EPA/600/A-92/279
92-142.03
Inventory of Methane Losses from the Natural Gas Industry
Michael V. Campbell, Lisa M. Campbell, and Clinton E. Burklin
Radian Corporation, Research Triangle Park, North Carolina 27709
INTRODUCTION
This paper presents the second year's results of an ongoing four-year
program undertaken jointly by the Gas Research Institute and the U.S.
Environmental Protection Agency (EPA) to assess the methane losses from the
U.S. natural gas industry. The program objective is to assess the
acceptability of natural gas as a substitute for other fossil fuels for
mitigating global climate change.
As shown in Figure 1, carbon dioxide (C02) is estimated to comprise more
than half of the global warming potential created by current trace gas
emissions. Figure 2 illustrates that fossil fuel combustion accounts for
nearly three-quarters of the anthropogenic sources of C02 emissions. While
reducing our reliance on fossil fuels would be the most effective means of
mitigating combustion sources of C02, such a program would be costly and would
take time to implement. In the interim, a mitigation program relying on the
most environmentally efficient fossil fuel would be very beneficial. As shown
in Figure 3, natural gas produces the least C02 per unit of energy output of
all of the fossil fuels.
However, the production and transport of natural gas results in
emissions of methane. As shown in Figure 1, methane is also considered a
significant greenhouse gas. The benefits of reduced C02 emissions may
consequently be outweighed by the methane loss from increased natural gas
operations. Therefore, to resolve the issue of the acceptability of natural
gas in the mitigation of global warming, the Gas Research Institute and the
EPA have embarked on a detailed study of methane loss from the U.S. natural
gas industry.
The scope of the program is to directly quantify methane losses from the
three major segments of the natural gas industry: production, transmission,
and distribution. The production segment comprises field production,
gathering, and gas processing. The transmission segment includes sources such
as transmission pipelines, meter and pressure regulating stations, odorant
stations, compressor stations, and gas storage facilities. The distribution
segment includes the underground distribution pipelines and above-ground
facilities such as meter and pressure regulating stations associated with the
distribution of natural gas to the consumer. The study does not address
methane emissions from residential, commercial, or industrial end-use sources.
The emission source categories contributing to methane emissions include
fugitive losses from valves, flanges, and equipment seals; vented losses from
process vents, pneumatic equipment, compressor starts, and maintenance
operations; combustion source flue gas losses; and losses due to upsets and

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Methane
15%
Carbon Dioxide
55%
Nitrous Oxide
6%
CFC's
24%
Figure 1. Contribution of Trace Gases to
Global Warming (1980s)1
Cement Production
2%
Figure 2. Anthropogenic Emissions of C022
250
200 -
CD
*0 150
us
c
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03
to
o
O
IU 100
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a.
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b.
a.
50 -
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3
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Figure 3. Carbon Dioxide Emissions
from Fossil Fuel Combustion
per Unit of Energy Output
^0
ho
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K3
O
UJ

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92-142.03
mishaps. Sources of methane loss from the production and transmission
segments are being covered in two separate papers. Fugitive losses and vented
gas from normal operations and routine maintenance activities are discussed in
Paper No. 92-142.06. Methane emissions from the exhaust of reciprocating
engines and gas turbines that are used to drive compressors for gas transport
are presented in Paper No. 92-142.05.
Methane emissions from the gas distribution segment of the U.S. natural
gas industry will be presented in this paper. In addition, this paper also
presents a summary of the current estimate of total methane emissions from all
sources within the natural gas industry.
DISTRIBUTION LEAK TEST PROGRAM
Scope
The distribution segment consists of both below- and above-ground
sources. Methane leakage from underground distribution systems was initially
estimated to be one of the largest emission sources from the gas industry.
Consequently, a leakage measurement program was developed to quantify losses
from this source. The objective of the cooperative leak test program is to
estimate total annual natural gas leakage from below-ground gas distribution
systems. The program consists of voluntary participation from nine U.S. gas
distribution companies, two Canadian companies, and one distribution system
from Northern Europe. The participants will perform leak tests to quantify
mean leak intensity and implement a standardized leak survey to quantify leak
frequency. The objective of the above-ground leak test program is to estimate
total annual methane emissions from all above-ground gas distribution
features. Emissions include fugitive losses and natural gas released during
normal system operations and routine maintenance activities. The primary
above-ground features include metering stations, pressure regulating stations,
odorant stations, and customer meters.
The final products of the program include individual tot;al leakage
estimates for the program participants, an annual gas leakage estimate from
the national distribution industry, and detailed documentation to assist other
distribution systems in estimating leakage. The target accuracy of the
estimate for each participating company is within 25 percent of the true value
with a 90 percent level of confidence.
Approach
The calculated below-ground emission rate, expressed as standard cubic
feet per hour (scf/hr)*, is the product of an emission factor and an activity
'Readers more familiar with metric units may use the following factors to
convert to this system: 1 ft3 = 0.028 m3, 1 lb/106 BTU = 435 ng/J,
1 mi = 1.6 km, and 1 ft = 0.3 m.
3

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92-142.03
factor. The emission factor is derived using the leak intensity and leak
frequency estimates. The participating companies measure gas leakage
intensity from underground mains by testing either individual leaks (units -
scf/leak-hour) or pipe segments (units - scf/mile-hour). Leakage intensities
from customer service lines are measured by isolating the entire length of
service line (units = scf/service-hour). The general procedure for testing
individual leaks entails selecting and centering the leak (without disturbing
the soil surrounding the leak), isolating the short segment of pipe containing
the leak, and measuring the gas rate required to maintain the isolated segment
at normal operating pressure. This technique is based upon testing detectable
leaks, and may exclude smaller or more diffuse leaks that are not detectable
at the soil surface. The general procedure for testing entire segments of
mains includes selecting the segment to be tested, isolating the segment, and
measuring the gas rate required to maintain the segment at normal operating
pressure. The resulting test data will represent a leakage intensity per
length of main that includes all sources of leakage in the segment, even leaks
that may not be detectable at the soil surface. The segment of pipe being
tested will also be surveyed to determine the number of detectable leaks and
the corresponding concentration of methane measured for each leak in the
segment. The number of leaks found in the segment can then be used to
estimate the average leakage rate per leak for an alternative comparison with
the individual leak test results. Standardized test procedures and quality
assurance/quality control (QA/QC) guidelines will be implemented by all
program participants.
Leak frequency estimates are derived by implementing a standardized leak
survey protocol over a selected portion of the distribution system. The
rigorous leak survey procedure employs a calibrated portable flame ionization
detector. Identical leak detection protocols will be implemented by the
program participants. Any reading above 10 ppm requires further
investigation. The concentration and location of the highest organic vapor
analyzer (OVA) reading is recorded. These leak frequency data will be used to
derive the number of total leaks per mile of main and per individual service
for the sections surveyed. By comparing the results from the standardized
leak survey procedure with existing company leak repair records, the leak
frequency for the entire underground distribution system can be calculated.
Leak duration will be factored into the leak frequency estimates for companies
that employ a multiyear leak survey cycle. By combining the leak intensity
and leak frequency estimates, an emission factor is developed (units =
scf/mile-hour, or scf/service-hour).
Activity data are represented by the miles of main and the number of
customer services maintained by the national gas distribution industry.
Detailed activity data are provided by program participants, while industry-
wide activity data are available from the U.S. Department of Transportation.
Many factors that influence below-ground natural gas leak rate§ were
identified by industry experts"and engineering judgments. The proposed
experimental design for the leak test program evaluates the influences of
seven independent variables. First, the design uses three primary factors
4

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92-142.03
(pipe use, pipe material, and pipe vintage) to stratify the participant group.
The resultant strata are then further evaluated according to the influence of
four secondary factors. Table I lists the primary and secondary factors and
defines the discrete categories within these factors. Figure 4 shows the 16
primary test strata. Specific strata are omitted where material/age
categories do not exist. The goal of this stratified, factorial design is to
increase the accuracy of the stratum-specific and overall estimates by
defining strata that did not contain as much variation as was observed over
the entire population. The stratified approach is also needed to meet the
target accuracy of the leakage estimates for the individual companies.
Using summary statistics from available leak test data and the desired
accuracy of the final estimates, a minimum sample size of 200 leak tests has
been calculated. A two-stage sampling scheme will be implemented to maximize
the amount of information gained about the influencing factors, both primary
and secondary, while effectively allocating the limited sample size. Stage-
one sampling will initially assign 8 leak tests to each of the 16 strata
presented in Figure 4, thus satisfying the requirements of the factorial
design (n=128). The analysis of the stage-one data should indicate which
primary and secondary variables are influencing gas leak rates. Based on the
stage-one findings, stage-two leak tests will be allocated to specific strata
to enhance stage-one analyses and to increase estimate precision (n-72).
The methane emission rate for above-ground facilities (units = scf/hr)
is also the product of an emission factor and an activity factor. The
emission factor is derived from point source tracer emission flux measurements
conducted at the above-ground facilities of selected program participants.
The tracer tests estimate natural gas emissions from selected above-ground
features such as pressure regulating stations (units - scf/feature-hrs). The
activity factors are the number of specific above-ground features in the U. S,
natural gas industry. Activity data counts will be collected via surveys and
site visits.
Individual tracer tests are performed on randomly selected above-ground
facilities. The number of tests initiated on each category of above-ground
features, while still undetermined, must be large enough to ensure a
calculated precision that will meet the desired accuracy of the emission
estimate.
Preliminary Findings
The assumption that the below-ground sample population (i.e., program
participants) is representative of the target population (i.e., national
distribution industry) is an important consideration in developing the
experimental design, defining the appropriate sampling scheme, and assessing
the accuracy of the leakage estimates. A comprehensive industry
characterization analysis suggests that the 9 U. S. program participants are
very representative of the national industry with respect to pipe material and
pipe age. Figures 5 and 6 compare the 9 participants to the top 100 U. S. gas
5

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92-142.03
TABLE I. Factors Influencing Leakage Rate From
Below-Ground Distribution Systems.
Influencing Factor
Assigned Categories
Primary Factors

Pipe Use
Main, Service
Pipe Material
Unprotected Steel

Cathodically Protected Steel

Plastic

Cast Iron®

Copperb
Pipe Vintage
Pre-1940, 1940-1969, 1970-1990
Secondary Factors
Leak Detection & Repair Practices
Gas Operating Pressure
Soil Characteristics
Pipe Diameter
Good, Fair
High, Low
Porous, Nonporous
Large, Small
aHains only.
bServices only.
6

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MAINS
SERVICES
Material
Pre-1940
1940-1969
1970-1900
Unprotected
Steel

Be
Protected
Steel



Plastic



Cast
Iron



Age
Material
Pre-1940
194Q-19G9
1970-1990
Unprotected
Steel


1
I

I
ft



S!v5:%
y;
1


Protected
Steel
-4/1
"• \ ¦» * 3 's *5. """ ¦¦ «¦
«
* . dWS S * tti, ff<


Plastic
<>• ' /s*1" *¥< "*>
'' \ f / v ' *
Ililili!
A JaS ' v


Copper


l

= Stratum included in design.
= Stratum omitted from design.
FIGURE 4.
Leak Test Program Primary Strata.

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92-142.03
distribution systems. The ranking of the top 100 distribution systems is
based on total miles of underground mains. The material and age information
was provided by the U.S. Department of Transportation. These 100 distribution
systems account for roughly 80 percent of the total national gas throughput.
Figure 5 clearly shows that the relative proportions of distribution main pipe
materials for the 9 companies are nearly equal to the proportions for the 100
companies. Figure 6 shows that the program participants are representative of
the national population in terms of number of services broken down by pipe
material. Figures 7 and 8 show that the pipe vintage classes within the
program participants are representative of the age classes for the top 100
companies.
Four leak test program participants have collected preliminary leak rate
data. Two companies used the segment testing method and the remaining two
employed the individual leak test approach. The following preliminary
national emission estimates are based on 37 main leak tests and 30 service
tests.
The estimated national leak rate from underground mains is just under
2 x 10® scf/hr. The data suggest that plastic mains contribute approximately
16 percent to the total hourly emissions. The protected and unprotected steel
mains account for roughly 10 percent and 8 percent, respectively. Cast iron
mains make up possibly as much as 65 percent. The -estimated national leak
rate from underground services is approximately 3 x 105 scf/hr. Unprotected
steel services contribute over 65 percent to the total hourly emissions.
Cathodically protected steel and copper each accounts for roughly 15 percent of
the total, while plastic services make up approximately 2 percent.
Total annual emissions from underground main leaks are approximately
16 x 109 scf per year. Total annual emissions from below-ground service leaks
are approximately 3 x 109 scf per year.
Significant uncertainty is associated with nearly all of the leakage
estimates. The 90 percent confidence interval for each material-specific
estimate, except protected steel services, includes a leak rate of 0 scf/hr,
suggesting that additional data points must be collected to increase the
precision around the calculated emission totals for mains and services.
The reported emission totals for each of the pipe material classes will
shift as more leak test data are collected. The protected and unprotected
steel classes, for both mains and services, have an adequate preliminary
sample size. It is likely that additional leak tests in the steel groups will
increase the precision of the estimated leak rates. The plastic mains and
services, while potentially maintaining a very low leak frequency, will likely
have a large variation in leak intensity. Additional data collection in the
plastic classes is required to increase the precision of the estimated leak
rates. Cast iron mains are unique in the study of below-ground pipes in that
leaks typically originate from joints. Cast iron is very resistant to
corrosion. Depending on the age and the specific type of iron, bell and
spigot joints are at uniform intervals (e.g., 12, 16, and 18 feet).
8

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350
300
250
200
52.1%
33.4%
150
100
Bare Coated Bare Coaled Plastic Iron
Unprotected	Cathodlcally
Steel	Protected
Steel
-15.3%
23.5%
10.0%
9.8% 9-5%
\/ /
Bare Coated Bare Coated Pln.ftic Iron
Unprotected	Cathodlcally
Steel	Protected
Steel
n = 100	n = 9
FIGURE 5. Comparison of Top 100 Companies and Program Participants
for Miles of Main Broken Down by Pipe Material.
fO
ro
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LO

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40.1%
36.1%
11.0%
4.2%
Bare Coated Bare Coated Plastic Iron Copper
Unprotected CathodLcally
Steel	Protected
Steel
CD
O
CO

o
>
0)
3d.4%	OJJ |
o.5/o 7.9%
Bare Coated Bare Coated Plastic Iron Copper
Unprotected Cathodically
Steel	Protected
St eel
11
FIGURE 6.
= 100
n = 9
Comparison of Top 100 Companies and Program Participants
for Number of Services Broken Down by Pipe Material.

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58%
Pre-1940 1940-1969 1970-1990	Pro-1940 1940-1969 1970-1990
n = 100	n — 9
FIGURE 7. Comparison of Top 100 Companies and Program Participants
for Miles of Main Broken Down by Proposed Age Intervals.

ho
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20
56%
60%
CO
V 10
o
«
>
u
OJ
cn
14%

3 -

u
V
in
11
m
29%
Pre-1940 1940-19G9 1970-1990
Pre-1940 1940-1969 1970-1990
n = 100
ri
= 9
FIGURE 8. Comparison of Top 100 Companies and Program Participants	^
for Number of Services Broken Down by Proposed Age Intervals.
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92-142.03
Therefore, estimating the leak rates from cast iron mains may require a unique
approach. For example, cast iron leak frequency calculations will depend on
the specific segment lengths (i.e., joint interval) and past repair or
replacement programs.
The national emission estimates presented above are based on leak
frequencies calculated from reported leak repair records. Unrepaired leaks
and undetected leaks are not included in these preliminary leak frequency
estimates. Therefore, the reported values may underestimate total annual
emissions. The leak repair frequencies were scaled up to account for
multiyear leak survey cycles. Many of the larger distribution companies must
employ multiyear leak detection and repair programs. The leak test program
will adjust leak frequency estimates for companies with multiyear leak survey
cycles.
This discussion of uncertainty is intended to discourage the perception
that the presented emission totals are accurate estimates of natural gas
leakage from below-ground distribution systems. These preliminary estimates
are presented as part of an overall introduction to the cooperative leak test
program. The proposed experimental design will build on these available data
to estimate annual natural gas leakage from underground pipes.
Initial estimates of above-ground leakage are based on 13 point source
tracer tests performed in four midwestern cities and three southern plain
cities. The tests are limited to distribution system metering and pressure
regulating stations. The calculated emission factor is approximately
10 scf/station-hr, with a standard error of over 3 scf/station-hr. Based on
U.S. Department of Transportation data and a frequency estimate from two gas
companies, an estimated 1.4 x 10s regulator stations are operating across the
U.S. gas distribution network. The preliminary above-ground emission estimate
is approximately 12 x 109 scf of methane per year with a standard error of
4 x 109 scf per year.
INDUSTRY TOTAL LOSSES
As part of the overall program to quantify methane losses, a preliminary
assessment of actual emissions has been made for each individual segment of
the gas industry. Because of the complexity of the gas industry, an effort
was made to prioritize the research activities. Therefore, a preliminary
estimate of emissions from each source was made to focus the research in
accordance with the relative importance of the source to the national total
loss. The total methane emissions from the U.S. natural gas industry were
estimated to be approximately 200 x 10s scf/yr.
The sources of emissions were classified according to their associated
segment of the industry. The industry segments include gas production,
gathering systems, gas processing plants, transmission systems, storage
facilities, and distribution systems. Gas production and gathering consist
primarily of gas and oil wells, field separation equipment, gas compressors
used in production, and gathering pipelines. Gas processing plants comprise
13

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92-142.03
all process operations associated with natural gas purification and transport
to transmission custody. The gas transmission segment includes compressor
stations, transmission pipelines, odorant facilities, and above-ground meter
and pressure regulating stations. Distribution systems consist of the
underground main and service pipelines and above-ground facilities such as
meter and pressure regulating stations.
Emission estimates were divided into two broad categories based on the
inherent characteristics of the source. The first category, fugitive
emissions, includes continuous leakage from equipment components such as
valves, flanges, and pump and compressor seals, as well as leakage from
underground pipelines. As shown in Table II, emission estimates from fugitive
sources in each segment of the gas industry account for approximately half of
the total industry emissions.
Fugitive emissions for most segments of the industry were estimated by
average component counts based on model facilities and the use of fugitive
emission factors. Preliminary emission factors developed based on ongoing
bagging and screening studies by API/Star Environmental for offshore and
onshore oil and gas production and gas plants are currently being used to
estimate fugitive emissions. Above-ground emission sources from transmission
and distribution systems, such as meter and pressure regulating stations, were
estimated using interim data supplied by Aerodyne/Washington State University
based on a tracer technique to quantify methane loss. These studies will be
completed in 1993. Fugitive losses from underground transmission and
distribution pipelines were estimated based on leak test data from four gas
distribution companies in the United States. Leakage from underground
distribution services and mains was estimated to be the most significant
contributor to fugitive losses in the industry.
The second broad category of emissions, non-fugitives, includes all
intermittent losses directly to the atmosphere or to a flare. Non-fugitive
sources are more difficult to measure because of the intermittent nature of
the emissions. Non-fugitive emissions may occur during normal operations of
some equipment, during routine maintenance activities where gas is purged from
the system, or during process upsets and mishaps. Non-fugitive sources also
include exhaust emissions from combustion engines and turbines used to drive
compressors. The total emissions estimate from all non-fugitive sources in
the industry accounts for approximately half of the total national estimate.
Both fugitive and non-fugitive estimates for each segment of the
industry are significant as shown in Table II. Estimated losses from the gas
production and gathering operations are the largest in the industry, followed
by transmission and storage. Losses from gas plants and the distribution
segment are significantly lower; however, the uncertainty in the emissions
estimate from gas plants and distribution is substantial.
14

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92-142.03
Table II. Methane Emissions from
U.S. Natural Gas Industry
Methane Emissions
(percent of total)
Industry Segment
Fugitive
Venting/Flaring/Upsets
Production and Gathering
13
26
Processing Plants
5
5
Transmission and Storage
13
19
Distribution
17
2
TOTAL (percent)
48
52
15

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92-142.03
REFERENCES
1.	Intergovernmental Panel on Climate Change, Working Group I. "Summary
for Policymakers." In: Climate Change: The IPCC Scientific
Assessment. J.T. Houghton, G.J. Jenkins, and J.J. Ephraums, eds.
Cambridge University Press. Cambridge, England, 1990. p. xx.
2.	U.S. Environmental Protection Agency. Policy Options for Stabilizing
Global Climate. Office of Policy, Planning, and Evaluation.
Washington, D.C. June 1990. pp. II-8, V-102.
ACKNOWLEDGEMENTS
This project was cofunded by the Gas Research Institute,
Chicago, Illinois, and the Office of Research and
Development, U.S. Environmental Protection Agency, Research Triangle Park,
North Carolina. Radian gratefully acknowledges the contribution made by the
sponsors.
16

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, t^> Ann TECHNICAL REPORT DATA
A hilKL." 1 t)ZZ (Please read Instructions on the reverse before compter
1. REPORT NO. 2.
EPA/600/A-92/279
3.
4, TITLE AND SUBTITLE
Inventory of Methane Losses from the Natural Gas
Industry
5. REPORT DATE
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
M. V. Campbell, L, M. Campbell, and C. E. Rurklin
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
P. C. Box 13000
Research Triangle Park, North Carolina 27709
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-D1-0031
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Cffice of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT ANO PERIOD COVERED
Published paper; 10/91— 4 /92
14. SPONSORING AGENCY CODE
EPA/600/13
15.supplementary notes AEERL project officer is David A. Kirchgessner, Mail Drop 63.
919/541-4021. For presentation at AWMA Conference, Kansas City, MO, 6/22-26/92.
16. ABSTRACT ... j i n. r a
The paper gives the second year's results of an ongoing 4-year program
undertaken jointly by the Gas Research Institute and the U. S. EPA to assess the me-
thane (CH4) losses from the U.S. natural gas industry. The program's objective is
to assess the acceptability of natural gas as a substitute for other fossil fuels for
mitigating global climate change. The scope of the program is to directly quantify
CH4 losses from the three major segments of the natural gas industry: production,
transmission, and distribution. The study does not address CH4 emissions from
residential, commercial, or industrial end-use sources. The paper covers CH4
emissions from the gas distribution segment of the natural gas industry. Methane
losses from the production and transmission segments are covered in other papers.
In addition, this paper summarizes the current estimate of total CH4 emissions from
all sources within the natural gas industry.
17. KEY WORDS AND DOCUMENT ANALYSIS
a, DESCRIPTORS
b,IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Methane
Natural Gas
Gas Distribution
Pollution Control
Stationary Sources
Methane Losses
Global Climate
13 B
07C
21D
15E
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
17
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 <9-73)

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