivity level selected from Table 3 to subpart A of this 

part for the optical gas imaging instrument. 

(iii) The analysis to determine the piece of equipment in contact with the 

lowest mass fraction of chemicals that are detectable, as specified in paragraph 

(g)(2)(i)(A) of this section. 

(iv) The technical basis for the mass fraction of detectable chemicals used in 

the equation in paragraph (g)(2)(i)(B) of this section. 

(v) The daily instrument check. Record the distance, per paragraph 

(g)(2)(iv)(B) of this section, and the flow meter reading, per paragraph 

(g)(2)(iv)(C) of this section, at which the leak was imaged. Keep a video record of 

the daily instrument check for each configuration of the optical gas imaging 

instrument used during the leak survey (for example, the daily instrument check 

must be conducted for each lens used). The video record must include a time and 

date stamp for each daily instrument check. The video record must be kept for 5 

years. 

(vi) Recordkeeping requirements in the applicable subpart. A video record 

must be used to document the leak survey results. The video record must include a 

time and date stamp for each monitoring event. A video record can be used to 

meet the recordkeeping requirements of the applicable subparts if each piece of 

regulated equipment selected for this work practice can be identified in the video 

record. The video record must be kept for 5 years. 

(vii) The results of the annual Method 21 screening required in paragraph 

(f)(7) of this section. Records must be kept for all regulated equipment specified in 

paragraph (f)(1) of this section. Records must identify the equipment screened, 

the screening value measured by Method 21, the time and date of the screening, 

and calibration information required in the existing applicable subparts. 

Background Technical Support Document – Petroleum and Natural Gas Industry 174
 

Method 21, Section 8.3

8.3 Individual Source Surveys. 

8.3.1 Type I - Leak Definition Based on Concentration. Place the probe inlet 

at the surface of the component interface where leakage could occur. Move 

the probe along the interface periphery while observing the instrument 

readout. If an increased meter reading is observed, slowly sample the 

interface where leakage is indicated until the maximum meter reading is 

obtained. 

Leave the probe inlet at this maximum reading location for approximately two 

times the instrument response time. If the maximum observed meter reading is 

greater than the leak definition in the applicable regulation, record and report 

the results as specified in the regulation reporting requirements. Examples of 

the application of this general technique to specific equipment types are: 

8.3.1.1 Valves. The most common source of leaks from valves is the seal 

between the stem and housing. Place the probe at the interface where the stem 

exits the packing gland and sample the stem circumference. Also, place the 

probe at the interface of the packing gland take-up flange seat and sample the 

periphery. In addition, survey valve housings of multipart assembly at the 

surface of all interfaces where a leak could occur. 

8.3.1.2 Flanges and Other Connections. For welded flanges, place the probe 

at the outer edge of the flange gasket interface and sample the circumference 

of the flange. Sample other types of nonpermanent joints (such as threaded 

connections) with a similar traverse. 

8.3.1.3 Pumps and Compressors. Conduct a circumferential traverse at the 

outer surface of the pump or compressor shaft and seal interface. If the source 

is a rotating shaft, position the probe inlet within 1 cm of the shaft-seal 

interface for the survey. If the housing configuration prevents a complete 

traverse of the shaft periphery, sample all accessible portions. Sample all 

other joints on the pump or compressor housing where leakage could occur. 

8.3.1.4 Pressure Relief Devices. The configuration of most pressure relief 

devices prevents sampling at the sealing seat interface. For those devices 

equipped with an enclosed extension, or horn, place the probe inlet at 

approximately the center of the exhaust area to the atmosphere. 

8.3.1.5 Process Drains. For open drains, place the probe inlet at 

approximately the center of the area open to the atmosphere. For covered 

drains, place the probe at the surface of the cover interface and conduct a 

peripheral traverse. 

8.3.1.6 Open-ended Lines or Valves. Place the probe inlet at approximately 

the center of the opening to the atmosphere. 

8.3.1.7 Seal System Degassing Vents and Accumulator Vents. Place the probe 

inlet at approximately the center of the opening to the atmosphere. 

8.3.1.8 Access door seals. Place the probe inlet at the surface of the door seal 

interface and conduct a peripheral traverse. 

8.3.2 Type II - "No Detectable Emission". Determine the local ambient VOC 

concentration around the source by moving the probe randomly upwind and 

Background Technical Support Document – Petroleum and Natural Gas Industry 175
downwind at a distance of one to two meters from the source. If an 

interference exists with this determination due to a nearby emission or leak, 

the local ambient concentration may be determined at distances closer to the 

source, but in no case shall the distance be less than 25 centimeters. Then 

move the probe inlet to the surface of the source and determine the 

concentration as outlined in Section 8.3.1. The difference between these 

concentrations determines whether there are no detectable emissions. Record 

and report the results as specified by the regulation. For those cases where 

the regulation requires a specific device installation, or that specified vents be 

ducted or piped to a control device, the existence of these conditions shall be 

visually confirmed. When the regulation also requires that no detectable 

emissions exist, visual observations and sampling surveys are required. 

Examples of this technique are: 

8.3.2.1 Pump or Compressor Seals. If applicable, determine the type of shaft 

seal. Perform a survey of the local area ambient VOC concentration and 

determine if detectable emissions exist as described in Section 8.3.2. 

8.3.2.2 Seal System Degassing Vents, Accumulator Vessel Vents, Pressure 

Relief Devices. If applicable, observe whether or not the applicable ducting or 

piping exists. Also, determine if any sources exist in the ducting or piping 

where emissions could occur upstream of the control device. If the required 

ducting or piping exists and there are no sources where the emissions could 

be vented to the atmosphere upstream of the control device, then it is 

presumed that no detectable emissions are present. If there are sources in the 

ducting or piping where emissions could be vented or sources where leaks 

could occur, the sampling surveys described in Section 8.3.2 shall be used to 

determine if detectable emissions exist. 

C. Leak measurement instruments to be reviewed; review existing instrument protocol 

documents 

i. High volume sampler 

Bacharach provides a user manual for the HiFlow® Sampler on its website. The 

manual has seven chapters, several of which are useful to this rule: 

Chapter 2: Technical Data

This chapter provides specifications such as measurable leak rates from 0.05 to 

8.00 cubic feet per minute (scf/min), sampling flow rate of 10.5 scf/min, accuracy 

of +/- 10%, as well as natural gas sensor specifications. 

Chapter 3: Operation

This chapter discusses operation of the instrument; providing useful protocol steps 

such as: 

a) To ensure gas sensors are properly zeroed, turn the instrument on in clean 

air. 

b) Calibrate the instrument every 30 days to assure accuracy. 

c) Create a maintenance log to track calibration dates, etc. 

d) Always purge the instrument with clean air after testing. 

e) Instructions on how to ground the instrument for safety. 

Background Technical Support Document – Petroleum and Natural Gas Industry 176
f) Instructions on how to equip attachments, use them, and when tips for 

when they are useful. 

g) Instructions on how to use various menus programmed into the 

instrument. 

h) Step-by-step instructions on how to measure leaks (section 3.18 pages 31 

– 37), including what modes (e.g. automatic 2-stage mode) for 

measurement. 

Chapter 4: Calibration

This chapter provides step-by-step instructions on how to calibrate the instrument, 

and provides useful specifications such as using 2 calibration gases: 1) 2.5% CH4 

in air, 2) 100% methane. 

ii. Rotameters 

Rotameters are not complicated instruments. A few key considerations for use of 

a rotameter are: 

a) Using the proper size. Rotameters have ranges of flow rates that they can 

measure. It is important to select the appropriate size so as not to exceed 

or fall below this range. For best results, the leak size should fall toward 

the middle of the acceptable range. 

b) Rotameter use a “float bob” in the measurement, and the readings assume 

the force for gravity pulling down on the float bob. Thus, the rotameter 

must be upright during measurement. 

c) Rotameters require that all of the gas is directed into them, and a tight seal 

is formed around the edges of the inlet so that gas does not escape out the 

sides. This would require a flexible hose or tubing with suitable reducers 

to fit over different size vent pipes. 

d) Greenhouse gas emissions are calculated using the following equation: 

Fi 3600 i ×××××= hgAkw

where, 

Fi = the leak flow rate of greenhouse gas “i” 

wi = the concentration of greenhouse gas “i” in the natural gas 

k = constant provided by the rotameter documentation 

A = annular area between the float and the tube wall 

g = acceleration due to gravity 

h = the pressure drop across the float (as shown by height) 

iii. Turbine meters 

Daniels (subsidiary of Emerson) provides a user manual for its turbine meters. 

This document provides equipment specifications for each of its models, detailed 

instructions for installation and use, as well as maintenance instructions. 

Amongst the key considerations for the use of this instrument are: 

a) The meter should be installed in the horizontal position with the arrow 

pointing in the direction of the flow. 

b) To maintain accuracy, the meter should have an upstream meter tube with 

recommended minimum length of 10 pipe diameters of straight pipe, and a 

Background Technical Support Document – Petroleum and Natural Gas Industry 177
downstream meter tube with recommended minimum length of 5 pipe 

diameters of straight pipe. 

c) A straightening vane should be installed with a minimum of 5 pipe 

diameters upstream of the meter (measured from the downstream end of 

the vane). 

d) For accurate measurement, the meter must be installed in the pipe (metertube) without offsets at the flanges and without gaskets protruding into the 

line bore. 

e) Wet gas may only require inspection of the internal assembly once per 

year, while dusty gas may require inspection every 30 days. 

f) Depending on the model selected, accuracy can be +/- 0.25% of better. 

Operational over a temperature range from 0 to 220°F. 

g) The majority of this 91-page document is dedicated to the use of the 

instrument, including the removal and reassembly of internal assembling 

of the meter for purposes of calibration and measurement. 

iv. Hot wire anemometers 

Do not have adequate info to elaborate on possible performance criteria for this 

measurement device. 

v. Pitot tube 

Accuracy can be more than 1%. 

Method 2C provides details on performance criteria in paragraph 6.1, 6.2, and 6.7 

of Method 2: 

6.1 Standard Pitot Tube (instead of Type S). A standard pitot tube 

which meets the specifications of Section 6.7 of Method 2. Use a coefficient of 

O.99 unless it is calibrated against another standard pitot tube with a NISTtraceable coefficient (see Section 10.2 of Method 2). 

6.2 Alternative Pitot Tube. A modified hemispherical-nosed pitot tube 

(see Figure 2C-1), which features a shortened stem and enlarged impact and 

static pressure holes. Use a coefficient of 0.99 unless it is calibrated as 

mentioned in Section 6.1 above. This pitot tube is useful in particulate liquid 

droplet-laden gas streams when a "back purge" is ineffective.” 

“6.7 Calibration Pitot Tube. When calibration of the Type S pitot tube 

is necessary (see Section 10.1), a standard pitot tube shall be used for a 

reference. The standard pitot tube shall, preferably, have a known coefficient, 

obtained either (1) directly from the National Institute of Standards and 

Technology (NIST), Gaithersburg MD 20899, (301) 975-2002, or (2) by 

calibration against another standard pitot tube with an NIST-traceable 

coefficient. Alternatively, a standard pitot tube designed according to the 

criteria given in Sections 6.7.1 through 6.7.5 below and illustrated in Figure 

2-5 (see also References 7, 8, and 17 in Section 17.0) may be used. Pitot tubes 

designed according to these specifications will have baseline coefficients of 

0.99 ± 0.01. 

6.7.1 Standard Pitot Design. 

Background Technical Support Document – Petroleum and Natural Gas Industry 178
6.7.1.1 Hemispherical (shown in Figure 2-5), ellipsoidal, or conical 

tip. 

6.7.1.2 A minimum of six diameters straight run (based upon D, the 

external diameter of the tube) between the tip and the static pressure holes. 

6.7.1.3 A minimum of eight diameters straight run between the static 

pressure holes and the centerline of the external tube, following the 90E bend. 

6.7.1.4 Static pressure holes of equal size (approximately 0.1 D), 

equally spaced in a piezometer ring configuration. 

6.7.1.5 90E bend, with curved or mitered junction. 

Method 2C provides detail on the protocol for use of a pitot tube for flow rate 

measurement. Below is an excerpt, section 8: 

8.1 Follow the general procedures in Section 8.1 of Method 2, except 

conduct the measurements at the traverse points specified in Method 1A. The 

static and impact pressure holes of standard pitot tubes are susceptible to 

plugging in particulate-laden gas streams. Therefore, adequate proof that the 

openings of the pitot tube have not plugged during the traverse period must be 

furnished; this can be done by taking the velocity head (Δp) heading at the 

final traverse point, cleaning out the impact and static holes of the standard 

pitot tube by "back-purging" with pressurized air, and then taking another 

(Δp) reading. If the Δp readings made before and after the air purge are the 

same (within ±5 percent) the traverse is acceptable. Otherwise, reject the run. 

Note that if the Δp at the final traverse point is unsuitably low, another point 

may be selected. If "back purging" at regular intervals is part of the 

procedure, then take comparative Δp readings, as above, for the last two back 

purges at which suitably high Δp readings are observed. 

vi. Calibrated bagging 

Calibrated bags are relatively simple instruments to measure flow rates. The key 

concepts are: 

a) Calibrated bagging requires proximity to the leak, requiring user to be 

cautious of safety considerations (e.g. temperature of emissions and vent 

pipe). 

b) Ensure that the entire emission is captured by the bag. 

c) Measure the time required to completely fill the bag. Repeat the process 

at least 3 times to improve accuracy. 

d) The bag must be made of a static material that will not build charge or 

create sparks under any operating conditions. 

2. Data Sources for Research 

• CAA – LDAR program, Method 21 guidance documents 

• Manufacturers information (Heath, FLIR, etc) 

• CDM leak detection methodologies (AM0023) 

3. Summary 

Background Technical Support Document – Petroleum and Natural Gas Industry 179
It is likely that existing performance criteria and protocols may need selective references and 

exclude selective provisions which do not apply for mandatory reporting for the expressed 

purpose of finding and measuring methane leaks for the reporting of GHG emissions. 

Information from Method 21 and the Alternative Work Practice may be adapted into 

performance criteria for OVAs, TVAs, and infrared imaging cameras. These documents do 

not contain any standards for performance criteria of leak measurement devices. 

Manufacturer data may serve as a starting point for developing measurement device 

performance criteria. 

Background Technical Support Document – Petroleum and Natural Gas Industry 180
Appendix P: Discussion on Methodologies in Emission References 

API’s Emission Factors for Oil and Gas Production Operations48

Emissions factors were developed using the following approach: 

1. The contributions of screening values that are less than 10 ppmv; screening values 10 to 

9,999 ppmv; and emitters pegged at 10,000 ppmv were summed for each component 

type. Emissions from components with these screening values were calculated using the 

methods below: 

 a. Emission rates for screening values: < 10 ppmv 

1) EPA default zero values for connectors and open ended lines; and 

2) Emission rates for non-emitters (at 10 ppmv) were used for flanges, pumps, 

valves, and other components. 

b. Emission rates for components with screening rates from 10 ppmv to 9,999 ppmv 

1) Correlation equations from the Protocol for Equipment Leaks Emission Estimates 

(6/1993) were used to calculate emission rates. 

c. Emission rates for components pegged at 10,000 ppmv 

1) EPA 10,000 ppmv pegged emission factors were used to calculate emission rates. 

2. The sum of emissions for each component (from step (1)) was then divided by the total 

number of components of that type to develop average emission factors. 

3. The sum of emissions for each component from step (1a) and step (1b) were divided by 

the total number of components of that type to develop no-leak factors. 

4. The sum of emissions for each component from step (1c) was divided by the total number 

of components of that type to develop leak factors. 

5. The emission factors for each type of component were then separated by facility type (i.e. 

light crude, gas production). 

Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas 

Processing Plants49. AND 

Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas 

Processing Plants and Upstream Gathering Compressor Stations and Well Sites50. 

Emission factors were also developed using the following approach: 

1. Equipment components were screened using bubble tests with soap solution, portable 

hydrocarbon gas detectors and ultrasonic leak detectors. 

a. The majority of the equipment was screened using the bubble test with soap solution 

method. 

b. Ultrasonic detectors were used to screen equipment in areas with low background 

noise levels in the ultrasonic range. 

c. Gas detectors were used to screen equipment that could not be screened using the 

bubble test such as equipment in high-temperature service, certain flanged 

connections and open-ended lines. 

Background Technical Support Document – Petroleum and Natural Gas Industry 181
d. The five facilities surveyed in (Clearstone 2006) conducted supplementary leak 

surveys using a passive midwave infrared camera to qualitatively compare the 

method with the more traditional portable hydrocarbon analyzer method. 

e. Those components found emitting from the bubble test or ultrasonic detectors were 

rescreened with a portable hydrocarbon vapor analyzer to determine whether they met 

the leaker definition. 

f. 10,000 ppmv or greater was used as the “leaker definition.” 

2. A HiFlow® Sampler was used to measure components that exceeded 10,000 ppm. 

a. Equipment leaks that were greater than the upper limit of the unit and most openended lines and vents were not measured using the HiFlow® Sampler. They were 

measured using bagging or other “direct measurement techniques.” 

3. Equipment component counts were conducted. 

4. The average emission factors for each type of component were calculated as follows: 

a. The measured emissions were aggregated by component type which also included 

“non-leaking” components emission rates. The non-leaking emission rates from the 

EPA’s Protocol for Equipment Leak Emission Estimates were used for non-leaking 

components (screening values < 10,000 ppmv). 

b. The aggregate emissions were divided by the number of components to estimate 

average emissions factors. 

Handbook for Estimating Methane Emissions from Canadian Natural Gas Systems51, 

AND 

Measurement of Natural Gas Emissions from the Canadian Natural Gas Transmission 

and Distribution Industry52 

1. Component Screening Process

Leak screening was conducted using ultrasonic leak detectors, bubble tests with soap 

solution and portable hydrocarbon vapor analyzers calibrated to methane. A positive 

qualitative screening process was followed by a quantitative screening process in 

which the screening value, 10,000ppmv, was verified. Components that have a 

screening value equal to or greater than 10,000ppm were categorized as leaking. The 

leak detection survey was conducted in accordance with Method 2167 developed by 

the EPA, and the measurements were conducted in accordance with the Fugitive 

Emissions Measurement Protocol68. 

 

2. Leak Rate Measurement

Emission rates were measured using a variety of techniques that are outlined in 

Section 4 of the Fugitive Emissions Measurement Protocol. The primary instrument 

 

67 U.S. EPA (Environmental Protection Agency). 1997. Method 21 – Determination of Volatile Organic 

Compound Leaks. 

68 Clearstone Engineering Ltd. 2006. Canadian Energy Partnership for Environmental Innovation (CEPEI) – 

Fugitive Emissions Measurement Protocol. 

Background Technical Support Document – Petroleum and Natural Gas Industry 182
used to quantify the emission rate was the HiFlowTM Sampler. However, depending 

on the source type and emission rate, velocity probes (i.e. hot wire anemometer, 

thermal dispersion anemometer, vane anemometer and micro-tip anemometer) and 

flow-through meters (i.e. rotary meter, diaphragm meter and rotameter) were also 

used. Data was collected and reported in accordance to Section 2 of the Fugitive 

Emissions Measurement Protocol. 

3. Component Count

Clearstone Engineering conducted a thorough count of components in the surveyed 

facilities in accordance to the Fugitive Emissions Measurement Protocol. These 

numbers were compared to independent counts provided by facility operators. 

Significant discrepancies were noticed during the comparison as follows: 

 Facility operators used piping and instrumentation drawing that 

underestimated the number of components. The drawings did not have the 

detail required to make an accurate component count. 

 Facility operators did not use a systematic approach as stipulated by the 

Fugitive Emissions Measurement Protocol leading to double counting or 

undercounting. 

When developing the average emission factors, the Clearstone component counts 

were used. 

4. Emission Factors

a. Average Emission Factors

Average emission factors include emissions rates from leaking and non-leaking 

components. Emission rates from leaking components were measured using the 

procedure described earlier. Non-leaking components were assigned emission rates 

found in EPA’s Protocol for Equipment Leak Emission Estimates69. Prior to 

calculating average emission factors, components were grouped into the following 

source categories: centrifugal compressor seal, reciprocating compressor seal, 

connector, control valve, controller, blowdown system, open-ended line, orifice 

meter, other flow meter, pressure regulator, pressure relief valve and valve. Finally, 

average emission factors were calculated by summing the total organic emission in 

each source category and dividing by the corresponding component count. 

A 95 percent confidence interval limit was created for the average emission factors in 

each source category. Total organic emissions were calculated for the entire company 

using average emission factors utilizing the following equation; 

= ∑∑ ⋅⋅ i jER , XNEF jiji

 where 

i denotes the source category, 

j denotes the facility type (i.e. transmission or distribution), 

ER is the total emission rate for the target source population (kg/h), 

 EF is the average emission factor (kg TOC/h/source), 

 

69 US EPA. 1995. Protocol for Equipment Leak Emission Estimates. Publication No. EPA-453/R-95-017 

Background Technical Support Document – Petroleum and Natural Gas Industry 183
 N is the number of source, 

 X is the mass fraction of the target pollutant in the process fluid. 

b. Screening Range Approach

Leaking components were separated from non-leaking components. As described 

earlier, components found to have a screening value greater than or equal to 

10,000ppmv were labeled as leaking. Subsequently, the components were categorized 

into the source groups. Leaker factors were calculated by summing the emission rates 

from leaking components in a particular source group and dividing by the number of 

corresponding component count. Non-leaking components are assigned emission 

rates found in EPA’s Protocol for Equipment Leak Emission Estimates. 

Total organic emissions for the entire company was calculated using leaker and nonleaker emission factors using the following equation; 

∑∑( ) ( ⋅+⋅= )

i j

ETOC GG , ji NFNF LL , ji

 

 where 

i denotes the source category, 

j denotes the facility type (i.e. transmission or distribution), 

ETOC is emission rate for an equipment type (kg/hr), 

FG is applicable emission factor for sources with screening values ≥

10,000 ppmv (kg/hr/source), 

NG is equipment count (specific equipment type) for sources with 

screening values ≥ 10,000 ppmv, 

FL is applicable emission factor for sources with screening values < 

10,000 ppmv (kg/hr/source), 

NL is equipment count (specific equipment type) for sources with 

screening values < 10,000 ppmv. 

Background Technical Support Document – Petroleum and Natural Gas Industry 184
Appendix Q: 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 carbon dioxide (CO2) contaminants that 

are separated from sour natural gas by an acid gas removal. 

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 stack 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 low Btu natural gas (i.e., high non-combustible component 

content). 

Blowdown vent stack emissions mean natural gas released due to maintenance and/or 

blowdown operations including but not limited to 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 a 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 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 from escaping to the atmosphere. 

Centrifugal compressor dry seals emissions mean natural gas 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 venting emissions means emissions that 

occur when the high-pressure oil barriers for centrifugal compressors are depressurized to 

Background Technical Support Document – Petroleum and Natural Gas Industry 185
release absorbed natural gas. 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. 

Coal Bed Methane (CBM) means natural gas which is extracted from underground 

coal deposits or “beds.” 

Component, for the purposes of subpart W only, means but is not limited to 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. 

Compressor means any machine for raising the pressure of a natural gas by drawing 

in low pressure natural gas and discharging significantly higher pressure natural gas. 

Condensate means hydrocarbon and other liquid separated from natural gas that 

condenses due to changes in the temperature, pressure, or both, and remains liquid at storage 

conditions, includes both water and hydrocarbon liquids. 

Conventional wells mean gas wells in producing fields that do not employ hydraulic 

fracturing to produce commercially viable quantities of natural gas. 

Dehydrator means a device in which a liquid absorbent (including but not limited to 

desiccant, ethylene glycol, diethylene glycol, or triethylene glycol) directly contacts a natural 

gas stream to absorb water vapor. 

Dehydrator vent stack emissions means natural gas released from a natural gas 

dehydrator system absorbent (typically glycol) reboiler or regenerator, 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. Desiccants include activated alumina, palletized calcium chloride, 

lithium chloride and granular silica gel material. Wet natural gas is passed through a bed of 

the granular or pelletized solid adsorbent in these dehydrators. As the wet gas contacts the 

surface of the particles of desiccant material, water is adsorbed on the surface of these 

desiccant particles. Passing through the entire desiccant bed, almost all of the water is 

adsorbed onto the desiccant material, leaving the dry gas to exit the contactor. 

E&P Tank means the most current version of an exploration and production field tank 

emissions equilibrium program that estimates flashing, working and standing losses of 

Background Technical Support Document – Petroleum and Natural Gas Industry 186
hydrocarbons, including methane, from produced crude oil and gas condensate. Equal or 

successors to E&P Tank Version 2.0 for Windows Software. Copyright (C) 1996-1999 by 

The American Petroleum Institute and The Gas Research Institute. 

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 rule, EOR applies to injection of critical phase carbon 

dioxide into a crude oil reservoir to enhance the recovery of oil. 

Field means standardized field names and codes of all oil and gas fields identified in 

the United States as defined by the Energy Information Administration Oil and Gas Field 

Code Master List. 

Flare combustion efficiency means the fraction of natural gas, on a volume or mole 

basis, that is combusted at the flare burner tip. 

Flare combustion means unburned hydrocarbons including CH4, CO2, N2O emissions 

resulting from the incomplete combustion of gas in flares. 

Fugitive emissions means those emissions which are unintentional and could not 

reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening. 

Fugitive emissions detection means the process of identifying emissions from 

equipment, components, and other point sources. 

Gas conditions mean the actual temperature, volume, and pressure of a gas sample. 

Gas gathering/booster stations mean centralized stations where produced natural gas 

from individual wells is co-mingled, compressed for transport to processing plants, 

transmission and distribution systems, and other gathering/booster stations which co-mingle 

gas from multiple production gathering/booster stations. Such stations may include gas 

dehydration, gravity separation of liquids (both hydrocarbon and water), pipeline pig 

launchers and receivers, and gas powered pneumatic devices. 

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. 

High-Bleed Pneumatic Devices are 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 which is regulated by 

Background Technical Support Document – Petroleum and Natural Gas Industry 187
the process condition flows to a valve actuator controller where it vents (bleeds) to the 

atmosphere at a rate in excess of six standard cubic feet per hour. 

Liquefied natural gas (LNG) means natural gas (primarily methane) that has been 

liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric pressure. 

LNG boiloff 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 which is regulated by 

the process condition flows to a valve actuator controller where it vents (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 tidal-affected borders of the U.S. lands, both state and Federal, 

adjacent to oceans, bays, lakes or other normally standing water. 

Onshore petroleum and natural gas production owner or operator means the entity 

who is the permitee to operate petroleum and natural gas wells on the state drilling permit or 

a state operating permit where no drilling permit is issued by the state, which operates an 

onshore petroleum and/or natural gas production facility (as described in §98.230(b)(2). 

Where more than one entity are permitees on the state drilling permit, or operating permit 

where no drilling permit is issued by the state, the permitted entities for the joint facility must 

designate one entity to report all emissions from the joint facility. 

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 by positive displacement, employing linear movement of a shaft driving a 

piston in a cylinder. 

Background Technical Support Document – Petroleum and Natural Gas Industry 188
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 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/o r gases. A reservoir is characterized by a 

single natural pressure system. 

Sales oil means produced crude oil or condensate measured at the production lease 

automatic custody transfer (LACT) meter or custody transfer meter tank gauge. 

Sour natural gas means natural gas that contains significant concentrations of 

hydrogen sulfide and/or carbon dioxide 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) CO2) that 

does not require (or has already had) acid gas treatment to meet pipeline corrosionprevention specifications for transmission and distribution. 

Transmission pipeline means high pressure cross country pipeline transporting 

sellable 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. 

Unconventional wells means gas well in producing fields that employ hydraulic 

fracturing to enhance gas production volumes. 

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 but 

not limited to process designed flow to the atmosphere through seals or vent pipes, 

Background Technical Support Document – Petroleum and Natural Gas Industry 189
equipment blowdown for maintenance, and direct venting of gas used to power equipment 

(such as pneumatic devices). 

Well Completions means a 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. This process includes high-rate back-flow of injected water and sand used to 

fracture and prop-open fractures in low permeability gas reservoirs. 

Well Workover means the performance of one or more of a variety of remedial 

operations on producing oil and gas wells to try to increase production. This process also 

includes high-rate back-flow of injected water and sand used to re-fracture and prop-open 

new fractures in existing low permeability gas reservoirs. 

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. 

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 190
Appendix R: References 

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Guidelines for the Natural Gas Distribution Sector. 

API (2004) Compendium of Greenhouse Gas Emissions Estimation Methodologies for the 

Oil and Gas Industry. 

<http://www.api.org/ehs/climate/new/upload/2004_COMPENDIUM.pdf>. 

API. (2007) Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well 

Technology. 

<http://www.api.org/aboutoilgas/sectors/explore/upload/API_CO2_Report_August2007.pdf> 

Bacharach, Inc. (2005) HiFlow® Sampler Natural Gas Leak Rate Measurement: Instruction 

55-9017, Operation & Maintenance. < http://www.bacharach-inc.com/PDF/Instructions/55-

9017.pdf>. 

Bureau of Economic Analysis (2007) Table 1.1.9. Implicit Price Deflators for Gross 

Domestic Product. <http://www.bea.gov/bea/dn/nipaweb/TableView.asp#Mid>. 

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> 

California Environmental Protection Agency (2007) Rulemaking to Consider Adoption of a 

Regulation for the Mandatory Reporting of Greenhouse Gas Emissions. 

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The Climate Registry (2007) General Reporting Protocol for the Voluntary Reporting 

Program. < http://www.theclimateregistry.org/>. 

DOE/ NETL (2009). Electricity Use of Enhanced Oil Recovery with Carbon Dioxide (CO2-

EOR). < http://www.netl.doe.gov/energy-analyses/pubs/Electricity%20Use%20of%20CO2-

EOR.pdf> 

DOE/ NETL (2008). Storing CO2 with Enhanced Oil Recovery. DOE/NETL-402/1312/02-

07-08 

EIA (2006) Underground Storage Field Level Data From EIA-191A. 

<http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/undrgrnd

_storage.html>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 191
EIA (2008) Official Energy Statistics from the U.S. Government Glossary. 

<http://www.eia.doe.gov/glossary/index.html>. 

Emery, Brian 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< 

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EPRI (1999).Enhanced Recovery Scoping Study. 

http://www.energy.ca.gov/process/pubs/electrotech_opps_tr113836.pdf

GRI (1992) GRI Report, Methane Emissions from the Natural Gas Industry, Volumes 1- 15. 

Energy Information Agency (U.S. DOE) 

EU ETS (2004) Establishing Guidelines for the Monitoring and Reporting of Greenhouse 

Gas Emissions. < http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2004:059:0001:0074:EN:PDF>. 

FERC (2008) Existing LNG Terminals. <http://ferc.gov/industries/lng.asp>. 

FLIR (2006) ThermaCAM® GasFindIRTM Brochure. 

<http://www.flirthermography.com/media/GasFindIR%20Brochure.pdf>. 

GOADS (2000). Gulfwide Offshore Activity Data System. 

<http://www.gomr.mms.gov/homepg/regulate/environ/airquality/goad.html > 

GRI (1992) GRI Report, Methane Emissions from the Natural Gas Industry, Volumes 1- 15. 

Energy Information Agency (U.S. DOE)

GRI (2008) GRI-GLYCalcTM Software Program. 

<http://www.gastechnology.org/webroot/app/xn/xd.aspx?it=enweb&xd=1ResearchCap/1_5E

andP/1_5_1_AreasOfRsch/Gas_Processing/GP_Dehydration/GRIGLYCalcFactSheet.xml>. 

GTI (1999), Gas Resource Database: Unconventional Natural Gas and Gas Composition 

Databases, 2nd Edition CD-ROM 

GTI(2007) The World Energy Source Book – Fourth Edition, An Encyclopedia of the World 

LNG Industry, GTI 07/0002

INGAA (2008) Greenhouse Gas Emissions Estimation Guidelines for Natural Gas 

Transmission and Storage, Volume 1. <http://www.ingaa.org/cms/33/1060/6435.aspx>. 

IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories. 

<http://www.ipcc-nggip.iges.or.jp/public/2006gl/index.html>. 

Background Technical Support Document – Petroleum and Natural Gas Industry 192
IPIECA (2003) Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions. 

<http://www.ipieca.org/activities/climate_change/downloads/publications/ghg_guidelines.pd

f>. 

Lasser Production Data, Version 3.0.8 

MMS (2000) Goads Summary Access File "Final GOADS Emissions Summaries”. 

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0GulfwideEmissionInventory.html>. 

NESHAP (accessed 2008) 40 CRF Part 63. 

<http://www.tceq.state.tx.us/permitting/air/rules/federal/63/63hmpg.html>. 

OGJ (2006) Worldwide Gas Processing Survey. <http://www.ogj.com> 

OGJ (2006) EOR/ Heavy Oil Survey. 

OGJ (2007) Worldwide Gas Processing Survey. <http://www.ogj.com> 

New England Governors and Eastern Canadian Premiers (2003) Resolution Concerning 

Environmental Projects Issues. <http://www.negc.org/03resolutions/res28_7.html>. 

New Mexico State (2008) New Mexico Green House Gas Mandatory Emissions Inventory 

Emissions Quantification Procedures. 

<http://www.nmenv.state.nm.us/aqb/ghg/documents/NM_GHGEI_quantif_proced2008.pdf>.

OPS (2006) Transmission Annuals Data. <http://ops.dot.gov/stats/DT98.htm>. 

Spring, P.S., R.H. Hugman, and E.H. Vidas, (1999) Unconventional Gas Field, Reservoir, 

and Completion Analysis of the Continental United States – 1998 Update. Gas Research 

Institute, Contract 5097-210-4018 

TCEQ (2009) Upstream Oil and Gas Storage Tank Project Flash Emissions Models 

Evaluations. Texas Commission on Environmental Quality, Air Quality Division. TX: 1-73. 

TERC (2009) VOC Emissions from Oil and Condensate Storage Tanks. Texas Environmental 

Research Consortium. The Woodlands, TX: 1-34 Available online at: 

<http://files.harc.edu/Projects/AirQuality/Projects/H051C/H051CFinalReport.pdf> 

U.S. Department of Labor, Bureau of Labor Statistics National Compensation Survey - 

Compensation Cost Trends, Employer Cost for Employee Compensation (ECEC), 

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 

Inventory Program. 

Background Technical Support Document – Petroleum and Natural Gas Industry 193
Background Technical Support Document – Petroleum and Natural Gas Industry 194

U.S. EPA (2007) Natural Gas STAR Emissions Reduction Quantification Reference Guide. 

<http://www.epa.gov/gasstar/docs/quantifying_ngs_methane_reductions.xls>. 

U.S. EPA (2009) Final Mandatory Reporting of Greenhouse Gases Rule. U.S. 

Environmental Protection Agency, Washington D.C. Docket ID No. EPA-HQ-OAR-2008-

0508-2278. 

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

Environmental Protection Agency, Washington D.C. USEPA #430-R-08-005.c Available 

online at: < http://www.epa.gov/climatechange/emissions/downloads/08_CR.pdf> 

U.S. EPA (2008) Natural Gas Methane Units Converter. 

<http://www.epa.gov/gasstar/pdf/unitconverter_final.pdf>. 

WCI (2008) WCI Meetings and Events. 

<http://www.westernclimateinitiative.org/WCI_Meetings_Events.cfm>. 

World Resources Institute and World Business Council for Sustainable Development (2008) 

Corporate Accounting and Reporting Standard. <http://www.ghgprotocol.org/standards>. 

WRAP (2005) Oil and Gas Emissions Inventories for the Western States. 

<http://www.wrapair.org/forums/ssjf/documents/eictts/OilGas/WRAP_Oil&Gas_Final_Repo

rt.122805.pdf>.