United States
Environmental Protection
Agency
National Risk Management
Research Laboratory
Research Triangle Park NC 27711
Research and Development
EPA/600/SR-96/080 June 1997
the
Matthew R. Harrison, Theresa
Cowgill
1. Shires, Jane K. Wessels, and R. Michael
Gas Research Institute (GRI) and
the U.S. Environmental Protection
Agency's (EPA's) Office of Research
and Development cofunded a major
study to quantify methane emissions
from U.S. natural gas operations. For
the 1992 base year, total methane
emissions were estimated at 314 ±
105 (6.04 ± 2.01 Tg), which is
equivalent to 1.4% + 0.5% of gross
natural gas production.
Since 1992, many companies have
participated in voluntary programs de-
signed to reduce emissions. Methane
emission reductions from these pro-
grams are not reflected in the report.
However, methane emissions from a
future incremental increase in gas
were evaluated. Depending on
the size of the potential increase in
sales, estimated emissions would be
between 0.5% and 1.0% of the incre-
mental increase.
This study provides data from the
U.S. natural gas industry needed for
constructing global methane invento-
ries and for determining the relative
impacts of coal, oil, and natural gas
use on global warming. Using this
study's emissions estimate and some
key assumptions, an analysis showed
that the impact on warming from the
use of oil and coal per unit of energy
generated is much larger than that from
the use of natural gas.
This study is documented in 15 vol-
umes. Volume 2 is a technical sum-
mary that includes what was done and
how the measurements and calcula-
tions were performed.
This Project Summary was developed
by EPA's National Risk Management
Research Laboratory's Air Pollution
Prevention and Control Division, Re-
search Triangle Park, NC, to announce
key findings of the research project that
is fully documented in 15 volumes com-
prising a report of the same title (see
Project Report ordering information at
back),
Introduction
This report summarizes a major study
conducted by GRI and EPA to quantify
methane emissions from U.S. natural gas
operations. The goal was to determine
these emissions to within + 0.5% of natu-
ral gas production, starting at the well-
head and ending immediately downstream
of the customer's meter. The study was
conducted because this information is
needed to determine if natural gas can be
used as an integral part of a fuel switch-
ing strategy to reduce the potential of glo-
bal warming, and to provide data for a
global methane inventory.
Carbon dioxide (CO2) contributes nearly
as much to global warming as all other
greenhouse gases combined. Since natu-
ral gas produces much less CO2 per unit
of energy when combusted than either
coal or oil, the Intergovernmental Panel
on Climate Change (IPCC), EPA, and oth-
ers have suggested that, by promoting
the increased use of natural gas, global
warming could be reduced. However,
methane, which is the major constituent
of natural gas, is also an important green-
house gas and, on a weight basis, meth-
ane is a more potent greenhouse gas
than CO2. For this reason, it was impor-
tant to determine if emissions from the
natural gas industry are large enough to
substantially reduce or even eliminate the
advantage that natural gas has because
of its much lower CO2 emissions during
combustion.
This study, like other efforts to develop
emission inventories, had to address sev-
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eral difficult problems. Most of these prob-
lems were primarily associated with the
size and diversity of the natural gas in-
dustry and the number of sources that
must be considered. This industry com-
plexity, combined with the lack of both
equipment populations and methods for
estimating emissions, meant that early in
the program, resources were devoted to
developing comprehensive methods for
estimating and extrapolating emissions.
This also included selecting an accuracy
goal that could reasonably be achieved
but was sufficiently accurate to examine
the fuel switching strategy.
Considering these issues, a method of
approach was developed that
Accounted for all emission sources;
Measured and calculated emis-
sions;
Extrapolated emissions data; and
Assessed the accuracy of the final
estimate.
Method for Estimating
Emissions
This summary briefly describes the
method used to estimate methane emis-
sions from the natural gas industry.
Accounting for All Emission
Sources
The natural gas industry (shown in Fig-
ure 1) was divided into four segments:
production, processing, transmission/stor-
age, and distribution. The project estab-
lished boundaries for each industry
segment to specify the equipment included
in the study. The guideline used for set-
ting the boundary was to include only the
equipment in each segment that is re-
quired for marketing natural gas.
To fully characterize the natural gas
industry and account for all potential
sources of methane, the four industry seg-
ments were divided into facilities, equip-
ment, and components; and emission
sources were identified by equipment type,
mode of operation, and type of emission.
Equipment types included individual de-
vices, such as a pneumatic operator; large
pieces of equipment, such as a compres-
sors; or a grouping of equipment, such as
an offshore platform. Modes of operation
are start-up, normal operations, mainte-
nance, upsets, and mishaps. Emission
types are fugitive, vented, and combus-
tion.
For this project each emission source
was accounted for by carefully examining
the operating mode for each equipment
category. This differentiation ensured that
all emission sources were accounted for
and that all types of emissions from the
source were considered. For example,
compressor engines can be a significant
source of fugitive, vented, and combus-
tion emissions that result from a variety of
operating modes. During normal opera-
tions, unburned methane is emitted in the
Production
Distribution
Main and
service pipelines
Surface
facilities
Underground
storage
reservoir
Customer meters
C | Compressor
Meter
Pressure regulator
Figure 1. Gas industry flow chart.
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engine exhaust, and fugitive emissions can
result from leaks in valves and pressur-
ized connections. Also, natural gas is
vented during engine start-ups if natural
gas is used to power the starter turbine.
During upsets, natural gas is released from
compressor blowdown and pressure relief
valves, and natural gas is vented during
compressor blowdown for maintenance.
Measuring Calculating
Emissions
Initially, few methods were available for
measuring and/or calculating emissions
from natural gas facilities. Therefore, the
early stages of this study were spent de-
veloping measurement techniques and
demonstrating them in the field before us-
ing them to gather data for the study. On
the basis of these proof-of-concept tests,
three measurement methods were even-
tually chosen for use in this study. For
pipeline leaks, the emission rate was mea-
sured by isolating the leaking section of
pipe and measuring the amount of gas
needed to maintain operating pressure in
the line. For fugitive leaks from above-
ground facilities, either a tracer gas method
or a component emission factor approach
was used.
For the tracer gas method, a tracer gas
such as sulfur hexafluoride is released at
a known constant rate near the methane
source. The emission rate was determined
by measuring the concentration of the
tracer and methane downwind; since the
ratio of emission rates is equal to the ratio
of concentrations, the methane emission
rate can be calculated.
The component emission measurement
approach develops average emission rates
for the basic components (valves, flanges,
seals, and other pipe fittings) that com-
prise natural gas facilities. The total emis-
sions from the facility are the product of
the number of components times the cor-
responding emission factor.
New component emission factors were
developed as a result of this study for
natural gas production and processing fa-
cilities, compressor stations, and residen-
tial and commercial meters. Also a new
"Hi-Flow" instrument was developed that
can measure emissions quickly and accu-
rately from pneumatic control devices,
valves, flanges, and other pipe fittings.
In some cases it is more accurate and
less complicated to calculate, rather than
measure, emissions. An example is emis-
sions from a "blowdown" to make a pipe
repair. Knowing the temperature and pres-
sure of the gas, the volume of the pipe,
and the frequency of the event, emissions
can be calculated. Another reason for cal-
culating emissions is that it may not be
practical to measure emissions from some
sources. Since annual emissions are
needed for the study, it is not practical to
try to measure highly variable, unsteady
emissions. In developing engineering mod-
els for calculating these types of emis-
sions, it is necessary to first understand
the equipment and the nature of the pro-
cess causing the emissions and then to
collect field data on the frequency of the
event.
A considerable amount of field data was
collected during this study. In addition to
measuring emissions and collecting infor-
mation on operating characteristics of
equipment and frequency of events, a sub-
stantial effort was required to collect infor-
mation on equipment populations.
Equipment counts are needed to extrapo-
late measured and calculated emissions
to other similar sources in the industry.
Data were collected on each source
category identified during initial stages of
the project. However, because of the large
number of sources in each source cat-
egory, data were collected on a relatively
small percentage of all sources in each
category. Therefore, these data had to be
extrapolated to account for the sources
that were not measured in order to de-
velop a national emissions estimate. To
extrapolate the emission data, emission
and activity factors were defined so that
their product equals the annual nation-
wide emissions from a given source cat-
egory. Typically, the emission factor is
defined as the average annual emissions
from a piece of equipment or event. The
activity factor would then be the national
population (i.e., the total equipment count
or total number of events). For example, if
fugitive emissions from compressor en-
gines is the source category, then aver-
age emissions per engine would be the
emission factor, and the number of en-
gines would be the activity factor.
Although this approach is straightfor-
ward, the application proved to be difficult
due to the lack of data on equipment
populations and operational events. Lim-
ited information is available on a national
basis. Collecting data on activity factors,
e.g., number of separators, pneumatic con-
trol devices, miles of gathering lines,
blowdown events, required a large num-
ber of site visits and was therefore a ma-
jor part of the study.
Accuracy
The accuracy of the emissions estimate
depends on the precision and bias of both
the activity and emission factors. In devel-
oping activity factors, as in conducting
emission measurements, care was taken
in developing sampling protocols, detect-
ing and eliminating bias, and developing
methods for calculating precision.
The accuracy goal of the project was to
determine emissions from the natural gas
industry to within + 0.5% of gross natural
gas production. This goal was established
based on the accuracy needed for con-
structing emission inventories for use in
global climate change models and for as-
sessing the validity of the proposed fuel
switching strategy.
The first step in achieving the accuracy
goal was to develop accuracy targets for
each source category. Accuracy targets
were assigned so that a higher degree of
accuracy would be required for the largest
sources while achieving the overall pro-
gram goal. This had the additional advan-
tage of automatically assigning more
program resources to the most important
source categories.
Accuracy is made up of precision and
bias. Precision can be calculated, but bias
can only be minimized. To minimize bias,
a sampling approach similar to dispropor-
tionate stratified random sampling was
developed. A project review committee was
established and industry advisory groups
were formed for production, transmission,
and distribution to review the program and
ensure that any potential for bias was
identified and eliminated. Also the data
were analyzed to ensure that data were
not sampled disproportionately with respect
to the parameters that had a large impact
on emissions. This not only minimized bias
but also reduced the impact that outlying
data points had on the result. The preci-
sion of the activity and emission factors
was calculated for a 90% confidence level
from the number of data points collected
and the standard deviation. The precision
of the emission estimate for each source
category as well as the national estimate
was also calculated in a statistically rigor-
ous fashion.
Results
1992
Total methane emissions from the natu-
ral gas industry for the 1992 baseline year
are 314 + 105 Bscf (6.04 + 2.01 Tg). This
is approximately 1.4% + 0.5% of gross
natural gas production, a result that meets
the project accuracy goal. This represents
approximately 19% of total U.S. anthropo-
genic emissions, based on methane emis-
sion estimates reported by the EPA for
major anthropogenic sources (see Figure
2).
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Domesticated Livestock 19%
Coal Mining 15%
Other 6%
.; ;.S"-,'\ Livestock Manure 9%
Figure 2. Contribution of major methane sources to total U.S. anthropogenic emissions.
Figure 3 presents methane emissions
for the natural gas industry by industry
segment. The transmission/storage seg-
ment accounts for the largest portion of
emissions (37%) with the processing seg-
ment contributing the least (12%).
The largest emission sources for each
industry segment are presented in Table
1. Fugitive emissions are the largest con-
tributor to methane emissions from natu-
ral gas processing, transmission, and
storage. Nearly 90% of these emissions
result from leaks on compressor compo-
nents such as the suction, discharge,
blowdown, and pressure regulator valves
and compressor seals. Fugitive emissions
from all compressor components are ap-
proximately 80 Bscf (1.6 Tg), while fugi-
tive emissions from all other compressor
station components, such as yard piping
and filter-separators, are approximately 10
Bscf (0.19 Tg). Compressor engine ex-
hausts are responsible for slightly more
than 25 Bscf (0.48 Tg) of methane emis-
sions.
Fugitive emissions from pipelines are
approximately 48 Bscf (0.93 Tg), of which
42 Bscf (0.80 Tg) is from distribution pip-
ing. Distribution piping systems actually
emit 51 Bscf (0.98 Tg), but approximately
18% of the natural gas leaked is oxidized
in the soil by methanotrophs. Approxi-
mately 22 Bscf (0.42 Tg) is leaked from
cast iron mains that constitute only 6% of
the total length of distribution main pipe-
lines. However, most cast iron leaks are
very small and, since the oxidation rate
varies inversely with leak rate, only 60%
of the leaks (13 Bscf or 0.25 Tg) reach
the surface.
The two largest methane emission
sources in natural gas production are
Distribution 24%
Transmission/Storage 37%
Figure 3. Summary of methane emissions.
pneumatic control devices and fugitives.
Prior to this study, pneumatic devices were
not considered a major emission source.
Approximately a third of these devices
bleed natural gas to the atmosphere con-
tinuously. Pneumatic devices are the larg-
est source of methane emissions in the
production segment, accounting for 31 Bscf
(0.60 Tg). Total fugitive emissions from
production equipment are large even
though the average leak rate is small,
because of the large number (approxi-
mately 80 million) of valves, connectors,
and other pipe fittings on equipment lo-
cated at production sites across the coun-
try.
Emissions from Incremental
Increases in Gas Sales
Consumption of natural gas has in-
creased since the 1992 base year. To
determine the effect that this increase and
future increases will have on emissions, a
study was conducted to determine the per-
cent increase in emissions resulting from
an incremental increase in natural gas
production and sales. The study found
that increases in throughput would, in
many cases, produce increases in emis-
sions. However, the average increase in
emissions would be proportionally smaller
than the increase in system throughput.
The study examined the consequences
of increasing gas sales by 5%, 15%, and
30% under three scenarios: uniform, win-
ter peak, and summer peak load profiles.
All segments of the gas industry were
examined to determine the percent in-
crease in equipment that would be needed
to meet the increased demand. The per-
cent increase in emissions was then esti-
mated based on changes in the current
system that would be required to accom-
modate the increase in gas sales. The
GRI/EPA emission estimate was used to
calculate the percent increase in emis-
sions that would result from an incremen-
tal increase in natural gas sales for several
scenarios examined in the study.
The most realistic scenario assumed
that the system would be expanded using
the latest technologies, whereas the most
conservative scenario assumes that the
expanded system mirrors the existing sys-
tem. Generally, as the system expands,
the emission rate for the expansion would
be less, as a percent of throughput, than
for the base system. Emissions from a
system load increase (an increase in con-
sumption of gas) of 30% would emit at
only one- to two-thirds of the base emis-
sion rate. For example, if gas production
increased by 30% (6 to 7 trillion cubic feet
per year), emissions from the system ex-
pansion would be between 30 and 70
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Table 1. Largest Emission Sources by Industry Segment
Annual Methane
Emissions
Segment
Production
Processing
Transmission/
Storage
Distribution
Source
Pneumatic devices
Fugitive emissions
Dehydrators
Other
Fugitive emissions
Compressor exhaust
Other
Fugitive emissions
Blow and purge
Pneumatic devices
Compressor exhaust
Other
Underground pipeline leaks
Meter and pressure regulating stations
Customer meters
Other
(Bscf)
31
17
14
21
24
7
5
68
19
14
11
5
42
27
6
2
(Tg)
0.60
0.33
0.28
0.41
0.47
0.13
0.10
1.30
0.36
0.27
0.22
0.10
0.80
0.53
0.11
0.04
Percent of
Segment
Total
37
21
17
25
67
19
14
58
16
12
10
4
54
35
8
3
Total1
314 Bscf 6.04 Tg
1 Individual sources may not sum exactly to total shown due to roundoff errors.
Bscf. These emissions, when divided by
the incremental production, are equivalent
to an emission rate between 0.4% and
1.0% of incremental production. This is
much lower than the 1.4% of production
emitted from the current base system for
1992.
Emissions are lower for an incremental
increase in gas sales because the current
system has excess capacity and any ad-
ditional equipment that would have to be
installed to meet increased demand would
use current and lower emitting technol-
ogy. A few examples of these technolo-
gies are no-bleed pneumatic devices,
turbine compressor engines, and plastic
pipe instead of steel and cast iron mains.
Emissions Fuel Switching
The estimate of methane emissions from
natural gas operations was used in an
analysis to determine if the potential for
global warming could be reduced by
switching from coal or oil to natural gas.
Emissions from coal and oil were esti-
mated from other sources. Other than CO2
and methane, emissions from other green-
house gases from the fuel cycle of fossil
fuels are negligible. Methane, however is
a more potent greenhouse gas than CO2.
The approach used was to determine the
emissions of methane and CO2 for the
complete fuel cycle of natural gas, oil, and
coal, and to convert the methane emis-
sions to equivalent CO2 using the Global
Warming Potential (GWP).
The GWP is an index that relates the
impact of releasing quantities of the vari-
ous greenhouse gases to the release of
an amount of CO2 that would produce the
same impact on global warming. Currently,
there is a great deal of uncertainty in the
time period associated with the GWP of
methane. Typical time periods range from
50 to 500 years, which correspond to GWP
values of 34 and 6.5, respectively. This
means that 1 Ib of methane is equivalent
to between 6.5 and 30 Ib of CO2.
Equivalent CO2 emissions from the fuel
cycle of natural gas were calculated to be
132 lb/106 Btu (57 kg/GJ) for a GWP of
6.5 and 152 lb/106 Btu (66 kg/MJ) for a
GWP of 34. Even for a GWP of 34, the
analysis showed that, compared to natu-
ral gas, oil has 1.2 times the impact on
global warming and coal has 1.5 times
the impact.
Conclusions
Based on data collected, methane emis-
sions from natural gas operations are es-
timated to be 314 + 105 Bscf (6.04 + 2.01
Tg) for the 1992 baseline year. This is
approximately 1.4% + 0.5% of gross natu-
ral gas production. This study also deter-
mined that the percentage of methane
emitted per gas production rate for an
incremental increase in natural gas sales
would be between 1.19% and 1.38% of
the total gas production, compared to 1.4%
of production for the baseline case.
Results from this study were used to
compare greenhouse gas emissions from
the fuel cycle for natural gas, oil, and coal
using the GWPs recently published by the
IPCC. The analysis showed that natural
gas contributes significantly less to global
warming per unit of energy than coal or
oil, which supports the fuel switching strat-
egy suggested by IPCC and others.
This study, like other efforts in develop-
ing emission inventories, had to address
the following typical but nevertheless diffi-
cult problems:
Collecting demographic information;
Developing methods for measuring
and calculating emissions;
Extrapolating a limited amount of
data to a large, diverse national
population; and
Determining the accuracy of the fi-
nal estimates.
The most difficult of these is evaluating
the accuracy. Accuracy targets were es-
tablished for each source category that
would be needed to achieve the overall
accuracy goal of the study. A sampling
procedure with checks for bias was then
established, data were collected, and the
precision of the emission estimate was
rigorously calculated for each category,
as well as for the national estimate.
During the course of the study, equip-
ment population in the gas industry was
collected and new methods were devel-
oped for measuring emissions from a va-
riety of sources. Unique methods were
developed using tracer gas techniques,
and a new "Hi-Flow" instrument was de-
veloped that provides a quick, cost-effec-
tive method for measuring the leak rate of
valves, seals, pneumatic devices, and con-
nectors.
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 par-
ticipating 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 reduc-
tions and to report reductions to the 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 emis-
sions.
In conclusion, the project reached its
accuracy goal and provides an accurate
estimate of methane emissions for 1992
gas industry practices. The results can be
used to construct U.S. methane invento-
ries and analyze fuel switching strategies.
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Matthew R. Harrison, Theresa M. Shires, Jane K. Wessels, and R. Michael Cowgill are
with Radian International LLC, Austin, TX 78720-1088.
David A. Kirchgessner is the EPA Project Officer (see below).
The complete report, consisting of 15 volumes, is titled "Methane Emissions from the
Natural Gas Industry" and has the following order numbers and costs:
The set (Order No. PB97-142913; Cost: $331.00, subject to change)
Volume 1: Executive Summary (Order No. PB97-142921; Cost: $19.50, subject to
change)
Volume 2: Technical Report (Order No. PB97-142939; Cost: $31.00, subject to change)
Volume 3: General Methodology (Order No. PB97-142947; Cost: $38.00, subject to
change)
Volume 4: Statistical Methodology (Order No. PB97-142954; Cost: $31.00, subject to
change)
Volume 5: Activity Factors (Order No. PB97-142962; Cost: $31.00, subject to change)
Volume 6: Vented and Combustion Source Summary (Order No. PB97-142970; Cost:
$21.50, subject to change)
Volume 7: Blow and Purge Activities (Order No. PB97-142988; Cost: $25.00, subject to
change)
Volume 8: Equipment Leaks (Order No. PB97-142996; Cost: $31.00, subject to change)
Volume 9: Underground Pipelines (Order No. PB97-143002; Cost: $25.00, subject to
change)
Volume 10: Metering and Pressure Regulating Stations, Etc. (Order No. PB97-143010;
Cost: $21.50, subject to change)
Volume 11: Compressor Driver Exhaust (Order No. PB97-143028; Cost: $25.00, subject
to change)
Volume 12: Pneumatic Devices (Order No. PB97-143036; Cost: $25.00, subject to
change)
Volume 13: Chemical Injection Pumps (Order No. PB97-143044; Cost: $21.50, subject
to change)
Volume 14: Glycol Dehydrators (Order No. PB97-143051; Cost: $21.50, subject to
change)
Volume 15: Gas-Assisted Glycol Pumps (Order No. PB97-143069; Cost: $21.50, subject
to change)
These volumes will be available only from
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at
Air Pollution Prevention and Control Division
National Risk Management Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
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Environmental Protection Agency
Center for Environmental Research Information
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