Gt"'I® 

Unned States 

Envifonmental Prolection 

Agency 

_oEPA Research and 

=====Development 

METHANE EMISSIONS FROM THE 

========:=J\~Au URAL GAS INDUSTRY 

Volume 8: Equipment Leaks 

Prepared for 

Energy Information Administration (U.S. DOE) 

-----Prepared by 

National Risk Management 

--------Research Laboratory 

Research Triangle Park, NC 27711 

GRl-94 / 0257.25 

EPA· 600/R-96-0BOh 

ne 1996 

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FOREWORD 

The U.S. Environmental Protection Agency is charged by Congress with protecting the Nation's land, air. and water resources. Under a mandate of national 

environmental laws, the Agency strives to formulate and implement actions leading to a compatible balar.~e between human activities and the ability of natural 

systems to support and nurture life. To meet this mandate, EPA1 s research 

program is providing data and technical support for solving environmental proble·ms today and building a science knowledge base necessary to manage our ecological resources wisely, understand how pollutants affect our health. and prevent or reduce environmental risks in the future. 

The National Risk Management Research Laboratory is the Agency's center for 

investigation of technological and management approaches for reducing risks 

from threats to human health and the environment. The focus of the Laboratory's 

research program is on methods for the prevention and control of pollution to air, 

land. water. and subsurface resources; protection of water quality in public water 

systems; remediation of contaminated sites and groundwater: and prevention and 

control of indoor air pollution. The goal of Uris research effort is to catalyze 

development and implementation of innovative. cost-effective environmental 

technologies; develop scientific and engineering information needed by EPA to 

support regulatory and policy decisions; and provide technical support and information transfer to ensure effective implementation of environmental regulations 

and strategies. 

This publication has been produced as part of the Laboratory1 s strategic longterm research plan. It is published and made available by EP .A I s Office of Research and Develo?ment to assist the user community and to link researchers 

with their clients. 

E. Timothy Oppelt, Director 

National Risk Management Research Laboratory 

EPA REVIEW NOTICE 

This report has been peer and administratively reviewed by the U.S. Environmental 

Protection Agency, and approved for publication. Mention of trade names or 

commercial products does not constitute endorsement or recommendation for use. 

This document is available to the public through the National Technical Information 

Service, Springfield, Virginia 22161. 
METHANE EMISSIONS FROM 

THE NATURAL GAS INDUSTRY, 

VOLUMES: EQUIPMENT LEAKS 

FINAL REPORT 

Prepared by: 

Kirk E. Hummel 

Lisa M. Campbell 

Matthew R. Harrison 

Radian International LLC 

8501 N. Mopac Blvd. 

P.O. Box 201088 

Austin, TX 78720-1088 

DCN: 95-263-081-12 

For 

GRI Project Manager: Robert A. Lott 

GAS RESEARCH INSTITUTE 

Contract No. 5091-251-2171 

8600 West Bryn Mawr Ave. 

Chicago, IL 6063 I 

and 

C-R I-9t.f/o;;s 7. :?.~ 

EPA-600 iR-S6-C8Ch 

June 1996 

EPA Project Manager: David A. Kirchgessner 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Contract No. 68-Dl-0031 

National Risk Management Research Laboratory 

Research Triangle Park, NC 27711 
DISCLAIMER 

LEGAL NOTICE: This report was prepared by Radian International LLC as an account 

of work sponsored by Gas Research Institute (GRI) and the U.S. Environmental Protection 

Agency (EPA). Neither EPA, GR!, Members of GR!, nor any person acting on behalf of 

either: 

a. Makes any warranty or representation, express or implied, with respect to the 

accuracy, completeness, or usefulness of the infonnation contained in this report, or 

that the use of any apparatus, method, or process disclosed in this report may not 

infringe privately owned rights; or 

b. Asswnes any liability with respect to the use of, or for damages resulting from the 

use of, any infonnation, apparatus, method, or process disclosed in this report. 

NOTE: EPA's Office of Research and Development quality assurance/quality control 

(QNQC) requirements are applicable to some of the count data generated by this project. 

Emission data and additional count data are from industry or literature sources, and are not 

subject to EPAIORD's QA/QC policies. In all cases, data and results were reviewed by the 

panel of experts listed in Appendix D of Volume 2. 

II 
Title 

Contractor 

Principal 

Investigators 

Report Period 

Objective 

Technical 

Perspective 

Results 

RESEARCH SUMMARY 

Methane Emissions from the Natural Gas Industry, 

Volume 8: Equipment Leaks 

Final Report 

Radian International LLC 

GR! Contract Number 5091-251-2171 

EPA Contract Number 68-D 1-0031 

Kirk E. Hummel 

Lisa M. Campbell 

Matthew R. Harrison 

March 1991 - June 1996 

Final Report 

This report describes the approach used to quantify the annual methane 

emission from equipnient leaks using the component method. It includes 

equipment leaks from .gas production, gas processing, transmission, 

storage, and customer meters. 

The increased use of natural gas has been suggested as a strategy for 

reducing the potential for global warming. During combustion, natural 

gas generates less carbon dioxide (C02) per unit of energy produced than 

either coal or oil. On the basis of the amount of C02 emitted, the 

potential for global wanning could be reduced by substituting natural gas 

for coal or oil. However, since natural gas is primarily methane, a potent 

greenhouse gas, losses of natural gas during production, processing, 

transmission, and distribution could reduce the inherent advantage of its 

lower C02 emissions. 

To investigate this, Gas Research Institute (GR!) and the U.S. 

Environmental Protection Agency's Office of Research and Development 

(EPA/ORD) cofunded a major study to quantify methane emissions from 

U.S. natural gas operations for the 1992 base year. The results of this 

study can be used to construct global methane budgets and to determine 

the relative impact on global warming of natural gas versus coal and oil. 

The national annual emissions from equipment leaks are: 17.4 Bscf for 

production; 24.4 Bscf for gas processing; 50. 7 Bscf for transmission; 

16.8 Bscf for gas storage; and 5.8 Bscf for customer meters. 

llI 
Technical 

Approach 

Based on data from the entire program, methane emissions from natural 

gas operation~ are estimated to be 314 ± I 05 Bscf for the 1992 base 

year. This is about 1.4 ± 0.5% of gross natural gas production. This 

study also showed that the percentage of methane emitted for an 

incremental increase in natural gas sales would be significantly lower 

than the baseline case. 

The project reached it accuracy goals and provided an accurate methane 

emissions estimate that can be used in fuel switching analyses. 

In the component method for estimating emissions from equipment leaks, 

an average emission factor is determined for each of the basic 

components, such as valves, flanges, seals, and other connectors that 

compdse a facility. The component emission factor, determined from 

measured data, is combined with the average number of components 

comprising the facility to estimate average facility emissions. The 

average facility emissions are extrapolated to a national estimate by the 

number of facilities within the gas industry. 

Two approaches were used to quantify component emission factors for 

each segment of the industry. The first approach, based on EPA's 

protocol for fugitive emissions estimation, involves screening 

components using a portable instrument to detect total hydrocarbon leaks. 

The corresponding screening value for a component is then converted to 

an emission rate by using a correlation equation developed from data 

collected using an enclosure method. The EPA protocol approach was 

used to quantify component emission factors for onshore production 

(excluding the Atlantic and Great Lakes region), offshore production, and 

gas processing. 

The second approach used to quantify emissions from equipment 

components is a modification of the EPA protocol using the GRI HiFlownr (trademark of Gas Research Institute) sampler or a direct flow 

measurement to replace the data collected using an enclosure method. 

The GRI Hi-Flow sampler is a newly developed device which allows the 

leak rate of a component to be measured directly. The GRI Hi-Flow 

sampler approach was used to quantify component emission factors fof 

onshore production in the Atlantic and Great Lakes region, gas 

transmission and storage facilities, and customer meter sets. 

Component counts for all segments were estimated based on data 

collected during the measurement programs, site visits, and site surveys. 

IV 
Project 

Implications 

For the I 992 base year, the annual methane emissions estimate for the 

U.S. natural gas industry is 314 Bscf ± 105 Bscf (± 33%). This is 

equivalent to 1.4% ± 0.5% of gross natural gas production. Results from 

this program were used to compare greenhouse gas emissions from the 

fuel cycle for natural gas, oil, and coal using the global warming 

potentials (GWPs) recently published by the Intergovernmental Panel on 

Climate Change (JPCC). The analysis showed that natural gas 

contributes less to potential global wanning than coal or oil, which 

supports the fuel switching strategy suggested by JPCC and others. 

In addition, results from this study are being used by the natural gas 

industry to reduce operating costs while reducing emissions. Some 

companies are also participating in the Natural Gas-Star program, a 

voluntary program sponsored by EPA's Office of Air and Radiation in 

cooperation with the American Gas Association to implement costeffective emission reductions and to report reductions to EPA. Since this 

program was begun after the I 992 baseline year, any reductions in 

methane emissions from this program are not reflected in this study's 

tota1 emissions. 

Robert A. Lott 

Senior Project Manager, Environment and Safety 

v 
TABLE OF CONTENTS 

Page 

1.0 SUMMARY ................................................. I 

2.0 INTRODUCTION ............................................. 3 

3.0 EMISSION FACTOR METHODOLOGY ............................. 5 

3. I EPA Protocol Approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 

3.l.I Component Screening ................................ 6 

3. l.2 Enclosure Method/Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 

3.1.3 Correlation Equation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 

3. l.4 Pegged Source Emission Factors . . . . . . . . . . . . . . . . . . . . . . . . 19 

3.1.5 Default Zero Emission Factors . . . . . . . . . . . . . . . . . . . . . . . . . 22 

3.2 Alternative Approach Using the GR! Hi-FlowTM Sampler ............ 22 

4.0 AVERAGE EMISSIONS FROM EQUIPMENT AND FACILITIES ......... 26 

4.1 Onshore Gas Production ................................... 28 

4.1.1 Onshore Production in the Eastern U.S. Region ............. 28 

4.1.2 Onshore Production in the Western U.S. Region ,. ............ 34 

4.2 Offshore Gas Production .................................. 37 

4.3 Gas Processing .......................................... 42 

4.4 Transmission Compressor Stations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 

4.4.1 Station Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 

4.4.2 Compressor-Related Components . . . . . . . . . . . . . . . . . . . . . . . 53 

4.5 Gas Storage Facilities ..................................... 61 

4.5. ! Station Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 

4.5.2 Compressor-Related Components . . . . . . . . . . . . . . . . . . . . . . . 67 

4.5.3 Injection/Withdrawal Wellhead-Related Components . . . . . . . . . . 67 

4.6 Customer Meter Sets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 

5.0 NATIONAL EMISSIONS FROM EQUIPMENT AND FACILITIES ........ 72 

5.1 Onshore Gas Production ................................... 72 

5.2 Offshore Gas Production .................................. 75 

5.3 Gas Processing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 

5.4 Transmission Compressor Stations ............................ 77 

5.5 Gas Storage Facilities ..................................... 78 

5.6 Customer Meter Sets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 

6.0 REFERENCES .............................................. 82 

VI 
TABLE OF CONTENTS (Continued) 

Page 

APPENDIX A - Compressor Slowdown Operating Practices A-1 

APPENDIX B - Source Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1 

APPENDIX C - Conversion Table ................................ C-1 

Vil 
LIST OF FIGURES 

l -1 Summary of Equipment Leaks Using Component Method 

Page 

2 

3-1 Overview of EPA Protocol . . . . . . . . . . . . . . . . . . . ................... 7 

3-2 Conventional Gate Valve ........................................ 9 

3-3 Manual Globe Valve .......................................... JO 

3-4 Plug Valve ................................................. 11 

3-5 Ball Valve ................................................. 12 

3-6 Threaded and Flanged Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 

3-7 Pressure Relief Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 

3-8 Open-Ended Line .......... : . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 

3-9 Screening Instruments ...................................... , .. 16 

3-10 Sampling Train for Bagging a Source Using the Vacuum Method ........... 18 

3-11 Scatter Plot of Bagging Data and Correlation Equation .................. 20 

4-1 Illustration of Compressor Slowdown Valve Arrangement ................ 55 

4-2 Overhung and Beam-Type Centrifugal Compressors ... , . . . . . . . . . . . . . . . . 62 

viii 
LIST OF TABLES 

Page 

3-1 Correlation Equations Developed by EPA . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 

3-2 Default Zero and Pegged Emission Factors Developed by EPA . . . . . . . . . . . . . 23 

4-1 Equipment Categories by Segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 

4-2 Equipment Leak Measurement Programs ............................ 29 

4-3 Component Emission Factors for Eastern U.S. Gas Production . . . . . . . . . . . . . 31 

4-4 Average Component Co~ts for Gas Production Equipment in the Eastern U.S. . 32 

4-5 Average Equipment Emissions for Onshore Production in the Eastern U.S. . . . . 33 

4-6 Component Emission Factors for Onshore Production in the Western U.S. . . . . . 35 

4-7 Average Component Counts for Onshore Production in the Western U.S ....... 36 

4-8 Average Equipment Emissions for Onshore Production in the Western U.S ..... 38 

4-9 Average Component Emission Factors for Offshore Gas Production ....... -. . 40 

4-10 Average Component Counts for Offshore Gas Production Equipment ........ 41 

4-11 Average Facility Emissions for Offshore Production .................... 43 

4-12 Component Emission Factors for Gas Processing 45 

4-13 

4-14 

4-15 

4-16 

4-17 

4-18 

Average Component Counts for Gas Processing Equipment . . . . . . . . . . . . . . . 4 7 

Average Facility Emissions for Gas Processing Plants .................. , 48 

Component Emission Factors for Transmission ........................ 50 

Average Component Counts for Transmission 51 

Average Facility Emissions for Transmission ......................... 52 

Breakdown of Compressor Emissions by Component Type . . . . . . . . . . . . . . . . 53 

IX 
LIST OF TABLES (Continued) 

Page 

4-19 Average Emission Rates for Compressor Blowdown Valves in Pressurized/ 

Depressurized Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 

4-20 Operating Modes of Compressors in Gas Transmission .................. 57 

4-21 Compressor Seal Emission Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 

4-22 Component Emission Factors for Gas Storage 64 

4-23 Average Component Counts for Gas Storage 65 

4-24 Average Facility Emissions for Gas Storage .......................... 66 

4-25 Operating Modes of Compressors in Gas Storage . . . . . . . . . . . . . . . . . . . . . . 68 

4-26 Summary of Emission Rates from Outdoor Residential Customer Meter Users . . 69 

4-27 Summary of Emission Rates from Commercial/Industrial Customer Meter Sets . . 71 

5-1 National Activity Factors for Gas Production . . . . . . . . . . . . . . . . . . . . . . . . . 73 

5-2 National Annual Emissions from Onshore Production in the Eastern U.S. 74 

5-3 Nat~onal Annual Emissions from Onshore Production in the Western U.S. 75 

5-4 National Annual Emissions from Offshore Production. . . . . . . . . . . . . . . . . . . . 76 

5-5 National Annual Emissions from Gas Processing. . . . . . . . . . . . . . . . . . . . . . . 77 

5-6 National Annual Emissions from Transmission Compressor Stations . . . . . . . . . 78 

5-7 National Annual Emissions from Gas Storage Facilities . . . . . . . . . . . . . . . . . . 79 

5-8 Statistics on Indoor Customer Meters by Region . . . . . . . . . . . . . . . . . . . . . . . 80 

5-9 N ationaI Annual Emissions from Customer Meter Sets . . . . . . . . . . . . . . . . . . 8 I 

A-I Compressor Blowdown Valve Operating Practices-Transmission .......... A-2 

A-2 Compressor Blowdown Valve Operating Practices-Storage Stations ........ A-4 

A-3 Compressor Blowdown Valve Operating Practices---Gas Processing Plants ... A-5 

x 
1.0 SUMMARY 

This report is one of several volumes that provide background information 

supporting the Gas Research Institute (GRI) and U.S. Environmental Protection Agency 

Office of Research and Development (EPA/ORD) methane emissions project. The 

objective of this comprehensive program is to quantify methane emissions from the gas 

industry starting at the wellhead and ending immediately downstream of the customer's 

meter. The accuracy goal of the program is to determine these emissions to within ± 5% of 

national gas production for the 1992 base year. 

This report documents the approach used to estimate methane emissions from 

equipment leaks using the component method. In this method, an average emission factor 

is determined for each of the basic components, such as valves, flanges, seals, and other 

connectors that comprise a facility. The component emission factor, detennined from 

measured data, is combined with the average number of components comprising the facility 

to estimate average facility emissions. The average facility emissions are extrapolated to a 

national estimate by the number of facilities within the gas industry. 

The component method was used to estimate methane emissions from 

equipment leaks for onshore and offshore gas production, gas processing, 

transmission/storage, and customer meter sets. As shown in Figure 1-1, the total industry 

emissions from equipment leaks using the component method are 115 Bscf. The major 

contributors to emissions from equipment leaks are components associated with 

compressors, which have unique design and operating characteristics and are subject to 

vibrational wear. The single component with the largest emission rate is the compressor 

blowdown open-ended line which allows the compressor to be depressurized for 

maintenance or when idle. The compressor blowdown open-ended lines leak continuously 

at different rates depending upon Whether the compressor is pressurized ( operating or idle) 

or depressurized (idle). 

I 
Production 

17.4 Bscf 

Customer Meters 

5.8 Bscf Storage 

16.8 Els::f 

Transmission 

50.7 Bscf 

Figure 1-1. Summary of Equipment Leaks Using Component Method 

Equipment leaks from onshore and offshore production contribute around 

16.2 Bscf ± 43% and 1.2 Bscf ± 29%, respectively. to annual national methane emissions. 

The emissions from onshore production were estimated separately for the Atlantlc and 

Great Lakes region (Eastern U.S.) and the rest of the country (Western U.S.) because of 

regional differenc;es in number and type of equipment, and leak detection and repair 

practices. Likewise, the emissions from offshore production were estimated separately for 

the Gulf of Mexico and Pacific Outer Continental Shelf (OCS) regions. 

Equipment leaks from gas processing a.Te 24.4 Bscf ± 68%. For gas 

processing, transmission, and storage facilities, fugitive emissions from compressor-related 

· components were estimated separately from the remaining facility because of differences in 

leakage characteristics. In gas processing, compressor-related components account for 90% 

of the total emissions from equipment leaks. 

Fugitive emissions from transmission and storage stations in the United States 

are 50.7 Bscf± 52% and 16.8 Bscf± 57°/o, respectively. As with gas processing, the 

emissions from compressor-related components account for the majority of emissions, at 

89% and 74% of annual fugitive emissions from transmission and storage, respectively. 

Customer meter sets contribute approximately 5.8 Bscf ± 20% to annual 

emissions from equipment leaks. Emissions from outdoor residential customer meter sets 

account for 96% of the annual fugitive emissions from customer meters, whereas 

commercial/industrial meter sets account for only 4%. 

2 
2.0 INTRODUCTION 

In the GRI/EPA program to quantify methane emissions from the U.S. natural 

gas industry, estimates were developed for each source of methane emissions. Fugitive 

emissions from equipment leaks were identified as a potentially significant source of 

methane losses from production, processing, and gas transmission/storage. The purpose of 

the study documented in this report was to define and quantify fugitive emissions from 

equipment leaks using the component method.· 

Equipment leaks are typically low-level, unintentional losses of process fluid 

(gas or liquid) from the sealed surfaces of above-ground process equipment. Equipment 

components that tend to leak include valves, flanges and other connectors, pump seals, 

compressor seals, pressure relief valves, open-ended lines, and sampling connections. 

These components represent mechanical joints, seals. and rotating surfaces, which in time 

tend to wear and develop leaks. 

In the component method for estimating emissions from equipment leaks. an 

average emission factor is determined for each of the basic components, such as valves, 

. flanges, seals, and other connectors that comprise a facility. The average emission factor 

for each type of component is determined by measuring the emission rate from a large 

number of randomly selected components from similar types of facilities throughout the 

country. By knowing the average emission factor per component type (i.e., the component 

emission factor) and the average number of components associated with the major 

equipment or facility. an average estimate of the emissions per equipment/facility can be 

determined. Extrapolation to a national emissions estimate can then be made by 

determining the total count of that specific equipment/facility in the United States. 

*Other types of fugitive emissions from the gas industry, including leaks from underground 

pipelines and meter and pressure regulating stations, are documented in separate reports. 1

•

2 

3 
Component emission factors can vary depending upon the operating pressure, 

age, and leak detection and repair practices at the site. By randomly selecting a large 

number of sites to measure leaks, these variations from site to site are taken into account. 

However, it is important to develop different component emission factors for segments of 

the gas industry with uniquely different emission characteristics to avoid introducing bias. 

For example, typical component sizes, manufacturers, service, and maintenance practices 

are different for facilities in gas production, processing, transmission, and distribution. To 

eliminate bias, different component emission factors were developed for each of the 

industry segments. In gas production, regional differences were found between similar 

facilities that affected the emissions. Therefore, regional component emission factors were 

developed for onshore and offshOre gas production. 

This report documents the overall approach used to estimate emissions from 

equipment leaks using the component method. The method used to measure and evaluate 

emission rates ls discussed in Section 3. The estimation of emission factors for specific 

equipment or facilities by combining the component emission factor with average 

component counts is described in Section 4. The extrapolation to a national estimate for 

each equipment or facility type is discussed in Section 5. This report is one of several 

volumes prepared under the GRI/EPA methane emissions project. 

4 
3.0 EMISSION FACTOR METHODOLOGY 

Component emission factors are used with the average component counts to 

determine average emissions from equipment and/or facilities. Two approaches were used 

to quantify component emissions for valves, flanges, seals, and other components. The first 

approach is based on the EPA protocol document3 and EPA Reference Method 21, 

Determination of Volatile Organic Compound Leaks. "

4 EPA Method 21 involves screening 

components using a portable instrument to detect total hydrocarbon (THC) leaks. Based on 

the EPA protocol document, the corresponding screening value for a component is then 

converted to an emission rate by using a correlation equation developed from data collected 

using an enclosure method. (Note: The correlation equation may have been developed 

from screening and enclosure data collected at similar, but different, facilities.) EPA 

Method 21 and the approach based on the EPA protocol used to calculate emission rates 

from the resulting data are described in detail in Section 3.1. 

The second approach used to quantify emissions from equipment components 

is a modification of the EPA protocol using the GRI Hi-FlowTM (trademark of Gas Research 

Institute) sampler or a direct flow measurement to replace the data collected using an 

enclosure method. The ORI Hi-Flow sampler is a ne~ly developed device which allows 

the leak rate of a component to be measured directly. The sampler creates a flow field 

around the component in order to capture the entire leak. As the stream passes through the 

instrument, the flow rate and concentration are measured. The GRI Hi-Flow sampling 

method and the approach used to calculate emissions from the resulting data are described 

in Section 3.2. 

3.1 EPA Protocol Approach 

In general, EPA Method 21 and the EPA protocol were used to estimate 

emissions from equipment components in onshore production (except for production 

facilities in the Atlantic and Great Lakes region), offshore production, and gas processing. 

5 
Using EPA Method 21 and the EPA protocol, emission factors are derived from screening 

data for a single component type depending upon the service [i.e., gas, light liquid (high 

vapor pressure) or heavy liquid (low vapor pressure)]. (Note: There are very few heavy 

liquid streams in the gas industry.) The screening data are converted to an emission rate 

using an existing or newly generated correlation equation. The correlation equation is 

developed from rneasured data using an enclosure method coUected from the same 

component type in similar facilities and similar service. The component emission factor is 

then derived as the average emission rate from all components screened. The following 

subsections describe the screening, enclosure, and correlation equation techniques. Figure 

3-1 shows an overview of the EPA protocol as it was applied to sources in the gas industry. 

3.1.1 Component Screening 

The EPA Method 2 I screening measurement technique uses a portable 

instrument to detect I~ge around flanges, valves, and any other components by traversing 

the instrument probe over the entire surface of the component interface where leakage could 

occur. Components are typically subdivided according to type and service as follows: 

• Valves •• gas/vapor, light liquid, heavy liquid; 

• Pump Seals -· light liquid, heavy liquid; 

• Compressor Seals -- gas/vapor; 

• Pressure Relief Valves -- gas/vapor; 

• Connections (includes flanges and threaded unions) -- aII services; 

• Open-Ended Lines' -· all services; and 

• Sampling Connections -- all services. 

The components that may be subject to fugitive leakage at natural gas 

facilities include valves, flanges and other connections, pump and compressor seals, 

**Only includes fugitive leakage from around the valve seat when the valve is closed. 

6 
Conduct Complete 

Screening Survey 

(EPA Method 21) 

Approach 1 Apply Existing 

Correlation 

Equations 

N 

~ 

0 

• e 

~ 

~ 

<( 

Develop Component Apply Average Calculate Average 

Emission Factors Component Equipment/Facility Bag a Fraction of Counts for Emissions the Components for Equipment/Facility 

Each Component Type 

Develop Correlation Apply New 

Equations for Each Correlation 

Component Type Equations 

Figure 3-1. Overview of EPA Protocol 
pressure relief valves (PRVs), and open-ended lines (OELs). Components in heavy liquid 

service are not associated with gas operations. Pump seals and sample connections were 

considered outside of the gas industry boundary. Figures 3-2 through 3-8 show typical 

gate, globe, plug, and ball valves, flanged and threaded connections, pressure relief valves, 

and open-ended lines with the areas of possible fugitive leakage identified. 

All components associated with an equipment source or facility are screened 

using the procedures specified in EPA Method 21. The components are categorized as to 

type (e.g., valves, flanges, and other connections) and also possibly by service (e.g., gas and 

light liquid). The maximum measured concentration, or screening value, is recorded. 

Levels below the detection limit of the instrument and levels above the full-scale range of 

the instrument are also recorded. 

The portable instrument used for screening must meet the specifications and 

performance criteria ·contained in EPA Method 21. In general, an organic vapor analyzer 

(OVA) that uses a flame ioniz.ation detector (FID) is typically used for screening 

measurements. Figure 3-9 shows two typical OVA instruments used for component 

screening measurements. The portable instrument provides a concentration measurement of 

THC from the screened component. 

The portable monitoring instrument has a pump that draws a continuous 

sample of gas from the leak interface to the detector. Because the commercially available 

FID instruments that meet the criteria specified in the method have limited pump capacity, 

the instrument does not always capture the entire leak or, for large leaks, the concentration 

may exceed the fuU-scale range. As part of the GRI/EPA methane emissions program, a 

dilution probe was used during co11ection of some of the screening data to extend the upper 

range of the instrument from I 0,000 to 100,000 ppmv. 

8 
PACKING GLAND ---, 

PACKING RINGS ---~ 

VALVE STEM 

Figure 3-2. Conventional Gate Valve 

9 

POSSIBLE 

LEAK AREA 
STEM 

PACKING GLAND 

PACKING--~ 

SEAT---__/ 

Figure 3-3. Manual Globe Valve 

10 

~-- POSSIBLE 

LEAK AREA 

BODY 
.-~- LUBRICANT SCREW 

/ 

/ ~ STEM // ~ GLAND STUD ANO NUT 

_,;/. // / -~ LUBRICANT CHECK VALVE / . 

BODY~~'- ~ COVER 

PLUG~ 

0 

0 

0 

Figure 3-4. Plug Valve 

II 
POSSIBLE 

LEAKAREA- -- STEM 

SPHERICAL PLUG --

BALL VALVE(OPEN) 

C) 

C) 

C) 

C) 

- BODY 

POSSIBLE 

LEAKAREA- ~-- STEM 

SPHERICAL PLUG --

C) C) 

SEATRJNG ----

- BODY 

BALL VALVE(CLOSED) 

Figure 3-5. Ball Valve 

12 
POSSIBLE 

LEAK AREA --~ 

FLANGED CONNECTION 

---POSSIBLE 

LEAK AREA ---

THREADED CONNECTION 

Figure 3-6. Threaded and Flanged Connections 

13 
ALTERNATE SCREENING 

AREA IF HORN 

INACCESSIBLE 

i--- HORN. 

POSSIBLE 

LEAK AREA 

' 

TO PROCESS ' 

Figure 3-7. Pressure Relief Valve 

14 

TENSION ADJUSTMENT 

THIMBLE 

SPRING 

'--NOZZLE 
OPEN 

TO 

ATMOSPHERE 

POSSIBLE 

LEAK AREA --~ 

SEAT RING ----~ 

POSSIBLE 

LEAK AREA -t----~-

OPEN 

TO 

ATMOSPHERE 

~-SEAT 

OPEN-ENDED LINE 

(Globe Valve-Closed) 

OPEN-ENDED LINE 

(Ball Valve-Closed) 

Figure 3-8. Open-Ended Line 

15 

BODY 

BODY 

CONNECTED 

TO 

PROCESS 

CONNECTED 

TO 

PROCESS 
f 

(a) TL V Sniffer 

(b) OVA-108 

Figure 3-9. Screening Instruments 

16 

' ' ' ' 
3.1.2 Enclosure Method/Data 

To convert the screening, or concentration, data to an emission rate, a 

correlation must be developed between the screening concentrations and the actual mass 

emission rates. The first step in this process is to directly measure some of the mass 

emi~sion rates that were screened. The procedure used to directly measure the emission 

rate is an enclosure method, which is often referred to as the "bagging" technique. 

The bagging technique is used to provide mass emission rates by measuring 

the THC concentration for a known flow rate of inert gas. In the bagging technique, a 

leaking component is completely enclosed in a bag and a measured flow rate of inert gas is 

passed through the bag either by vacuwn pump or blower. The concentration of THC is 

then measured at the outlet of the bag after complete mixing of the inert gas with the 

leaking process fluid. The actual leakage rate is the product of the flow rate and the 

concentration measurement. In some cases, a sample of the stream flowing through the bag 

is collected and analyzed to speciate the hydrocarbon compounds. Figure 3-10 illustrates a 

typical sampling system for the enclosure measurement method. 

Typically, bagging data are obtained from a relatively small, random sample 

of leaking components identified using the screening technique. (The reason that bagging 

data are not collected for all leaking components is that the method is relatively expensive 

and time consuming.) The bagging data are used to correlate concentration values obtained 

using the screening technique with mass emission rates. 

3.1.3 Correlation Equation 

A correlation equation is developed which relates the concentration measured 

during the screening test to the emission rate measured from the bagging data. Because the 

screening values and mass emission rates span several orders. of magnitude and are highly 

variable, the equation is derived as a logarithmic function. In general, a correlation 

17 
, ...... 

...... 

°""" 

Tbs lne shJlAd 

beM:ll'at 

--

'"" 

0 ea"" 

Figure 3-10. Sampling Train for Bagging a Source Using the Vacuum Method 

18 
equation is derived for each specific component type (e.g., valves, connections, open-ended 

lines, pressure relief valves) for a given type of facility. Figure 3-11 illustrates the 

correlation equation derived from the screening and bagging data for connectors in the oil 

and gas industry. 3 

Components associated with a specific facility type/service may have unique 

emission characteristics because size, manufacturer, service, age, and/or leak detection and 

repair practices are unique to that type of facility. Therefore, to avoid introducing bias, the 

correlation equation may only be applicable to similar facility types within the gas industry 

or other like industries. 

Correlation equations derived for a given type of facility can be used to 

convert screening data from a similar, but different, facility into mass emission rates. 

Therefore, extensive bagging data are not required by every facility that desires to quantify 

fugitive emissions from equipment components. Screening data alone can be collected and 

used to predict emissions using an existing correlation equation derived from similar 

facilities. However, because of the high variability in the data which are used to generate 

the correlation equation, the uncertainty in the estimated mass emission rates generated 

from screening data and the correlation equation approach may be high. For many sources 

of fugitive emissions from the gas industry, a single set of correlation equations developed 

from data co1Iected in the petroleum and gas industries were used to estimate mass 

emission rates from screening data.5 Table 3-1 shows the EPA correlation equations used. 

3.1.4 Pegged Source Emission Factors 

Although components with large leaks typically account for only a small 

fraction of the total components at a facility (often 2% or less), their emissions can 

contribute over 90% to the total emissions from the facility. Because of the limitations of 

commercially available instruments which meet the EPA Method 21 criteria, components 

19 
1E+01 

!E<OO 

1E-01 

i 1E-02 

• iS < 

~ % 

• " !E-03 • • 

E • w > • • ~ !E-04 • • • 

IE-OS 

!E--06 

1E·07 

- eo,,.11:tion E~tiOII 

• Sc:r•enlng/Bllgging Cata Pai 

Fugitive Correlation Equation 

Connectors 

• • ' • :• • •• • f •• • •• ·•I. ... tr: ••••• .·.r.. ••• 41• 

, ......... . 

. .-..._.. . .. - • • 

.. • . 

• 

10 100 1000 

~pm~ 

Sc:re•ning V1lut1 

10000 

• • 

100000 

Figure 3-11. Scatter Plot of Bagging Data and Correlation Equation3 

20 
TABLE 3-1. CORRELATION EQUATIONS DEVELOPED BY EPA 

Component Typea 

Connector 

Flange 

Open-Ended Line 

Pump Seal 

Valve 

Other 

Correlation Equation b,c 

THC (lb/day) - (7.99 x 10·') x (ISVJ0 "' 

THC (lb/day) - (2.35 x l 04 ) x (JSV)0 '°' 

THC (lb/day) - (I.14 x 104

) x (ISV)0

·

7

°' 

THC (lb/day) - (2.55 x 10·') x (ISV)''" 

THC (lb/day) - (1.21 x 104 ) x (ISV)'"' 

THC (lb/day) - (6.98 x 104

) x (!SV)0

·'" 

" Combined for all services (e.g., gas, light liquid, heavy liquid). 

b Per EPA study of fugitive emissions from petroleum refineries, marketing terminals, and 

oil and gas production. s 

c THC = total hydrocarbon; ISV = instrument screening value. 

leaking at a high rate can exceed the full-scale range of the screening instrument (5-15% of 

all leaks exceed the full-scale range of the instrument). This results in a practical upper 

limit to the correlation equation and requires that a separate "pegged source" emission rate 

be developed. Typically, the pegged source emission rate is the lognonnal mean emission 

rate of all the bagging data collected for pegged components. Pegged source emission rates 

were developed for full-scale screening values of 10,000 and 100,000 ppmv based on 

screening data obtained without and with an instrument dilution probe, respectively. 

Because of the high variability in measured leakage rates for pegged sources 

(refer to Figure 3-11 for a typical range in emission rates at I 0,000 and I 00,000 ppm 

screening values), an average pegged source emission factor developed from screening and 

bagging data has a high uncertainty. Since the majority of emissions from a typical site are 

due to pegged sources, estimated emissions based on screening data and EPA correlation 

equations, default zero, and pegged source factors also have a high uncertainty. 

21 
3.1.5 Default Zero Emission Factors 

For components with screening values below the detection limit of the 

method or below the background concentration level, a zero response level is recorded 

during data collection. In an EPA study of fugitive emissions from refineries, marketing 

tenninals, and oil and gas production, 5 default zero factors were calculated based on 

bagging data collected from a random sample of each component type with screening 

values below the detection limit of the method. The default zero factors were calculated as 

the lognorrnaI mean emission rate from the bagging data for the components with a "zero" 

screening value. Table 3-2 presents the average default zero and pegged source factors 

developed in the EPA study5 which were used for many sources of fugitive emissions in the 

gas industry. At sites with few leaks (e.g., sites subject to strict regulations, such as 

petrolemn refineries and synthetic organic chemical manufacturing facilities), the value of 

the default zero factor can have a significant influence on the overall site emission rate. 

3.2 Alternative Approach Usin& the GRI Hi-Flow Sampler 

The GRI Hi-Flow sampler was developed to provide a more accurate 

evaluation of emissions from equipment leaks than the EPA protocol approach. 6

•

7 In 

general, the GRl Hi-Flow sampler, which is used to measure the emission rate of a 

component, is a low cost replacement for bagging measurements. Because of the lower 

cost and ease of use, it can be used to measure a11 leaking components at a facility instead 

of only a fraction of the leaking components, as with the bagging method. 

The GRI Hi-Flow sampler has a high flow rate and generates a flow field· 

around the component that captures the entire leak. As the sample stream passes through 

the instrument, both the sample flow rate and THC concentration are measured. With 

accurate flow rate and concentration measurements, the mass emission rate can be 

calculated as the product of the flow rate and concentration .. Because of the high flow rate, 

22 
TABLE 3-2. DEFAULT ZERO AND PEGGED EMISSION FACTORS 

DEVELOPED BY EPA' 

Pegged Factor, 

lb THC/day 

Default Zero Factor, b 

Component Type lb THC/day >10,000 ppmt >100,000 ppmd 

Connector 3.97 x 104 1.48 1.59 

Flange 1.64 x 10·5 4.50 4.44 

Open-Ended Line 1.06 x 104 1.59 4.18 

Pump Seal 1.27 x I 0-3 3.92 8.47 

Valve 4.13 x 104 3.39 7.41 

Other 2.12 x 104 3.86 5.82 

3

Per EPA study of fugitive emissions from petroleum refineries, marketing terminals, and 

oil and gas production. 5 

bDefault zero factors calculated from refinery and marketing terminal data only. 

cBased on lognonnal mean emissions using emission and screening data for screening 

values above 10,000 ppm (includes screening data of I 00,000 ppm). 

dBased on lognormal mean emissions using emission and screening data for screening 

values above 100,000 ppm. 

the instrument can accurately measure the emission rate from large leaks which would 

exceed the fuII-scale range of most commercially available OV ('\. instruments. 

The GRI Hi-Flow sampler is different than the conventional approach based 

on the EPA protocol for the following reasons: 

• The emission rate is measured directly by providing both 

concentration and sample flow rate measurements. 1-n contrast, the 

EPA protocol approach requires the use of either bagging data to 

determine the emission rate from a component or use of a correlation 

equation to calculate the emission rate. Bagging data are very costly 

to obtain and the correlation equation approach has a high uncertainty. 

• Because using the GRI Hi-Flow sampler is much faster than bagging, 

the total emissions from a given facility can be measured within a few 

percent. [The sampler is not well suited for generating default zero 

23 
factors because of the higher dilution rate leading to lower 

concentrations (i.e., lower resolution) for small leaks. However, 

because 90% of the emissions from a facility are from leaks that 

exceed the upper range of the screening instrument, emissions from 

components that are below the threshold (i.e., default zeros) have an 

insignificant impact on total emissions.] 

• Because of the much higher flow rate, the sampler can accurately 

measure large leaks. In contrast, the EPA protocol approach classifies 

large leaks (i.e., those that exceed the full-scale range of the screening 

instrument) as pegged sources and an average emission factor (with 

high uncertainty) is assigned as the leak rate. 

The GRI Hi-Flow sampler was used to measure fugitive emission rates from 

onshore production sites in the Atlantic and Great Lakes region, transmission compressor 

stations, and customer meters. Two general approaches were implemented for gas industry 

sources using the GRl Hi-Flow sampler. The first approach, used for transmission 

compressor stations and customer meters, included the identification of all leaking 

components using soaping tests. AH components found to be leaking were then measured 

using the GRI Hi-Flow sampler. Leaks in excess of the GRI Hi-Flow sampler range were 

measured directly using rotameters. Component emission factors were derived from the 

emission rates of all components, including leaking and non-leaking components. (NonIeaking components were assumed to have a negligible emission rate.) This approach 

provided a direct measurement of all leaking components at a site and, consequently, an 

accurate estimate of emissions without the use of correlation equations. 

The second general approach using the GRI Hi-Flow sampler included 

screening of all components at a site using EPA Method 21 with a conventional FID 

instrument. All components with screening values exceeding the full-scale range of the 

instrument (i.e., pegged sources) were measured using the GRI Hi-Flow sampler. 

Therefore, a direct measurement of emissions was provided for the pegged sources which 

contribute around 90% to total emissions. A fraction (30-50%) of the components with 

screening values below 10,000 ppm were also measured using the GRJ Hi-Flow sampler 

instead of bagging measurements. A correlation equation was then developed for 

24 
components with screening values below I 0,000 ppm and applied to all components 

screened at less than I 0,000 ppm. Because all large leaks (i.e., above I 0,000 ppm) were 

measured, this approach provides a more accurate estimate of emissions than the EPA 

protocol approach where a pegged source emission factor is applied. This approach was 

used for onshore production sites in the Atlantic and Great Lakes region. 

25 
4.0 AVERAGE EMISSIONS FROM EQUIPMENT AND FACILITIES 

This section presents the component emission factors for the various 

segments of the industry, and how these were used to determine the average emissions from 

equipment and facilities. Emission factors for equipment leaks were developed for: 

in Table 4-1. 

• Onshore production in the Atlantic and Great Lakes region (i.e., 

Eastern U.S.) and the rest of the U.S. (i.e., Western U.S.); 

• Offshore production in the Gulf of Mexico and Pacific OCS; 

• Gas processing; 

• Transmission; 

• Storage; and 

• Customer meters. 

Fugitive methane emissions were estimated for the types of equipment listed 

The average emissions for a given type of equipmenVfacility were calculated 

as the product of the component emission factor (i.e., the average emission rate per 

component) and the average number of components, summed over al! the types of 

components associated with the equipment/facility: 

where: 

E, = 

E, = I (EF, x CC;) 

Average equipment emissions for equipment/facility type A 

(Mscf/equipment-yr); 

26 
TABLE 4-1. EQUIPMENT CATEGORIES BY SEGMENT 

• Production: 

Onshore gas production: 

Wellhead emissions 

Heater emissions 

Separator emissions 

Meters and piping 

Gathering compressors (small) 

Large production (gathering) compressors 

Dehydrators 

Offshore gas production: 

Platforms (one EF that includes all equipment on the 

platform) 

• Transmission: 

Pipelines 

Transmission and storage compressor stations (reciprocating 

compressors, centrifugal compressors, and rest of station) 

• Processing: 

Gas processing plants (reciprocating compressors, centrifugal 

compressors, and rest of station) 

• Distribution: 

Customer meters (residential and commercial/industrial) 

27 
EF, 

cc, -

Average component emission factor for component type i 

(Mscf/component-yr); 

Average component count for component type i. 

Type of component (e.g., valves, connectors, open-ended lines). 

This section provides documentation of the component emission factor and 

component count data and the resulting average equipment emissions for 

equipment'facilities within the gas industry where the component method was used. Table 

4-2 presents a summary of the measurement programs providing data for each 

segment'region within the gas industry where the component method was used for 

estimating fugitive emissions. 

4.1 Onshore Gas Production 

Component emission factors for fugitive equipment leaks in gas production 

were estimated separately for onshore and offshore production due to differences in 

operational characteristics. Regional differences were found to exist between onshore 

production .in the Eastern U.S. (i.e., Atlantic and Great Lakes region) and the Western U.S. 

(i.e., rest of the country, excluding the Atlantic and Great Lakes region) and between 

offshore production in the Gulf of Mexico and the Pacific OCS. Therefore, separate 

measurement programs were conducted to account for these regional differences. 

4.1.l Onshore Production in the Eastern U.S. Region 

Fugitive emissions from equipment leaks were estimated separately for 

onshore production in the Eastern U.S. because of differences in the service, number, type, 

age, and leak detection and repair characteristics of equipment typically located at 

production sites in this region. In general, the gas produced from wells in the Eastern U.S. 

region has a very low hydrogen sulfide (H2S) and carbon dioxide (CO,) content, relatively 

28 
TABLE 4-2. EQUIPMENT LEAK MEASUREMENT PROGRAMS 

Measurement Correlation Equation Pegged Source Default Zero 

Industry Area Study Approach Technlque(s) Used Method Method 

Production 

Onshore Eastern U.S. Star/GRI8 GRI Hi-Flow Screening and Developed new GRI Hi-Flow Assumed negligible 

GRI Hi-Flow correlation equation measurements leakage 

Onshore Western U.S. APIIGRl 9 EPA Protocol Screening and Bagging EPA Correlation EPA Factors5 EPA Faccors5 

Equations 

Offshore Gulf of Mexico API/GRl 9 EPA Protocol Screening and Bagging Developed new Developed new Developed new 

correlation equation pegged source default zero 

factors 

Offshore Pacific OCS MMS10 EPA Protocol Screening and Bagging Developed new Developed new ' 

correlation equation pegged source 

factors 

Gas Plants API/GRl9

•

11 EPA Protocol Screening and Bagging EPA Correlation EPA Factors5 EPA Factors5 

(excluding compressors) Equation5 

N Transmission Stations Indaco/GRl 12 GRI Hi-Flow Soaping and GRI Hi- Direct measurement used Direct measurement Assumed negligible 

'<> (excluding compressors) Flow (all leaking instead of correlation using GRI Hi-Flow leakage 

components) equation 

Compressors lndaco/GRI 12 GRI Hi-Flow GRI Hi-Plow or Direct measurement used Direct measurement Assumed negligible 

(transmission, Rotameter (all leaking instead of correlation using GRI Hi-Flow leakage 

processing, storage) components) equation and rotameter 

Customer Meter Sets Indaco/GRin EPA Protocol Screening EPA Correlation EPA Factors5 Assumed negligible 

Equation5 leakage 

Indaco/GRI" ORI Hi-Flow Screening and Direct measurement used Direct measurement Assumed negligible 

GRI Hi-Flow instead of correlation using GRI Hi-Flow leakage 

equation 

Star/GRI 15 GRI Hi-Flow Screening and Direct measurement used Direct measurement Assumed negligible 

GRI Hi-Flow instead of correlation using GRI Hi-Flow leakage 

equation 

• Developed non-emitter emission factor for components which have a screening value less than 500 ppm. 
low moisture content, and low production rates per well compared to gas produced in the 

other regions of the United States. For this reason, there are significant regional differences. 

(Note: A statistical analysis of the data also confirmed a significant difference between 

regions.) 16 

Component emission factors for onshore production in the Eastern U.S. were 

based on a measurement program using a combination of screening to identify leaking 

components and the GRI Hi-Flow device to quantify emission rates from leaking 

components. 8 A total of 192 individual well sites were screened using EPA Method 21 at 

12 eastern gas production facilities. All pegged source components (with screening values 

above 10,000 ppm) and a fraction (30-50%) of the leaking components with screening values 

less than 10,000 ppm were measured using the GR! Hi-Flow sampler. A correlation 

equation was developed from the screening and direct measurement data for components with 

screening values less than 10,000 ppm. This correlation equation was used to estimate 

emission rates from all components with screening values Jess than 10,000 ppm. The 

emission rates for components with screening values of 10,000 ppm and above were 

measured directly. The component emission factors were estimated based on the average 

emission rates of all components (i.e., calculated using the developed correlation equation or 

directly measured). The component emission factors were adjusted for the average methane 

content (69.6 wt. % or 78.8 volume % in production"). Table 4-3 shows the component 

emission factors for valves, connections, open-ended lines, and pressure relief valves. 

Component counts for gas production in the Eastern U.S. were based on 

information collected as part of the Eastern U.S. production fugitives study. 8 Component 

count data were coIIected for gas wellheads, separators, meters and the associated aboveground piping, and gathering compressors. Few in-line heaters and glycol dehydrators exist 

for gas production in the Eastern region. Although no heaters and dehydrators were 

identified as pan of the measurement study ,

8 site visits and phone surveys of seven additional 

sites provided data used for determining the number of units in the region. For the small 

30 
TABLE 4-3. COMPONENT EMISSION FACTORS FOR 

EAS_TERN U.S. GAS PRODUCTION 

Total Number of Component Emission 90% Confidence 

Components Factor, 11 Interval, 

Component Screened Mscf/component-yr % 

Valves 4200 0.184 29 

Connections 18639 0.024 20 

Open-Ended Lines 260 0.42 54 

Pressure Relief Valve 92 0.279 88 

3 Total methane emission rate adjusted for average 69.6 wt. % (78.8 vol. %) methane in 

production. 17 

number of heaters and dehydrator units that do exist in the Eastern region. the component 

counts were assumed to be identical to those derived from data collected in the Western U.S. 

(see next section). Table 4-4 presents a summary of the average component counts estimated 

for each type of equipment associated with gas production in the Eastern U.S. Confidence 

intervals were not available for the component count data provided from the measurement 

program. 

The average equipment emissions for each type of equipment associated with 

gas production in the Eastern U.S. were derived as the product of the component emission 

factors and the average number of components, summed over all component types. Table 

4-5 presents the component emission factors and component counts for each type of 

component associated with the equipment, along with the average equipment 

emissions and 90 % confidence interval. 

31 
w 

N 

TABLE 4-4. AVERAGE COMPONENT COUNTS FOR GAS PRODUCTION EQUIPMENT 

IN THE EASTERN U.S. 

Average Component Counia 

Quantity of Open-Ended Pressure Relief 

Equipment No. of Sites Equipment Valves Connections Lines Valves 

Gas Wellheads 12 192 8 38 0.5 0 

Separators II 110 I 6 0 0 

Meters/Piping 12 83 12 45 0 0 

Gathering Compressors I 2 12 57 0 0 

In~Line Heatersb II 77 14 65 2 I 

Dehydratorsb 10 52 24 90 2 2 

a Based on the Eastern U.S. onshore production study of fugitive emiss_ions from equipment leaks,8 unless otherwise noted. 

b Based on the oil and gas production operations study of fugitive emissions from equipment leaks. 9 
TABLE 4-5. AVERAGE EQUIPMENT EMISSIONS FOR ONSHORE PRODUCTION IN THE EASTERN U.S. 

Component Emission Average Equipment 90% Confidence 

Component Factor, t> Average Component Emissions, [nterval, 

Equipment Type Type' :Mscf/component-yr Count scf/equipment-yr % 

Gas Wellheads Valve 0.184 8 2,595 27 

Connection 0.024 38 

OEL 0.42 0.5 

Separators Valve 0.184 328 27 

Connection 0.024 6 

Heaters Valve 0.184 14 5,188 43 

Co1U1ection 0.024 65 

OEL 0.42 2 

PRY 0.279 l 

= Glycol Dehydrators Valve 0.184 24 7,938 35 = 

Connection 0.024 90 

OEL 0.42 2 

PRY 0.279 2 

Meters/Piping Valve 0.184 12 3,289 30 

Connection 0.024 45 

Gathering Valve 0.184 12 4,417 6 

Compressors Connection 0.024 57 

OEL 0.42 2 

a OEL = Open-Ended Line; PRY = Pressure Relief Valve. 

b Total methane emission rate adjusted for average 69.6 wt. % (78.8 vol. %) methane in production.17 
4.1.2 Onshore Production in the Western U.S. Region 

Component emission factors for onshore production in the Western U.S. (i.e., 

all regions excluding the Atlantic and Great Lakes region) were based on an API/GRI 

measurement program using the EPA Method 21/protocol approach to screen and bag 

selected components at 12 oil and gas production sites. 9 In this measurement program, 

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

Pacific, Mountain, Central, and Gulf regions. Component emission factors were determined 

from the screening data that were converted to emission rates using a correlation equation 

developed by EPA in a separate study.' (The EPA study' developed new equipment leak 

correlation equations, default zero factors, and pegged source factors based on a combination 

of the API/GRJ study' and data from petroleum production, refineries, and marketing 

terminals.) 

To est~ate component emission factors, Radian used the screening data from 

the API/GRJ study' and the component correlation equations derived by EPA' for 

components with screening values between 10 ppm and 10,000 ppm. For components with 

screening values below IO ppm, the default zero factors developed by EPA were used. For 

pegged source components (i.e., with screening values of 10,000 ppm and above), the 

10,000 ppm pegged source factor developed by EPA was applied. 

The component emission factors were recalculated instead of using those 

presented in the API/GRJ report' because: (!) confidence intervals needed to be provided 

which were not available from the API/GRJ report; (2) the API/GRJ report combined 

pressure relief valves and compressor seals, both with relatively high emission rates, into a 

single "other" category (separate emission factors were recalculated for pressure relief valves 

and compressor seals as part of this study); and (3) because some of the site visit data 

combined flanges and connectors into a single category, a combined component emission 

factor for flanges/connectors was calculated. 

34 
The component emission factors for gas production in the Western U.S. are 

presented in Table 4-6 for valves, connections, open-ended lines, pressure relief valves, and 

compressor seals. The 90% confidence intervals for the average component emission rates 

were calculated based on the variability in the estimated emission rates for all components 

screened as part of the API/GRI study. 

TABLE 4-6. COMPONENT EMISSION FACTORS FOR ONSHORE PRODUCTION 

IN THE WESTERN U.S. 

Total Number of Component Emission 90% Confidence 

Components Factor,a Interval, 

Component Screened Mscf/component-yr % 

Valves 6059 0.835 10 

Connections 32513 0.114 9 

Open-Ended Lines 1051 0.215 33 

PRVs" 448 1.332 37 

Compressor Seals 40 2.37 72 

a Total methane emission rate adjusted for average 69.6 wt. % (78.8 vol. %) methane in 

production. 17 

t> Pressure relief valves. 

The average component counts for each piece of major process equipment 

associated with gas production in the Western U.S. were based on data from the 

API/GRI study' and additional data collected for this project during 13 site visits to gas 

production fields. Table 4-7 shows the number of production sites and equipment used as 

data sources and the average component counts for wellheads, separators, heaters, glycol 

dehydrators, meters and the associated piping, and field gathering compressors. For large 

reciprocating compressor stations in production, the component counts were assumed to be 

identical to those in transmission compressor stations (see Section 4.4). 

35 
TABLE 4-7. AVERAGE COMPONENT COUNTS FOR ONSHORE PRODUCTION IN THE WESTERN U.S. 

Average Component Counia 

No. of Open-Ended Compressor 

Equipment No. of Sites Equipment Valves Connections Lines PRVs' Seals 

Gas Wellheads 17 184 11 (30%) 36 (20%) I (28%) 0 0 

Separators 16 183 34 (44%) 106 (38%) 6 (94%) 2 (68%) 0 

Meters/Piping 12 73 14 (31 %) 51 (47%) 1 (113%) I (150%) 0 

Gathering 13 61 73 (102%) 179 (51 %) 3 (50%) 4 (84%) 4 (69%) 

Compressors 

Heaters II 77 14 (49%) 65 (70%) 2 (66%) 1 (89%) 0 

Dehydrators 10 52 24 (31 %) 90 (37%) 2 (69%) 2 (53%) 0 

~ 

"' a Values in parentheses represent the 90% confidence inte.r;val. 

ti Pressure relief valves. 
Overa11 average equipment emissions were derived from the component 

emission factors and component counts for each equipment type. Table 4-8 presents the 

average equipment emissions for each type of equipment along with the 90% confidence 

interval. 

Several transmission companies reported that some transmission-owned 

gathering stations were similar in size and operational characteristics to transmission 

compressor stations. Therefore, average equipment emissions for large reciprocating 

compressor stations in production were assumed equal to transmission compressor stations 

(Section 4.4). 

4.2 Offshore Gas Production 

Emissions from equipment leaks from offshore production sites in the United 

States were quantified based on two separate screening and bagging studies: 

• The API/GRI oil and natural gas production operations sti.J.dy, 9 which 

included four offshore production sites in the Gulf of Mexico; and 

• The Minerals Management Service study of seven offshore production 

sites in the Pacific OCS. 10 

The component emission factors and average component counts were taken 

directly from the field test reports. 9

•

10 Tables 4-9 and 4-10 present the component emission 

factors and average component counts, respectively, for offshore production in the Gulf of 

Mexico and Pacific OCS. The average component counts for offshore production in both the 

Gulf of Mexico and Pacific OCS were combined for all major equipment on a production 

platform. 

37 
TABLE 4-8. AVERAGE EQUIPMENT EMISSIONS FOR ONSHORE PRODUCTION IN THE WESTERN U.S. 

Component Emission Average Average Equipment 90% Confidence 

Factor," Component Emissions, Intenal, 

Equipment Type Component Type Mscf/component-yr Count scf/yr % 

Gas Wells Valve 0.835 11 13,302 24 

Connection 0.114 36 

Open-Ended Line 0.215 

Separators Va1ve 0.835 34 44.536 33 

Connection 0.114 106 

Open-Ended Line 0.215 6 

Pressure Relief Valve 1.332 2 

Heaters Valve 0.835 14 21,066 40 

Connection 0.114 65 w 

0, Open-Ended Line 0.215 2 

Pressure Relief Valve 1.332 1 

Dehydrators Valve 0.835 24 33,262 25 

Connection 0.114 90 

Open-Ended Line 0.215 2 

Pressure Relief Valve 1.332 2 

Meters/Piping Valve 0.835 14 19,310 30 

Connection 0.114 51 

Open-Ended Line 0.215 

Pressure Relief Valve 1.332 

Continued 
w 

'C 

Equipment Type 

Gathering Compressors 

Large Compressor Stations 

Station Components 

Compressor-Related Components 

TABLE 4-8. (Continued) 

Component Type 

Valve 

Connection 

Open-Ended Line 

Pressure Rdief Valve 

Compressor Seal 

b 

b 

Component Emission 

Factor," 

Mscf/component-yr 

0.835 

0.114 

0.215 

1.332 

2.37 

b 

b 

• Total methane emission rate adjusted for average 69.6 wt. % (78.8 vol. %) methane in production.17 

b Refer to Table 4-17 under transmission compn:ssor stations. · 

Average 

Component 

Count 

73 

179 

3 

4 

4 

b 

b 

Average Equipment 

Emissions, 

scf/yr 

97,729 

3.01 x IO' 

5.55 x 10• 

90% Confidence 

Interval, 

% 

68 

102 

65 
TABLE 4-9. AVERAGE COMPONENT EMISSION FACTORS FOR OFFSHORE 

GAS PRODUCTION' 

Component Emission Factor, Mscf/component~yr 

Component Gulf of Mexicol> Pacific ocsc 

Valve 0.187 0.048 

Connection 0.046 0.021 

Open-Ended Line 0.368 0.092 

Other 2.517 0.091 

• Confidence intervals were not available for the published component emission factors. 

b Total methane emission rate adjusted for average 79. l wt. % methane in Gulf of Mexico. 

c Total methane emission rate adjusted for average 72.8 wt. % methane for components in 

gas service in Pacific OCS. 

40 
TABLE 4-IO. AVERAGE COMPONENT COUNTS FOR OFFSHORE GAS PRODUCTION EQUIPMENT 

Average Component Counts 

Number of Open-Ended 

Equipment Sites Valves Connections Lines Other Total 

Gulf of Mexico Platform 4 2207 8822 326 67 11421 

Pacific OCS Platform 7 1833 13612 313 307 16065 
Separate component emission factors were estimated for valves, connections, 

open-ended lines. and other components from offshore production in the Gulf of Mexico and 

Pacific OCS. Confidence intervals were not provided for the component emission factors 

from either study9

•

10 and were not independently estimated as part of the GRI/EPA methane 

emissions program since this represents a small source of emissions. 

Table 4-11 presents the overall average facility emissions for offshore 

production platfonns in the Gulf of Mexico and Pacific OCS, respectively. The average 

facility emissions were derived as the product of the component emission factors and 

component counts. The 90% confidence interval was estimated based on the variability in 

the component count data for the Pacific OCS. For the Gulf of Mexico, the 90% confidence 

interval was based on the variability in. total estimated emissions from each of the four 

platfonns where measured data were collected. 

4.3 Gas Processin~ 

Component emission factors were developed for gas processing plants from 

screening data provided as part of the API/GRI oil and natural gas production study. 9

•

11 The 

screening data from eight gas processing plants were segregated by component type for the 

entire gas processing facility instead of by major equipment type. Correlation equations 

derived by EPA 5 were used to calculate emission rates for screening values between the 

background concentration and the .full-scale range of the instrument. Default zero and the 

appropriate pegged source factors developed by EPA were used to quantify screening values 

below background concentrations and above the range of the instrument, respectively. 

Site blowdown open-ended lines allow a facility to depressure equipment to the 

atmosphere for maintenance or allow the entire facility to be depressured for emergency 

situations. Site blowdown open-ended lines are found at gas processing plants, gas 

transmission stations, and gas storage stations. These open-ended lines are much larger than 

42 
TABLE 4-11. AVERAGE FACILITY EMISSIONS FOR OFFSHORE PRODUCTION 

Equipment Type 

Gulf of Mexico 

Platfonn 

Pacific OCS Platform 

Component Type 

Valve 

Connection 

Open-Ended Line 

Other 

Valve 

Connection 

Open-Ended Line 

Other 

Component Emission 

Factor, a,b 

Mscf/component-yr 

0.187 

0.046 

0.368 

2.517 

0.048 

0.021 

0.092 

0.091 

Average Component 

Count 

2.207 

8,822 

326 

67 

1833 

13612 

313 

307 

• Total methane emission rate adjusted for average 79. l wt. % methane in Gulf of Mexico. 

Average Equipment 

Emissions, 

Mscf/yr 

1,064 

430 

b Total methane emission rate adjusted for average 72.8 wt. % methane for components in gas service in Pacific OCS. 

90% Confidence 

Interval 

27 

36 
those typically used as drain valves and bleeder valves. Although site blowdown valves are 

infrequently operated, they have a significantly higher leakage rate than those associated with 

small valves. 

Component emission factors from compressor-related components were 

estimated separately because these components were found to have significantly higher 

emission rates than components associated with other equipment. This results from the 

unique design, size, and operation of some compressor components, as well as from the 

vibrational wear associated with compressors. The components associated with compressors 

include :an fittings and sealed surfaces physically connected to, or immediately adjacent to, 

the compressor. Two types of compressors are employed in the gas industry: reciprocating 

and centrifugal. In general, reciprocating compressors are driven by internal combustion 

(IC) engines and centrifugal compressors are driven by gas turbines. 

The component emission factors for compressor-related components were 

based on screening data provided by a separate GRI study. 12 A detailed discussion of 

component emission factors from compressor-related components is given in Section 4.4. 

Adjustments were made for the fraction of time reciprocating and centrifugal compressors are 

pressurized in gas processing service (89.7% and 43.6% for reciprocating and centrifugal 

compressors, respectively, as shown in Appendix A). Based on data collected during site 

visits, some fugitive sources (i.e., pressure relief valves and compressor blowdown openended lines) at a few gas processing plants are routed to a flare. It was found that 

approximately 11 % of compressors in gas processing have blowdown valves and pressure 

relief valves which are routed to a flare. 

Table 4-12 shows the component emission factors for each component type in 

gas processing, with separate estimated values for compressor-related components and the 

remainder of the gas plant. 

44 
TABLE 4-12. COMPONENT EMISSION FACTORS FOR GAS PROCESSING"·' 

Component 

Valve 

Connection 

Open-Ended Line 

Pressure Relief Valve 

Blowdown Open-Ended Line 

Compressor Seal 

Miscellaneous 

Gas Plant 

(non-compressor) 

1.305 (6%) 

0.117 (9%) 

0.346 (31 %) 

0.859 (56%) 

230 (190%) 

Reciprocating 

Compressor 

1341' (121 %) 

349'·' (171 %) 

2035'·' ( 144 % ) 

450' (53%) 

189' (19%) 

Centrifugal 

Compressor 

1341' (121 %) 

6447'·' (46%) 

228' (53%) 

31' (220%) 

a Component emission factors in units of Mscf/component-yr. Values in parentheses represent the 90% confidence interval. 

b Annual methane emission rate adjusted for average 87 .0 vol. % methane in gas processingY 

c Starter Open-Ended Line. 

d Adjusted for 89. 7% of time reciprocating compressors in processing are pressurized. 

c Adjusted for 11.1 % of streams routed to flare. 

r Adjusted for 43.6% of time centrifugal compressors in processing are pressurized. 
Component counts for gas processing plants were based on 21 sites from the 

following data sets: 

• Published counts from four gas plants in the API/GRI oil and gas 

production study; 9 

• An additional four gas plants in a later update to the API/GRI study;1i 

• Six gas plants included in the EPA study of natural gas liquids plants;18 

and 

• Site visits to seven gas plants conducted by Radian International for this 

project. 

Table 4-13 presents the average component counts for a gas plant and the 

reciprocating and turbine compressor engines located at a gas plant. Because only a fraction 

of compressor starters in gas processing use natural gas. the component counts for 

compressor starter open-ended lines were adjusted for the fraction of units that are operated 

with natural gas (i.e., 25% and 66. 7% for reciprocating and centrifugal compressors, 

respectively). 

The average facility emissions, shown in Table 4-14, were derived as the 

product of the component emission factors and the average component counts. 

4.4 Transmission Compressor Stations 

Equipment leaks from transmission compressor stations were separated into 

two distinct categories because of differences in leakage characteristics: 

• Station components including all sources associated with the station 

inlet and outlet pipelines, meter runs. dehydrators, and other piping 

located outside of the compressor building; and 

• Compressor-related components including all sources physically 

connected to or immediately adjacent to the compressors. 

46 
TABLE 4-13. AVERAGE COMPONENT COUNTS FOR GAS PROCESSING EQUIPMENT' 

Component 

Valve 

Connection 

Open-Ended Line 

Pressure Relief Valve 

Blowdown Open-Ended Line 

Compressor Seal 

Miscellaneous 

Gas Plant 

(non-compressor) 

1392 (26%) 

4392 (31 %) 

134 (54%) 

29 (35%) 

2 

Reciprocating 

Compressor 

I 

I 

2.5 

I' 

a Average component counts. Values in parentheses represent the 90% confidence intervals. 

b Starter open-ended line. 

c Only 25 % of starters for reciprocating compressors in processing use natural gas. 

d Other components counted/measured in aggregate per compressor. 

Centrifugal 

Compressor 

0.667' 

I 

1.5 

I' 
TABLE 4-14. AVERAGE FACILITY EMISSIONS FOR GAS PROCESSING PLANTS 

Equipment Type 

Gas Plant (noncompressor related 

components) 

Reciprocating 

Compressor 

Centrifugal 

Compressor 

Component Type 

Valve 

Connection 

Open-Ended Line 

Pressure Relief Valve 

Site Blowdown Open-Ended Line 

Compressor Slowdown OpenEnded Line 

Pressure Relief Valve 

Miscellaneousb 

Starter Open-Ended Line 

Compressor Seal 

Compressor Blowdown OpenEnded Line 

Miscellaneousb 

Starter Open-Ended Line 

Compressor Seal 

Component 

Emission Factor: 

Mscf/component-yr 

1.305 

0.117 

0.346 

0.859 

230 

31' 

1341 

2282 

Average 

Component 

Count 

1392 

4392 

134 

29 

2 

,. 

2.5 

I' 

1.5 

• Annual methane emission rate adjusted for average 87.0 vol. % methane in gas processing. 17 

b Includes cylinder valve covers and fuel valves. 

c Adjusted for J 1.1% of compressors which have sources routed to flare. 

4 Adjusted for 89.7°/o of time reciprocating compressors in processing are pressurized. 

e Other components counted/measured in aggregate per compressor. 

Average 

Equipment 

Emissions, 

MMscf/yr 

2.89 

4.09 

7.75 

90% Confidence 

Interval, 

% 

48 

74 

39 

r Only 25% of starters for reciprocating compressors in processing use natural gas.g Adjusted for 43.6"/o of time centrifugal compressors in processing 

are pressurized. 

s Adjusted for 43.6% of time centrifugal compressors in processing are pressurized. 
The component emission factors, average component counts, and average 

facility emissions for station and compressor-related components in gas transmission are 

presented in Tables 4-15 through 4-17. Table 4-15 shows the component emission factors 

for the station components (discussed in Section 4.4.1), along with component emission 

factors for reciprocating and centrifugal compressor-related components (discussed in Section 

4.4.2). Table 4-16 presents the average component counts for transmission compressor 

stations. Table 4-17 presents the average facility emissions for station and compressorrelated components. The component emission factors and average component counts for 

station components (i.e .• non-compressor related components) and compressor-related 

components are discussed in Sections 4.4.1 and 4.4.2, respectively. 

4.4.1 Station Components 

Component emission factor.s for station components were based on a 

measurement program conducted at six compressor stations using the GRI Hi-Flow sampler 

to quantify compressor station emissions and develop component emission factors. 12 Leaks 

were identified using soaping tests and all leaks found were measured using the GRI Hi-Flow 

sampler. [Note: Component emission factors were developed as part of the compressor 

station fugitive emissions measurement program12 assuming that non-leaking components had 

a negligible (i.e., zero) contribution to total emissions.] The component emission factors for 

station components are summarized in Table 4-15. 

Component counts for station components were estimated based on the 

following data collected at 24 sites: 

• Data from eight sites tested as part of the transmission station fugitives 

study; 12 

• Data from nine sites visited as part of this project~ and 

• Data from seven sites provided by two transmission companies. 

49 
~ 

0 

TABLE 4-15. COMPONENT EMISSION FACTORS FOR TRANSMISSION' 

Reciprocating Compressor-Related 

Station Components" Components 

Component 90% Component 

Emission Factor, Conndence Emission Factor, 

Component Mscf/comp-yr Interval Mscf/comp-,yr 

Valve 0.867 

Control Valve 8.0 

Connection 0.147 

Open-Ended Line I 1.2 

Site Blowdown Open- 264 84% 

Ended Line 

Pressure Relief Valve 6.2 3724 

Compressor Dlowdown 3683d 

Open-Ended Line 

Compressor Starter .. • 

Open-Ended Line 

Compressor Seal 396d,r 

Miscellaneous< 180' 

• Annual methane emission rate adjusted for average 93 .4 vol. % methane in gas transmission. 17 

b Excludes components physically connected to or directly adjacent to compressor. O Includes cylinder valve covers and fuel valves associated with compressors. 

90% 

Confidence 

Interval 

171 % 

96% 

53% 

19% 

Centrifugal Compressor-Related 

Components 

Component 90% 

Emission Factor, Confidence 

Mscf/comp-yr Interval 

9352d 38% 

1440 121 % 

16Sd 53% 

18' 223% 

d Adjusted for the fraction of time the compressor is pressurized (79.1 % and 24.2% for reciprocating and centrifugal compressors, respectively). 

• Reciprocating compressor starters were assumed to use compressed air or electricity instead of natural gas based on site visit data (see Appendix A). 

r Includes adjustment for seals equipped with Static-Pac•. 
TABLE 4-16. AVERAGE COMPONENT COUNTS FOR TRANSMISSION 

Component 

Valve 

Control Valve 

Connection 

Open-Ended Line 

Site Blowdown OpenEnded Line 

Pressure Relief Valve 

Compressor Blowdown 

Open-Ended Line 

Compressor Staner 

Open-Ended Line 

Compressor Seal 

Miscellaneousb 

Station Components• 

Average Component 90% Confidence 

Count Interval 

673 26% 

31 62% 

3068 28% 

51 60% 

4 49% 

14 45% 

Reciprocating Compre$0rRelated Components 

Average Component Count 

--' 

3.3 

l' 

• Excludes components physically connected to or directly adjacent to compressor. 

b Includes cylinder valve covers and fuel valves associated with compressors. 

c Miscellaneous equipment counted in aggregate for compressor. 

d Reciprocating compressor Starters were assumed to use compressed air or electricity instead of natural gas. 

Centrifugal Compressor-Related 

Components 

Average Component Count 

1.5 

l' 
TABLE 4-17. AVERAGE FACILITY EMISSIONS FOR TRANSMISSION 

Equipment Type 

Compressor Station 

(non-compressor 

related components) 

Reciprocating 

Compressor 

Centrifugal 

Compressor 

Component Type 

Valve 

Control Valve 

Connection 

Open-Ended Line 

Pressure Relief Valve 

Site Slowdown OpenEnded Line 

Compressor Blowdown 

Open-Ended Line 

Pressure Relief Valve 

Miscellaneous 

Compressor Starter OpenEnded Line 

Compressor Seal 

Compressor Blowdown 

Open-Ended Line 

Miscellaneous 

Compressor Starter OpenEnded Line 

Compressor Seal 

Component Emission 

Factor: 

Mscf/component·yr 

0.867 

8.0 

0.147 

11.2 

6.2 

264 

368Jb 

__ , 

9352' 

18" 

1440 

165" 

Average 

Component 

Count 

673 

31 

3068 

51 

14 

4 

I' 

·-' 

3.3 

l' 

1.5 

• Annual methane emission rate adjusted for average 93.4 vol. % methane in gas transmission. 17 

Average Equipment 

Emissions, 

MMscf/yr 

3.01 

(Note: 3.2 MMscf/yr 

used in national 

emission estimate)" 

5.55 

11.I 

b Adjusted for the fraction of time the compressor is pressurized (79. I% and 24.2% for reciprocating and centrifuga], respectively). 

c Reciprocating compressor starters were assumed to use compressed air or electricity instead of naturaJ gas. 

d Miscellaneous equipment counted in aggregate for compressor. 

• Adjusted for data received from one company that were not considered representative of national average. 

r Includes adjustment for seals equipped with Static-Pac.® 

90% Confidence 

Interval, 

% 

102 

65 

34 
The average facility emissions for the station and compressor-related 

components were calculated as the product of the individual component emission factors and 

the associated average component counts. As shown in Table 4-17. the average facility 

emissions are 3.2 MMscf/station-yr for the station components (excluding compressor-related 

components), with a 90% confidence interval of± 102 %. 

4.4.2 Compressor-Related Components 

Emissions from compressor-related components were estimated separately 

because of the differences in leakage characteristics for components subject to vibrational 

conditions, in addition to the unique types of components associated with compressors. The 

types of components associated with compressors include blowdown open-ended lines, starter 

open-ended lines, pressure relief valves, compressor seals, and other components such as 

cylinder valve covers and fuel valves. Compressor blowdown and starter open-ended lines 

are unique to compressors and were found to have very high leak rates. Table 4-18 provides 

a breakdown of the compressor emissions by component type for reciprocating and 

centrifugal compressors. 

TABLE 4-18. BREAKDOWN OF COMPRESSOR EMISSIONS 

BY COMPONENT TYPE 

Reciprocating Compressors Centrifugal Compressors 

Component . 

Type Mscf/yr % Mscf/yr % 

Compressor Blowdown 3,683 66.4 9,352 84.6 

Open-Ended Line 

Pressure Relief Valve 372 6.7 - . 

Miscellaneous 180 3.2 18 0.2 

Compressor Starter Open- . . 1,440 13.0 

Ended Line 

Compressor Seal 10 315 23.7 248 2.2 

Total 5,550 IJ,058 

53 
Compressor Blowdown Open-Ended Lines 

Compressor blowdown open-ended lines allow a compressor to be 

depressurized when idle, and typically leak when the compressor is operating or idle. Figure 

4-1 illustrates the compressor blowdown valve arrangement. 

There are two primary modes of operation leading to different emission rates 

for compressor blowdown open-ended lines. The first operating mode is when the blowdown 

valve is closed and the compressor is pressurized, either during normal operation or when 

idle. The second operating mode is when the blowdown valve is open. This occurs when 

the compressor is idle, isolated from the compressor suction and discharge manifolds, and 

the blowdown valve is opened to depressure the compressor. (Note: Fugitive losses do not 

include the vented emissions from depressuring the compressor. 1

9) The fugitive emission rate 

is higher for the second operating mode 'Yhen the blowdown valve is open, since leakage 

occurs from the valve seats of the much larger suction and discharge valves. Separate 

component emission factors were developed for the two operating modes of the compressor 

blowdown valve open-ended line. 

The component emission factors for each mode of compressor blowdown 

operation wete estimated from measured data collected at 15 compressor stations using a 

rotameter to measure the large leakage rates. 12 Of the 15 compressor stations that were 

measured, four were operated by a company that had instituted a voluntary gas conservation 

program that included the investigation and repair of leaks from compressor blowdown 

valves in 1984. These four stations were found to have lower than average emission rates 

from the compressor blowdown valve when the compressor was pressurized; however, when 

the compressor was depressurized, the leakage rate was higher than average. These data 

were not considered significantly different from the rest of the measurement data and were 

included in the overall average emission rates. Table 4-19 presents the average emission 

rates for compressor blowdown valves in the pressurized and depressurized mode of 

operation. 

54 
Compressor 

PRV 

Comp.OEL 

BID 

Discharge 

Block Valve 

Suction 

Block Valve 

Open 

Vent 

- - - - - - - - - - - - - _1 

Figure 4-1. Illustration of Compressor Blowdown Valve Arrangement 
TABLE 4-19. A VERA GE EMISSION RA TES FOR COMPRESSOR BLOWDOWN 

VALVES IN PRESSURIZED/DEPRESSURIZED OPERATION 

Reciprocating Compressor 

Operating Mode 

Pressurized a 

Depressurizedb 

Emission Rate, Mscf/yr 

1,361 

13,729 

' Either (a) operating or (b) idle, pressurized. 

b Depressurized, idle. 

90% Confidence Interval 

36% 

30% 

An overall average component emission factor was derived for compressor 

blowdown open-ended lines by determining the fraction of time the compressor operates in 

each mode (i.e., pressurized and depressurized). The total fraction of compressors that are 

idle was estimated from the Federal Energy Regulatory Commission (FERC) database, the 

GRI TRANSDAT database, and a transmission company supplied database.'° The fraction of 

idle compressors that are pressured was estimated using the data supplied by 13 transmission 

companies. Operating practices at the sites differed significantly. (A summary is provided 

in Appendix A for transmission, storage, and gas processing.) Overall, reciprocating 

compressors operated 45 % of the time during the 1992 base year. Of the idle reciprocating 

compressors, 62% are left in a pressurized mode and 38% are depressurized. Nearly all 

(92 % ) centrifugal compressors are depressurized when idle. Table 4-20 shows the fraction 

of time associated with each operating mode for reciprocating and centrifugal compressors in 

gas transmission. 

56 
TABLE 4-20. OPERATING MODES OF COMPRESSORS IN GAS TRANSMISSION 

Percent of Time Associated with Operating Mode 

Operating Mode Reciprocating Compressor Centrifugal Compressor 

Pressurized: 

In Operation 

Idle, Pressurized 

45.2 

33.9 

24.2 

5.8 

Depressurized: 

Idle, Depressurized 20.9 70.0 

Based on the average emission rate and fraction of time each type of 

compressor is pressurized versus depressurized, an overaII average component emission 

factor was calculated for compressor blowdown valves using Equation 1. 

where: 

EF ~I/romp = (~u.) x (F ,,) + (ER,,~.,,) x (F • ...,J (1) 

EF oelloomp = component emission factor for compressor blowdown openended line; 

ERoc,1,pr = average emission rate for compressor blowdown open-ended line 

when compressor is pressurized (operating or idle, pressurized); 

Fp, = fraction of compressors that are pressurized (operating or idle, 

pressurized); 

ERid-<1epr = average emission rate for compressor blowdown open-ended line 

when compressor is idle and depressurized; and 

F;d-<1,:pr = fraction of compressors that are depressurized and idle. 

The overall component emission factor is 3,683 ± 96% and 9,352 ± 38% 

Mscf/component-yr for reciprocating and centrifugal compressor blowdown valves, 

respectively, as shown in Table 4-15. Each compressor has one blowdown open-ended line. 

57 
Compressor Starter Open-Ended Lines 

Most compressors have a starter motor that turns the compressor shaft to start 

the engine. Many of the starters use natural gas as the motive force to spin the starter's 

turbine blades and then vent the discharge gas to the atmosphere. The inlet valve to the 

starter can leak and therefore is considered an open-ended line unique to compressors. 

Compressor starters that use compressed air or electricity instead of natural gas to power the 

starter motor are not sources of methane emissions. Based on data from site visits to six 

transmission companies, all centrifugal compressors use natural gas to power the starter 

motor, whereas no reciprocating compressor starter motors use natural gas. The percentages 

of compressors that use natural gas for starter motors in other segments are: (1) storage: 

50% of centrifugal compressors and 60% of reciprocating compressors; and (2) processing: 

100% of centrifugal compressors and 25% of reciprocating compressors. 

Component emission factors for compressor starters were based on the 

measurement data collected at 15 compressor stations. 12 The average emission rate from a 

compressor starter open-ended line is 1,524 Mscf/component-yr ± 121 %. 

Compressor Seals 

All compressors have a mechanical or fluid seal to minimize the flow of 

pressurized natural gas that leaks from the location where the shaft penetrates the 

compression chamber. These seals are vented to the atmosphere after passing through 

labyrinth seals or a seal oil trap and degassing tank. Compressor seal emissions were 

measured as part of the transmission station fugitives study .

12 Different component emission 

rates were calculated for the different operating modes of compressors, as follows: 

• Operating and pressurized; 

• Idle and fully pressurized; 

58 
• Idle and partially pressurized (using a fuel-saver system - reciprocating 

compressors only); and 

• Idle and depressurized. 

The pressurized seal emission rates ( operating and idle) were calculated as the 

ave!age of aII reciprocating and centrifugal compressor seals combined, since the data 

indicate that the emission rates were similar. Table 4-21 shows the compressor seal emission 

rates based on the data collected as part of the transmission station fugitives study .

12 The 

average emission rate for compressor seals when the compressor is idle but pressurized is 

slightly lower than when the compressor is operating, due to the absence of compressor shaft 

motion when the compressor is idle. About 5 % of reciprocating compressors in gas 

transmission have a fuel-saver system which allows the compressor blowdown line to go to 

the fuel gas system (net effect is that idle, pressurized compressors are not at full operating 

pressure). The fuel-saver system results in substantially lower fugitive emission rates from 

the compressor seal during idle time periods where the compressor is pressurized. The 

overall component emission factors for compressor seals (shown in Table 4-15) were 

calculated based on the emission rates (Table 4-21) and fraction of time (Table 4-20) for each 

mode of operation using Equation 2. (Note: For compressor seals, the emission rate was 

assumed to be negligible when the compressor is depressurized and idle.) 

TABLE 4-21. COMPRESSOR SEAL EMISSION RATES 

Operating Mode 

Pressurized, Operating 

Pressurized, Idle 

Pressurized, Fuel Saver8 

Component Emission Rate, 

Mscf/seal-yr 

599 

531 

116 

a Reciprocating compressors only. 

59 

90% Confidence Interval, 

% 

30 

19 

46 
EFsea1 = 

where: 

(ER,..,,,..,,) x (F,,..,,) + (ER,,.,,) x (F"_,,) + (ER,,.,,) x (F,,.,,) (2) 

EF seal = component emission factor for compressor seals; 

ERsea1,op-pr = average emission rate for compressor seal when compressor is 

pressurized and operating; 

Fop-pr = fraction of compressors that are pressurized and operating; 

ERid-pr = average emission rate for compressor seal when compressor is 

id! e and pressurized; 

Fid-pr = fraction of compressors that are pressurized and idle; 

ER.rs-pr = avei-age emission rate for compressor seal when idle, partially 

pressurized on a fuel-saver system; and 

F ts-pr = fraction of compressors that are idle. partially pressurized on a 

fuel-saver system. 

Reciprocating compressors have sliding shaft seals equal in number to the 

stages of compression. The average number of reciprocating compressor seals in 

transmission was estimated from data collected at four gas transmission sites with a total of 

47 reciprocating compressors. The average number of seals per compressor was calculated 

for each site and the overall average for the four sites used as the average component count 

for reciprocating compressor seals. The average component count of 3.3 seals per 

reciprocating compressor compares well with system-wide data supplied by a major gas 

transmission company. An additional adjustment was made to account for the number of 

reciprocating compressors seals equipped with Static-Pac.~ 21 According to the vendor, this 

device can reduce or eliminate gas leakage from idle. pressurized compressor seals. An 

estimated 1750 kits for reciprocating compressor seals have been sold in the gas industry .

21 

These were accounted for in the component emission factor as having negligible fugitive 

emission rates; however, the overa11 industry effect was small since this device is used on 

less than 8 % of the reciprocating compressors in transmission. 

60 
The number of centrifugal compressor seals per compressor depends on the 

type of compressor. As shown in Figure 4-2, centrifugal compressors with overhung rotors 

have one seal and beam-type compressors have two compressor seals. According to the 

results of a survey of three compressor vendors and one seal vendor,22 there is an even split 

between the number of overhung and beam-type centrifugal compressors in the gas industry. 

In addition, the more recent trend toward dry gas seal technology as opposed to mechanical 

contact (face or sleeve seals with oil lubrication) was evaluated. Although the dry gas seal 

technology could potentially result in lower emissions, this is a recent trend for new 

installations and was estimated to have a negligible impact on emissions from compressor 

seals in 1992, the base year of this study. 

Other Components 

The component emission factors for other components associated with 

compressors, such as pressure relief valves, were adjusted for the average fraction of time 

compressors are pressurized in transmission service (79.1 % and 24.2% for reciprocating and 

centrifugal compressors, respectively). 

4.5 Gas Storage Facilities 

Equipment leaks from gas storage facilities were separated into three 

categories due to differences in leakage characteristics: 

• Station components including all sources associated with the storage 

station inlet and outlet lines, meter runs, dehydrators, and other piping 

located outside of the compressor building; 

• Injection/withdrawal well components including all sources associated 

with the injection/withdrawal well "Christmas tree" piping 

configuration; and 

• Compressor-related components including all sources physically 

connected to or immediately adjacent to the compressors. 

61 
Diso:hult flange -.c;:==? (Olll.lel) 

Inlet 

Guide 

Vanes 

SUCtiOII 

FJ,ng, 

(in!«) 

,_ 

..... 

}"""" MecbUtied Bemngs 

r-'::,,'l':'.1,--T, Gu Seal 

Overhung Axial-Inlet Centrifugal Compressor 

(Single Seal) 

::; 

-

Beam-Type Centrifugal Compressor 

(Two seals) 

Coupling and 

Drive End 

-. 

-

Figure 4-2. Overhung and Beam-Type Centrifugal Compressors 

62 
The component emission factors, average component counts, and average 

facility emissions for station, injection/withdrawal well, and compressor-related components 

in gas storage are presented in Tables 4-22 through 4-24. Table 4-22 presents the component 

emission factors for storage facility components (discussed in Section 4.5.1), compressorrelated components (discussed in Section 4.5.2), and injection/withdrawal wellhead-related 

components (discussed in Section 4.5.3). Table 4-23 presents the average component counts 

for storage compressor stations. Table 4-24 presents the average facility emissions for 

station and compressor-related components. The component emission factors and average 

component counts for station-, compressor-. and injection/withdrawal weIIhead-related 

components are discussed in Sections 4.5.1 th.rough 4.5.3. 

4.5.1 Station Components 

Component emission factors for station components not associated with the 

compressors or wellheads are similar in type, service, and operation to those in gas 

transmission. Therefore, component emission factors for the station components in gas 

storage are the same as for gas transmission, as shown in Table 4-22. 

63 
a, 

... 

TABLE 4-22. COMPONENT EMISSION FACTORS FOR GAS STORAGE' 

Reciprocating Centrifugal 

Injection/Withdrawal Compressor- CompressorWellhead-Related Related Related 

Component Station Components' Components Components Components 

Valve 0.867 0.918 (10%) 

Connection 0.147 0.125 (9%) 

Open-Ended Line 11.2 0.237 (33%) 

Site Blowdown Open- 264 (84%) 

Ended Line 

Pressure Relief Valve 6.2 1.464 (37%) 317' (171 %) 

Compressor Blowdown 5024' (71 %) I 0233' (35 % ) 

Open-Ended Line 

Compressor Starter Open- 1440 (121 %) 1440 (121 %) 

Ended Line 

Compressor Seal 300' (53%) 126' (53%) 

Miscellaneousc 153' (19%) 17' (223%) 

a Component emission factors in Mscf/component-yr. Values in parentheses represent the 90% confidence interval. Total 

methane emission rate adjusted for average 93.4 vol. % methane in gas transmission/storage. 17 

1, Excludes components physically connected to or directly adjacent to compressor. 

c Includes cylinder valve covers and fuel valves associated with compressors. 

d Adjusted for the fraction of time the compressor is pressurized (67.5% and 22.4% for reciprocating and centrifugal 

compressors, respectively). 
°' v, 

TABLE 4-23. AVERAGE COMPONENT COUNTS FOR GAS STORAGE' 

lnjectfon/Wlthdrawal Reciprocating Centrifugal 

Station · Wellhead-Related Compressor-Related Compressor-Related 

Component Components" Components Components Components 

Valve 1868 (120%) 30 (82%) 

Connection 5571 (120%) 89 (82%) 

Open-Ended Line 353 (194%) 7 (98%) 

Site Blowdown Open- 4 (74%) 

Ended Line 

Pressure Relief Valve 66 (107%) I (130%) 

Compressor Blowdown 

Open-Ended Line 

Compressor Starter 0.6' 0.5' 

Open-Ended Line 

Compressor Seal 4.5 1.5 

Miscellam:uusd I" I" 

a Average component counts. Values in parentheses·represent the 90% confidence interval. 

b Excludes components physically connected to or directly adjacent to compressor or wellhead. 

' Adjusted for the fraction of compressor starters using natural gas (60% and 50% for reciprocating and centrifugal compressors, respectively). 

d Includes cylinder valve covers and fuel valves associated with compressors. 

• Miscellaneous equipment counted in aggregate for compressor. 
TABLE 4-24. AVERAGE FACILITY EMISSIONS FOR GAS STORAGE 

Component Emission Average Average Equipment 90% Confidence 

Factor,• Component Emissions, Interval, 

Equipment Type Component Type Mscf/component~yr· Count MMscf/yr % 

Storage Facility (non- Valve 0.867 1868 7.85 100 

compressor related 

Connection 0.147 5571 components) 

Open-Ended Line 11.2 353 

Pressure Relief Valve 6.2 66 

Site Blowdown 264 4 

Open-Ended Line 

Injection/Withdrawal Valve 0.918 30 0.042 76 

WdJhead Connection 0.125 89 

Open -Ended Line 0.237 7 

Pressure Relief Valve l.464 

Reciprocating Compressor Blowdown 5024b 7.71 48 

a, Compressors Open-Ended Line 

a, Pressure Relief Valve 317b 

Miscellaneous l53b I 

Compressor Staner 1440 0.6° 

Open-Ended Line 

Compressor Seal 300' 4.5 

Centrifugal Compressors Compressor Blowdown 

Open-Ended Line 

l023Jb l l.16 34 

Miscellaneous 17" 

Compressor Starter 1440 o.sc 

Open-Ended Line 

Compressor Seal 126b 1.5 

• Total methane emission rate adjusted for average 93.4 vol.% methane in gas transmission/storage. 17 

b Adjusted for the fraction of time the compressor is pressurized (67.5% and 22.4% for reciprocating and centrifugal compressors, respectively). O Adjusted for the fraction of compressor starters using natural gas (60% and 50% for reciprocating and centrifugal compressors, respectively). 
The average component counts for station components were based on site visits 

to five storage facilities as part of the GRI/EPA methane emissions program. Table 4-23 

presents the average component counts for gas storage. 

The overall average facility emissions were estimated as the product of the 

component emission factors and the average component counts. Table 4-24 presents the 

average facility emissions for gas storage, with the associated 90% confidence interval. 

4.5.2 Compressor-Related Components 

The individual component emission rates for compressor-related components 

(e.g., compressor blowdown open-ended lines, starter open~ended lines. and compressor 

seals) in gas storage are identical to those estimated for gas transmission (refer to Section 

4.4). However, the overall component emission factors for compressor blowdown openended lines and compressor seals in storage were adjusted for the average time allocated to 

each mode of operation: pressurized and operating, pressurized and idle, and depressurized 

and idle. Table 4-25 shows the fraction of time associated with each operating mode for 

reciprocating and centrifugal compressors in gas storage. 

The component counts for compressor starter open-ended lines were adjusted 

for the fraction of starters using natural gas. Based on data from five sites, 60% of 

reciprocating compressors and 50 % of centrifugal compressors use natural gas starters in gas 

storage facilities. 

4.5.3 Injection/Withdrawal Wellhead-Related Components 

The component emission factors for onshore gas production equipment 

(Section 4.1.2) were used to estimate emissions from storage wellheads and related 

equipment. The component emission factors for onshore gas production in the Western U.S. 

67 
TABLE 4-25. OPERATING MODES OF COMPRESSORS IN GAS STORAGE 

Operating Mode 

Pressurized: 

In Operation 

Idle, Pressurized 

Depressurized: 

Idle, Depressurized 

Fraction of Time Associated with Operating Mode 

Reciprocating Compressor Centrifugal Compressor 

43.1 

24.4 

32.5 

22.4 

0 

77.6 

(Table 4-6) were adjusted for an average of 93.4 volume % methane from equipment leaks in 

gas transmission/storage. 17 

Average component counts for injection/withdrawal wellhead-related 

components were based on the site visit" data from five storage facilities. 

4.6 Customer Meter Sets 

Commercial/industrial and residential customer meter sets include the meter 

itself and the related pipe and fittings. Leakage from customer meter sets occurs from the 

fittings associated with the meter, including the valve, regulator, and inlet and outlet pipe 

connectors. Although the joints and gaskets associated with the meter were screened, 

virtually no leakage was detected from the meter itself. 

Equipment emission factors from customer meter sets were estimated based on 

test data collected from 10 local distribution companies across the United States. 13 •

14•

15 

Customer meter screening data were coUected at three Eastern U.S. sites, a midwestern site, 

a Rocky Mountain site, and five Western U.S. sites. A summary of the total number of 

meter sets tested, the number and percentage of leaking meters, and the average emission 

rates from each of the 10 sites is shown in Table 4-26. A total of approximately 1600 meter 

68 
TABLE 4-26. SUMMARY OF EMISSION RATES FROM OUTDOOR RESIDENTIAL CUSTOMER METER USERS 

Number of Number of Perceotage of Average Leak Standard 

Meters Meter Sets Meter Sets Rate," Deviation," 

Site Screened Leaking Leaking lb methane/day lb methane/day 

Site 1 -- West Coast 134 37 27.6 0.0098 0.0239 

Site 2 -- East Coast 40 29 72.5 0.0002 0.0004 

Site 3 -- East Coast 158 37 23.4 0.0789 0.1753 

Site 4 -- Midwest 156 8 5.1 0.0057 0.0061 

Site 5 -- Rocky Mountain 188 28 14.9 0.0035 0.0082 

Site 6 -- West Coast 194 5 2.6 0.0002 0.0001 

Site 7 -- Southeast 201 56 27.9 0.0146 0.0328 

°' Site 8 -- Northwest 101 31 30.7 0.0101 0.0199 

"' Site 9 -- Southwest 150 50 33.3 0.0222 0.0404 

Site 10 -- Northwest 150 40 26.7 0.0125 0.0230 

Average 0.0158 

a Average value for all meters (i.e .. leaking and non-leaking) screened at the site. 
sets were tested as part of the GRI/EPA study. About 20% of the meter sets were found to 

be leaking at low levels. The average leak rate per meter set was only 0.0157 scf/hr. 

For the majority of customer meter sets screened, the GRl Hi-Flow sampler 

was used to develop emission factors. For the other meter sets screened, the EPA protocol 

approach was used to convert the screening data into emission rates. Average emission rates 

from the customer meter sets screened at each site were estimated by averaging the emission 

rates of all the meters screened, including those where no measurable leak was detected by 

the screening instrument. The overall average equipment emissions for outdoor residential 

customer meter sets were derived by averaging the emission rates for the 10 sites. 

Emissions from indoor meters are much lower than for outdoor meters because 

gas leaks within the confined space of a residence are readily identified and repaired. This is 

consistent with the findings that pressure regulating stations located in vaults have 

substantially lower emissions than stations located above-ground.2 The emissions from 

indoor customer meters were assumed to be negligible. 

Fugitive screening of commercial/industrial meter sets was conducted at four 

sites for a total of 149 meter sets. A summary of the total number of meters screened, the 

nwnber and percentage of leaking meter sets, and the average emissions from each of the 

four sites is shown in Table 4-27. The overall equipment emissions from 

conunerciaI/industrial customer meter sets were derived by averaging the emission rates for 

the four sites. The resulting average equipment emissions are 47 .9 scf/meter-yr ± 35 % for 

conunerciaI/industriaI meter sets. 

70 
TABLE 4-27. SUMMARY OF EMISSION RATES FROM COMMERCIAL/INDUSTRIAL CUSTOMER METER SETS 

Number of Number of Percentage of 

Meters Meter Sets Meter Sets 

Site Screened Leaking Leaking 

Site 3 -- East Coast 45 12 26.7 

Site 4 -- Midwest 61 0 0 

Site 5 -- Rocky Mountain 21 6 28.6 

Site 6 -- West Coast 22 I 4.5 

Average 

a Average value for all meters (i.e .• leaking and non-leaking) screened at the site. 

Average Leak 

Rate,a 

lb methane/day 

0.0112 

0.0088 

0.0018 

0.0055 

Standard 

Deviation," 

lb methane/day 

0.0251 

0.0076 
5.0 NATIONAL EMISSIONS FROM EQUIPMENT AND FACILITIES 

Methane emissions from equipment leaks using the component approach were 

extrapolated to a national estimate for the 1992 base year. The national armual emissions are 

the product of the average equipment or facility emissions, as documented in Section 4, and 

a national activity factor. The national activity factor is the population of sources, equipment 

or facilities, within the U.S. natural gas industry. Although some national population 

statistics are published, such as the number of onshore gas wells, others were not known and 

had to be calculated, such as the number of separators in onshore gas production. This 

section documents the national activity factors that were used to develop the national 

emissions estimate for each source within the gas industry where the component method was 

used to guantitate fugitive emissions. A detailed discussion of the activity factors is provided 

in Volume 5 on activity factors.23 

5.1 Onshore Gas Production 

National activity factors are provided for the following onshore production 

equipment: 

• Gas wells; 

• Separators; 

• Heaters; 

• Dehydrators; 

• Metering runs; and 

• Gathering compressors . 

Table 5-1 presents the national activity factor estimates for onshore production 

in the Eastern and Western U.S. regions, along with the 90% confidence interval. 

72 
TABLE 5-1. NATIONAL ACTIVITY FACTORS FOR 

GAS PRODUCTION 

Eastern U.S. Western U.S. 

Activity 90% Activity 90% 

Factor, Confidence Factor, Confidence 

Equipment Count Interval, % Count Interval, % 

Gas Wells 129, 157 5 142,771 5 

Separators 91,670 23 74,674 57 

Heaters 260 196 50,740 95 

Dehydrators 1,047 20 36,777 20 

Metering Runs 76,262 100 301,180 100 

Small Gathering 129 33 16,915 52 

Compressors 

Large Gathering 96 100 

Compressors 

Large Gathering 12 100 

Compressor Stations 

The total number of active gas wells is a nationally tracked statistic. The 

breakdown between gas wells in the Eastern and WCstem U.S. regions was based on a count 

of producing gas wells published by the American Gas Association.24 

Total U.S. activity factors or equipment counts for separators, heaters, 

metering runs, and gathering compressors were based on site visit data. For all equipment 

except dehydrators, the average count per well was calculated from the site visit data and 

used to calculate a regional estimate based on the regional well count. The total number ·of 

glycol dehydrators in gas production were based on published data from a separate GRJ 

srudy. 25 The equipment counts associated with Eastern U.S. production were estimated from 

data collected during the measurement program conducted. at 12 Eastern production sites. 8 

Likewise, the equipment associated with production in the W~stern U.S. was estimated based 

73 
on data collected as part of the oil and gas production fugitive emissions measurement 

program9 and 13 additional site visits conducted as part of this program. 

The extrapolation to national methane emissions from onshore production is 

shown in Tables 5-2 and 5-3 for Eastern and Western U.S. regions, respectively. As shown, 

the national annual methane emissions from onshore production in the Eastern and Western 

U.S. are 0.63 Bscf ± 46% and 15.6 Bscf ± 45%, respectively. 

TABLE 5-2. NATIONAL ANNUAL EMISSIONS FROM ONSHORE 

PRODUCTION IN THE EASTERN U.S. 

Average Activity. 

Equipment Factor, Annual Methane 90% Confidence 

Emissions, Equipment Emissions, Interval, 

Equipment scf/yr Count Bscf % 

Gas Well 2,595 129,157 0.34 27 

Separator 328 91,670 0.03 36 

Heater 5,188 260 0.001 218 

Dehydrator 7,938 1,047 0.008 41 

Meters/Piping 3,289 76,262 0.25 109 

Gathering 4,417 129 0.0006 44 

Compressors 

Total 0.63 46 

74 
TABLE 5-3. NATIONAL ANNUAL EMISSIONS FROM ONSHORE 

PRODUCTION IN THE WESTERN U.S. 

Average Activity Annual 90% 

Equipment Factor, Methane Confidence 

Emissions, Equipment Emissions, Interval, 

Equipment sef/yr count Bscf % 

Gas Well 13,302 142,771 1.9 25 

Separator 44,536 74,674 3.33 69 

Heater 21,066 50, 740 1.07 110 

Dehydrator 33,262 36,777 1.22 32 

Meters/Piping 19,310 301,180 5.82 109 

Small Gathering 97,729 16,915 1.65 93 

Compressors 

Large Gathering 5.55E+06 96 0.53 136 

Compressors 

Large Gathering 3.0IE+06 12 0.04 176 

Compressor Stations 

Total 15.6 45 

5.2 Offshore Gas Production 

The activity factors for offshore gas production were based on data from the 

Minerals Management Service26 and Offshore Data Services27 for the Pacific OCS and Gulf 

of Mexico, respectively. Half of the offshore platforms were allocated to the oil industry 

and, therefore, were not included within the boundaries of the gas industry. Table 5-4 

summarizes the activity factors and resulting annual methane emissions from offshore 

production. As shown, the national fugitive emissions from offshore production are 

1.2 Bscf ± 29%. 

75 
TABLE 5-4. NATIONAL ANNUAL EMISSIONS FROM OFFSHORE PRODUCTION 

Activity 

Average Factor, Annual 90% 

Facility Number of Methane Confidence 

Emissions, Platforms in Emissions, Interval, 

Region Mscf/yr Gas Industry Bscf % 

Pacific OCS 430 22 0.01 38 

Gulf of Mexico 1,064 1,092 1.16 29 

Total 1.17 29 

5.3 Gas Processinll 

The number of gas processing plants in the U.S. was based upon published 

statistics from the Oil & Gas Journal." Based upon data from 1992, the total number of gas 

plants is 726. A confidence limit of ± 2 % was assigned based on engineering judgement. 

The number and type of compressor drivers in gas processing were based on site visit data 

from 11 gas plants. The average ratios of reciprocating and centrifugal compressors per 

plant were scaled up to national estimates by multiplying by the total number of gas plants. 

The confidence interval was estimated from a statistical analysis of the individual site 

averages. The split between reciprocating and centrifugal compressors estimated from the 

site visit data (i.e .• 85% reciprocating and 15% centrifugal) agrees well with the results from 

a national survey conducted in the 1980s'' (i.e., 90% reciprocating and 10% centrifugal). 

The national annual emissions from gas processing plants was calculated as the 

product of the activity factor and the average facility emissions (see Section 4.3). Table 5-5 

presents a sununary of the national annual emissions from gas processing plants in the U.S. 

Emissions from compressor-related components account for the majority of the total 24.4 

Bscf ± 68% fugitive losses from gas processing plants. 

76 
TABLE 5-5. NATIONAL ANNUAL EMISSIONS FROM GAS PROCESSING 

Activity 

Average Factor, Annual 90% 

Facility Number of Methane Confidence 

Equipment/ Emissions, Plants/ Emissions, Interval, 

Facility MMscf/yr Compressors Bscf % 

Gas plants 2.89 726 2.1 48 

Reciprocating 4.09 4,092 16.7 95 

Compressors 

Centrifugal 7.75 726 5.6 91 

Compressors 

Total 24.4 68 

5.4 Transmission Compressor Stations 

The activity factor for transmission compressor stations was based on 

nationally tracked statistics by the Federal Energy Regulatory Commission (FERC). 20 The 

data reported to FERC account for around 70% of the total transmission pipeline mileage. 

The average station per mile data from FERC was extrapolated to a national estimate based 

on the total transmission pipeline mileage.24 The confidence interval was estimated as 

± IO% based on engineering judgement. 

The split between reciprocating and turbine compressor engines in gas 

transmission was estimated from the GRI TRANSDAT database,30 adjusting for the total 

industry horsepower. Transmission compressor stations were split from those associated with 

storage according to site visit data from eight storage stations and published information on 

storage stations.24 A further adjustment was made to account for compressors with electric 

motor drivers. The 90% confidence interval of the estimate was calculated from the 

variation in site visit data accounting for the storage station allocation and assignment of 

± 10% error in the GR! TRANSDAT database information. 

77 
Table 5-6 presents the annual methane emissions from transmission compressor 

stations in the United States. As shown, the overall estimate of 50. 7 Bscf ± 52 % from 

transmission compressor stations is primarily due to fugitive emission losses from 

compressor-related components. 

TABLE 5-6. NATIONAL ANNUAL EMISSIONS FROM TRANSMISSION 

COMPRESSOR STATIONS 

Average Activity Annual 90% 

Facility Factor, Methane Confidence 

Equipment/ Emissions Number of Stations/ Emissions, Interval, 

Facility MMscf/yr Compressors Bscf % 

Compressor 3.2 1700 5.4 103 

Stations 

Reciprocating 5.55 6799 37.8 68 

Compressors 

Centrifugal I 1.1 681 7.5 44 

Compressors 

Total 50.7 52 

s.s Gas Storaie Facilities 

The activity factors for storage injection and withdrawal and liquefied natural 

gas (LNG) storage facilities were compiled from published statistics. The number of 

underground storage facilities and LNG storage facilities is based on published data in Gas 

Facts. 24 As previously discussed in Section 5.4, the activity factor for compressors 

associated with gas storage were estimated from data collected during visits to eight storage 

sites. The number of injection/withdrawal wells was also estimated from the site visit data. 

The annual fugitive emissions from gas storage facilities are presented in Table 

5· 7. As shown, the total annual emissions are 16.8 Bscf ± 57%. 

78 
TABLE 5-7. NATIONAL ANNUAL EMISSIONS FROM GAS STORAGE 

FACILITIES 

Activity 

Average Factor, Annual 90% 

Facility Number of Methane Confidence 

Equipment/ Emis.sions, Facilities/ Emissions, Interval, 

Facility MMscf/yr Compressors Bscf % 

Storage 7.85 475 3.7 100 

Facilities 

Injection/ 0.042 17,999 0.75 76 

Withdrawal 

Wells 

Reciprocating 7.71 1,396 10.8 80 

Compressors 

Centrifugal 11.16 136 1.5 130 

Compressors 

Total 16.8 57 

5.6 Customer Meter Sets 

· The total number of residential and commercial/industrial customer meters in 

the U.S. gas industry was based on published data available in Gas Facts .

24 The number of 

residential customer meters located indoors versus outdoors was estimated based on a 

published regional breakdown of total customers combined with data obtained from 22 

individual gas companies within different regions of the country. (Note: The number of 

customers in each region was assumed to be equivalent to the number of customer meters 

because a regional breakdown of customer meters was not available.) Table 5-8 summarizes 

the average percentage of customer meters located indoors in each region. 

79 
TABLE 5-8. STATISTICS ON INDOOR CUSTOMER METERS BY REGION 

Average 

Total Percent Estimated 90% 

Residential Indoor Sample Indoor Confidence 

Region Customers Meters Size Meters Interval 

New England 1,886,500 52 I 980,980 471,625' 

Middle 8,403,400 61 7 5,126,074 I ,905,371 

Atlantic 

East North I 1,633,500 17 7 I ,977 ,695 1,461,663 

Central 

West North 4,684,100 40 l 1,873,640 1,873,640' 

Central 

South Atlantic 4,987,700 21 4 I ,030,680• I ,030,680' 

East South 2,465,200 0 0 123,260' 

Central 

West South 5,666,600 0 0 283,330' 

Central 

Mountain 3,318,700 0 0. 331,870' 

Pacific 9,724,500 5 2 486,225 486,225' 

Total 52,770,200 22 I 1,475,294 3,317,254 

a Estimated based on engineering judgement. 

b Estimated for each state separately in region, since Northern States (Maryland and 

Delaware) are included. 

c Estimated based on industry comments suggesting that customer meters in southern 

regions are essentially all located outdoors. 

The estimated number of indoor meters, 11.475,294, was subtracted from the 

total number of reported meters, 51 ,524,600, to derive an estimated 40,049,306 outdoor 

residential customer meters in the United States. The 90% confidence interval was estimated 

from the data provided by companies, engineering judgement for some regions, and an 

estimated 5% error in the nationally reported number of residential customer meters. 

80 
For commercial/industrial customer meters, the activity factor of 4,608,000 is 

a nationally tracked statistic24 and the precision is assumed to be ± 5% based on engineering 

judgement. 

The total annual emissions from customer meter sets are presented in Table 

5-9. As shown, customer meters contribute 5.8 Bscf ± 20% to annual methane emissions 

from the gas industry. 

TABLE 5-9. NATIONAL ANNUAL EMISSIONS FROM CUSTOMER METER SETS 

Average Activity Annual 90% 

Equipment Factor, Methane Confidence 

Emissions, number of Emissions, Interval, 

.Category scf/yr · meter sets Bscf % 

Outdoor residential 138.5 40.049.306 5.55 20 

meter sets 

Commercial/industrial 47.9 4,608,000 0.22 35 

meter sets 

Total 5.77 20 

81 
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(Houston, Texas) by K.E. Hummel, Radian Corporation, April 27, 1994. 

Oil & Gas Journal. 1992 Worldwide Gas Processing Survey Database, 1993. 

Farmer, J.R. Equipment Leaks of VOC in Natural Gas Production IndustryBackground Information for Promulgated Standards, EPA-450/3-82-024b 

(NT!S PB85-233112), May 1985. 

Biederman, N. GR! TRANSDAT Database: Compressor Module. (prepared 

for Gas Research Institute). npb Associates with Tom Joyce and Associates, 

Chicago, IL, August 1991. 

84 
APPENDIX A 

Compressor Blowdown Operating Practices 

A-1 
TABLE A-1. COMPRESSOR IlLOWDOWN VALVE OPERATING PRACTICES - TRANSMISSION 

- =-~ -- N•. ml ~Int:~ Tutblnn 

Sil .. -------·---- ..... AlmBD .. _. Idle Cornprtsor Pnttka •• .... ... "-•o ,.,,. ,ou.. ..... """,o 

Alm 

'llat,e 

BO Stp:uace 

,ou... 

Id'- Compnaur l"raclke< 

St-,-<_,., -~ 

"' b7 lbiri ""' ...... c. ... lo Low P 0. oo,. or..ow~r ~G• U..Go ... Col.ow P .. 00p . ill' Lo .. ., ""~;.,, ,....,.. ' ... Tc,Alm .. , ,,._, -- ... _ 1oAtm .. To Alm , .. , s,.1en,! n•nsun l"r ........ Pn.ssure .\!,,, '" -

' N n ; ,{ domplo ' ' - - - ·- - - ....... ' D N ' Not a--" -•• ' ; ,.. .. N I ouro ,., 

' N • N.,. • ..•• ' ; ,.. .. N ./ aulo 

• N • ; ; ' - - -- --- ·- ---· 

' ., N , ; ; • • - -- -- ---··· -

• N - No ala - Nodala ·- , N • NOii · •• '" ' ' ; 

" --

• N • ••• . . ... ' ' ; . , 

;: • .. N " ; , .. ; • ' '"' - ' " N • , .. ; I ; ' ; - .. " N ' ; , .. ; ' - - -·- -- --·· -·- -- - -

" N • ; , .. ; • -- ·-- --- --·-· ·- -----

n " N " ; , .. ; ' ; ' ; --- -

" N " ; ... N .... ; • ' ; • N ; ,w 

··

" " N " ; ... N ./ If >l41u- ; • ' ; ' N ; t<NJ -- --

-, 

1

.. , --

" " - i 
> 

w ' 

F'" -- No.er 

S,g 

Ropr,e-

.... 1tc1 "" "' l,y tbJI 

........ "'" ' 

" Y"' 

" "' N 

" N 

" ~ N 

" • N 

" • N 

~ n Nu• 

" 

" n 

" 

" 

l,~akl,he,a ... .. 0 ( ,·,>ttlfupl tompr~, >rilb r..:lproc.Cinr: ffllln,t. 

••Fi..,, does no1 hand!• Comp BO or SH, BO. 

• 00 Sit• lluo Ill 2 nf H f•<il11!N, 

"'""Si1< d.-p,..::mrod In lllt p:m. 

...... 

u..c. 

No. ToAtm 

• { 

' { 

•• { 

.. { 

' { 

• 

• { 

• 

• 

• 

• 

"' ·-

TABLE A-1. (Continued) 

. 

RecipToco1lnC Ea,;,... 

AunBD ,.,.,.., Idle Comp,-or Pt11<11c.,. 

Vlln ....... "" lo Low P ... oo,. Syst,m! 01.o ... , ""' --- ......... "== 

I 112" N { 

{ ... 

, . N I 

{ 

,. { { 

Nae •n..,'-1blt 

, . N { 

{ 

{ ./ dump to 

... ""' 

{ 

{ I dump to 

""'""' l-4" 4121 = &Ill = U/21 ~ llll = 1,.a.. 38.1'4 57,l'J, 4.1'1. 

- . . ---- ---·· -.-=--.c 

!nrhi"" 

,o, .I.Im BO Separat< ldlo Comp<e«Or Pra<Hoti • o, 

Stan,,.. """'" Vat,, BD Un• Slon,r, 

on Ga. Un,Go ... lo low P ... @Op . @Lo "" (;., \o .. ,, -·~ No. To Aun (in) Sy,t,m! oressur• Pressure Prcsom< Alm 

• ' { , .. N { HHl 

' ' { , .. N { '"' 

• ' { ,. N { ,oo 

' ' -- -- -- ···-· ---

' --

' { ,,, N { 

• { " { 

.. 

--

0.0'1. " ,oo• U" 0.0'1. tl/lJ = !!B - 0.0"' JOU'' 

92.}'l, 1.1~ [[ . .. 
TABLE A-2. COMPRESSOR BLOWDOWN VALVE OPERATING PRACTICES - STORAGE STATIONS 

- " No. ol 

.... 

...... _ .. ... ,, ... ..... """ ....... .. ... ...... ' No. To Alm 

' ' ' I 

' N ' I 

' ' ' I 

• ' ' I 

' ' ooa• I 

• N " I 

' N ' I 

• N • I 

T«llhfA•I U .... = .. " •oo• 

'-

?"" 'llrprn,u~ lo 900I for first l haor,, !hen dtP to a.Im U kll• o.-.er 2 boun. 

+>,. ''1 .. pr=.urffl to 900#, but this it •••Y n.ar """"''Ina I"°""'•· 

''f,lo•,·irk•lly di, .. ., tD&U>ff al thl< •l1e. 

AlmllD v,. 

-

(ia) 

' 

w 

'"" 

112 -l" 

·--- T<1•hi11M 

,.,..., ldlt c.,........... Pr..&es "'-.ith ,wom Separate ldlt Comp,osso, Purlk<s 

........ G• """'" Vol•e . ...... l<IL.•P ... OOp. • Lo••• Slffl•n U..G• ''" lo Lo•P ... COp. O Lowu s,a .... ! ...... Pr""'11H .. - No. To Alm ,., Syst«nr ft<=U~ l'rtiL<U1"0 l'.-,.su« 

' 

I • ' 

I ,oo • 

I• "' ' 

, .. ' ' 

I ,oo ' I I 

I ,_,., • 

I 1-IIOI ' 

.., " <n· "'. ... ' ,oo, ,oo, 

57.1\1, 1'.)~ 211.6'1. 

.. c. 

.. " , 1.,, 

1,., \!n, 

' 

' 00 

• O'f • 
TABLE A-3. COMPRESSOR BLOWDOWN VALVE OPERATING PRACTICES • GAS PROCESSING PLANTS 

-

N<>.of 

sn.., 

R•p«- AlmBD Hnltd "" """ .. Val•e h1 lbll "'" ""'"" Sli.e Sitt ""''" ' No. ToAtm <m) 

' N ' I 

' N • I 

' ,. " I 

• , . ' I 

' N ' 

• N ' 

' ' " N 

• , . • N 

• , . • N 

JO • 

"' " I ,. 

TOl•ls/A•I ,. 

• 11.1';1. " •Flore dou not handle compreoaor blow<lo>wno .,,. equ<pment blowdown•. 

""To flare. -

Roapronua, En,in .. 

~-· Idle C-i,..- Pnctku 

.. ,.. lo Low P ,,_, ....... oo,. OLowu .... .... N I 

N I 

N I 

N I 

N<111.-·llub1t 

N•• ''" 

, .. I 

, .. I 

, .. I 

I 

,,. . "'. ..... lS.H, 75.H, 

Turhtn" 

-·--· ';l.wi1h Attn BO S.pual• ldlt Comprff>or Pnc!lc .. 

"• ...... Val•t BDUnt 

Suri,,.. Lint Go "" 10 Low P 

= OOp. @ Lower to Aun No. To Alm (in) s,,tem• o,rw,u P'rn,u,e PrtS>ur< 

,oo ' Nol an, licahlt 

)00 ' Not onnlicahl< 

' ' Nol aoolle•blt 

' ' 

) I N I 

' I 

' • Not app\icohlt 

• ' Nol anohcable 

' • Nol ann~cable 

• • Nol •Mlicable 

' I ' 

u.o .. ,oo, 

----

'l, ~1,1, 

(;., 

Ston,,. 

lo,\lm 

--

-

-

Uk• - ,oo 

-

---

- H•n 

APPENDIXB 

Source Sheets 

B-1 
SOURCES, 

OPERA TING MODE, 

EMISSION TYPE, 

ANNUAL EMISSIONS: 

BACKGROUND, 

P-2 

PRODUCTION SOURCE SHEET 

All Production Equipment {See Below) 

Nonnal Operation 

Steady, Fugitive 

l7.4Bscf±41% 

Equipment leaks are typically low-level, unintentional losses of process fluid (gas or liquid) from the sealed surfaces 

of above-ground process equipment. Equipment components that tend to leak include valves, flanges and other 

connectors, pump seals, compressor seals, pressure relief valves, open-ended lines, and sampling connections. 

These components represent mechanical joints, seals, and rotating surfaces, which in time tend to wear and develop 

leaks. 

EMISSION FACTOR: (scf/equipment-yr, see below) 

In the component method for estimating emissions from equipment leaks, an average emission factor is detennined 

for each of the basic components, such as valves, flanges, seals, and other connectors that comprise a facility. The 

average emission factor for each type of component is detennined by measuring the emission rate from a large 

number of randomly selected components from similar types of facilities throughout the country. An average 

estimate of the emissions per equipment or facility are determined as the product of the average emission factor per 

component type (i.e., the component emission factor) and the average number of components associated with the 

major equipment or facility: 

Ef = f(Nvlv X EFviJ + {Nert X Ef .,,) + (Noel X Ef oe1) + (Nath X Ef...JJ 

where: 

N, = average count of components offype x per plant, and 

EF, = average methane emission rate per component of type x. 

Component emission factors for fugitive equipment leaks in gas production were estimated separately for onshore 

and offshore production due to differences in operational characteristics. Regional differences were found to exist 

between onshore production in the Eastern U.S. (i.e., Atlantic and Great Lakes region) and the Western U.S. (i.e., 

rest of the country, excluding the Atlantic and Great Lakes region) and between offshore production in the Gulf of 

Mexico and the Pacific Outer Continental Shelf (OCS). Separate measurement programs were conducted to account 

for these regional differences. 

Onshore Production in the Eastern U.S. Region. Gas production in the Eastern U.S. accounts for only 4.2% of 

gross national gas production, but includes 47% of the total gas wells in the country. Component emission factors 

for onshore production in the Eastern U.S. were based on a measurement program conducted by GRI/Star 

Envirorunental of 192 individual well sites at 12 eastern gas production facilities. Component counts for gas 

wellheads, separators, meters and the associated above-ground piping, and gathering compressors were based on 

infonnation collected as part ofthe Eastern U.S. produCtion measurement program. Site visits and phone surveys of 

7 additional sites provided data used for determining the number of heaters and dehydrators in the Eastern U.S. 

region. Component counts for heaters and dehydrators were assumed to be identical to those derived from data 

collected in the Western U.S. The following table presents the component emission factors, average component 

counts, and average equipment emissions for onshore gas production in the Eastern U.S. region. 

B-2 
Average Equipment Emissions for Onshore Production in the Eastern U.S. 

Equipment Type Component Type Component Average Average Equipment 

Emission Factor, Component Emissions,• 

Mscf/component-yr Count scf/equipment-yr 

Gas Wellheads Valve 0.184 8 2,595 (27%) 

Connection 0.024 38 

Open-Ended Line 0.42 0.5 

Separators Valve 0.184 I 328 (27%) 

Connection 0.024 6 

Heaters Valve 0.184 14 5,188 (43%) 

Connection 0.024 65 

Open-Ended Line 0.42 2 

Pressure Relief 0.279 I 

Valve 

Glycol Valve 0.184 24 7,938 (35%) 

Dehydrators Connection 0.024 90 

Open-Ended Line 0.42 2 

Pressure Relief 0.279 2 

Valve 

Meters/Piping Valve 0.184 12 3,289 (30%) 

Connection 0.024 45 

Gathering Valve 0.184 12 4,417 (27%) 

Compressors Connection 0.024 57 

Open-Ended Line 0.42 2 

• Values in parentheses represent the 90% confidence interval. 

Onshore Production in the Western U-S. Region. Component emission factors for onshore production in the 

Western U.S. were based on a comprehensive fugitive emissions measurement program conducted by API/GRl at 

12 oil and gas production sites. In this program, measurement data were collected from 83 gas-wells at 4 gas 

production sites in the Pacific, Mountain, Central, and Gulf regions. The average component counts for each piece 

of major process equipment associated with gas production in the Western U.S. were based on data collected during 

the APVGRl study and additional data collected for GRl during 13 site visits to gas production fields. The 

following table presents the component emission factors, average component counts, and average equipment 

emissions for onshore gas production in the Western U.S. region. 

B-3 
A v~~a~e Eauinment Emissions for Onshore Production in the Weste"' US. 

Equipment Type Component Component Average Average 

Typ, Emission Factor, Component Equipment 

Mscflcomponent-yr Count Emissions,' 

scf/equipmen 

t-yr 

Gas Wellheads Valve 0.835 11 13,302 (24%) 

Connection 0.114 36 

OEL 0.215 I 

Separators Valve 0.835 34 44,536 (33%) 

Connection 0.114 106 

OEL 0.215 6 

PRY 1.332 2 

Heaters Valve 0.835 14 21,066(40%) 

Connection 0.114 65 

OEL 0.215 2 

PRY 1.332 I 

Glycol Dehydrators Valve 0.835 24 33,262 (25%) 

Connection 0.114 90 

OEL 0.215 2 

PRY 1.332 2 

Meters/Piping Valve 0.835 14 . 19,310 (300/c) 

Connection 0.114 51 

OEL 0.215 I 

PRY 1.332 I 

Gathering Compressors Valve 0.835 73 97, 729 (68%) 

Connection 0.I 14 179 

OEL 0.215 3 

PRY 1.332 4 

Compressor 2.37 4 

Seal 

Large Compressor Stations 3.01 x 10° 

a a a (102%) 

Station Components 

Compressor-Related Components a a a 

5.55 x l(f 

f65%\ 

• Values m parentheses represent the 90% confidence mterval. 

b Refer to T-1 source sheet for a discussion of the basis for estimated emissions from large compressor stations. 

B-4 
Offshore Gas Production. Emissions from equipment leaks from offshore production sites in the U.S. were based 

on two separate measurement programs: 

• The API/GRI oil and natural gas production operations study, which included 4 offshore 

production sites in the Gulf of Mexico; and 

• The Minerals Management Service study of7 offshore production sites in the Pacific 

Outer Continental Shelf. 

The component emission factors and component counts were taken directly from the field test reports from these 

studies. The following table presents the component emission factors, component counts, and average facility 

emissions for offshore production in the Gulf of Mexico and Pacific OCS. 

Avera2:e Facili"'' Emissions for Offshore Production 

Equipment T}'pe Component T}'pe Component Average Average Facility 

Emission Factor, Component Count Emissions,• 

Mscf/component-yr Mscf/yr 

Gulf of Mexico Valve 0.187 2,207 1,064 (27%) 

Platfonn 

Connection 0.046 8,822 

Open-Ended Line 0.368 326 

Other 2.517 67 

Pacific OCS Valve 0.048 1,833 430 (36%) 

Platfonn 

Connection 0.021 13,612 

Open-Ended Line 0.092 313 

Other 0.091 307 

• Values in parentheses represent the 900/o confidence interval. 

EF DAT A SOURCES, 

I. Emission Factors for Eastern Gas Production based upon data from the GRI/Star program 

for the component EPs at 12 gas production sites. 

2. Fraction of methane (78.8 mo!%) based on data from Me1hane Emissions from the 

Natural Gas Industry, Volume 6: Vented and Combuslion Source Summary(]). 

Conversion of emission factors from (pounds THC per day) to (methane Mscf/yr) also 

required estimation of gas average molecular weight. Based on data from Perry's 

Chemical Engineer Handbook (2), Table 9-15, selected most si!nilar gas composition 

speciation from C1 through C6+ and perfonned linear extrapolation from average of 3 

lowest data (87 mo!% methane) to 78.8 mol% methane. Resultant weight percent of 69.6 

wt% methane used to speciate methane emissions. 

3. Component counts in Eastern gas production were based on average counts per 

equipment from the GRI/Star program at 12 gas production sites. Component counts for 

heaters and dehydrator in the Eastern region were based on data collected in the Western 

region. Component counts for onshore production in the Western U.S. were based on the 

averages from the GRI!Star program at 4 gas production sites and GRJ/Radian data from 

I 3 site visits to gas production fields. 

B-5 
4. Offshore data from API/GRI/Star 20-site program for Gulf of Mexico platforms (4 

platforms, site numbers 17 through 20), and Minerals Management Service/ABB Pacific 

OCS fugitive study (7 platforms). See respective test reports (Gulf of Mexico Offshore: 

API/Star 20-site study (3); Pacific OCS Offshore: MMS report 92-0043 November 30, 

1992) (4). 

5. Large gathering compressors and large gathering compressor station emission factors are 

taken from Transmission segment (see Sheet T-1). 

EF PRECISION: Gas Wells - Eastern 

Basis: 

Separators - Eastern 

Heaters - Eastern 

Dehydrators - Eastern 

Meters/piping - Eastern 

Gathering Compressors - Eastern 

Gas Wells - Western 

separators - Western 

Heaters - Western 

Dehydrators - Western 

Meters/piping - Western 

Gathering Compressors - Western 

Large Gathering Compressors 

Large Gathering Stations 

Offshore (GulO 

Offshore (Pacific) 

±27% 

±27% 

±43% 

±35% 

±30% 

±27% 

±24% 

±33'% 

±40% 

±25% 

± 30% 

±68% 

±65% 

± I02o/e 

±27% 

±36% 

The accuracy is rigorously propagated through the EF calculation from the range of individual 

measurements. Ninety percent confidence intervals were calculated for the sites using the tstatistic method. Computed 90% confidence intervals for site average component counts were 

combined with 90% confidence intervals for component emission factors to obtain pooled 

uncenainty in aggregate emission factor. 

ACTIVITY FACTOR: (129157 Gas Wells- Eastern) 

(91670 Separators- Eastern) 

(260 Heaters - Eastern) 

(1047 Dehydrators - Eastern) 

(76262 Meters - Eastern) 

(129 Gathering Compressors- Eastern) 

(142771 Gas Wells-Western) 

(74674 Separators- Western) 

(50740 Heaters - Western) 

(36777 Dehydrators - Western) 

(301180 Meters - Western) 

(16915 Gathering Compressors - Western) 

(96 Large Gathering Compressors) 

(12 Large Gathering Stations) 

(1092 Gulf of Mexico Platforms) 

(22 Western Offshore) 

B-6 

±5% 

±23% 

±196% 

±20% 

± 100% 

±33°/. 

±5% 

±57% 

±95% 

±20% 

± 100°1. 

±52% 

± 100% 

± 100% 

±10% 

±10% 
AF DATA SOURCES: 

AF PRECISION: 

I. The gas well count is from A.G.A.'s Gas Facts 1992 data (5). 

2. Eastern gas wells and equipment AFs were regiona!ized using site visit data. Eastern 

meter AF based on 0.43 meter per gas industry well (per Star Environmental). Western 

U.S. meter AF based on industry advisor infonnation of 1: I meter per gas industry well. 

3. Dehydrator counts are based on 37,824 glycol dehydrators in production (see Sheet P-6 

for details). Adjustment to activity factor for Eastern gas production: subtract l ,047 

dehydrators (included in Eastern gas production component counts). 

4. Offshore platform counts provided by Offshore Data Services, Inc., Houston, Texas, and 

Minerals Management Service MOAD database for producing platforms (6). Assumed 

50/50 split between "oil" industry and "gas" industry. 

5. Large gathering compressors and compressor station counts were estimated from FERC 

Fonn 2 database. Large gathering compressor stations were those with at least 16 stages 

of compression (5 compressors per station and an average of 3.3 stages per compressor). 

The result was extrapolated to the national total by ratioing on gathering miles covered in 

FERC to total gathering mileage. 

6. The other eqtiipment counts were produced from equipment count data taken during the 

site visits by Radian and Star. As explained in the activity factor section of the text of 

this report, extrapolation to national counts was done on a regional basis to account for 

regional equipment configuration differences. 

Basis: 

I. 

2. 

The precision for the active wells is assigned by engineering judgement, based upon the 

fact that the number of active wells is tracked nationally and known accurately by 

A.G.A./DOE, etc. 

The accuracy for the other equipment types is based upon rigorous propagation of error 

from the range in averages from the 9 production sites visited. 

B-7 
ANNUAL EMISSIONS: (17.4 Bscf/yr± 7.1 Bscf/yr) 

The annual emissions were determined by multiplying the average equipment emissions by the population of 

equipment in the segment. 

Ca<<go,y Em1ss,on Factor Aotiv,ty Factor Em,sswn Rate Unocrtaintv 

Gas W•llhoa.d {Easttto US) 2595 sofly, m<th.,,• 129157 us w<lls(EOS1cm US) 0 34 B,oliyr methane 2'7"!. 

Sopar>1ors{E11S1om US) J2B soliyr methane 91670,epar11or, (East<m US) Om B,oflvr me,hane )6% 

He••«• (Eas,em US) S tB7 scf!yr m<thane 260 healer, (Ea.,1cm U S ) 0001 Bsof7vrmo,h.,,• 118% 

0.hvdrators (Easlm, US) 79)9 <cf/yr m<!hano )047 dehydra!Ors (&sl•m US) 0008 Bscf/y,me<li.,,, 4W, 

M<!en-P',pin~ (Eo.,ttm US> 3289sc;f/yr~ar,o. 76262 mo,er,, {Eastern U S ) 0 25 Bsc:f/y, me1hane ID9>/, 

G,thfflng Comires,<><s (E&<lcm US) 4417sc:f/y,~ane J29 gathenng compre,,or, (E&<lem US ) 00006 Bsof,y, m<!hlUl< 44o/, 

Gas We!lh .. ds (WcS!ern US) 1]]02 ,.,Jiy, mcthanc 142771 gas ,..,..lb (W<stem U S ) I 9 Bsc:flvr rno,ha,ie 21'4 

S<t>arators (Won«• U S ) «536 scf!yr m""1atl< 74674 -•nn!Wn1emUS) J JJ Bscflyr m<!hane 61"4 

H .. ,.,., (Wenem U S ) 21066 seflyr m<th11rt< 50740 ;.,.!i<>eh .. cr, (W"'cm U.S) I 07 8,cf/y, mothaoe 110% 

O.hydratOrs !Western US) JJ262 ,d/op methMO ]6717 dehydraiors(Westem US) l 22 Bscflvr m<!hane J2'1o 

M<!er,(Wes,em US) 19l!O scfiy, fntthane JOI l80m.,...{W~om US) 5 82 Bsc:fiyrmOlhane ,=, 

Smol! Gatherin>< Compf<'lOfS(Weoicm US) 97729 rd/yr methane !6915 <IO -··n(W«nemUS.) I 6S 8,of/yr m<!hane 9)~. 

L.,g• Ga•hffln~ Cornpfe!>Ors (Weoicm U S ) S 55 MMscflyr med,8"e 96 large comp,~ O SJ Bscf/yr mtlhaoe nw. 

Ulg<: Gathering Compressor SWiOJ>I (Western Jot MM«:f/yr ~""• 12 large gath<nng comp= >t&tion, 0 04 8,ofl~, motha,,o "~ US) 

O!fshoreO,l!G&< (Gulf) 1064 Ms<fl , mothono ]092 Gulf of Me>1co ,1atfomu; I 16Bscf/yrm<!hMo ,~ 

Olfshoro Oil/Gas ((Pacifi<) 4JOOM,<f/y,-m<!hane 22 piaitonr,,(Pacifio) O Ot B,cllyr mothaoe 38% 

TOTAL 17 4 B,of!yr methane 41'/o 

REFERENCES 

I. Shires, T.M. and M.R. Harrison. Methane Emissionsfrom the Natural Gas Industry. Volume 6: 

2. 

3. 

4. 

Vented and Combustion Source Summary, Final Report, GRI-94/0257.23 and EPA-600/R.-96-

080f; Gas Research Institute and U.S. Environmental Protection Agency, June 1996. 

Perry, J.H. (ed). Chemical Engineers Handbook 5th Edition, McGraw-HilJ Book Co., New York, 

NY, 1984. 

Star Environmental. Emission Factors for Oil and Gas Production Operations, AP! Publication 

No., 4615. American Petroleum Institute, January 1995. 

Minerals Management Service. Fugitive Hydrocarbon Emissions from Pacific OCS Facilities. 

Volume I, Final Report. MMS 92-0043. U.S. Department of Interior, New Orleans, LA, 

November 30, !992. 

B-8 
5. 

6. 

American Gas Association. Gas Facts, Arlington, VA. 1992. 

Minerals Management Service. Users Guide. MMS Outer Continental Shelf Activity Database 

(MOAD), OCS Study MMS 94-0018, U.S. Department ofthe Interior, New Orleans, LA, April 

1994. 

B-9 
SOURCES: 

OPERATING MODE: 

EMISSION TYPE: 

ANNUAL EMISSIONS: 

BACKGRvUND: 

GP-I 

PROCESSING SOURCE SHEET 

All Equipment at Gas Processing Plants 

Normal Operation 

Steady and Unsteady, Fugitive 

24.45 Bscf ± 68% 

Equipment leaks are typically low-level, unintentional losses of process fluid (gas or liquid) from the sealed surfaces 

of above-ground process equipment. Equipment components that tend to leak include valves, flanges and other 

connectors, pump seals, compressor seals, pressure relief valves, open-ended lines, and sampling connections. 

These components represent mechanical joints, seals, and rotating surfaces, which in time tend to wear and develop 

leaks. 

EMISSION FACTOR: 

a. Plant"" 2.89 MMscf/yr methane per plant 

b. Reciprocating Compressor"" 4.09 MMscf/yr methane per recip 

c. Centrifugal Compressor= 7.75 MMscf/yr methane per turbine 

The average fugitive emission rate for gas processing plants was determined to be composed of two parts: a) plant 

component counts (excluding compressor components), and b) compressor-related components. 

Fugitives from the compressor-related components have much higher emission factors than components in the rest 

of the facility. Pan ofthis is due to the high vibration that compressors generate, but most ofthe larger emissions 

are due to unique compressor components, as explained below. 

a. The contribution from non-compressor components was determined by multiplying the average component count 

by the component emission factor. The number of components was subdivided into valves, connections/flanges, 

small open-ended lines, site blowdown (BID) OELs, control valves, and other components (such as pressure relief 

valves). (Tubing components were determined to be insignificant.) All of these components are typical fugitive 

components (as described in the EPA Fugitive Emissions Protocol) with the exception of control valves and site 

BJD OELs. Control valves emit at a higher rate than manual isolation valves since their packing is stressed more 

often as they are activated much more frequently. Site BID OELs are the large diameter emergency station 

blowdown valves that are designed to depressure the entire site to the atmosphere when the valve is opened. 

The component emission factors for gas plant components (i.e., non.compressor related) were based on an_ API/GRJ 

measurement program conducted at 8 gas plants. The average facility emlssions are then calculated as follows: 

where: 

N, = average count of components of type x per plant, and 

EF, = average methane emission rate per component of type x. 

b. The contribution from compressor-related components was obtained by multiplying the average number of 

fugitive components per compressor engine by component emission factors. The component emission factors were 

based on the GRI/Jndaco measurement program conducted at 15 compressor stations. Some compressor 

components are unique, while others have higher leak rates than identical components elsewhere in the plant due to 

vibration. Compressors have the following types of components: 

B-10 
I) Comp. BID OEL A blowdown (BID) valve to the annosphere that can depressure the compressor when 

idle. The B/P valve or the large unit block valves (depending on the operating status of 

the compressor) can act as an open-ended line that leaks at an extraordinarily high rate 

through the valve seat. The leak rate is dependent upon whether the compressor is 

pressurized (in operation or idle, pressurized} or depressurized (idle, depressurized). 

2) Comp. PRY The pressure relief valve {PRV) is usually installed on a compressor discharge line, and 

leaks at a higher than average rate due to vibration. 

3) Comp. Starter OEL Most compressors have a gas starter motor that turns the compressor shaft to start the 

engine. Some use natural gas as the motive force to spin the starter's turbine blades, and 

vent the discharge gas to the annosphere. The inlet valve to the starter can leak and is 

therefore an OEL unique to compressors. 

4) Comp. Seal All compressors have a mechanical or fluid seal to minimize the flow of pressurized 

natural gas that leaks from the location where the shaft penetrates the compression 

chamber. These seals are vented to the annosphere. Reciprocating compressors have 

sliding shaft seals while centrifugal compressors have rotating shaft seals. 

5) Miscellaneous There are many components on each compressor, such as valve covers on reciprocating 

compressor cylinders and fuel valves. 

Each compressor has one BID OEL, one PRV, and one starter OEL. Reciprocating compressors have one 

compressor seal per compression cylinder (which averaged 2.5 per engine), while centrifugal compressors have 1.5 

seals per gas turbine. For the miscellaneous component category, there are many components per compressor 

engine, but the emission rates were minor and so were added into one lump emission factor per compressor for 

miscellaneous components. 

All of the compressor emission factors take several correction factors into account. First, the various phases of 

compressor operations f such as the amount of time that compressors are a) idle and depressured, b) idle and 

pressured up, or c) runningJ. This is actually a complex adjustment that takes into account valve position practices. 

[See Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks(!) for details.} Correction 

factors were also added for fraction of starter gas turbines using air instead of gas (75% for recip, 33% for turbines 

in gas processing), and for sites with flares handling PRV or compressor BID discharge (approximately 11% of the 

compressor blowdown OELs were routed to a plant flare). 

EF DAT A SOURCES: 

I. Component emission factors based on screening results from API/GRI/Star program for 

the component EF's for eight gas processing plants and EPA's current default zero 

factors, correlation equations, and pegged source factors. Confidence limits derived from 

analysis of screening data by Radian in April 1995. 

2. OEL (site BID) emission factor based on results from GRI/Jndaco program for 

compressor stations (June 1994). 

3. Plant component counts were based on average of 8 API/Star sites, 6 EPA/Radian sites in 

1982, and 7 sites visited under this project in I 992. 

4. Compressor emission factors based on results from GRIIIndaco program for 15 

compressor stations (June 1994). Compressor operating hours (% running) based on data 

from 3 gas processing company databases. 

B-11 
Average Facility Emissions for Gas Processing 

Equipment Type Component Type Component Average Component 

Emission Factor, Count 

Mscf/component-yr 

Gas Plant (non- Valve 1.305 1,392 

compressor related 

components) Connection 0.117 4,392 

Open-Ended Line 0.346 134 

Pressure Relief 0.859 29 

Valve 

. 

Site Blowdown 230 2 

Open-Ended Line 

Reciprocating Compressor 2,036b.c I 

Compressor Slowdown OpenEnded Line 

Pressure Relief 349b,c I 

Valve 

Miscellaneous 189< I 

Starter Open-Ended 1,341 0.25~ 

Line 

Compressor Seal 450< 2.5 

Centrifugal Compressor 6,447b.d l 

Compressor Slowdown OpenEnded Line 

Miscellaneous 3 J' I 

Starter Open-Ended 1,341 0.667[ 

Line 

Compressor Seal 228d 1.5 

• Values in parentheses represent 90% confidence interval. 

b Adjusted for 11.1% of compressors which have sources routed to flare. 

< Adjusted for 89. 7% of time reciprocating compressors in processing are pressurized. 

d Adjusted for 43.6% of time centrifugal compressors in processing are pressurized. 

< Only 25% of starters for reClprocating compressors in processing use natural gas. 

r Only 66. 7% of staners for centrifugal compressors in processing use natural gas. 

B-12 

Average Equipment 

Emissions,' 

MMscf/yr 

2.89 (48%) 

4.09 (74%) 

7.75 (39%) 
EF ACCURACY: 

Basis: 

l. 

ACTIVITY FACTOR 

a. Plant Emission Factor = ± 48% 

b. Recip. Compressor = ± 74% 

c. Turbine Compressor = ± 39% 

The accuracy was propagated through the EF calculation from each terms accuracy. 

90% confidence intervals were calculated for the sites using the t-statistic method. 

The 90% confidence intervals accounted for variability in component count from the 

range in site averages and estimates were also provided for the component emission 

factors from the API/Star and GRI/Indaco program. 

a. Plant Activity Factor = 726 plants 

b. Compressor Activity Factor = 4092 recip engines, 726 turbines 

The number of gas processing plants was determined from the Oil and Gas Journal (2) (July 1993). 

The number and type of gas processing compressor engines were determined from eleven gas plant site visits. 

The average ratio of compressors per plant was multiplied by the total number of plants, 726, to obtain these 

estimates. [See Methane Emissions from the Natural Gas Industry, Volume 5: Activity Factors (3) for 

details.] 

AF DATA SOURCES: Oil and Gas Journal (July 1993) (2) 

AF ACCURACY, 

Basis: 

l. 

2. 

3. 

a. Plant Activity Factor: ± 2% 

b. Compressor Activity Factor: Redp engines = ± 48%; Turbines = ± 77% 

An accurate count of gas plants by the Oil and Gas Journal (2) is very likely since 

counting such large, discreet facilities should be straightforward. The ± 2% was 

assigned by engineering judgement. 

The compressor count accuracy was determined by statistical analysis of the 

"compressor per site" averages for I I gas plant sites. 

A check was performed to estimate whether gas plant sites visited for compressor 

counts were representative of industry average. Based on Oil and Gas Journal, the 

average plant capacity was 88.3 MMscfd and throughput was 51.2 MMscti'd. Site 

visit data averaged 271 MMscfd and throughput was 182 MMscfYd, suggesting that 

plants visited were larger than average. However, further investigation revealed that 

there is no correlation between plant capacity/throughput and number of compressors 

(The plant visited with the most compressors had 20 engines with 20,000 HP and a 

low throughput of 56 MMscfd, while the plant with the highest current operating 

rate of 750 MMscfd had only one compressor at 17,500 HP.) 

B-13 
ANNUAL EMISSIONS: (24.45 Bscf/yr ± 16.7 Bscf/yr) 

The annual emissions were determined by multiplying the average equipment/facility emissions by the population 

of equipment in the segment. 

Category Emission Factor Activity Emission Uncertainty 

Factor Rate 

Gas processing 2.89 MMscflyr 726 plants 2. 1 Bscf/yr 48% 

plants methane methane 

Recip Comp 4.09 MMscflyr 4092 1':Cip !6.7Bscflyr 95% 

methane methane 

Turbine Comp 7.75 MMsc£1yr 726 turbine 5 .6 Bscflyr 91% 

methane methane 

TOTAL 24.4 Bsc£1yr 68% 

methane 

REFERENCES 

I. 

2. 

3. 

Hummel, K.E., L.M. Campbell, and M.R. Harrison. Methane Emissions from the Natura/Gas 

Industry, Volume 8: Equipment Lea/cs, Final Report, GRI-94/0257.25 and EPA-600/R-96-080h, 

Gas Research Institute and U.S. Environmental Protection Agency, June 1996. 

Oil and Gas Journal. 1992 Worldwide Gas Processing Survey Database, July 1993. 

Stapper, B.E .. Methane Emissions from the Natural Gas Industry, Volume 5: Activity Factors, 

Fina! Repon, GRI-94/0257.22 and EPA-6001R.-96-080e, Gas Research Institute and U.S. 

Environmental Protection Agency, June 1996. 

B-14 
SOURCES: 

OPERA TING MODE: 

EMISSION TYPE: 

ANNUAL EMISSIONS: 

BACKGROUND: 

T-1 

TRANSMISSION SOURCE SHEET 

Compressor Stations 

Nonna! Operation 

Steady and Unsteady, Fugitive 

50.7 Bscf± 52% 

Equipment leaks are typically low-level, unintentional losses of process fluid (gas or liquid) from the sealed surfaces 

of above-ground process equipment. Equipment components that tend to leak include valves, flanges and other 

connectors, pump seals, compressor seals, pressure relief valves, open-ended lines, and sampling connections. 

These components represent mechanical joints, seals, and rotating surfaces, which in time tend to wear and develop 

leaks. 

EMISSION FACTOR: a. Station = 3.2 MMscf/yr methane per plant 

b. Recip. Compressor= 5.55 MMscf/yr methane per recip 

c. Turbine Compressor= 11.1 MMscf/yr methane per turbine 

The average fugitive emi$sion rate for transmission compressor stations was determined to be composed of two 

parts: a) station components (excluding compressor-related components); and b) compressor-related components. 

Fugitives from the compressor-related components have much higher emission factors than components in the rest 

of the facility. This is due in part to the high vibration that compressors generate, but most of the larger emissions 

are due to unique compressor components, as explained below. 

a. The contribution from non-compressor components was detennined by multiplying the average component count 

]JY the component emission factor. The number of components was subdivided into valves, connections/flanges, 

small open-ended lines, site blowdown (BID) OELs, control valves, and other components (such as pressure relief 

valves). (Tubing components were determined to be insignificant.) All ofthese components are typical fugitive 

components (as described in the EPA Fugitive Emissions Protocol) with the exception of control valves and site 

BID OELs. Control valves emit at a higher rate than manual isolation valves since their packing is stressed more 

often as they are activated much more frequently. Site BID OELs are the large diameter emergency station 

blowdown valves that are designed to depressure the entire site to the atmosphere when the valve is opened. 

The component emission factors for station components were based on a GRI/Indaco measurement program 

conducted at 6 compressor stations. The average facility emissions are then calculated as follows: 

where·. 

N, = average count of components of type x per plant, and 

EF, = average methane emission rate per component of type x. 

b. The contribution from compressor-related components was obtained by multiplying the average number of 

fugitive components per compressor engine by the component emission factors. The component emission factors 

were based on the GRI/Indaco measurement program conducted at 15 compressor stations. Some compressor 

components are unique, while others have higher leak rates than identical components elsewhere in the plant due 

to vibration. Compressors have the following types of components: 

I) Comp. BID OEL A blowdown (BID) valve to the atmosphere thal can depressure the compressor when 

idle. The BID valve or the large unit block valves (depending on the operating status of 

the compressor) can act as an open-ended line that leaks at an extraordinarily high rate 

B-15 
through the valve seat. The leak rate is dependent upon whether the compressor is 

pressurized(~ operation or idle, pressurized) or depressurized (id.le, depressurized). 

2) Comp. PRV The pressure relief valve (PRV) is usually installed on a compressor discharge line and 

leaks at a higher than average rate due to vibration. 

3) Comp. Staner OEL Most compressors have a gas starter motor that rums the compressor shaft to start the 

engine. Some use natural gas as the motive force to spin the starter's turbine blades 

and vent the discharge gas to the atmosphere. The inlet valve to the starter can leak 

and is therefore an OEL unique to compressors. 

4) Comp. Seal All compressors have a mechanical or fluid seal to minimize the flow of pressurized 

natural gas that leaks from the location where the shaft penetrates the compression 

chamber. These seals are vented 10 the atmosphere. Reciprocating compressors have 

sliding shaft seals while centrifugal compressors have rotating shaft seals. 

5) Miscellaneous There are many components on each compressor, such as valve covers on reciprocating 

compressor cylinders and fuel valves. 

Each compressor has one BID OEL, one PRV, and one starter OEL. Reciprocating compressors have one 

compressor seal per compression cylinder (which averaged 3.3 per engine), while centrifugal compressors have 

1.5 seals per gas turbine. For the miscellaneous component category, there are many components per compressor 

engine, but the emission rates were minor and so were added into one lump emission factor per compressor for 

miscellaneous components. 

All of the compressor emission factors lake several correction factors into account. First, lhe various phases of 

compressor operations (such as the amount of time that compressors are a) idle and depressured, b) idle and 

pressured up, or c) running). This is actually a complex adjustment that takes into account valve position 

practices. [See Methane Emissions from the Natural Gas Industry, Volume 8: Equipmenr, Leaks (1) for more 

details.] Correction factors were also added for fraction of starter gas turbines using air instead of gas (100 % for 

recip, 0% for turbines in Transmission). 

EF DATA SOURCES, 

I. Component emission factors based on results from GRI/Indaco program for the 

component EF's for 6 transmission compressor stations (June 1994). Adjustment of 

station EF is to account for data obtained from one interstate transmission pipeline 

company that was found to have higher emissions than average. 

2. Plant component counts were based on an average of 8 Indaco sites in 1994 and 9 sites 

visited under this project in 1993, plus 7 industry sites. 

3. Compressor emission factors based on results from GRI/Indaco program for 15 

compressor stations (June 1994). Compressor operating hours(% running) baseC on 

data from FERC database, GRI TRANSDAT database, and data supplied by one large 

interstate transmission pipeline company. 

4. Fraction of methane (93.4 mo!%) based on data from GRI TRANSDAT database. 

B-16 
Average Facility Emissions for Gas Transmission 

Equipment Type Component Type Component Average Average Equipment 

Emission Factor, Component Emissions,' 

Mscf/component-yr Count MMscf/yr 

Compressor Station Valve 0.867 673 3.01 (102%) 

(non-compressor (Note: 3.2 MMscf/yr 

related components) Control Valve 8.0 31 used in national 

emission estimate)" 

Connection 0.147 3.068 

OEL 11.2 51 

PRY 6.2 14 

Site B/D OEL 264 4 

Reciprocating Compressor BID 3,683 1 5.55 (65%) 

Compressor OEL 

PRY 372° 1 

Miscellaneous 180' 1 

Compressor Starter d d 

OEL 

Compressor Seal 396° 3.3 

Centrifugal Compressor B/D 9,352 1 11.1 (34%) 

Compressor OEL 

Miscellaneous 18' 1 

Compressor Starter 1,440 1 

OEL 

Compressor Seal 165° 1.5 

• Values in parentheses represent 90% confidence interval. 

b Adjusted for data received from one company that was not considered representative of national average. 

" Adjusted for the fraction of time the compressor is pressurized (79. l % and 24.2 % for reciprocating and 

centrifugal 

compressors, respectively). 

d Reciprocating compressor staners were assumed to use compressed air or electricity instead of natural gas. 

B-17 
EF ACCURACY, a. Station = 102% 

b. Recip. Compressor = 65% 

c. Turbine Compressor = 34% 

Basis: 

Rigorous propagation of error from the spread of thousands of individual measurements taken 

by Indaco. 

ACTIVITY FACTOR: a. Station Activity Factor = 1700 stations 

b. Compressor Activity Factor = 6799 recip engines, 681 turbines 

AF DATA SOURCES, 

I. 1992 FERC Fenn 2 responses accounted for 70% of national transmission pipeline 

mileage. Total station count extrapolated using national total transmission mileage of 

276,900 miles from A.G.A. Gas Facts (2). 

2. Compressor engine count based on GRI TRANSDAT ~industry database" with 

adjustments for total industry horsepower. Transmission compressor station counts 

were split from storage based upon storage station site visit data and Gas Facts (2) 

data on storage stations. Added 0.2% to recip count account for electric motor 

drivers. 

AF ACCURACY, 

Basis: 

I. 

2. 

a. Station Activity Factor: ± 10% 

b. Compressor Activity Factor: Recip engines = ± 17 %; Turbines = ± 26 % 

FERC Form 2 data have a high percentage (70%) of all transmission comparties. 

Therefore a national extrapolation should not add much error. This 10% figure was 

assigned based on engineering judgement. 

The compressor count accuracy was assigned based upon the propagation from: a) 

rigorous error propagation for the 8 storage station ~compressor/station- averages; and 

b) engineering judgement assignment of ± 10% error to the large GRI TRANSDAT 

database. 

B-18 
ANNUAL EMISSIONS: (50.73 Bscf/yr ± 26.3 Bscf/yr) 

The annual emissions were determined by multiplying the average facility/equipment emissions by the population 

of equipment in the segment. 

Category 

Station 

Recip Comp 

Turbine Comp 

TOTAL 

REFERENCES 

I. 

2. 

Emission Factor Activity Factor Emission Rate Uncertamty 

3.2 MMscflyr ! 700 stations 5.4 Bscf/yr 103% 

CH4 CH4 

5.55 MMscf/yr 6799 recip 37.8 Bscf/yr 68% 

CH4 CH4 

11.1 MMscf/yr 68! rurbine 7.5 Bscflyr 44% 

CH4 CH4 

50.7 Bscf/yr 52% 

CH4 

Hummel, K.E., L.M. Campbell, and M.R. Harrison. Methane Emissions from the Natural Gas 

Industry, Volume 8: Equipment Leaks, Final Report, GRI-94/0257 .25 and EPA-600/R-96-080h, 

Gas Research Institute and U.S. Environmental Protection Agency, June 1996. 

American Gas Association, Gas Facrs. Arlington, VA, 1992. 

B-19 
SOURCES: 

OPERA TING MODE: 

EMISSION TYPE: 

ANNUAL EMISSIONS: 

BACKGROUND: 

S-1 

STORAGE SOURCE SHEET 

Storage Facilities (Compressor Stations and WeJ/s) 

Nonn al Operation 

Steady and Unsteady, Fugitive 

16.76 Bscf ± 57% 

Equipment leaks are typically !ow-level, unintentional losses of process fluid (gas or liquid) from the sealed 

surfaces of above-ground process equipment. Equipment components that tend to leak include valves, flanges 

and other connectors, pump seals, compressor seals, pressure relief valves, open-ended lines, and sampling 

connections. These components represent mechanical joints, seals, and rotating surfaces, which in time tend 

to wear and develop leaks. 

EMISSION FACTOR: a. Station = 7.85 MMscUyr methane per station 

b. Wellhead .. 41.8 Mscf/yr methane per wellhead 

c. Recip. Compressor = 7.71 MMscf/yr methane per recip 

d. Turbine Compressor = 11.16 MMscf/yr methane per turbine 

The average fugitive emission rate for storage facilities was detennined to be composed of three parts: a) 

storage compressor station components (excluding compressor-related components), b) injection/withdrawal 

wellhead components, and c) compressor-related components. Fugitives from the compressor-related 

components have much higher emission factors than components' in the rest of the facility. This is due in part 

to the high vibration that compressors generate, but most of the larger emissions are due to unique compressor 

components as explained below. 

a) The contribution from non-compressor components was detennined by multiplying the average number of 

fugitive components by the component emission factor. The number of components was subdivided into 

valves, connections/flanges, small open-ended lines, and other components (such as pressure relief valves); 

tubing components were detennined to be insignificant. All of these components are typical fugitive 

components (as described in the EPA Fugitive Emissions Protocol) with the exception of site blowdown 

(BID) open-ended lines (OELs). Site BID OELs are the large diameter emergency station blowdown valves 

that are designed to depressure the entire site to the atmosphere when the valve is opened. Emission factors 

for storage station components were based on the GRI/Jndaco program at 6 transmission compressor station 

sites. 

b) The contribution from storage injection/withdrawal wells was determined in the same manner as storage 

compressor stations (see below). Emission factors for storage injection/withdrawal wells were based on the 

updated API/GRVStat 20-site study (4 gas production sites). Physical and operational character:istics of 

injection/withdrawal wells were compared to gas production wells, and were found to be similar but typically 

larger (more components). This was taken into account in the component count data. 

The number of components was subdivided into types, such as valves, connections/flanges, open-ended lines, 

and other components (such as pressure relief valves). The average facility/equipment emissions are 

calculated as follows: 

where: 

Nx = average count of components of type x per plant, and 

EF, = average methane emission rate per component of type x. 

B-20 
c} The contribution from compressor-related components was obtained by multiplying the average number of 

fugitive components per compressor engine by the component emission factors. The component emission factors 

were based on the GRI/Indaco measurement program conducted at J 5 compressor stations. Some compressor 

components are unique, while others have higher leak rates than identical components elsewhere in the plant due to 

vibration. Compressors have the following types of components: 

I} Comp. BID OEL A blowdown (BID) valve to the atmosphere that can depressure the compressor when 

idle. The BID va!ve 0r the large unit block valves (depending on the operating status of 

the compressor) can act as an open-ended line that leaks at an extraordinarily high rate 

through the valve seat. The leak rate is dependent upon whether the compressor is 

pressurized (in operation or idle, pressurized) or depressurized (idle, depressurized}. 

2) Comp. PRV The pressure relief valve (PRV} is usually installed on a compressor discharge line and 

leaks at a higher than average rate due to vibration. 

3) Comp. Starter OEL Most compressors have a gas starter motor that turns the compressor shaft to start the 

engine. Some use natural gas as the motive force to spin the starter's turbine blades and 

vent the discharge gas to the atmosphere. The inlet valve to the starter can leak and is 

therefore an OEL unique to compressors. 

4) Comp. Seal Ail compressors have a mechanical or fluid seal to minimize the flow of pressurized 

natural gas that leaks from the location where the shaft penetrates the compression 

chamber. These seals are vented to the atmosphere. Reciprocating compressors have 

sliding shaft seals while centrifugal compressors have rotating shaft seals. 

5) Miscellaneous There are many components on each compressor, such as valve covers on reciprocating 

compressor cylinders and fuel valves. 

Each compressor has one BID OEL, one PRV, and one starter OEL. Reciprocating compressors have one 

compressor seal per compression cylinder (which averaged 4.5 per engine), while centrifugal compressors have ! .5 

seals per gas turbine. For the misceJlaneous component category, there are many components per compressor 

engine, but the emission rates were minor and so were added into one lump emission factor per compressor for 

miscellaneous components. 

All of the compressor emission factors take several correction factors into account. First, the various phases of 

compressor operations (such as the amount of time that compressors are a) idle and depressured, b) idle and 

pressured up, or c) running). This is actually a complex adjustment that takes into account valve position practices. 

[See Methane Emissions .from Natural Gas Industry, Volume 8: Equipment Leaks (I) for more details. J Correction 

factors were also added for fraction of starter gas turbines using air instead of gas (40% for recip, 50% for turbines 

in storage). 

EF DAT A SOURCES: 

I. Emission Factors for storage compressor stations are based upon GRI/Indaco 

transmission compressor station fugitive leak measurement surveys at 6 compressor 

stations. Compressor operating hours (% running) based on data from 5 national gas 

storage companies. 

2. Component counts for storage compressor stations and injection/withdrawal wellheads 

are based on Radian site visits to 5 storage facilities. 

3. Component emission factors for compressor-related components based on GRI/Indaco 

transmission compressor station fugitive leak measurement program at 15 compressor 

stations. 

4. Wellhead emission factors based on simple average of GRI/Star data for gas production 

wellheads (Atlantic/Eastern region and Rest of U.S.). 

5. Fraction of methane (93.4 mo!%) based on data from GRI TRANSDAT database. 

B-21 
Average Facility Emissions for Gas Storage 

Equipment Type Component Type Component Average Component Average Equipment 

Emission Factor, Count Emissions,' 

Mscf/component-yr MMscf/yr 

Storage Facility Valve 0.867 J,868 7.85 (100%) 

(non-compressor 

related components) Connection 0.147 5,571 

OEL 11.2 353 

PRV 6.2 66 

Site BID OEL 264 4 

lnjectiow'Withdrawa Valve 0.918 30 0.042 (76%) 

I Wellhead 

Connection 0.125 89 

OEL 0.237 7 

PRV l.464 I 

Reciprocating Compressor BID 5,024b I 7.71 (48%) 

Compressors OEL 

PRV 317b I 

Miscellaneous 153b I 

Compressor Starter 1,440 0.6< 

OEL . 

Compressor Seal 300b 4.5 

Centrifugal Compressor BID I0,233b I l 1.16 (34%) 

Compressors OEL 

Miscellaneous 17' I 

Compressor Starter 1,440 OS 

OEL 

Compressor Seal 126b 1.5 

• Values in parentheses represent 90% confidence interval. 

b Adjusted for the fraction of time the compressor is pressurized (67.5% and 22.4% for reciprocating and 

centrifugal compressors, respectively). 

< Adjusted for the fraction of compressor starters using natural gas (60% and 50% for reciprocating and 

centrifugal compressors, respectively). 

B-22 
EF ACCURACY: a. Station = ± 100% 

b. Wellhead = ± 76% 

b. Recip. Compressor = ± 48% 

c. Turbine Compressor = ± 34% 

Basis: 

Rigorously propagation of error from the spread of thousands of individual measurements 

taken by Indaco and Star. 

ACTIVITY FACTOR a. Station Activity Factor= 475 stations 

b. Wellhead Activity Factor= 17999 wellheads 

b. Compressor Activity Factor = 1396 recip compressors, 136 turbines 

The activity factors for the segment were compiled from published statistics in Gas Facts (2). The total count 

for Underground storage stations was 386, and the total LNG storage count was 89. 

AF DATA SOURCES: 

I. 

2. 

3. 

AF ACCURACY, 

Basis: 

I. 

2. 

The number of underground storage facilities was taken directly from A.G.A. Gas 

Facts, (2), Table 4-5: Number of Pools, Wells, Compressor Stations, and 

Horsepower in Underground Storage Fields. Data from base year 19n were used. 

The number of Liquefied Natural Gas Storage Facilities was summed from A.G.A. 

Gas Facts (2), Table 4-3, "Liquefied Natural Gas Storage Operations in the U.S. as 

of December 31, 1987." The table lists 54 complete plants, 32 satellite plants, and 3 

impon tennina!s for a tota! of 89 facilities . 

. Compressor engine count based on GRI TRANSDAT "industry database" with 

adjustments for total industry horsepower. Storage site visits to 8 storage sites 

provided number of reciprocating engines and turbines per site Isee Activity Factor 

Repon (3)}. Also, the number of reciprocating compressors in storage was increased 

by 31% to account for electric motor drivers. 

a. Station Activity Factor: ± 5% 

b. Wellhead Activity Factor. ± 5% 

b. Compressor Activity Factor: Recip engines = ± 58 %; Turbines = ± II9 % 

A.G.A. Gas Facts (2) has a high percentage of all storage facilities represented in 

Tables 4-5 and 4-3. Therefore a national extrapolation should not add much error. 

This 5% figure was assigned based on engineering judgement. 

The compressor count accuracy was assigned based upon the propagation from: a. 

Rigorous error propagation for the 8 storage station "compressor/station" averages; 

and b. Engineering judgement assignment of± 10% error to the large GRI 

TRANSDAT database. 

B-23 
ANNUAL EMISSIONS: (16.76 Bscf/yr::1: 9.6 Bscf/yr) 

The annual emissions were detennined by multiplying an emission factor for an average equipment type by the 

population of equipment in the segment. 

Category 

Station 

lnj/With Wellheads 

RecipComp 

Turbine Comp 

TOTAL 

REFERENCES 

I. 

2. 

3. 

Emission Faclor Activity Factor Emission Rate Uncertainty 

7 .85 MMscf7yr CH4 415 stations 3.73 BscflyrCH4 !00% 

41.8 Mscflyr CH4 ! 7999 wellheads 0. 752 BscUyr CH4 76% 

7 7 ! MMscf/yr CH4 1396 reclp I 0. 76 Bscflyr CH4 80% 

l ! 16 MMscf/yr CH4 136 turbine l 52 Bscf/yr CH4 129% 

I 6.76 Bsd/yr CH4 57% 

Hummel, K.E., LM. Campbell, and M.R. Harrison. Methane Emissions from the Natural Gas 

Jnd.ustry, Volume 8: Equipment Leaks, Final RepoM, GRJ-94/0257.25 and EPA-600/R-96-080h, 

Gas Research Institute and U.S. Environmental Protection Agency, June 1996. 

American Gas Association. Gas Facts, Arlington, VA. 1992. 

Stapper, B.E. Methane Emissions from the Natural Gas Industry, Volume 5: Activity Factors, 

Final Report, GRI-94/0257.22 and EPA-600fR .. 96-080e, Gas Research Institute and U.S. 

Environmental Protection Agency, June 1996. 

B-24 
SOURCES: 

OPERA TING MODE, 

EMISSION TYPE, 

ANNUAL EMISSIONS: 

BACKGROUND: 

D-5 

DISTRIBUTION SEGMENT SOURCE SHEET 

Customer Meters 

Nonna] Operations 

Steady, Fugitive 

5.8 ± t.l bscfy 

Losses from customer meters are caused by fugitive leakage from the connections and other fittings surrounding the 

meter set. 

EMISSION FACTOR: (outdoor residential meters: 138.5 =: 23.1 scUmeter-yr 

commercial/industrial meters: 47.9 ± 16.7 scf/meter-yr) 

The estimate of leakage from customer meters is based on screening and bagging studies conducted at ten sites 

throughout the United States. The initial study was conducted by lndaco to measure customer meters in the west 

coast [Indaco Air Quality Services, Inc., Methane Emissions from Natural Gas Customer Meters: Screening and 

Enclosure Studies, draft report, August 15, 1992 (I)]. Data were also collected at nine additional sites across the 

United States, including three east coast sites, a mid-western site, a rocky mountain site, and five western U.S. sites. 

A summary of the average emissions from residential customer meters from each of the ten sites is shown in the 

following table: 

Site Number ofMeters Number of Meters Average Leak Rate• Standard 

Screened Leaking (lb methane/day) Deviation• 

(lb methane/day) 

Site I -- West Coast 134 37 0.0098 0.0239 

Site 2 -- East Coast 40 29 0.0002 0.0004 

Site 3 -- East Coast 158 37 0.0789 0.1753 

Site 4 -- Mid-West 156 8 0.0057 0.0061 

Site 5 -- Rocky 188 28 0.0035 0.0082 

Mountain 

Site 6 -- West Coast 194 5 0.0002 0.0001 

Site 7 - South East 201 56 0.0146 0.0328 

Site 8 -- North West 101 31 0.0101 0.0199 

Site 9 -- South West 150 50 0.0222 0.0404 

Site 10-- North West 150 40 0.0125 0.0230 

"Average value for all meters (i.e., leaking and non-leaking) screened at the site. 

B-25 
The average emission factor for residential customer meters was derived by averaging the emission rates for the ten 

sites. The emission factor was converted to units of scf/meter-yr by assuming that the losses from the leaking 

meters were continuous throughout the year. 

The precision represents the 90 % confidence interval and was calculated by averaging the standard deviations for 

the ten sites. 

The emission factor for commercial/industrial customer meters was derived from screening data collecteu at a total 

of four sites. A summary of the average emissions from each of the four sites is shown in the following table: 

Site Number of Meters Number of Leaking Average Leak Rate• Standard Deviation• 

Screened Meters {lb methane/day) {lb methane/day) 

Site 3 -- East Coast 45 12 0.0112 0.0251 

Site 4 -- Mid-West 61 0 -- --

Site 5 -- Rocky 21 6 0.0088 0.0076 

Mountain 

Site 6 -- West Coast 22 l 0.0018 --

"Average value for all meters (i.e., leaking and non-leaking) screened at the site. 

The average emission factor for commercial/industrial customer meters was derived by averaging the emission rates 

for the four sites. The emission factor was converted to units of scfi'meter-yr by assuming that the losses from the 

leaking meters was continuous throughout the year. 

ACTMTY FACTOR: (outdoor residential meters: 40,049,306 ± 4,200,135 

commercial/industrial meters: 4,608,000 ± 230,400) 

The total number of customer meters in the U.S. gas industry, 56, 132,300, and the number of residential customer 

meters, 51,524,600, were based on Gas Facts, American Gas Association, 1992 (2). The number of residential 

customer meters located indoors versus outdoors was estimated based on a regional breakdown of total customers 

presented in Gas Facts (2) combined with data obtained from 22 individual gas companies within different regions 

of the country. (Note: The number of customers in each region was used to estimate the number of indoor meters 

because data on number of customer meters segregated by region were not available.) 

Following is the average percentage of customer meters located indoors in each region: 

B-26 
Total 

Residential Average Percent 

Region Customers Indoor Meters 

New England l ,886,500 52 

Middle Atlantic 8,403,400 61 

East North Central 11,633,500 17 

West North 4,684,100 40 

Central 

South Atlantic 4,987,700 21 

East South Central 2,465,200 0 

West South 5,666,600 0 

Central 

Mountain 3,318,700 0 

Pacific 9,724,500 5 

TOTAL 52,770,200 

•Estimated based on engineering judgement. 

bEstimated for each state separately in region. 

Estimated 

Sample Indoor 

Size Meters Precision 

1 980,980 471,625' 

7 5,126,074 1,905,371 

7 1,977,695 !,461,663 

1 1,873,640 l,873,6401 

4 l ,030,680b 1,030,680' 

.. 0 123,260' 

.. 0 283,330< 

.. 0 331,870' 

2 486,225 486,225" 

22 l 1,475,294 3,317,254 

0

Estimated based on industry comments suggesting that customer meters in southern regions are essentially all 

located outdoors. 

The estimated number of indoor meters, l I ,475,294, was subtracted 'from the total number ofreported meters, 

51,524,600, to derive an estimated 40,049,306 outdoor residential customer meters in the United States. The 

precision was estimated from the data provided by the companies, engineering judgement for some regions, and an 

estimated 5% error in the nationally reported number of residential customer meters. 

The leakage rates from customer meters located indoors was assumed to be negligible based on the increased 

probability that leaks on indoor meter sets are detected and repaired promptly. This assumption of negligible 

leakage from indoor meters is consistent with the findings from pressure regulating stations located in vaults. 

The precision of the total estimated commerciaVindustrial customer meters is assumed to be± 5% of the estimated 

4,608,000 meters. 

ANNUAL EMISSIONS: (5.8 ± I. I Bscrtyr) 

REFERENCES 

1. 

2. 

Indaco Air Quality Services, Inc. Methane Emissions.from Natural Gas Customer Meters: 

Screening and Enclosure Studies, Draft Report, August I 5, 1992. 

American Gas Association. Gas Facrs. Arlington, VA. 1992. 

B-27 

APPENDIXC 

Conversion Table 

C-1 
Unit Conversion Table 

English to Metric Conversions 

I scf methane = 19 .23 g methane 

I Bscf methane = 0.01923 Tg methane 

I Bscf methane = 19,230 metric tonnes methane 

l Bscf = 28.32 miIIion standard cubic meters 

I short ton (ton) = 907.2 kg 

I lb = 0.4536 kg 

I ft' = 0.02832 m3 

I ft' = 28.32 liters 

I gallon = 3.785 liters 

I barrel (bbl) = 158.97 liters 

I inch = 2.540cm 

I ft = 0.3048 m 

I mile = 1.609 km 

I hp = 0.7457 kW 

I hp-hr = 0.7457 kW-hr 

!Btu = 1055 joules 

I MMBtu = 293 kW-hr 

I lb/MMBtu = 430 g/GJ 

T (°F) = 1.8 T (°C) + 32 

1 psi = 51.71 mm Hg 

Global Warming Conversions 

Calculating carbon equivalents of any gas: 

MMTCE ( 

MW, carbon) = (MMT of gas) x x {GWP) MW, gas 

C-2 
Calculating C02 equivalents for methane: 

MMT of C02 equiv. ' (-M_w_, _c_o~') ' I GW p I 

MW, CH 4 

where MW (molecular weight) of C02 = 44, MW carbon= 12, and MW CH,= 16. 

scf = 

Bscf 

MMscf = 

Mscf = 

Tg 

Giga (G) = 

Metric toJU1es = 

ps1g = 

psia = 

GWP = 

MMT = 

MMTCE = 

MMT ofC02 eq. = 

Standard cubic feet. Standard conditions are at 14.73 psia and 60°F. 

Billion standard cubic feet (IO' sci). 

Million standard cubic feet. 

Thousand standard cubic feet. 

Teragrarn (IO" g). 

Sarne as billion (1 O'). 

1000 kg. 

Gauge pressure. 

Absolute pressure (note psia = psig + atmospheric pressure). 

Global Warming Potential of a particular greenhouse gas for a given 

time period. 

Million metric tonnes of a gas. 

Million metric tonnes, carbon equivalent. 

Million metric tonnes, carbon dioxide equivalent. 

C-3 
TECHNICAL REPORT DATA 

(Pk~ rad /'"'1Ucti01Uon tM revou Mfore compl~ting) 

1. REPORT NO. I' 3. REC!PU:"NT'S ACCESSION NO. 

EPA-600/R-96-080h 

4. TtTLE AND SUBTITLE 5. REPORT DATE 

Methane Emissions from the Natural Gas Industry, June 1996 

Volumes 1-15 (Volume 8: Equipment Leaks) 6. PERFORMING ORGANIZATION CODE 

1. AUTHOACsl L. CamfJr.bell, M. Cam/bell. M. Cow~!, D. Ep- 8. PERFORMING ORGANIZATION REPORT NO. 

¥-er son, M. Hall, . Harrison, . Hummel. D. yers, DCN 96-263-081-17 . Shires. B. Stapper, c. Stapper, J. Wessels, and * 

$. PERFORMING OROANIZATION NAME ANO ADDRESS 10. PROGRAM ELEMENT NO. 

Radian International LLC 

P. 0. Box 201088 11. CONTRACT;GRANT NO. 

Austin, Texas 78720-1088 5091-251-2171 (GRI) 

68-Dl-0031 (EPA) 

1:Z.SPONSORING AGENCY NAME ANO ADDRESS 13. TYPE OF Rf PORT 7ND PERIOD COVERED 

EPA, Office of Research and Development Final; 3 91-4 96 

14. SPONSORING AGENCY CODE .Air Pollution Prevention and Control Division 

Research Triangle Park, NC 277ll EPA/600/13 

1s. suPPLEMENTARY NoTEs EPA project officer is D. A.Kirchgessner. MD-63, 919 / 541-4021. 

Cosponsor GR! project officer is R. A. Lott. Gas Research Institute, 8600 West Bryn 

Mawr Ave., Chicago, IL 60631. (*)H. Williamson (Block 7). 

1s. ABSTRACT The 15-volume report summarizes the results of a comprehensive program 

o quantify methane (CH4) emissions from the U.S. natural gas industry for the base 

lvear. The objective was to determine CH4 emissions from the wellhead and ending 

kiownstream at the customer•s meter. The accuracy goal was to determine these 

~missions within +/-0. 5% of natural gas production for a 90% confidence interval. Fo1 

:he 1992 base year, total CH4 emissions for the U.S. natural gas industry was 314 

+/- 105 Bscf (6.04 +/- 2.01 Tg). This is equivalent to 1.4 +/- 0.5% of gross natural 

gas production, and reflects neither emissions reductions (per the voluntary AmeriGas Association/EPA Star Program) nor incremental increases (due to increased 

gas usage) since 1992. Results from this program were used to compare greenhouse 

as emissions from the fuel cycle for natural gas •. oil. ·and coal using the global warming potentials (GWPs) recently published by the Intergovernmental Panel on Climate 

Change (IPCC). The analysis showed that natural gas contributes less to potential 

global warming than coal or oil, which supports the fuel switching strategy suggested 

by the IPCC and others. In addition, study results are being used by the natural gas 

industry to reduce operating costs while reducing emissions. 

"· KEV WORDS AND DOCUMENT ANALYSIS 

,. DESCRIPTORS b.lDENTIF/ERS/Dl>EN ENDED TERMS c COSATl Field/Group 

Pollution Pollution Prevention 13B 

Emission Stationary Sources 14G 

Greenhouse Effect Global Warming 04A 

Natural Gas 21D 

Gas Pipelines 15E 

Methane 07C 

18. DISTRlSUTION STATEMENT 19. SECURITY CLASS {This RepOHJ 21.NO.OFPAGES 

Unclassified 130 

Release to Public :ZO. SECURITY ClASS {Thi~ page} :Z:Z. PRICE 

Unclassified 

EPA Form 2220-1 (9-73) C-4 
------------ ------------ -------
t 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Research and Development 

National Risk Management Research Laboratory 

Technology Transfer and Support Division 

Cincinnati, Ohio 45268 

OFFICIAL BUSINESS 

PENAL TY FOR PRIVATE USE. :S300 

AN EQUAL OPPORTUNITY EMPLOYER 

If rour addrttn is incorrect. pl.ase changtt on lht1 abovtt label 

tear oll; and retum to thtt above addrus. 

If you do not desire to continue receiving these technical 

reports, CHECK HEREO: tear off label, and 1eturn it to the 

above address. 

Publication No. EPA-600/R-96-080h 

:i

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