Methane Emissions from the Natural Gas Industry Volume 8: Equipment Leaks


o                   United States                           GRI-94 / 0257 25
P       ^^^^*l®      Environmental Protection                      EPA - 60Q/R-96-080h
p       fc» •       A9«ncv                         	June 1996	
P                   ____	.	—	
       <&ER\     Research and          PB9 i429,6
p
                   Development
                   METHANE EMISSIONS FROM THE
                   NATURAL GAS INDUSTRY
                   Volume 8: Equipment Leaks
                   Prepared for
                        TnfnT-mafrirni AHmini ssfri^aHnn ^TI S
                        ~~-— —- —  »»-—   —-   ——.—• ~— -«~ — -   .
                   Prepared by
                   National Risk Management
                   Research Laboratory
                   Research Triangle Park, NC 27711

-------
TECHNICAL REPORT DATA
(Pttasf nod Imtlntf lions an tlte rerene before compi
1. REPORT NO.
EPA-600/R-96-080h
12.
PB97-142996
4. TITLE AND SUBTITLE
Methane Emissions from the Natural Gas Industry,
Volumes 1-15 (Volume 8: Equipment Leaks)
5. REPORT DATE
June 1996
6. PERFORMING ORGANIZATION CODE
7. AUTHORS
. Campbell. M. Campbell, M. Cowgill. D. Ep-
person, M. Hall, M. Harrison, K. Hummel, D .Myers,
T. Shires, B. Stapper, C. Stapper, J. Wessels, and *
B. PERFORMING ORGANIZATION REPORT NO.
DCN 96-263-081-17
>. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian International LLC
P. O. Box 201088
Austin, Texas 78720-1088
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
5091-251-2171 (GRI)
68-D1-0031 (EPA)
12. SPONSORING AGENCV NAME AND ADDRESS
EPA, Office of Research and Development
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 3/91-4/96
14. SPONSORING AGENCV CODE
EPA/600/13
is.SUPPLEMENTARY MOTES EPA project officer is D. A. Kirchgessner, MD-63,919/541-4021.
Cosponsor GW project officer is R. A. Lott, Gas Research Institute, 8600 West Bryn
Mawr Ave., Chicago. IL 60631. (*)H. Williamson (Block 7).
15~volume report summarizes the results of a comprehensive program
to quantify methane (CH4) emissions from the U. S. natural gas industry for the base
year. The objective was to determine CH4 emissions from the wellhead and ending
downstream at the customer's meter. The accuracy goal was to determine these
emissions within +/-0. 5% of natural gas production for a 90% confidence interval. For
the 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 Ameri-
Gas Association/EPA Star Program) nor incremental increases (due to increased
gas usage) since 1992. Results from this program were used to compare greenhouse
-— -"— y
gets,
cuid uua usng e goa war~
ming 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
ay the IPCC and others. In addition, study results are being used by the natural gas
industry to reduce operating costs while reducing emissions.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b-IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Emission
Greenhouse Effect
Natural Gas
Gas Pipelines
Methane
Pollution Prevention
Stationary Sources
Global Warming
13 B
14G
04A
21D
15E
07 C
18. DISTRIBUTION STATEMENT

Release to Public
19. SECURITY CLASS (This Report/
Unclassified
21. NO. OF PAGES
130
2O. SECURITY CLASS (This page)
Unclassified
22, PRICE
EPA Form 2220-1 (9-73)

-------
TECHNICAL REPORT DATA
(Float nod liulnictioiu an At nrtne before compi
1. REPORT NO.
EPA-600/R-96-080h
PB97-142996
4. TITLE AND SUBTITLE
Methane Emissions from the Natural Gas Industry.
Volumes 1-15 (Volume 8: Equipment Leaks)
5. REPORT OAT6
June 1996
6. PERFORMING ORGANIZATION CODE
7. AUTHORS L. Campbell, M. Campbell. M. Cowgill, D. Ep-
person, M. Hall, M. Harrison, K. Hummel, D. Myers,
T. Shires, B. Stapper, C. Stapper, J. Wessels, and *
8, PERFORMING ORGANIZATION REPORT NO.
DCN 96-263-081-17
>. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian International LLC
P. O. Box 201088
Austin, Texas 78720-1088
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
5091-251-2171 (GUI)
68-D1-0031 (EPA)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 3/91-4/96
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES EPA project officer is D. A. Kirchgessner, MD-63,919/541-4021.
Cosponsor GRI project officer is R. A. Lott, Gas Research Institute, 8600 West Bryn
Mawr Ave., Chicago, IL 60631. (*)H. Williamson (Block 7).
15~volume report summarizes the results of a comprehensive program
to quantify methane (CH4) emissions from the U. S. natural gas industry for the base
year. The objective was to determine CH4 emissions from the wellhead and ending
downstream at the customer's meter. The accuracy goal was to determine these
smissions within +/-0.5% of natural gas production for a 90% confidence interval. For
the 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 Ameri-
Gas Association/EPA Star Program) nor incremental increases (due to increased
gas usage) since 1992. Results from this program were used to compare greenhouse
i sxno f *»*-»¥*>* (H-*<
-"—^ Cycle fo.i ncitUi al g
-------
FOREWORD
The U. S. Environmental Protection Agency is charged by Congress with pro-
tecting the Nation's land, air, and water resources. Under a mandate of national
environmental laws, the Agency strives to formulate and implement actions lead-
ing to a compatible balance between human activities and the ability of natural
systems to support and nurture life. To meet this mandate, EPA's research
program is providing data and technical support for solving environmental pro-
blems today and building a science knowledge base necessary to manage our eco-
logical resources wisely, understand how pollutants affect our health, and pre-
vent 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 Laboratory1 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 this 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 infor-
mation transfer to ensure effective implementation of environmental regulations
and strategies.

This publication has been produced as part of the Laboratory's strategic long-
term research plan. It is published and made available by EPA1 s Office of Re-
search and Development 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.
PBOTECTEDUNDER.NTERNAT.ONALCOPVR.GHT

ALL R(GI5S RESERVEONFORMATION SERVICE
-------
FOREWORD
The U.S. Environmental Protection Agency is charged by Congress with pro-
tecting the Nation's land, air, and water resources. Under a mandate of national
environmental laws, the Agency strives to formulate and implement actions lead-
ing to a compatible balance between human activities and the ability of natural
systems to support and nurture life. To meet this mandate, EPA's research
program is providing data and technical support for solving environmental pro-
blems today and building a science knowledge base necessary to manage our eco-
logical resources wisely, understand how pollutants affect our health, and pre-
vent 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 this 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 infor-
mation transfer to ensure effective implementation of environmental regulations
and strategies.

This publication has been produced as part of the Laboratory's strategic long-
term research plan. It is published and made available by EPA'fi Office of Re-
search and Development 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 document is available to the public through the National Technical Information
Service, Springfield, Virginia 22161.
1NFORMATION
S&iSgSSSSEE
-------
EPA-600/R-S6~080h
June 1996
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 60631

and

EPA Project Manager: David A. Kirchgessner
U.S. ENVIRONMENTAL PROTECTION AGENCY
Contract No. 68-D1-0031
National Risk Management Research Laboratory
Research Triangle Park, NC 27711
-------
EPA-600m-S6-080h
June 1996
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

ORI Project Manager: Robert A. Lott
GAS RESEARCH INSTITUTE
Contract No. 5091-251-2171
8600 West Bryn Mawr Ave.
Chicago, IL 60631

and

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, GRI, members of GRI, 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 information 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.
Assumes any liability with respect to the use of, or for damages resulting from the
use of, any information, apparatus, method, or process disclosed in this report.
NOTE: EPA's Office of Research and Development quality assurance/quality control
(QA/QC) 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 EPA/ORD's QA/QC policies. In all cases, data and results were reviewed by the
panel of experts listed in Appendix D of Volume 2.
-------
DISCLAIMER

b. Assumes any liability with respect to the use of, or for damages resulting from the
use of, any information, apparatus, method, or process disclosed in this report.

NOTE: EPA's Office of Research and Development quality assurance/quality control
(QA/QC) 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 EPA/ORD's QA/QC policies. In ail cases, data and results were reviewed by the
panel of experts listed in Appendix D of Volume 2.
-------
RESEARCH SUMMARY
Title
Contractor
Principal
Investigators
Report Period

Objective
Technical
Perspective
Results
Methane Emissions from the Natural Gas Industry,
Volume 8: Equipment Leaks
Final Report

Radian International LLC

GRI Contract Number 5091-251-2171
EPA Contract Number 68-D1-0031

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 equipment 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 (CO2) per unit of energy produced than
either coal or oil. On the basis of the amount of CO2 emitted, the
potential for global wanning could be reduced by subsiituiing 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 CO2 emissions.

To investigate this, Gas Research Institute (GRI) 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.
111
-------
Based on data from the entire program, methane emissions from natural
gas operations are estimated to be 314 ± 105 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.

Technical In the component method for estimating emissions from equipment leaks,
Approach 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, 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 GR1 Hi-
Flow™ (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 GRJ Hi-Flow
sampler approach was used to quantify component emission factors for
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
-------
RESEARCH SUMMARY
Title Methane Emissions from the Natural Gas Industry,
Volume 8: Equipment Leaks
Final Report

Contractor Radian International LLC
Principal
Investigators
Report Period

Objective
Technical
Perspective
Results
GRI Contract Number 5091-251-2171
EPA Contract Number 68-D1-0031

Kirk E. Hummel
Lisa M. Campbell
Matthew R. Harrison

March 1991 - June 19%
Final Report

The increased use of natural gas has been suggested as a strategy for
reducing the potential for global wanning. During combustion, natural
gas generates less carbon dioxide (CO2) per unit of energy produced than
either coal or oil. On the basis of the amount of CO2 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 CO2 emissions.

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.
in
-------
Based on data from the entire program, methane emissions from natural
gas operations are estimated to be 314 ± 105 Bscf for the 1992 base
year. This is about 1.4 ± 0.5% of gross natural gas production Thi5
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

Technic; 1 In the component method for estimating emissions from equipment leaks,
Approach 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, 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.

The second approach used to quantify emissions from equipment
components is a modification of the EPA protocol using the GRI Hi-
Flow™ (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 for
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.
-------
Project For the 1992 base year, the annual methane emissions estimate for the
Implications 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 (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 IPCC 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 cost-
effective emission reductions and to report reductions to EPA. Since this
program was begun after the 1992 baseline year, any reductions in
methane emissions from this program are not reflected in this study's
total emissions.
Robert A. Lott
Senior Project Manager, Environment and Safety
-------
TABLE OF CONTENTS

Pa-e

1.0 SUMMARY 1

2.0 INTRODUCTION 3

3.0 EMISSION FACTOR METHODOLOGY 5

3.1 EPA Protocol Approach 5
3.1.1 Component Screening 6
3.1.2 Enclosure Method/Data 1?
3.1.3 Correlation Equation 17
3.1.4 Pegged Source Emission Factors 19
3.1 5 Default Zero Emission Factors 22
3.2 Alternative Approach Using the GRI Hi-Flow™ 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 ^ (~***c ^frkt-anr** Co/^ili+t^o f, 1
"""*' *^"M»*7 h^kVAMg^ A UV«,l,l«JI
-------
TABLE OF CONTENTS

Pa-e

1.0 SUMMARY 1

2.0 INTRODUCTION 3

3.0 EMISSION FACTOR METHODOLOGY 5

3.1 EPA Protocol Approach 5
3.1.1 Component Screening 6
3.1.2 Enclosure Method/Data 17
3.1.3 Correlation Equation 17
3.1.4 Pegged Source Emission Factors 19
3.1-5 Default Zero Emission Factors 22
3.2 Alternative Approach Using the GRI Hi-Flow™ 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 Storawe Facilities 6!
4.5.1 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
-------
REFROOUCEOBY:
I S.
T
TABLE OF CO^^^ENTS (Continued)

Page

APPENDIX A - Compressor Slowdown Operating Practices A-l

APPENDIX B - Source Sheets B-l

APPENDIX C - Conversion Table C-l
-------
LIST OF FIGURES

Page

1-1 Summary of Equipment Leaks Using Component Method 2

3-1 Overview of EPA Protocol 7

3-2 Conventional Gate Valve 9

3-3 Manual Globe Valve 10

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 2C

4-1 Illustration of Compressor Slowdown Valve Arrangement 55

4-2 Overhung and Beam-Type Centrifugal Compressors 62
-------
LIST OF FIGURES

Page

1-1 Summary of Equipment Leaks Using Component Method 2

3-1 Overview of EPA Protocol 7

3-2 Conventional Gate Valve 9

3-3 Manual Globe Valve 10

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 2G

4-1 Illustration of Compressor Slowdown Valve Arrangement 55

4-2 Overhung and Beam-Type Centrifugal Compressors 62
-------
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 Counts 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 Average Component Counts for Gas Processing Equipment 47

4-14 Average Facility Emissions for Gas Processing Plants 48

4-15 Component Emission Factors for Transmission 50

4-16 Average Component Counts for Transmission 51

4-17 Average Facility Emissions for Transmission 52

4-18 Breakdown of Compressor Emissions by Component Type 53
IX
-------
LIST OF TABLES (Continued)

Page

4-19 Average Emission Rates for Compressor Slowdown 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 National 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 National Annual Emissions from Customer Meter Sets 81

A-l Compressor Slowdown Valve Operating Practices—Transmission A-2

A-2 Compressor Slowdown Valve Operating Practices—Storage Stations A-4

A-3 Compressor Slowdown Valve Operating Practices—Gas Processing Plants . . . A-5
-------
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, 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.

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 depresr>urized 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).
-------
Processing
24.4 Bscf
Production
17.4 Bscf
Customer Meters
5.8 Bscf
Transmission
50.7 Bscf
Storage
16.8 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 Atlantic and
Great Lakes region (Eastern U.S.) and the rest of the country (Western U.S.) because of
regional differences 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 are 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%, 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 on'v *%.
-------
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.12
-------
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 offshcre 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 is 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.
-------
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-Flow™ (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 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
-------
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 measured data using an enclosure method collected 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 21 screening measurement technique uses a portable
instrument to detect leakage 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) — all 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.
-------
Conduct Complete
Screening Survey
(EPA Method 21)
eg
-C
u
ra
o
a.
a.
,, Approach 1
Apply Existing
Correlation
Equations
Bag a Fraction of
the Components for
Each Component Type
Develop Component
Emission Factors
Develop Correlation
Equations for Each
Component Type
Apply New
Correlation
Equations
Apply Average
Component
Counts for
Equipment/Facility
Calculate Average
Equipment/Facility
Emissions
Figure 3-1. Overview of EPA Protocol
LL
H
CC
.a.
u
-------
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 ionization 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 full-scale range. As part of the GRI/EPA methane emissions program, a
dilution probe was used during collection of some of the screening data to extend the upper
range of the instrument from 10,000 to 100,000 ppmv.
-------
PACKING GLAND

PACKING RINGS

VALVE STEM
POSSIBLE
LEAK AREA
Figure 3-2. Conventional Gate Valve
-------
STEM
PACKING GLAND
PACKING
SEAT
POSSIBLE
LEAK AREA
BODY
Figure 3-3. Manual Globe Valve
10
-------
LUBRICANT SCREW
POSSIBLE LEAK
AREA
BODY
PLUG
STEM

— GLAND STUD AND NUT

LUBRICANT CHECK VALVE

GLAND

COVER
STEM PACKING
Figure 3-4. Plug Valve
-------
POSSIBLE
LEAK AREA
STEM
SPHERICAL PLUG
SEAT RING
— BODY
BALL VALVE (OPEN)
POSSIBLE
LEAK AREA
STEM
SPHERICAL PLUG
SEAT RING
— 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
SPRING
TENSION ADJUSTMENT
THIMBLE
TO PROCESS
DISK
NOZZLE
POSSIBLE
LEAK AREA
Figure 3-7. Pressure Relief Valve
14
-------
OPEN
TO
ATMOSPHERE

POSSIBLE
LEAK AREA
CONNECTED
TO
PROCESS
SEAT

OPEN-ENDED LINE

(Globe Valve-Closed)
SEAT RING
POSSIBLE
LEAK AREA

OPEN
TO
ATMOSPHERE
CONNECTED
TO
PROCESS
BODY
OPEN-ENDED LINE
(Bail Valve-Closed)
Figure 3-8. Open-Ended Line
-------
(a) TLV 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
emission 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 vacuum 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
-------
This Ine lhauM
be as that
COM Trap in lee Bath
(Optional)
Trap
Hg Manometer
Sam pie Bag
Pump
Two-Way Valve
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 collected 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
Fugitive Correlation Equation
Connectors
Comtalion Equation

Scf««ninfl
-------
TABLE 3-1. CORRELATION EQUATIONS DEVELOPED BY EPA
Component Type* Correlation EquationM
Connector THC (Ib/day) = (7.99 x 105) x (ISV)0735
Flange THC (Ib/day) = (2.35 x ID"4) x (ISV)0703
Open-Ended Line THC (Ib/day) = (1.14 x 10"4) x (ISV)0704
Pump Seal THC (Ib/day) = (2.55 x 10'3) x (ISV)0610
Valve THC (Ib/day) = (1.21 x 10"4) x (ISV)0746
Other THC (Ib/day) = (6.98 x KT1) x (ISV)0589
* 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.5
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 lognormal 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 10,000 and 100,000 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.
-------
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
terminals, 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 lognormal 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 weie 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
petroleum 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 Using 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 GRI 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 all 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.
-------
TABLE 3-2. DEF4ULT ZERO AND PEGGED EMISSION FACTORS
DEVELOPED BY EPA'
Pegged Factor,
Ib THC/day
Component Type
Connector
Flange
Open-Ended Line
Pump Seal
Valve
Other
Default Zero Factor,6
Ib THC/day
3.97 x 10"
1.64x lO'5
1.06 x 10-4
1.27 x 10 3
4.13 x W
2.12 x 10-4
>10,000 ppmc
1.48
4.50
1.59
3.92
3.39
3.86
>1 00,000 ppmd
1.59
4.44
4.18
8.47
7.41
5.82
*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.
'Based on lognormal mean emissions using emission and screening data for screening
values above 10,000 ppm (includes screening data of 100,000 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 full-scale range of most commercially available OVA 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. In 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
pquation 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
2"?
-------
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 GRI Hi-Flow sampler. The first approach, used for transmission
compressor stations and customer meters, included the identification of all leaking
components using soaping tests. All 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. (Non-
leaking 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 GRI Hi-Flow sampler
instead of bagging measurements. A correlation equation was then developed for

24
-------
components with screening values below 10,000 ppm and applied to all components
screened at less than 10,000 ppm. Because all large leaks (i.e., above 10,000 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
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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:

* Onshore production in the Atlantic and Great Lakes region (i.e.,
Eastern U.S.) and the rest of the U.o. (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
in Table 4-1.

The average emissions for a given type of equipment/facility 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 all the types of
components associated with the equipment/facility:

EA = I (EF, x CC,)

where:
EA = Average equipment emissions for equipment/facility type A
(Mscf/equipment-yr);
26
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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
-------
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.

4.1.1 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
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TABLE 4-2. EQUIPMENT LEAK MEASUREMENT PROGRAMS
Industry Area
Production
Onshore Eastern U.S.
Onshore Western U.S.
Offshore Gulf of Mexico
Offshore Pacific OCS
Gas Plan!.:,
(excluding compressors)
Transmission Stations
(excluding compressors)
Compressors
(transmission,
processing, storage)
Customer Meter Sets

Study
Star/GRI'
API/GRI9
API/GRI9
MMS'°
API/GRI" '
Indaco/GRI12
Indaco/GRI'2
Indaco/GRI IJ
Indaco/GRI'4
Star/GRI'5
Approach
GRI Hi-Flow
EPA Protocol
EPA Protocol
EPA Protocol
EPA Protocol
GRI Hi-Flow
GRI Hi-Flow
EPA Protocol
GRI Hi-Flow
GRI Hi-Flow
Measurement
Technique(s)
Screening and
GRI Hi-Flow
Screening and Bagging
Screening and Bagging
Screening and Bagging
Screening and Bagging
Soaping and GRI Hi-
Flow (all leaking
components)
GRI Hi-Flow or
Rotameter (all leaking
components)
Screening
Screening and
GRI Hi-Flow
Screening and
GRI Hi-Flow
Correlation Equation
Used
Developed new
correlation equation
EPA Correlation
Equation9
Developed new
correlation equation
Developed new
correlation equation
EPA Correlation
Equation5
Direct measurement used
instead of correlation
equation
Direct measurement used
instead of correlation
equation
EPA Correlation
Equation9
Direct measurement used
instead of correlation
equation
Direct measurement used
instead of correlation
equation
Pegged Source
Method
GRI Hi-Flow
measurements
EPA Factors9
Developed new
pegged source
factors
Developed new
pegged source
factors
EPA Factors9
Direct measurement
using GRI Hi-Flow
Direct measurement
using GRI Hi-Flow
and rotameter
EPA Factors5
Direct measurement
using GRI Hi-Flow
Direct measurement
using GRI Hi-Flow
Default Zero
Method
Assumed negligible
leakage
EPA Factors9
Developed new
default zero
a
EPA Factors5
Assumed negligible
leakage
Assumed negligible
leakage
Assumed negligible
leakage
Assumed negligible
leakage
Assumed negligible
leakage
" 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 GRI 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 less 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 production17). 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 collected for gas wellheads, separators, meters and the associated above-
ground 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 part 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
EASTERN U.S. GAS PRODUCTION
Component
Valves
Connections
Open-Ended Lines
Pressure Relief Valve
Total Number of Component Emission
Components Factor,'
Screened Mscf/component-yr
4200 0.184
18639 0.024
260 0.42
92 0.279
90% Confidence
Interval,
%
29
20
54
88
1 Total methane emission rate adjusted for average 69.6 wt. % (78.8 vol. %) methane in
production."
number of heaters and dehydrate* 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
-------
TABLE 4-4. AVERAGE COMPONENT COUNTS FOR GAS PRODUCTION EQUIPMENT
IN THE EASTERN U.S.
Average Component Count*
Equipment
Gas Wellheads
Separators
Meters/Piping
Gathering Compressors
In-Line Heaters"
Dehydratorsb
No. of Sites
12
11
12
1
11
10
Quantity of
Equipment
192
110
83
2
77
52
Valves
8
1
12
12
14
24
Connections
38
6
45
57
65
90
Open-Ended
Lines
0.5
0
0
0
2
2
Pressure Relief
Valves
0
0
0
0
1
2
a Based on the Eastern U.S. onshore production study of fugitive emissions 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.
UJ
UJ
Equipment Type
Gas Wellheads

Separators

Heaters

Glycol Dehydrators

Meters/Piping

Gathering
Compressors

Component Emission
Component Factor,*
Type* Mscf/cont|»nent-yr
Valve
Connection
DEL
Valve
Connection
Valve
Connection
OEL
PRV
Valve
Connection
OEL
PRV
Valve
Connection
Valve
Connection
OEL
0.1114
o.o;>4
0.42
0.1*14
0.024
0.184
0.024
o.4;»
0.279
0.184
0.024
0.42
0.279
0.184
0.024
0.184
0.024
0.42
Average Equipment
Average Component Emissions,
Count scf/equipment-yr
8 2,595
38
0.5
1 328
6
14 5,188
65
2
1
24 7,938
90
2
2
12 3,289
45
12 4,417
57
2
90% Confidence
Interval,
%
27

1 OEL = Open-Ended Line; PRV = Pressure Relief Valve.
b Total methane emission rate adjusted for average 69.6 wt. % (78.8 vol. %) methane in production.11
-------
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.5 (The EPA study5 developed new equipment leak
correlation equations, default zero factors, and pegged source factors based on a combination
of the API/GRI study9 and data from petroleum production, refineries, and marketing
terminals.)

To estimate component emission factors, Radian used the screening data from
the API/GRI study9 and the component correlation equations derived by EPA5 for
components with screening values between 10 ppm and 10,000 ppm. For components with
screening values below 10 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/GRI report9 because: (1) confidence intervals needed to be provided
which were not available from the API/GRI report; (2) the API/GRI 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.
Component
Valves
Connections
Open-Ended Lines
PRVsb
Compressor Seals
Total Number of
Components
Screened
6059
32513
1051
448
40
Component Emission
Factor,'
Mscf/component-yr
0.835
0.114
0.215
1.332
2.37
90% Confidence
Interval,
%
10
9
33
37
72
* Total methane emission rate adjusted for average 69.6 wt. % (78.8 vol. %} methane in
production.17
b 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 study9 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
-------
Ox
-.:' ' '1' : '.: . ' ' ^^^^•^^=B^~"^^=^='^^^^=^^«B=»^^=ai^BBasi
Average Component Count*
Equipment
Gas Wellheads
Separators
Meters/Piping
Gathering
Compressors
Heaters
Dehydrators
No. of Sites
17
16
12
13
11
10
No. of
Equipment
184
183
73
61
77
52
Valves
11 (30%)
34 (44%)
14(31%)
73 (102%)
14 (49%)
24(31%)
Connections
36 (20%)
106 (38%)
51 (47%)
179(51%)
65 (70%)
90 (37%)
Open-Ended
Lines
1 (28%)
6(94%)
1 (113%)
3 (50%)
2(66%)
2 (69%)
PRVsb
0
2 (68%)
1 (150%)
4 (84%)
1 (89%)
2 (53%)
Compressor
Seals
0
0
0
4 (69%)
0
0
a Values in parentheses represent the 90% confidence interval.
" Pressure relief valves.
-------
Overall 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 study,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.
Equipment Type
Gas Wells

Separators

Heaters

Dehydrators

Meters/Piping

Component Emission
Factor,"
Component Type Mscf/component-yr
Valve
Connection
Open-Ended Line
Valve
Connection
Open- Ended Line
Pressure Relief Valve
Valve
Connection
Open-Ended Line
Pressure Relief Valve
Valve
Connection
Open-Ended Line
Pressure Relief Valve
Valve
Connection
Open-Ended Line
Pressure Relief Valve
0.835
0.114
0.215
0.835
0.114
0.215
1.332
0.835
0.114
0.215
1.332
0835
0.114
0.215
1.332
0.835
0.114
0.215
1.332
Average Average Equipment 90% Confidence
Component Emissions, Interval,
Count scf/yr %
11 13,302 24
36
I
34 44,536 33
106
6
2
14 21,066 40
65
2
1
24 33,262 25
90
2
2
14 19,310 30
51
1
1
Continued
-------
TABLE 4-8. (Continued)
Equipment Type
Gathering Compressors

Large Compressor SiJ'nns
Station Components
Compressor-Related Components
Component Emission
Factor,'
Component Type Mscf/component-yr
Valve
Connection
Open- Ended Line
Pressure Relief Valve
Compressor Seal
b
b
0.835
0.114
0.215
1.332
2.37
b
b
Average Average Equipment 90% Confidence
Component Emissions, Interval,
Count scf/yr %
73 97,729 68
179
3
4
4
b 3.01 x 10* 102
" 5.55 X 104 65
1 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 compressor stations.
-------
TABLE 4-9. AVERAGE COMPONENT EMISSION FACTORS FOR OFFSHORE
GAS PRODUCTION*

Component Emission Factor, Mscf/component-yr

Component Gulf of Mexico*1 Pacific PCS*

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.
11 Total methane emission rate adjusted for average 79.1 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
-------
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 frcility emissions for offshore
production platforms 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
platforms where measured data were collected.

4.3 Gas Processing

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 EPA5 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
Platform

Pacific OCS Platform

Component Emission
Factor,'-1'
Component Type Mscf/compoiiart-yr
Valve
Connection
Open-Ended Line
Other
Valve
Connection
Open-Ended Line
Other
0.187
0.046
0.368
2.517
0.048
0.021
0.092
0.091
Average Equipment
Average Component Emissions,
Count Mscf/yr
2,207 1,064
8,822
326
67
1833 430
13612
313
307
90% Confidence
Interval
27

Total methane emission rate adjusted for average 79.1 wt. % mettume in Gulf of Mexico.
Total methane emission rate adjusted for average 72.8 wt. % methzme for components in gas service in Pacific OCS.
to
-------
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 all 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
(1C) 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 giver, 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 open-
ended 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 PROCESSING1*
Component
Valve
Connection
Open-Ended Line
Pressure Relief Valve
Slowdown 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
—
—
134 lc (121%)
349"-" (171%)
2035d'e (144%)
450" (53%)
189" (19%)
Centrifugal
Compressor
~
~
1341C(121%)
--
6447e-f (46%)
228f(53%)
31f (220%)
" 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 processing.17
c Starter Open-Ended Line.
d Adjusted for 89.7% of time reciprocating compressors in processing are pressurized.
e Adjusted for 11.1% of streams routed to flare.
' 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;"
• 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 Pliint
(non-compressor)
1392 (26%)
4392(31%)
134 (54%)
29 (35%)
2
—
—
Reciprocating
Compressor
—
—
0.25b'c
1
1
2.5
ld
Centrifugal
Compressor
--
—
0.667"
-
1
1.5
1"
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.
-------
TABLE 4-14. AVERAGE FACILITY EMISSIONS FOR GAS PROCESSING PLANTS
00
Equipment Type
Gas Plant (non-
compressor related
components)

Reciprocating
Compressor

Centrifugal
Compressor

. • : • - • • .• :
Component
Emission Factor,*
Component Type Mscf/component-yr
Valve
Connection
Open-Ended Line
Pressure Relief Valve
Site Slowdown Open-Ended Line
Compressor Slowdown Open-
Ended Line
Pressure Relief Valve
Miscellaneous11
Starter Open-Ended Line
Compressor Seal
Compressor Slowdown Open-
Ended Line
Miscellaneous1"
Starter Open-Ended Line
Compressor Seal
1.305
0.117
0.346
0.859
230
2QW
349cd
189"
1341
450"
64470-1
31*
1341
228»
Average
Average Equipment
Component Emissions,
Count MMscfyr
1392 2.89
4392
134
29
2
I 4.09
1
1'
025f
2.5
1 7.75
le
1
1.5
90% Confidence
Interval,
%
48

* Annual methane emission rate adjusted for average 87.0 vol. % methane in gas processing.17
6 Includes cylinder valve covers and fuel valves.
c Adjusted for 11.1% of compressors which have sources routed to flare.
A Adjusted for 89.7% of time reciprocating compressors in processing are pressurized.
' Other components counted/measured in aggregate per compressor.
' Only 25% of starters for reciprocating compressors in processing use natural gas.g Adjusted for 43.6% of time centrifugal compressors in processing
are pressurized.
8 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 compressor-
related 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 factors 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
-------
TABLE 4-15. COMPONENT EMISSION FACTORS FOR TRANSMISSION*
Reciprocating Compressor-Related Centrifugal Compressor-Related
Station Components" Components Components
Component
Valve
Control Valve
Connection
Open-Ended Line
Site Slowdown Open-
Ended Line
Component
Emission Factor,
Mscf/comp-yr
0.867
8.0
0.147
11.2
264
90%
Conlldence
Interval
-
-
-
-
84%
Component
Emission Factor,
Mscf/comp-yr
-
-
--
-
-
90% Component
Confidence Emission Factor,
Interval Mscf/comp-yr
..
..
..
..
-
90%
Confidence
Interval
-
--
--
--
--
Pressure Relief Valve 6.2 -- 372"1 171%

Compressor Slowdown -- -- 3683" 96% 9352" 38%
Open-Ended Line

Compressor Starter - -- •-' 1440 121%
Open-Ended Line

Compressor Seal - -- 396"' 53% 165" 53%

Miscellaneousc 180" 19% 18" 223 %

' Annual methane emission rate adjusted for average 93.4 vol. % methane in gas transmission.'7
b 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 (79.1% and 24.2% for reciprocating and centrifugal compressors, respectively).
e Reciprocating compressor starters were assumed to use compressed air or electricity instead of natural gas based on site visit data (see Appendix A).
' 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 Slowdown Open-
Ended Line
Pressure Relief Valve
Compressor Slowdown
Open-Ended Line
Compressor Starter
Open-Ended Line
Compressor Seal
Miscellaneous11
Reciprocating Compressor- Centrifugal Compressor-Related
Station Components' Related Components Components
Average Component S0% Confidence
Count Interval Average Component Count Average Component Count
673 26%
31 62%
3068 28%
51 60%
4 49%
14 45% 1
1 1
..- i
3,3 1.5
r i'
' 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.
-------
TABLE 4-17. AVERAGE FACILITY EMISSIONS FOR TRANSMISSION
Equipment Type
Compressor Station
(non-compressor
related components)

Reciprocating
Compressor

Centrifugal
Compressor

Component Emission
Factor,1
Component Type Mscf/component-yr
Valve
Control Valve
Connection
Open-Ended Line
Pressure Relief Valve
Site Slowdown Open-
Ended Line
Compressor Slowdown
Open-Ended Line
Pressure Relief Valve
Miscellaneous
Compressor Starter Open-
Ended Line
Compressor Seal
Compressor slowdown
Open-Ended Line
Miscellaneous
Compressor Siarter Open-
Ended Line
Compressor Seal
0.867
3.0
0.147
11.2
6.2
264
3683"
372"
180"
,-c
396"'
9352"
18"
1440
165"
Average Average Equipment 90% Confidence
Component Emissions, Interval,
Count MMscf/yr %
673 3.01 102
31 (Note: 3.2 MMscf/yr
306g used in national
emission estimate)'
51
14
4
1 5.55 65
1
1"
C
3.3
i 11.1 y,
i"
i
1.5
1 Annual methane emisskn rate adjusted for average 93.4 vol. % methane in gas transmission.17
b Adjusted for the fraction of time the compressoi is pressurized (79.1% and 24.2% for reciprocating and centrifugal, respectively).
c Reciprocating compressor starters were assumed to use compressed cir or electricity instead of natural gas.
" Miscellaneous equipment counted in aggregate for compressor.
" Adjusted for data received from one company that were not considered representative of national average.
' Includes adjustment for seals equipped with Static-Pac.*
-------
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, die 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
Component
Type
Compressor Blowdown
Open-Ended Line
Pressure Relief Valve
Miscellaneous
Compressor Starter Open-
Ended Line
Compressor Seal
Total
Reciprocating Compressors
Mscf/yr
3,683
372
ISO
-
1,315
5,550
%
66.4
6.7
3.2
-
23.7

Centrifugal Compressors
Msef/yr
9,352
-
18
1,440
248
11,058
%
84.6
-
0.2
13.0
2 ~>

53
-------
Compressor Slowdown 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.19) The fugitive emission rate
is higher for the second operating mode when 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 were 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
-------
Figure 4-1. Illustration of Compressor Slowdown Valve Arrangement
-------
TABLE 4-19. AVERAGE EMISSION RATES FOR COMPRESSOR SLOWDOWN
VALVES IN PRESSURIZED/DEPRESSURIZED OPERATION
Reciprocating Compressor
Operating Mode
Pressurized*
Depressurized"
Emission Rate, Mscf/yr
1,361
13,729
90% Confidence Interval
36%
30%
b
Either (a) operating or (b) idle, pressurized.
Depressurized, idle.
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.20 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 overall average component emission

factor was calculated for compressor blowdown valves using Equation 1.
v ff \ -4- (VTt \ v (V \ t"t\
^ \rpr/ ' VEISr/ ^ V1 id-depr' "*'
where:
EFoei/comp = component emission factor for compressor blowdown open-
ended line;

average emission rate for compressor blowdown open-ended line
when compressor is pressurized (operating or idle, pressurized);

./action of compressors that are pressurized (operating or idle,
pressurized);

= average emission rate for compressor blowdown open-ended line
when compressor is idle and depressurized; and

FkMepr = 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 men vent the discharge gas to die 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

AH 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 die 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 ftiel-saver system - reciprocating
compressors only); and
• Idle and depressurized.

The pressurized seal emission rates (operating and idle) were calculated as the
average of all 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 " I«;n the compressor is idle but pressurized is
slightly lower than when the compresror is operating, due to the absence of compressor shaft
motion when the compressor is idb. 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
Component Emission Rate, 90% Confidence Interval,
Operating Mode Mscf/seal-yr %
Pressurized, Operating 599 30
Pressurized, Idle 531 19
Pressurized. Fuel Saver* 116 46
* Reciprocating compressors only.
59
-------
EFseil = (ER,^^ X Ovpr) + (ER^) x (F^) + rERfS.pr) x (Ff$.pr) (2)
where:
EF^a = component emission factor for compressor seals;
= average emission rate for compressor seal when compressor is
pressurized and operating;
fraction of compressors that are pressurizej and operating;
average emission rate for compressor seal when compressor is
idle and pressurized;
fraction of compressors that are pressurized and idle;
average emission rate for compressor seal when idle, partially
pressurized on a fuel-saver system; and
F^p, = 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 ecupares 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.*2I 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 tl^ component emission factor as having negligible fugitive
emission rates; however, the overall 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, dehydraters, and other piping
located outside of the compressor building;
• Injection/withdrawal well components including all sources associated
with the injection/withdraws! well "Christmas tree" piping
configuration; and
• Compressor-related components including all sources physically
connected to or immediately adjacent to the compressors.
61
-------
Discharge Piiate
Journal
Mechanical Bearings
Gas Seal
Coupling and
Drive End
Q
Overhung Axial-Inlet Centrifugal Compressor
(Single Seal)
Beam-Type Centrifugal Compressor
(Two seals)
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), compressor-
related 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 wellhead-related
components are discussed in Sections 4.5.1 through 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
-------
TABLE 4-22. COM1PONENT EMISSION FACTORS FOR GAS STORAGE1
Component
Valve
Connection
Open-Ended Line
Site Slowdown Open-
Station Components*
0.867
0.147
11.2
264 (84%)
Injection/Withdrawal
Wellhead-Related
Components
0.918 (10%)
0.125 (9%)
0.237 (33%)
Reciprocating
Compressor-
Related
Components
--
Centrifugal
Compressor-
Related
Components
..
Ended Line

Pressure Relief Valve

Compressor Blowdown
Open-Ended Line

Compressor Starter Open-
Ended Line

Compressor Seal

Miscellaneous11
6.2
1.464(37%)
317d(l71%)

5024" (71%)

1440(121%)

300" (53%)

153d (19%)
10233d (35%)

1440 (121%)

126d (53%)

17d (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
b 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).
-------
TABLE 4-23. AVERAGE COMPONENT COUNTS FOR GAS STORAGE*
O-i
Component
Valve
Connection
Open- Ended Line
Site Slowdown Open-
Ended Line
Pressure Relief Valve
Station
Components*
1868 (120%)
5571 (120%)
353 (194%)
4 (74%)
66 (107%)
Injection/Withdrawal
WcUhftad-RflatMl
Components
30 (82%)
89 (82%)
7(98/i)

1 (130%)
Reciprocating
Compressor-Related
Components
--
-
-
—
1
Centrifugal
Compressor-Related
Components
--
--
--
-
..
Pressure Relief Valve 66(107%) 1(130%)
Compressor Slowdown
Open-Ended Line
Compressor Starter
Open-Ended Line
Compressor Seal
Miscellaneous"
1
1
0.6C
4.5
1'
--
1
0.5C
1.5
!•
' Average component counts. Values in parentheses represent the 90% confidence interval.
b Excludes components physically connected to or directly adjacent to compressor or wellhead.
c 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. A^TCRAGE FACILITY EMISSIONS FOR GAS STORAGE
a-
Equipment Type
Storage Facility (non-
compressor related
components)

Injection/Withdrawal
Wellhead

Reciprocating
Compressors

Centrifugal Compressors

Component Enteton
Factor,*
Component Type Maef/compoaent-yr
Valve
Connection
Open-Ended Line
Pressure Relief Valve
Site Slowdown
Open-Ended Line
Valve
Connection
Open-Ended Line
Pressure Relief Valve
Compressor Slowdown
Open-Ended Line
Pressure Relief Valve
Miscellaneous
Compressor Starter
Open-Ended Line
Compressor Seal
Compressor Slowdown
Open-Ended Line
Miscellaneous
Compressor Starter
Open-Ended Line
Compressor Seal
0.867
0.147
11.2
6.2
264
0.918
0.125
0.237
1.464
5024"
317"
153b
1440
300*
10233"
17*
1440
I26b
Avenge Avenge Equipment
Component Emterioos,
Count MMscf/yr
1868 7.85
5571
353
66
4
30 0.042
89
7
1
1 7.71
1
1
0.6"
4.5
1 11.16
1
0.5C
1.5
90% Confidence
Interval,
%
100

' Total methane emission rate adjusted for average 93.4 vol. % methane in gas transmission/storage.17
' 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).
-------
Thv» 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 open-
ended 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 traction 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
Fraction of Time Associated with Operating Mode
Operating Mode Reciprocating Compressor Centrifugal Compressor
Pressurized:
In Operation
Idle, Pressurized

43.1
24.4

22.4
0
Depressurized:
Idle, Depressurized 32.5 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 IS
Customer meter screening data were collected 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
She
Site 1 -- West Coast
Site 2 -- East Coast
Site 3 - East Coast
Site 4 -- Midwest
Site 5 - Rocky Mountain
Site 6 -- West Coast
Site 7 -- Southeast
Site 8 -- Northwest
Site 9 -- Southwest
Site 10 -- Northwest
Average
Number of
Meters
Screened
134
4(1
158
155
18?
194
201
101
150
150

Number of
Meter Sets
Leaking
37
29
37
8
28
<
56
31
50
40

Percentage of
Meter Sets
Leaking
27.6
72.5
23.4
5.1
14.9
2.6
27.9
30.7
33.3
26.7

Average Leak
Rate,'
Ib methane/day
0.0098
0.0002
0.0789
0.0057
0.0035
0.0002
0.0146
0.0101
0.0222
0.0125
0.0158
Standard
Deviation,*
Ib methane/day
0.0239
0.0004
0.1753
0.0061
0.0082
0.0001
0.0328
0.0199
0.0404
0.0230

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 GRI 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 outdocr 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
number 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
commercial/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
commercial/industrial meter sets.
70
-------
TABLE 4-27. SUMMARY OF EMISSION RATES FROM COMMERCIAL/INDUSTRIAL CUSTOMER METER SETS
Site
Site 3 -- East Coast
Site 4 -- Midwest
Site 5 - Rocky Mountain
Site 6 -- West Coast
Average
Number of
Meters
Screened
45
61
21
22

Number of
Meter Sets
Leaking
12
0
6
1

Percentage of
Meter Sets
Leaking
26.7
0
28.6
4.5

Average Leak
Rate,*
Ib methane/day
0.0112
—
0.0088
0.0018
0.0055
Standard
Deviation,*
Ib methane/day
0.0251
~
0.0076
--

Average value for all meters (i.e., leaking and non-leaking) screened at the site.
-------
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 annual 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 quantitate 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
Equipment
Gas Wells
Separators
Heaters
Dehydrators
Metering Runs
Small Gathering
Eastern
Activity
Factor,
Count
129,157
91,670
260
1,047
76,262
129
U.S.
90%
Confidence
Interval, %
5
23
196
20
100
33
Western
Activity
Factor,
Count
142,771
74,674
50,740
36,777
301,180
16,915
U.S.
90%
Confidence
Interval, %
5
57
95
20
100
52
Compressors
Large Gathering
Compressors
Large Gathering
Compressor Stations
12
100
100
The total number of active gas wells is a nationally tracked statistic. The
breakdown between gas wells in the Eastern and Western 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 estmate based on the regional well count. The total number of
glycol dehydrators in gas production were based on published data from a separate GRI
study.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 Western 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.
Equipment
Gas Well
Separator
Heater
Dehydrator
Meters/Piping
Gathering
Compressors
Total
Average
Equipment
Emissions,
settyr
2,595
328
5,188
7,938
3,289
4,417

Activity
Factor,
Equipment
Count
129,157
91,670
260
1,047
76,262
129

Annual Methane
Emissions,
Bscf
0.34
0.03
0.001
0.008
0.25
0.0006
0.63
90% Confidence
Interval,
%
27
36
218
41
109
44
46
74
-------
TABLE 5-3. NATIONAL ANNUAL EMISSIONS FROM ONSHORE
PRODUCTION IN THE WESTERN U.S.
Equipment
Gas Well
Separator
Heater
Dehydrator
Meters/Piping
Small Gathering
Compressors
Large Gathering
Compressors
Large Gathering
Compressor Stations
Total
Average
Equipment
Emissions,
scf/yr
13,302
44,536
21,066
33,262
19,310
97,729
5.55E+06
3.01E+06

Activity
Factor,
Equipment
count
142,771
74,674
50,740
36,777
301,180
16,915
96
12

Annual
Methane
Emissions,
Bscf
1.9
3.33
1.07
1.22
5.82
1.65
0.53
0.04
15.6
90%
Confidence
Interval,
%
25
69
110
32
109
93
136
176
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

Region
Pacific OCS
Gulf of Mexico
Total

Average
Facility
Emissions,
Mscf/yr
430
1,064

Activity
Factor,
Number of
Platforms in
Gas Industry
22
1,092

Annual
Methane
Emissions,
Bscf
0.01
1.16
1.17

90%
Confidence
Interval,
%
38
29
29
5.3
Gas Processing
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
aYCTcuevS* "i'jiC soli* between reci?rcc«u««jb «nd centrifugal compressors estims^^ ftrwn th#»
site visit data (i.e., 85% reciprocating and 15% centrifugal) agrees well with the results from
a national survey conducted in the 1980s29 (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 summary of the national annual emissions from gas processing plants in the US.
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

Equipment/
Facility
Gas plants
Reciprocating
Compressors
Centrifugal
Compressors
Total

Average
Facility
Emissions,
MMscf/yr
2.89
4.09

7.75

Activity
Factor,
Number of
Plants/
Compressors
726
4,092

726

Annual
Methane
Emissions,
Bscf
2.1
16.7

5.6

24.4

90%
Confidence
Interval,
%
48
95

68
5.4
Transmission Comoressor 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 die total transmission pipeline mileage.24 The confidence interval was estimated as
± 10% 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 GRI 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
Stations
Reciprocating 5.55 6799
Compressors
Centrifugal 11.1 681
Compressors
Total
5.4 103
37.8 68
7.5 44
50.7 52
5.5
Gas Storase 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.2* 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

Equipment/
Facility
Storage
Facilities
Injection/
Withdrawal
Wells
Reciprocating
Compressors
Centrifugal
Compressors
Total

Average
Facility
Emissions,
MMscf/yr
7.85

0.042

7.71

11.16

Activity
Factor,
Number of
Facilities/
Compressors
475

17,999

1,396

136

Annual
Methane
Emissions,
Bscf
3.7

0.75

10.8

1.5

16.8

90%
Confidence
Interval,
%
100

130

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 Facts24 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 io 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
Region
New England
Middle
Atlantic
East North
Central
West North
Central
South Atlantic
East South
Central
West South
Central
Mountain
Pacific
Total
Total
Residential
Customers
1,886,500
8,403,400

11,633,500

4,684,100

4,987,700
2,465,200

5,666,600

3,318,700
9,724,500
52,770,200
Average
Percent
Indoor
Meters
52
61

21
0

0
5

Sample
Size
1
7

4
—

—

—
2
22
Estimated
Indoor
Meters
980,980
5,126,074

1,977,695

1,873,640

1,030,680"
0

0
486,225
11,475,294
90%
Confidence
Interval
471,625'
1,905,371

1,461,663

1,873,640»

1,030,680"
123,260*

283,330C

331,870°
486,225'
3,317,254
1 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 die 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

Category
Average
Equipment
Emissions,
scf/yr
Activity
Factor,
number of
meter sets
Annual
Methane
Emissions,
Bscf
90%
Confidence
Interval,
%
Outdoor residential 138.5 40,049,306 5.55
meter sets
Commercial/industrial 47.9 4,608,000 0.22
meter sets
Total 5.77
20

20
8!
-------
6.0 REFERENCES
1. Campbell, L.M., M.V. Campbell, and D.L. Epperson. Methane Emissions
from the Natural Gas Industry, Volume 9: Underground Pipelines, Final
Report, GRI-94/0257.26 and EPA-600/R-96-080i; Gas Research Institute and
U.S. Environmental Protection Agency, June 19%.

2. Campbell, L.M. and B.E. Stapper. Methane Emissions from the Natural Gas
Industry, Volume 10: Metering and Pressure Regulating Stations in Natural
Gas Transmission and Distribution, Final Report, GRI-94/0?57.27 and EPA-
600/R-96-080J, Gas Research Institute and U.S. Environmental Protection
Agency, June 1996.

3. Hausle, K.J. Protocol forEqw ent Leak Emission Estimation, EPA-453/R-
93-026 (NTIS PB93-229219), L ce of Air Quality Planning and Standards,
June 1993.

4. Code of Federal Regulations, Title 40, Part 60, Appendix A. National
Archives and Records Administration, Office of the Federal Register, July 1,
1995.

5. U.S. Environmental Protection Agency. New Equipment Leak Emission
Factors for Petroleum Refineries, Gasoline Marketing, and Oil & Gas
Production Operations (EPA file LEAKS_95.WP5; background file
LKS95_BK.ZIP). U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Technology Transfer Network bulletin board
system, February 1995.

6. Lott, R., M. Webb, and T. Howard. "Sampler Enables Measurement of
Leaks on Site-Specific Basis." American Oil and Gas Reporter, March 1995,
pp. 61-66.

7. Howard, T., et al. A High Flow Rate Sampling System for Measuring Leak
Rates at Natural Gas System Process Components. 1994 International
Workshop: Environmental and Economic Impacts of Natural Gas Losses,
Prague, Czech Republic, March 1994.

8. Star Environmental. Fugitive Hydrocarbon Emissions: Eastern Gas Wells,
Final Report, GRI-95/0117, Gas Research Institute, July 1995.

9. Star Environmental. Fugitive Hydrocarbon Emissions from Oil and Gas
Production Operations, API Publication Number 4589. American Petroleum
Institute, December 1993.
82
-------
10. ABB Environmental Services. Fugitive Hydrocarbon Emissions from Pacific
OCS Facilities, MMS Report 92-0043, U.S. Department of the Interior,
Minerals Management Service, November 1992.

11. Star Environmental. Emission Factors for Oil and Gas Production Operations,
API Publication No. 4615. American Petroleum Institute, January 1995

12. Indaco Air Quality Services, Inc. Leak Rate Measurements at U.S. Natural
Gas Transmission Compressor Stations, Gas Research Institute, July 1994.

13. Indaco Air Quality Services, Inc. Methane Emissions from Natural Gas
Customer Meters: Screening and Enclosure Studies, Draft Report, August 15,
1992.

14. Indaco Air Quality Services. Leak Rate Measurements for Natural Gas
Customer Meters, Gas Research Institute, 1996.

15. Star Environmental. Fugitive Methane Emissions: Customer Meter Sets, Final
Report, GRI-95/0204, Gas Research Institute, July 1995.

16. Williamson, H.J., M.B. Hall, and M.R. Harrison. Methane Emissions from
the Natural Gas Industry, Volume 4: Statistical Methodology, Final Report,
GRI-94/0257.21 and EPA-600/R-96-080d, Gas Research Institute and U.S.
Environmental Protection Agency, June 1996.

17. Shires, T.M. and M.R. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 6: 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.

18. Dobose, D.A., J.I. Steinmetz, G.E. Harris, and J.W. Kamas. Frequency of
Leak Occurrence and Emission Factors for Natural Gas Liquids Plants, EMB
80-FOV1. U.S. Environmental Protection Agency, Emissions Measurement
Branch, July 1982.

19. Shires, T.M. and M.R. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 7: Blow and Purge Activities, Final Report, GRI-94/0257.24
and EPA-600/R-96-080g, Gas Research Institute and U.S. Environmental
Protection Agency, June 1996.

20. Stapper, C.J. Methane Emissions from the Natural Gas Industry, Volume 11:
Compressor Driver Exhaust, Final Report, GRI-94/0257.28 and EPA-600/R
96-080R, Gas Research Institute and U.S. Environmental Protection Agency,
June 1996.
83
-------
21. Telephone conversation with Paul Hanlon, C. Lee Cook (Louisville, KY) by
K.E. Hummel, Radian Corporation, February 16, 1995.

22. Memorandum to M.R. Harrison, Radian Corporation, from K.E. Hummel,
Radian Corporation. "Overhung versus Beam-Type Centrifugal Compressors
in Transmission Pipeline Service," August 1994.

23. Stopper, B.E. Methane Emissions from the Natural Gas Industry, Volume 5:
Activity Factors, Final Report, GRI-94/0257.22 and EPA-600/R-96-080e, Gas
Research Institute and U.S. Environmental Protection Agency, June 1996.

24. American Gas Association, Gas Facts. Arlington, VA. 1992.

25. Wright Killen & Co. Natural Gas Dehydration: Status and Trends, Gas
Research Institute, GRI-94/0099, January 1994.

26. Minerals Management Service. Users Guide. MMS Outer Continental Shelf
Activity Database (MOAD), OCS Study MMS 94-0018, U.S. Department of
Interior, New Orleans, LA, April 1994.

27. Telephone conversation with David Sutherland, Offshore Data Services
(Houston, Texas) by K.E. Hummel, Radian Corporation, April 27, 1994.

28. Oil & Gas Journal. 1992 Worldwide Gas Processing Survey Database, 1993.

29. Farmer, J.R. Equipment Leaks of VOC in Natural Gas Production Industry-
Background Information for Promulgated Standards, EPA-450/3-82-024b
QV 1Q8S
m~j w. jr V** •
30. Biederman, N. GRI TRANSDAT Database: Compressor Module, (prepared
for Gas Research Institute), npb Associates with Tom Joyce and Associates,
Chicago, IL, August 1991.
84
-------
APPENDIX A

Compressor Slowdown Operating Practices
A-l
-------
TABLE A-l. COMPRESSOR SLOWDOWN VALVE OPERATING PRACTICES - TRANSMISSION

Sile
1
2
J
4
5
k
|i ^
«
'{ '
10
11
I]
1-1
H
II ,
i
1
No. if
Silo
lUpn-
M«l*d
bylhk
S-npk

12
M

SN*
•t»«
»
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N

H».
13
1
1
4
7

0
9
25
4
3
«
11
11
12
7
10

DM*BD
LtoeG.
To A«»
f

f
/

/
/
/
/
/

AMID
Vriv*
a»
(W

r
2"
J"
3H
3"
4"
4"

tedprat*
SlfM*
•Ottai
(•u«r
Sptaa?

N
N

tHK^kM.
Mb Co
D*-
*"
/*Mri>
IMflnt
N*»pp«e*M<
NMVfUobk

N(4*M
FMlMUullte
NUi^Bublt

••••
/If >Mhr

•fraHr Pni
• 0».
Pi nun

/
/

/
i
/
/
/
/
/

Oka
• Uwtr
PllKMI

*rf
Startm
•oCx
(•Am
«

•
D

No.
0
2
I
0
0

I
2
1
,
•
0
3
2
1

DxiBD
UxGj
To Aim

/
/

/
/
/

AMID
Vdve
StM
-------
TABLE A-l. (Continued)
Silt
11
19
20
21
12
23
24
25
26
27
2»
Inlah/Avgs
No at
Site*
Repre-
ItOlKj
by eta
S«enple

151

3)1
4
4
33
47
004

Stt«
Ftor.
*
V"
N
N
N
N
N
N'"

0%
Rtfipriculni Enfwti
N..
I
7
4«
II
1
0
4
,
9
»
»
in
DMBD
UoeCo
TttUm
f
{
j
/
f

lOt*
AtBBD
V«Ke
Ste
r
Sl.rt-.'
IKl Cf«% lo
Aim
IIW
100
100

IMS
.-ulnfueal ciHnpreraor wtth rrciproc
Hjrf don not hind'.t Camp «(> or Silf RD.
• Sile flare al 2 of M facilities
•"Site rte-pressur«) in Ihe pasl.
-------
TABLE A-2. COMPRESSOR BLOWDOWN VALVE OPERATING PRACTICES • STORAGE STATIONS
Silt
1
2
3
4
i
*
7
1
Tmah/Ar|
No. of
SMc*
ilxpr*>
MUltd
by Ihtt
sun*

Unknown

SUe
N
N
N
N
N
N
N
N
0*

No.
J
2
2
2
0".
13
J
9
M
DooBD
To AIM
/
/
f
f
f
f
f
f
100*
ABB ID
Viht
Sin
.

I/I"
1/J"
1/2 - 2"
Kodprocul
SrpM.
BDL*H
N

/
f

t^tm^m

Do-

/
/
/.
/••

4/7 »
*
^t.

1/7 .
14.)*

• Uwtr
Prawn

/-Mr
/-IMf
2/7-
».«*

CM
Slarlcn

0
IN
100
0
I0t

to*

0
0
2
0
3
0
0
s
TurMim !'
OoaBO
To Abu

100*
AlmiD
Voh«
Stan
(to)

•JD !-!••
MUvP

Mlt Cocmprtiotr Prxtko
•romm

100*
4U^«

• Lowtr

SUrlrn

100

50%
• \ Hprrssure to MM for fim 2 hours, Ihtn dtP to mm II Idh mtr 2 toun.
• Mirprniurni 10 WOf, but I hit U tery nrar opcraling (trcuure.
site
-------
TABLE A-3. COMPRESSOR BLOWDOWN VALVE OPERATING PRACTICES - GAS PROCESSING PLANTS
J
SHI
I
2
J
4
J
6
7
*
,
10
11"
TMiti/A>|
So. of
S«n
Reprf-
Hnttd
bjlhll
Simple

Stt.
rtmn
T
N
N
Y"
Y-
N
N
Y
Y'
Y-

- 11.1*
•tdpraaltit BaftaM
No.
7
4
20
7
0
0
13
4
4
4
17
V
DotlBD
UMG*
T.Atn.
/
/
/
/
AtmBD
VllTt
Sto
(M

BOLte*
N
N
N
N
14k Cm
BH~

ifiwmr PncikM
• Op.
/
/

/
• Uwtr
Pro.

CM
ftarttn
(•At*
1«
1*0
*
0
^.pplk^X.

N
N
N

Y"
Y"
Y"

KMiwUofclt

/
I/I -

I
f
,•

71.M

*•*

t
t
1
1

11. »%
rurbh,,,
N*.
ft
0
e
i
i
i
«
0
«
«
i

DM BO
UneGo
To AM
AUIBD
ViKt
Slu
(in)
SO Une
uu»r
Idle Camprcoar Prtctke*
De-
preuure
• Op.
PVessurt
9 Low,,
Pruiurf
% irtlh
to Mm
MM apptkabk
Not •pplkibk
N« mplkabk

/
/•

im
IWI
NM ippliciblt
N« .ppbcrtK
1
Not applklbb
1
Not ippllnMe
/

.«.%

vat
"Flwr-e doss oot_ handle compressor blowdowrm or equipment blowdowns
-------
APPENDIX B

Source Sheets
B-l
-------
P-2
PRODUCTION SOURCE SHEET
SOURCES: All Production Equipment (See Below)
OPERATING MODE: Noitnal Operation
EMISSION TYPE: Steady, Fugitive
ANNUAL EMISSIONS: 17.4 Bscf ±41%

BACKGROUND:
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 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. An average
estimate of die 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 = [(Nvlv x EF^ + ^ x EFJ - (N^ * EF^) + (N^ * EF^)]

where:
NK = average count of components of type 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 (QCS). Separate measurement programs were conducted to account
for these regional differences.

Onshore Production in the Eastern U.S. Region. Gas production in the Eastern L.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
Environmental 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
information col'^cted as part of the 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
Gas Wellheads
Separators
Heaters
Glycol
Dehydrators
Meters/Piping
Gathering
Compressors

Component Type
Valve
Connection
Open-Ended Line
Valve
Connection
Valve
Connection
Open-Ended Line
Pressure Relief
Valve
Valve
Connection
Open-Ended Line
Pressure Relief
Valve
Valve
Connection
Valve
Connection
Open-Ended Line
Component
Emission Factor,
Mscf/component-yr
0.184
0.024
0.42
0.184
0.024
0.184
0.024
0.42
0.279
0.184
0.024
0.42
0.279
0.184
0.024
0.184
0.024
0.42
Average
Component
Count
8
38
0.5
1
6
14
65
2
1
24
90
2
^
x
12
45
12
57
2
Average Equipment
Emissions,1
scf/equ ipm ent-yr
2,595 (27%)

328 (27%)
5,188(43%)
7,938 (35%)
3,289 (30%)
4,417(27%)
* 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/GRI 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 API/GRI study and additional data collected for GRJ 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
-------
Averace Equipment Emissions for Onshore Production in the Western U.S.
ffl &«* = ««-.*—* "V

Gas Wellheads
Separators
Heaters
Glycol Dehydrators

Meters/Piping

Gathering Compressors

Large Compressor Stations
Station Components
Compressor-Related Components
!„
v-onipunent
Type
Valve
Connection
DEL
Valve
Connection
OEL
PRV
Valve
Connection
OEL
PRV
Valve
Connection
OEL
PRV
Valve
Connection
OEL
PRV
Valve
Connection
OEL
PRV
Compressor
Seal
a
a
Component
Emission Factor,
Mscf/component-yr
0.835
0.114
0.215
0.835
0.114
0.215
1.332
0.835
0.114
0.215
1.332
0.835
0.114
0.215
1.332
0.835
0.114
0.215
1.332
0.835
0.114
0.215
1.332
2.37
a
a
1
Average
Component
Count
11
36
1
34
106
6
2
14
65
2
1
24
90
2
2
14
51
1
1
73
179
3
4
4
a
a
ii
Average
Equipment
Emissions,"
scf/equipmen
t-yr
13,302(24%)

44,536 (33%)
21,066(40%)
33,262 (25%)
19,310(30%)
97,729 (68%)
3.01 x I06
(102%)
5.55 x 106
(65%)
* Values in parentheses represent the 90% confidence interval.
b Refer to T-l 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

• Tne Minerals Management Service study of 7 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.
Average Facility Emissions for Offshore Production
Equipment Type
Gulf of Mexico
Platform
Pacific OCS
Platform

Component Type
Valve
Connection
Open-Ended Line
Other
Valve
Connection
Open-Ended Line
Other
Component
Emission Factor,
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
1,833
13,612
313
307
Average Facility
Emissions,*
Mscf/yr
1,064(27%)
430 (36%)
' Values in parentheses represent the 90% confidence interval.
EF DATA SOURCES:

2.
Emission Factors for Eastern Gas Production based upon data from the GRI/Star program
for the component EF's at 12 gas production sites.
Fraction of methane (78.8 mol%) based on data from Methane Emissions from the
Natural Gas Industry, Volume 6: Vented and Combustion Source Summary (I).
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 similar gas composition
speciation from C, through C^ and performed line v extrapolation from average of 3
lowest data (87 mol% methane) to 78.8 mol% methane. Resultant weight percent of 69.6
wt% methane used to speciate methane emissions.
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 GRI/Radian data from
13 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-l).

EF PRECISION: Gas Wells - Eastern ± 27%
Separators - Eastern ± 27%
Heaters - Eastern ± 43%
Dehydrators - Eastern ± 35%
Meters/piping - Eastern ± 30%
Gathering Compressors - Eastern ± 27%
Gas Wells - Western ± 24%
Separators - Western ± 33%
Heaters-Western ±40%
Dehydrators - Western ± 25%
Meters/piping - Western ± 30%
Gathering Compressors - Western ± 68%
Large Gathering Compressors ± 65%
Large Gathering Stations ± 102%
Offshore (Gulf) ±27%
Offshore (Pacific) ± 36%

Basis:
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 t-
statistic method. Computed 90% confidence intervals for site average component counts were
combined with 90% confidence intervals for component emission factors to obtain pooled
uncertainty in aggregate emission factor.

ACTIVITY FACTOR: (129157 Gas Wells - Eastern) ±5%
(91670 Separators - Eastern) ± 23%
(260 Heaters - Eastern) ± 196%

(76262 Meters • Eastern) ± 100%
(129 Gathering Compressors - Eastern) ± 33%
(142771 Gas Wells - Western) ± 5%
(74674 Separators - Western) ± 57%
(50740 Heaters - Western) ± 95%
(36777 Dehydrators-Western) ±20%
(301180 Meters - Western) ± 100%
(16915 Gathering Compressors - Western) ± 52%
(96 Large Gathering Compressors) ± 100%
(12 Large Gathering Stations) ± 100%
(1092 Gulf of Mexico Platforms) ± 10%
(22 Western Offshore) ± 10%
B-6
-------
AF DATA SOURCES:

1.
2.
5.
AF PRECISION:
Basis:
1.
The gas well count is from A.G.A.'s Gas Facts 1992 data (5).
Eastern gas wells and equipment AFs were regionalized 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 information of 1:1 meter per gas industry well.
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 1,047
dehydrators (included in Eastern gas production component counts).
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.
Large gathering compressors and compressor station counts were estimated from FERC
Form 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.
The other equipment 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.
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 die 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.
Category
Gas Wellhead (Eastern U S )
Separators (Eastern US)
Heaters (Eastern U.S.)
Detiydrators (Eastern U S )
Meiers/Piping (Eastern US)
Gathering Compressors (Eastern US)
Gas Wellhead, (Western US)
Separators (Western US)
Heaters (WestemUS)
Dehydrators (Western US)
MaersfWesternUS)
Small Gathering Compressors (Western US)
Large Gathering Compressors (Western US)
-arge Gathering Compressor Stations (Western
US)
Offshore Oil/Gas (Gulf)
Offshore Oil/Gas ((Pacific)
TOTAL
Emission Factor
2595 scf/yr meihane
328 scf/yr methane
5187 scf/yr methane
7939 scf/yr methane
3289 scf/yr methane
44l7sctVy. ""ethane
11302 scf/yr methane
44516 scf/yr mrthane
^ < "66 scfyr methane
)}262 scf/yr methane
1 93 10 scf/yr methane
97729 scf/yr methane
5.55 MMscf/yr methane
3.01 MMscf/yr methane
1 064 MsctTyr methane
430 OMscf/yr methane

Activity Factor
1291 57 gas wells (Eastern U S )
9! 670 separators (Eastern U S )
260 heaters (Eastern US)
1047 dehy.irato's (Eastern U S )
76262 meters (Eastern U.S.)
1 29 gathering compressors (Eastern US)
142771 gas wells (Western U S )
74674 separators (Western US)
50740 in-line healers (Western U S '
36777 dehydralors (Western U S )
301 180 meters (Western U S )
1691 5 compressors (Western US )
% large compressors
2 large gathering compressor stations
092 Gulf of Mexico platforms
22 platforms (Pacific)

Errusston Rate
034 Bscf/yr methane
0 OJ Bscf'vr methane
0001 Bscf/yr methane
0 008 Bscf/yr methane
025 Bscf/yr methane
0 0006 Bscf/yr methane
i 9 Bscf/yr methane
33) Bscf/yr methane
I 07 Bscf/yr methane
1 22 Bscf/yr methane
5 82 Bscf/yr methane
65 Bscf/yr methane
0.53 Bscf/yr methane
0 04 Bscf/yr methane
16 Bscf/yr methane
0 01 Bscf/vr methane
7 4 Bscf/yr methane
Uncertainty
27%
36".
218V,
41%
109%
44%
25%
tff/.
no%
32%
109%
93%
36%
76%
29%
8%
41%
REFERENCES

4.
Shires, T.M. and M.R. Harrison. Methane Emissions from the Natural Gas Industry, Volume 6:
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-Hill Book Co., New York,
NY, 1984.

Star Environmental. Emission Factors for Oil and Gas Production Operations. API Publication
No., 4615. American Petroleum Institute, January 1995.

Minerals Management Service. Fugitive Hydrocarbon Emissions from Pacific OCS Facilities.
Volume 1, Final Report. MMS 92-0043. U.S. Department of Interior, New Orleans. LA,
November 30, 1992.
B-8
-------
5. American Gas Association. Gas Facts, Arlington, VA. 1992.

6. Minerals Management Service. Users Guide. MMS Outer Continental Shelf Activity Database
(MOAD), OCS Study MMS 94-0018, U.S. Department of the Interior, New Orleans, LA, April
1994.
B-9
-------
GP-1
PROCESSING SOURCE SHEET

SOURCES: All Equipment at Gas Processing Plants
OPERATING MODE: Normal Operation
EMISSION TYPE: Steady and Unsteady, Fugitive
ANNUAL EMISSIONS: 24.45 Bscf ± 68%

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 Actors than components in the rest
of the facility. Part of mis is due 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 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 (B/D) 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
WD OELs. Control valves emit at a higher rate man manual isolation valves since their packing is stressed more
often as they are activated much more frequently. Site B/D OELs are the large diameter emergency station
blowdown valves mat 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/GRI
measurement program conducted at 8 gas plants. The average facility emissions are then calculated as follows:

EF = f(Nvtv x EFV|V) + (N. x EFJ + (NM, x EF^,) + (N^ * EF^) + QimVD x EF,,,eM>)]

where:
N, = average count of components of type x per plant, and
EFX = 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 GRJ/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:
B-10
-------
l)Comp. B/DOEL
2) Comp. PRV

3) Comp. Starter OEL
4) Comp. Seal
5) Miscellaneous
A blowdown (B/D) valve to the atmosphere that can depressure the compressor when
idle. The B/D 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).
The pressure relief valve (PRV) is usually installed on a compressor discharge line, and
leaks at a higher than average rate due to vibration.
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.
AH 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.
There are many components on each compressor, such as valve covers on reciprocating
compressor cylinders and fuel valves.
Each compressor has one B/D 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 die 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 the Natural Gas Industry, Volume 8: Equipment Leaks (1) 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 B/D discharge (approximately 11 % of the
compressor b'swdcwn CELs were routed to a puuu flare).
EF DATA SOURCES:
2.

4.
Component emission factors based on screening results from API/GRI/Star program for
the component EFs for eight gas processing plants and EPA's current default zero
factors, correlation equations, and pegged source factors. Confidence limits derived from
analysis of screer.jig data by Radian in April 1995.
OEL (site B/D) emission factor based on results fron, ORl/lndaco program for
compressor stations (June 1994).
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 1992.
Compressor emission factors based on results from GRI/lndaco program for 15
compressor stations (June 1994). Compressor operating hours (% running) based on data
from 3 gas processing company databases.
B-ll
-------
Average Facility Emissions for Gas Processing
Equipment Type
Gas Plant (non-
compressor related
components)
Reciprocating
Compressor
Centrifugal
Compressor

Component Type
Valve
Connection
Open-Ended Line
Pressure Relief
Valve
Site Slowdown
Open-Ended Line
Compressor
Slowdown Open-
Ended Line
••ressure Relief
Valve
Miscellaneous
Starter Open-Ended
-ine
Compressor Scai
Compressor
Slowdown Open-
Ended Line
Miscellaneous
Starter Open-Ended
Line
Compressor Seal
Component
Emission Factor,
Mscf/component-yr
1.305
0.117
0.346
0.859
230
2,036bc
349bc
189'
1,341
450"
6,447M
31"
,341
228d
Average Component
Count
1,392
4,392
134
29
2
1
1
1
0.25'
2.5
1
1
0.667f
1.5
Average Equipment
Emissions,*
MMscf/yr
2.89 (48%)
4.09 (74%)
7.75 (39%)
' Values in parentheses represent 90% confidence interval.
b Adjusted for 11.1% of compressors which have sources routed to flare.
c 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 reciprocating compressors in processing use natural gas
f Only 66.7% of starters for centrifugal compressors in processing use natural gas.
B-12
-------
EF ACCURACY:
Basis:
I.
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.
ACTIVITY FACTOR
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 multiplieH 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:
1.
2.
a. Plant Activity Factor: ± 2%
b. Compressor Activity Factor: Recip engines
± 48%; Tnrbines = ± 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 11 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 MMscf/d. Site
visit data averaged 271 MMscfd and throughput was 182 MMscf/d, 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
Gas processing
plants
Recip Comp
Turbine Comp
TOTAL
Emission Factor
2 89 MMscf/yr
methane
4 09 MMscf/yr
methane
7.75 MMscPyr
methane

Activity-
Factor
726 plants
4092 recip
726 turbine

Emission
Rale
2.1 Bscf/yr
methane
16 7 Bscf/yr
methane
56 Bscf/yr
methane
24.4 Bscf/yr
methane
Uncertainty
48%
95%
91%
68%
REFERENCES
2.
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.

Oil and Gas Journal. 1992 Worldwide Gas Processing Survey Database, July 1991.

Stopper, B.E.. Methane Emissions from the Natural Gas industry, Volume 5: Activity Factors.
Final Report, GRJ-94/0257.22 and EPA-600/R-96-080e, Gas Research Institute and U.S.
Environmental Protection Agency, June 1996.
B-14
-------
T-l
TRANSMISSION SOURCE SHEET

SOURCES: Compressor Stations
OPERATING MODE: Normal Operation
EMISSION TYPE: Steady and Unsteady, Fugitive
ANNUAL EMISSIONS: 50.7 Bscf ± 52%

BACKGROUND:
Equipment teaks 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 emission 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 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 (B/D) 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
B/D 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 B/D 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:
EF = [(Nvlv * EF.,.) + (Nc^. * EFc.vhr) +(N«. * EFJ + (N^ x EF^,) + fN_, x EF_,.) + (N- ^ x F.Fijic ._)]

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:

1) Comp. B/D OEL A blowdown (B/D) valve to the atmosphere that can depressure the compressor when
idle. The B/D valve or the large unit block valves {depending on the operatii;j status of
the compressor) can act as an open-ended line that leaks at an extraordinarily high rate

B 15
-------
through the valve s*at The ??=&• rate « dependent ""hcthcr the ccn;pre;;cr i;
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 mat 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 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. 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 cylindeis and fuel valves.

Each compressor has one B/D OEL, one PRV, and one starer 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 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 the Natural Gas Industry, Volume 8: Equipment Leaks (1) for more
details.] Ccrrection 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:

1. 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 IS
compressor stations (June 1994). Con^jressor operating hours (" running) based on
data from FERC database, GR1 TRANSDAT database, and data supplied by one large
interstate transmission pipeline company.
4. Fraction of methane (93.4 mol%) based on data from GRI TRANSDAT database.
B-16
-------
Average Facility Emissions for Gas Transmission
Equipment Type
Compressor Station
(non-compressor
related components)
Reciprocating
Compressor
Centrifugal
Compressor

Component Type
Valve
Control Valve
Connection
OEL
PRV
Site B/D OEL
Compressor B/D
OEL
PRV
Miscellaneous
Compressor Starter
OEL
Compressor Seal
Compressor B/D
OEL
Miscellaneous
Compressor Starter
OEL
Compressor Seal
Component
Emission Factor,
Mscf/component-yr
0.867
8.0
0.147
11.2
6.2
264
3,683
372C
180"
d
396C
9,352
18°
i,440
65C
Average
Component
Count
673
31
3,068
51
14
4
1
I
1
d
3.3
L

1
1.5
Average Equipment
Emissions,*
MMscf/yr
3.01 (102%)
(Note: 3.2 MMscf/yr
used in national
emission estimate)1"
5.55 (65%)
11.1 (34%)
* Values in parentheses represent 90% confidence interval.
" Adjusted for data received from one company that was not considered representative of national average.
c Adjusted for the fraction of time the compressor is pressurized (79.1 % and 24.2% for reciprocating and
centrifugal
compressors, respectively).
d Reciprocating compressor starters 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:
AF DATA SOURCES:
1.
2.
AF ACCURACY:
Basis:
1.
a. Station Activity Factor = 1700 stations
b. Compressor Activity Factor = 6799 recip engines, 681 turbines
1992 FERC Form 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).
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.

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 companies.
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
Emission Factor
3.2 MMscf/yr
CH4
5.55 MMscf/yr
CH4
11.1 MMscf/yr
CH4

Activity Factor
1700 stations
6799 recip
681 turbine

Emission Rate
5.4 Bscf'yr
CH4
37.8 Bscf/yr
CH4
7.5 Bscf/yr
CH4
50.7 Bscf/yr
CH4
Uncertainty
103%
68%
44%
52%
REFERENCES
2.
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 Facts. Arlington, VA, 1992
B-19
-------
S-l
STORAGE SOURCE SHEE~

SOURCES: Storage Facilities (Compressor Stations and Wells)
OPERATING MODE: Normal Operation
EMISSION TYPE: Steady and Unsteady, Fugitive
ANNUAL EMISSIONS: 16.76 Bscf ± 57%

BACKGROUND:
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 = 7.85 MMsof/yr 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 determined 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 determined 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 determined to be insignificant. All of these components are typical fugitive
components (as described in the EPA Fugitive Emissions Protocol) with the exception of site olowdown
(B/D) open-ended lines (OELs). Site B/D OELs are die large diameter emergency station blowdown valves
that arc designed to depressiire the entire she to the atmosphere when the valve is opened. Emission factors
for storage station components were based on the GRI/Indaco 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/GRI/Star 20-site study (4 gas production sites). Physical and operational characteristics 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:

EF = [(NVIV x EFvlv) + (Nco x EFcn) + (NM, x EFMl) + (Nolh x EF.J + (Nprv x EFptv) + (NSIKB/D x EFMeBB)|

where:
N, = 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 GRJ/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:
l)Comp.B/DOEL
2) Comp. PRV

3) Comp. Starter OEL
4) Comp. Seal
5) Miscellaneous
A blowdown (B/D) valve to the atmosphere that can depressure the compressor when
idle. The B/D valve or the large unit block valves (depending on the operating status of
die 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).
The pressure relief valve (PRV) is usually installed on a compressor discharge line and
leaks at a higher than average rate due to vibration.
Most compressors have a gas starter motor t! t 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.
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. Reciprocating compressors have
sliding shaft seals while centrifugal compressors have rotating shaft seals.
There are many components on each compressor, such as valve covers on reciprocating
compressor cylinders and fuel valves.
Each compressor has one B/D 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 1.5
seals per gas turbine. For the miscellaneous component category, there are many compo.-ents per compressor
engine, but the emission rates were minor and so were added into one lump emission factor |.er 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.] 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 DATA SOURCES:
2.

5.
Emission Factors for storage compressor stations are based upon GRI/lndaco
transmission compressor station fugitive leak measurement surveys at 6 compressor
stations. Compressor operating hours (% running) based on data from 5 national gas
storage companies.
Component counts for storage compressor stations and injection/withdrawal wellheads
are based on Radian site visits to 5 storage facilities.
Component emission factors for compressor-related components based on GRI/lndaco
transmission compressor station fugitive leak measurement program at 15 compressor
stations.
Wellhead emission factors based on simple average of GRI/Star data for gas production
wellheads (Atlantic/Eastern region and Rest of U.S.).
Fraction of methane (93.4 mol%) based on data from GRITRANSDAT database.
B-21
-------
Average Facility Emissions for Gas Storage
Equipment Type
Storage Facility
(non-compressor
related components)
Injection/Withdrawa
1 Wellhead
leciprocating
Compressors

Centrifugal
Compressors

Component Type
Valve
Connection
OEL
PRV
Site B/D OEL
Valve
Connection
OEL
PRV
Compressor B/D
OEL
PRV
Miscellaneous
Compressor Starter
OEL
Compressor Seal
Compressor B/D
OEL
Miscellaneous
Compressor Starter
OEL
Compressor Seal
Component
Emission Factor,
Mscf/component-yr
0.867
0.147
11.2
6.2
264
0.918
0.125
0.237
1.464
5,024"
317"
153b
1,440
300"
0,233b
7"
,440
26"
Average Componeni
Count
1,868
5,571
353
66
4
30
89
7
1
1
1
1
0.6C
4.5

0.5'
.5
Average Equipment
Emissions,*
MMscf/yr
7.85 (100%)

0.042 (76%)
7.71 (48%)
1.16 (34%)
* 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:
1.
2.
3.
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 1992 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
import terminals for a total of 89 facilities.
Compressor engine count based on GRJ 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 [see Activity Factor
Report (3)]. Also, the number of reciprocating compressors in storage was increased
by 31% to account for electric motor drivers.
AF ACCURACY:
Basis:
1.
a. Station Activity Factor: ± 5%
b. Wellhead Activity Factor: ± 5%
b. Compressor Activity Factor: Recip engines
± 58 %; Turbines = ± 119 %
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 GR1
TRANSDAT database.
B-23
-------
ANNUAL EMISSIONS: (16.76 Bscf/yr ± 9.6 Bscf/yr)

The annual emissions were determined by multiplying an emission factor for an average equipment type by the
population of equipment in the segment.
Category
Station
Inj/With Wellheads
Rccip Comp
Turbine Comp
TOTAL
Emission Factor
7.85MMscf/yrCH4
4l.8MscPyrCH4
771MMscf/yrCH4
11 !6MMscf/yrCH4

Activity Factor
475 stations
17999 wellheads
1396recip
1 36 turbine

Emission Rate
3 73 Bscf/yr CH4
0752 Bscf/yr CH4
10 76 Bscf/yr CH4
1 52 Bscf/yr CH4
16. 76 Bscf/yr CH4
Uncertainty
100%
76%
80%
129%
57%
REFERENCES
2.

3.
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 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-600/R-96-080e, Gas Research Institute and U.S.
Environmental Protection Agency, June 19%.
B-24
-------
SOURCES:
OPERATING MODE:
EMISSION TYPE:
ANNUAL EMISSIONS:
D-5
DISTRIBUTION SEGMENT SOURCE SHEET

Customer Meters
Normal Operations
Steady, Fugitive
5.8±l.lbscfy
BACKGROUND:
Losses from customer meters are caused by fugitive leakage from the connection and other fittings surrounding the
meter set.

EMISSION FACTOR: (outdoor residential meters: 138.5 ± 23.1 scf/meter-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 Indaco 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 (1)]. 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
Site 1 -- West Coast
Site 2 - East Coast
OK»_ ^ C»»A f*~. — — A
h-)iiv J — JL/Oat \_-UO3l
Site 4 - Mid- West
Site 5 -- Rocky
Mountain
She 6 - West Coast
Site 7 - South East
Site 8 -- North West
Site 9 - South West
Site 10 -- North West
Number of Meters
Screened
134
40
153
156
188
194
201
101
150
ISO
Number of Meters
Leaking
37
29
37
8
28
5
56
31
50
40
Average Leak Rate *
(Ib methane/day)
0.0098
0.0002
0.0789
0.0057
0.0035
0.0002
0.0146
0.0101
0.0222
0.0125
Standard
Deviation'
(Ib methane/day)
0.0239
0.0004
0.1753
0.0061
0.0082
0.0001
00328
0.0199
0.0404
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 collected 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
She 3 -- East Coast
Site 4 -Mid- West
Site 5 - Rocky
Mountain
Site 6 - West Coast
Number of Meters
Screened
45
61
21
22
Number of Leaking
Meters
12
0
6
1
Average Leak Rate'
(Ib methane/day)
0.0112
„
0.0088
0.0018
Standard Deviation*
(Ib methane/day)
0.0251
„
0.0076
--
'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 convened to units of scf/meter-yr by assuming that the losses from the
leaking meters was continuous throughout the year.
ACTIVITY FACTOR:
(outdoor residential meters: 40,049306 ± 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
-------
Region
New England
Middle Atlantic
East North Central
West North
Central
South Atlantic
East South Central
West South
Central
Mountain
Pacific
TOTAL
Total
Residential
Customers
1,886,500
8,403,400
11,633,500
4,684,100
4,987,700
2,465,200
5,666,600
3,318,700
9,724,500
52,770,200
Average Percent
Indoor Meters
52
61
17
40
21
0
0
0
5

Sample
Size
1
7
7
1
4
..
-
_
2
22
Estimated
Indoor
Meters
980,980
5,126,074
1,977,695
1,873,640
1,030,680"
0
0
0
486,225
11,475,294
Precision
471,625-
1,905,371
1,461,663
1,873,640'
1,030,680'
123,260'
283,330C
331,870°
486,225'
3,317,254
'Estimated based on engineering judgement.
"Estimated for each state separately in region.
'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
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 commercial/industrial customer meters is assumed to be ± 5% of the estimated
4,608,000 meters.
ANNUAL EMISSIONS:
(5.8 ±1.1 Bscf/yr)
REFERENCES
Indaco Air Quality Services, Inc. Methane Emissions from Natural Gas Customer Meters:
Screening and Enclosure Studies. Draft Report. August 15, 1992.
American Gas Association. Gas Facts. Arlington, VA. 1992.
B-27
-------
APPENDIX C

Conversion Table
C-l
-------
Unit Conversion Table
1 scf methane
1 Bscf methane
1 Bscf methane
IBscf
1 short ton (ton)
lib
1ft3
1ft3
1 gallon
1 barrel (bbl)
1 inch
1ft
1 mile
Ihp
Ihp-hr
IBtu
1 MMBtu
1 Ib/MMBtu
T(°F)
1 psi
English to Metric Conversions

19.23 g methane
0.01923 Tg methane
19,230 metric tonnes methane
28.32 million standard cubic meters
907.2 kg
0.4536 kg
0.02832 m3
28.32 liters
3.785 liters
158.97 liters
2.540 cm
0.3048 m
1.609km
0.7457 kW
0.7457 kW-hr
1055 joules
293 kW-hr
430 g/GJ
! =8 T (°C) +• 32
51.71 mm Hg
Global Warming Conversions
Calculating carbon equivalents of any gas:
MMTCE = (MMT of gas) *
MW, carbon 1
MW, gasJ
(GWP)
C-2
-------
Calculating CO2 equivalents for methane:
MMT of CO, equiv. = (MMT CH )
MW, CO2
MW, CH4
(GWP)
where MW (molecular weight) of CO2 = 44, MW carbon = 12, and MW CH4= 16.
Notes
scf

Bscf

MMscf

Mscf

Giga (G)

Metric tonnes

ps»g

psia

GWP

MMT

MMTCE

MMTofCO2eq.
= Standard cubic feet. Standard conditions are at 14.73 psia and 60°F.

= Billion standard cubic feet (109 scf).

= Million standard cubic feet.

= Thousand standard cubic feet.

— TeniTarr! ^10'^ s).

Same as billion (10").

1000kg.

= 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
-------
.•so'*
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