The Value of Fugitive Methane Emissions From Oil & Gas Sectors
The Value of Fugitive Methane Emissions from Oil, Gas, & Coal Sector
The Value of Fugitive Methane Emissions
from Oil, Gas, and Coal Sectors
June 30, 2015
The Value of Fugitive Emissions from Oil, Gas, & Coal Sectors
After carbon dioxide (CO2), methane emissions are the second largest source of greenhouse gas
emissions (GHG) in the United States. Compared to CO2, however, methane is 20 to 30 times
more effective in trapping radiation than CO2, although methane has a much shorter lifetime in
the atmosphere is than CO2. Although there is controversy over the accuracy of data, the
Environmental Protection Agency estimated that methane emitted by human activities comprised
approximately 9% (567 out of 6,303 metric tons CO2 equivalent) of all domestic greenhouse gas
emissions in 2012. Out of this, the fossil fuel sector (e.g., coal, oil, gas) contributed
approximately 38% of the methane GHG emissions; of which 28% came from natural gas and
petroleum (i.e., approximately 1% of overall GHG emissions [0.09 x 0.38 x 0.28 percent]). In
addition, agricultural (enteric digestion and manure), natural (bogs) and non-industrial (landfills)
sources contribute significantly to methane emissions.
Although methane emissions from natural gas and petroleum operations may contribute less to
GHG concentrations than CO2, there are important issues that warrant consideration of the value
of these methane emissions. First, unlike many emissions considered “pollutants,” methane is an
economically valued product, and emissions reduction may prove cost-effective by reducing
losses in marketable product. Second, U.S. production of natural gas, which is primarily methane,
has expanded rapidly in the past several years and production is likely to continue to increase.
Accordingly, this analysis of the sources and factors affecting methane emissions can provide
financial as well as environmental insights that may be of value to policy makers. While some
have expressed concern about methane emissions from expanding natural gas production and
distribution operations, others are concerned that efforts to control these emissions could hamper
development of natural gas, potentially causing other sources of GHG emissions to increase.
In the upstream oil and gas sector, methane may be encountered and released while drilling
through gas-bearing geologic formations, during drilling mud circulation, during well
development when formation fluids and fracture fluids flow back to the surface (following well
stimulation by hydraulic fracturing), and from oil, gas, and water separators, and stock tanks. In
oil- and gas-producing regions lacking pipeline take-away capacity, producers must resort to
“flaring” or burning gas to dispose of it. Flaring gas produced at the wellhead is a necessary
safety practice to eliminate explosive conditions from developing around the well pad. However,
flaring excess methane gas raises the question about the lost economic value of the gas both in
terms of value to the producer as well as potential foregone royalties to government and
landowners and the loss of a valuable energy resource.
Midstream, gathering lines—which connect the wellhead to oil field treatment equipment that
separates gas, oil and water into product streams—represent another opportunity for fugitive
methane and gas condensate emissions. Leaking vales, transmission lines, and pump stations add
to this sector’s emissions.
Downstream, older gas distribution pipelines constructed from cast iron or uncoated steel (some
installed early in the last century) are increasingly susceptible to corrosion or other material
failure and thus prone to leaks. In 2012, there were more than 1.2 million miles of distribution
mains in the United States. Of this, more than 32,000 miles of mains were cast iron or wrought
iron, and more than 61,000 miles were unprotected steel.
In 2012, the United States withdrew 29,542.3 billion cubic feet (BCF) of natural gas from a
combination offshore and onshore resources (conventional oil and gas wells, shale and tight sand
gas wells, and coalbed wells). Of that, producers vented or flared 260.4 BCF. Methane emissions
from all source of leaks in this sector total 313.2 BCF or roughly 1% of production. The
The Value of Fugitive Emissions from Oil, Gas, & Coal Sectors
emissions represent a loss of roughly $1.25 billion (assuming a natural gas price of $4 per
thousand cubic feet. Adding producer vented or flared gas raises the loss another $1 billion,
bringing the total loss to over $2.25 billion. (These estimates will be higher or lower depending
on the price of natural gas. For example, prices in February 2015 were in the high-$2 range.)
Counting coalbed methane production-related emissions would increase the loss. The cost over
the last 10 years from gas pipeline incidents—$1.43 billion from transmission pipelines and $725
million from distribution pipelines—compounds the losses even further.
Congress may have immediate concern that natural gas vented or flared from wells on federal
leases represents lost revenues. In addition, the low price of natural gas raises the question about
how tolerant producers and distributors of natural gas are to economic losses from leaks. Small
oil and gas producers may lack the financial incentive to manage natural gas leaks given their
tight profit margins. Threats to public safety from leaking pipelines, notwithstanding, low cost
natural gas may also make the economic loss from pipeline leaks tolerable to gas transmission
and local distribution companies compared to the cost of repairing or replacing pipelines.
The Value of Fugitive Emissions from Oil, Gas, & Coal Sectors
Measuring Fugitive Methane Emissions ...........................................................................3
Oil and Gas Industry Sectors..............................................................................................7
Onshore Oil and Natural Gas Production-Related Emissions......................................9
Offshore Oil and Natural Gas Production-Related Emissions....................................10
Natural Gas Venting and Flaring ...............................................................................11
Coal Production-Related Emissions...........................................................................13
Gas Processing-Related Emissions............................................................................15
Transmission and Distribution Pipelines..........................................................................17
All Sector Emissions Summary........................................................................................19
Reduced Emission Completions................................................................................20
Liquids Unloading Processes.....................................................................................21
Oil and Natural Gas Sector Compressors...................................................................21
Oil and Gas Sector Leaks...........................................................................................21
Oil and Natural Gas Sector Pneumatic Devices.........................................................22
Federal and State Regulatory Responses..........................................................................22
Figure 1. Onshore Oil and Natural Gas Production-Related Emissions in 2012..............10
Figure 2. Offshore Oil and Natural Gas Production-Related Emissions in 2012..............11
Figure 3. Natural Gas Withdrawals vs. Vented and Flared Gas ......................................12
Figure 4. U.S. Crude Oil Production...............................................................................13
Figure 5. Coalbed Methane Fields, Lower 48 States........................................................14
Figure 6. Methane Anomalies and Emissions over the Conterminous United States.......15
Figure 7. Onshore Gas Processing in 2012.......................................................................17
Figure 8. Emissions from Natural Gas Distribution System in 2012 ...............................18
Figure 9. PHMSA Pipeline Incidents...............................................................................19
Table 1. EPA’s Annual GHG Emissions Estimates for Natural Gas Systems.....................6
Table 2. EPA’s Annual GHG Emissions Estimates for Natural Gas Systems, Normalized.7
Table 3. Methane Emissions from Oil and Gas Sectors ...................................................20
Table A-1. Natural Gas Processing Plant Capacity by State.............................................25
Appendix.Natural Gas Processing Plants.........................................................................24
The Value of Fugitive Emissions from Oil, Gas, & Coal Sectors
The Value of Fugitive Methane Emissions for Oil, Gas, & Coal Sectors
Methane is the second most prevalent greenhouse gas (GHG) emitted in the United States after
carbon dioxide (CO2). Although carbon dioxide is the more serious actor by volume, methane
(CH4) is roughly 20 to 30 times more potent per unit of mass in trapping heat within the
atmosphere. However, methane has a comparatively short atmospheric residence time of
approximately 12 years.1
In 2009, the Environmental Protection Agency (EPA) included methane among six greenhouse
gases that threaten the public health and welfare in an Endangerment Finding under section
202(a) of the Clean Air Act.2
The finding did not impose any requirements on industry or other
entities. However, the action was a prerequisite for establishing greenhouse gas emissions
standards for vehicles, as well as for existing and new stationary sources of emissions that led to
voluntary actions for stationary sources by statute.
In 2012, EPA estimated that methane emitted from all U.S. sectors was the equivalent of 567.3
million metric tons of carbon dioxide (CO2), or about 9% of all domestically produced
greenhouse gas (GHG) emissions from human activities.3
The fossil energy sector as a whole
reportedly contributed over 38% of methane emissions, comprised of 28.5% from natural gas and
petroleum systems and 9.8% from coal mining in 2012.4
In the 2014 report Inventory of U.S Greenhouse Gas Emissions and Sinks, EPA reported that
methane emitted by the oil and gas sector generally had declined by 16% overall since 1990.5
Petroleum systems (crude oil production, transportation, and refining) emissions (1,511 Gg or the
equivalent of 78.3 BCF ) declined by 11.3% largely due to the declining numbers of offshore
shallow water drilling platforms operating in the Gulf of Mexico. Natural gas system (field
production, processing, transmission and storage, and distribution) emissions (6,186 Gg or the
equivalent of 320.5 BCF) declined by 17%. The emission estimates from these sectors excluded
gas purposely vented or flared (combusted). EPA added that emissions appeared to be on the rise
with the increase of onshore oil and gas production resulting from advanced drilling techniques in
shale and tight sandstone formations.6
Since 1990, gross natural gas withdrawals have increased
from roughly 21.5 trillion cubic feet (TCF) to over 30 TCF by 2013 (see “Natural Gas Venting
and Flaring,” below).7
Coal mining (surface, underground, and coalbed methane extraction)
emissions (2,658 Gg or the equivalent 137.7 BCF) saw a 31% decline.
Intergovernmental Panel on Climate Change, Working Group I: The Scientific Basis, http://www.ipcc.ch/ipccreports/
U.S. Environmental Protection Agency, "Endangerment and Cause or Contribute Findings for Greenhouse Gases," 74
Federal Register 66496, December 15, 2009, http://epa.gov/climatechange/endangerment/index.html. The
"endangerment" language in Clean Air Act Sections 108, 111, 211, 213, 115, and 231 provides fundamental authorities.
Also, Section 111(d) provides authority to control GHG emissions from existing sources, and Section 111(b) and (e)
provide similar authorities for new sources.
U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012,
Washington, DC, EPA 430-R-14-003, April 15, 2014.
EPA, Inventory of U.S. Greenhouse Gas Emission and Sinks: 1990-2012, April 15, 2014, pp. 3-55.
EPA, Table 3.-29 CH4 Emission from Coal Mining: 3,860 Gg (1990) vs 2,658 Gg (2012); Table 3-33 Emissions from
Abandoned Coal Mines: 228 Gg (1990) vs 226 Gg (2012); Table 3-37 CH4 Emissions from Petroleum Systems: 1,704
Gg (1990) vs 1,511 Gg (2012); Table 3-44 CH4 Emissions from Natural Gas Systems: 7,450 Gg (1990) vs 6,186 Gg
(2012). 1 Gg (Giggagram) CH4 = 51,813,417 cubic feet.
EPA, Inventory of U.S. Greenhouse Gas Emission and Sinks: 1990-2012, April 15, 2014, pp. 3-55.
Natural gas gross withdrawals, as defined by the Energy Information Administration: Full well-stream volume,
including all natural gas plant liquids and all no hydrocarbon gases, but excluding lease condensate. Also includes
amounts delivered as royalty payments or consumed in field operations.
Anthony Andrews 1
The U.S. Energy Information Administration (EIA) reports that oil and natural gas production
field operations account for 98% of total methane emissions from the petroleum sector, with
vented methane making up 90%.8
Crude oil transportation accounts for less than 0.4% of methane
emissions, and refining less than 1.3% for the industry. The decrease in CH4 emissions is because
of the large decrease in emissions from production and distribution.
Some reporting would suggest that that oil and gas field production operations are more
problematic methane emitters, aging natural gas distribution systems may be the cause for more
immediate concern. Since natural gas systems and operations handle methane exclusively, the
potential for fugitive emissions is likely greater than oil handling systems. Natural gas production
has been rising with the development of unconventional shale resources. Between 2008 and 2013,
natural gas production rose 18% from 25.6 trillion cubic feet (TCF) to 30.2 TCF.9
Over the same
period, crude oil production rose 50% from 1.8 billion barrels to 2.7 billion barrels annually.10
The expectation is that natural gas demand will rise as it displaces coal as the preferred fuel for
electric power generation. Whether fugitive methane emissions will rise with increased natural
gas use may depend upon the rate that the industry replaces aging gas systems.
The federal government has had an overriding interest in controlling methane emissions from oil
and natural gas systems stemming from concerns for public health and safety, resource recovery
and environmental and economic benefits. The Federal Energy Regulatory Commission (FERC)
regulates the interstate transmission of natural gas and oil, and reviews proposals to build
liquefied natural gas (LNG) terminals and interstate natural gas pipelines. The Pipeline and
Hazardous Material and Safety Administration (PHMSA) Pipeline Safety Enforcement Program
monitors and enforces pipeline operators’ compliance with safety regulations. PHMSA has
collected pipeline incident reports since 1970. Over the last two decades pipeline incidents have
produced 279 fatalities and 1,059 injuries. The EPA Natural Gas STAR Program is a voluntary
partnership that encourages oil and natural gas companies—both domestically and abroad—to
adopt cost-effective technologies and practices that improve operational efficiency and reduce
emissions of methane.
The Obama Administration announced in January 2015 that EPA would take additional steps to
address emissions from the oil and gas sector, including a proposal to build on the 2012 New
Source Performance Standards (NSPS) that will set standards for methane emissions from new
and modified oil and gas production sources, and from natural gas processing and transmission
This report reviews the issues involved in the data collection and analysis of fugitive methane
emissions from oil and gas systems from the well head to the consumer. It begins with a summary
description of the official inventories used for measurement and reporting. It then analyzes the
various source categories in the sector to assess the current understanding of emissions. In each
case, the report outlines the prevailing issues confronted by the sector and surveys the most recent
advances in mitigation technologies and best practices. For a summary of federal agencies’
responses to methane emissions from oil and gas systems, as well as a recent compendium of
legislative proposals regarding the issue, see CRS Report R43860, Methane: An Introduction to
Emission Sources and Reduction Strategies.
U.S. Energy Information Administration, Natural Gas, Natural Gas Gross Withdrawals and Production,
EIA, “Petroleum & Other Liquids, Crude Oil Production,” http://www.eia.gov/dnav/pet/
In 2010, Congress asked the Government Accountability Office (GAO) to examine available
estimates of the vented and flared natural gas on federal leases, estimate the potential to capture
additional gas, and assess the federal role in reducing venting and flaring. The natural gas lost to
venting and flaring from onshore federal leases in 2008 would have equaled approximately $58
million in federal royalty payments, as further discussed in the section on “Natural Gas Venting
and Flaring,” below.
With EPA’s announcement to set methane emission standards for oil and gas production,
Congress consider whether future increased regulatory oversight is warranted or whether
economic incentives might better motivate industry behavior. Should penalties apply to producers
whose poor practices result in lost oil and gas royalties, for example? Some states (e.g. North
Dakota) have begun to restrict the practice of flaring natural gas that is stranded because of the
lack of pipeline to deliver it to out of state markets because the flaring reduces royalties. Small oil
and gas producers may lack the financial resources to manage natural gas leaks given their tight
The low price of natural gas raises the question whether producers and distributors of natural gas
are to too tolerant to economic losses from leaks. Threats to public safety from leaking pipelines,
notwithstanding, low cost natural gas may also make the economic loss from pipeline leaks
tolerable to gas transmission and local distribution companies compared to the cost of repairing
or replacing pipelines. Reporting the value of economic losses from fugitive natural gas
emissions might compel better industry behavior when public utility commissions and the rate-
payers they represent consider utility rate adjustments.
Measuring Fugitive Methane Emissions
By definition, “fugitive” emissions are elusive and transitory. Thus, one of the greater difficulties
in estimating emissions is acquiring comprehensive and consistent measurement data. Broadly,
there are two different approaches to measurement: “bottom-up” and “top-down.”
Currently, the primary source of information on emissions in the natural gas industry is a methane
study published in 1996 by EPA and the Gas Research Institute (GRI).11
The study focuses on
1992 (as a base year) and uses a “bottom-up” methodology to estimate emissions. Bottom-up
approaches use direct measurement of select component emissions to produce emissions factors
(i.e., formulas) for the hundreds of different emissions sources within the industry. The methods
• “component measurement,” wherein emissions are measured directly
from a large number of randomly selected pieces of equipment to determine an
average emission factor for each type;
• “tracer gas,” wherein facility-wide emissions are calculated by injecting
a tracer gas into facility systems and measuring the downwind concentrations of
the tracer and methane; and
Gas Research Institute and U.S. Environmental Protection Agency, Methane Emissions from the Natural Gas
Industry, Volumes 1-15, GRI-94/0257 and EPA 600/R-96-080, June 1996. See “Executive Summary” at
• “leak statistics,” wherein emissions are measured for a large number of
pipeline leaks to determine an average emissions rate per leak as a function of
pipe material, age, operating pressure, and environmental characteristics.
Total industry emissions are then estimated by multiplying these emissions factors by the activity
levels for each system component (i.e., the number of wellheads, compressors, processing plants,
miles of pipeline in operation, and other components) across the entire industry. EPA annually
calculates emissions estimates for the industry using methodology based on the 1996 EPA/GRI
study and publishes the findings in its Inventory of U.S. Greenhouse Gas Emissions and Sinks.12
Bottom-up approaches are also used for EPA’s Greenhouse Gas Reporting Program13
as well as
the Energy Information Administration’s Natural Gas Annual.14
Due to differences in emissions
factors, methodology, and industry reporting, each study has returned different estimates. Further,
the three government inventories have been criticized by industry, environmental groups, and
other sources, many of which have put forth competing, and sometimes conflicting, estimates
over the past few years.
Sources other than the U.S. federal government have also designed bottom-up methodologies for
determining emissions from natural gas infrastructure. These include both international sources
(e.g., the Intergovernmental Panel on Climate Change)15
and industry sources (e.g., the American
Further, various state and local agencies have estimated—or have proposed
estimating—emissions from natural gas infrastructure in their regions (e.g., Texas,17
). These inventories do not always use the same methodologies as the federal (or
the other) inventories listed above; and thus, it may be difficult to compare them against the
Other published studies use “top-down” methodologies for the calculation of leakage (e.g.,
satellite observations, ambient atmospheric measurements, and geostatistical inverse modeling).
Various studies conducted by researchers in conjunction with the National Oceanographic and
Atmospheric Administration (NOAA) have analyzed daily air samples collected over local and
regional areas to estimate fugitive natural gas emissions from drilling operations.19
EPA, Inventory (various years), op cit.
Mandatory Reporting of Greenhouse Gases Rule became effective on December 29, 2009, and included industry
reporting requirements for facilities and suppliers in 32 source categories, including the oil and gas industry (U.S.
Environmental Protection Agency, “Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems,”
75 Federal Register 74458, November 30, 2010). See EPA’s GHGRP data on the agency’s website,
U.S. Energy Information Administration, Natural Gas Annual (various years), http://www.eia.gov/naturalgas/annual/.
Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories,
Volume 2, Chapter 4: “Fugitive Emissions,” Prepared by the National Greenhouse Gas Inventories Program, Eggleston
H.S., Buendia L., Miwa K., Ngara T., and Tanabe K. (eds), IGES, Japan, 2006. These guidelines provide methodologies
for high-level national emission factors. See http://www.ipcc.ch/meetings/session25/doc4a4b/vol1.pdf.
American Petroleum Institute, Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas
Industry, 2009, http://www.api.org/environment-health-and-safety/climate-change/whats-new/compendium-ghg-
Texas Commission on Environmental Quality, Barnett Shale Phase Two Special Inventory Data, 2011,
California Greenhouse Gas Emission Inventory, http://www.arb.ca.gov/cc/inventory/inventory.htm.
See, for example, Stefan Schwietzke, “Natural Gas Fugitive Emissions Rates Constrained by Global Atmospheric
Methane and Ethane,” Environmental Scene & Technology, 2014, 48 (14), pp 7714–7722, http://pubs.acs.org/doi/abs/
10.1021/es501204c; Scott Miller, “Anthropogenic Emissions of Methane in the United States,” Proceedings of the
National Academy of Sciences of the United States of America, November 25, 2013, http://www.pnas.org/content/early/
have focused on methane leakage from natural gas transmission and distribution networks in
urban centers of the United States.20
Atmospheric studies use data sets of ambient concentrations
of methane and related hydrocarbons near oil and gas operations, along with the known emissions
profiles for these gases from oil and gas operations, to infer the emissions from the industrial
sectors. (That is, these methodologies capture natural, biogenic, and thermogenic21
emissions from all natural, agricultural, and industrial activities, not just natural gas
infrastructure. Researchers must then parse data estimates for attribution to their appropriate
sources using such analyses as isotopic ratios or prevalence signatures from accompanying non-
methane hydrocarbons.) Due to the technology requirements, these studies are rarer than bottom-
up approaches. As with the bottom-up approaches, different top-down studies have returned
different values for leakage. Further, reported leakage rates have varied considerably across
different oil and gas basins, and different transmission and distribution networks.
In general, top-down methodologies have returned higher emission estimates than bottom-up
approaches. Reasons for this discrepancy may include:
• researchers may be attributing naturally occurring methane emissions to
• researchers may be attributing emissions inaccurately from one man-
made sector to another,
• atmospheric measurements may capture emissions that are not accounted
for in bottom-up inventory approaches (e.g., leakage from abandoned gas wells),
• atmospheric measurements capture all the gross emitters, accidents,
spills, and human errors, whereas bottom-up approaches use emission factors for
component parts averaged over instances of “normal operation,” and
• atmospheric methodologies may be biased to regions where there is
EPA’s annual emission Inventory estimates are summarized in Table 1. The table presents data as
they were initially reported each year by the Inventory, and not as they were revised in successive
2013/11/20/1314392110.abstract; Gabrielle Pétron et al., “Hydrocarbon Emissions Characterization in the Colorado
Front Range: A Pilot Study,” Journal of Geophysical Research, vol. 117 (2012), http://www.agu.org/pubs/crossref/pip/
2011JD016360.shtml; and A. Karion, et al., “Methane Emissions Estimate from Airborne Measurements over a Western
United States Natural Gas Field,” Geophysical Research Letters, 2013, http://onlinelibrary.wiley.com/doi/10.1002/
See, for example, Y.-K. Hsu, et al., “Methane Emissions Inventory Verification in Southern California,” Atmospheric
Environment, 2010, 44(2010): p. 1‐7, http://www.lgrinc.com/publications/Methane%20emissions%20inventory
%20verification%20in%20southern%20California.pdf; J. Peischl, et al., “Quantifying the Sources of Methane Using
Light Alkanes in the Los Angeles Basin, California,” Journal of Geophysical Research, 2013,
http://onlinelibrary.wiley.com/doi/10.1002/jgrd.50413/abstract; N. Phillips, et al., “Mapping Urban Pipeline Leaks:
Methane Leaks Across Boston,” Environmental Pollution, 2013, 173(February): pp. 1‐4, http://biology.duke.edu/
Thermogenic methane is understood to be different from biogenic methane in that it is formed from organic matter
exposed to heat and geologic processes (e.g., fossil fuels). Biogenic methane (e.g., from landfills, animal agriculture,
etc.) is formed from the degradation or fermentation of organic compounds.
years. Table 2 illustrates the evolution of EPA’s methodology as much as it presents changes in
annual emissions from the industry.
Table 1. EPA’s Annual GHG Emissions Estimates for Natural Gas Systems
1. Million Metric Tons of CO2 Equivalent (MMTCO2e) and
Billion Cubic Feet (BCF)
Gas Industry Sectors 1996 2008 2009 2010 2011 2012
Field Production 32.3 14.1 130.3 126.0 53.4 41.8
Processing 14.8 13.0 17.5 17.1 19.6 18.7
Transmission Storage 46.7 39.4 44.4 43.8 43.8 43.5
Distribution 33.6 29.9 29.0 28.5 27.9 25.9
subtotal MMTCO2e 127.4 96.4 221.2 215.4 144.7 129.9
Non Combusted CO2
Field Production - 8.5 10.9 10.9 10.8 13.7
Processing - 21.4 21.0 21.3 21.5 21.5
Transmission Storage - 0.1 0.1 0.1 0.1 0.1
subtotal MMTCO2e 30.0 32.2 32.3 32.3 35.2
Total MMTCO2e 127.4 126.4 253.4 247.7 177.0 165.1
Total Methane Emissions BCF 315.0 238.3 546.8 532.5 357.7 321.1
Natural Gas Marketed BCFg
19,812.0 21,112.0 21,647.9 22,381.9 24,036.4 25,307.9
Methane Leakage Rate
% of marketed production 1.59% 1.13% 2.53% 2.38% 1.49% 1.27%
Source: CRS, compiled from data by the Environmental Protection Agency and the Energy Information
Notes: (As reported initially for each year by EPA’s Inventory of U.S. GHG Emissions and Sinks in million metric
tons equivalent CO2 (MMtCO2)e
. Converted to BCF conversion using the factor of 1000 BCF CH4 = 0.4045
MMtCO2e at 60°F (15.6°C) and either 14.696 psi (1 atm or 101.325 kPa) or 14.73 psi (30 inHg or 101.6 kPa) of
.b EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2002 (April 2004).The inventory uses the
methodology from the Gas Research Institute and U.S. Environmental Protection Agency, Methane Emissions
from the Natural Gas Industry,Volumes 1-15, GRI-94/0257 and EPA 600/R-96-080, June 1996.
.c EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010), EPA 430-R-10-006.
Emission factors and activity data comparable to the 1996 EPA/GRI study.
.d EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009 (April 2011), EPA 430-R-11-005.The first
inventory to incorporate revised emissions factors for gas well cleanups, condensate storage tanks, and
centrifugal compressors, as well as new emissions factors for gas well completions in unconventional
resources with hydraulic fracturing.
.e EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010 (April 2012), EPA 430-R-12-001.
.f EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011 (April 2013).The inventory revisits
calculations for liquid unloading and makes other changes, including the count of the number of active wells
and the methodology for estimating emissions from hydraulic fracturing and refracturing well completions.
.g EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (April 2014).
.h EIA, U.S. Natural Gas Marketed Production, http://www.eia.gov/dnav/ng/hist/n9050us2a.htm.
Table 2 shows annual emission estimates from EPA’s Inventory normalized across the years using
the 2012 methodology. EPA’s Inventory reports a steady decline in both total emissions and
percentage leakage rates despite an increase in marketed natural gas production.
Table 2. EPA’s Annual GHG Emissions Estimates for Natural Gas Systems,
1. (As reported for each year using the 2012 methodology
in EPA’s Inventory of U.S. GHG Emissions and Sinks)
Emissions 1996 2008 2009 2010 2011 2012
Methane EmissionsTotal (MMTCO2e) 160.2 151.6 142.9 134.7 133.2 129.9
Methane Leakage Rate (% of marketed production) 2.00% 1.78% 1.63% 1.49% 1.37% 1.27%
Source: CRS, compiled from data from EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012
(April 2014) and EIA, U.S. Natural Gas Marketed Production, http://www.eia.gov/dnav/ng/hist/n9050us2a.htm.
Oil and Gas Industry Sectors
All sectors of fossil energy production—crude oil, natural gas, and coal-bed methane extraction—
inadvertently release methane primarily from normal operations, maintenance, fugitive leaks, and
While the natural gas industry as a whole emits the greatest volume of methane,
emissions also result during crude oil production because natural gas is closely associated with
crude oil in petroleum reservoirs. These emissions primarily result from field production
operations such as venting of associated gas from oil wells, oil storage tanks, and production-
related equipment such as gas dehydrators, pig traps, and pneumatic devices. In addition to
sharing similar production methods, all the sectors also share similarities in processing, and
The upstream production side applies virtually the same drilling, well stimulation (e.g., hydraulic
fracturing), and oil field technology whether crude oil, natural gas, or coal-bed methane are the
targets. In many cases, the same well that produces crude oil also produces natural gas and
condensate/natural gas liquids. At the midstream side, petroleum refineries upgrade crude oil into
finished products based on boiling point temperatures and gas fractionation plants based on
liquefaction temperatures. Similar pipeline transmission and storage terminals infrastructure
serves all sectors.
• Upstream: Production. In the upstream oil and gas sector, methane may
be encountered and released while drilling through gas-bearing geologic
formations, during drilling mud circulation, during well development (following
well stimulation by hydraulic fracturing) when formation fluids and fracture
fluids flow back to the surface, and from oil, gas, and water separators, and stock
tanks. In addition, these upstream activities may also emit gas condensates and
volatile organic compounds (VOCs) associated with oil and gas. In oil- and gas-
producing regions lacking pipeline take-away capacity, producers must resort to
“flaring” gas and gas condensates and VOCs produced in association with crude
oil. The practice is a necessary safety precaution to eliminate explosive
conditions from developing around the well pad. However, the flaring practice
raises the question about the consequence of combusting methane, condensates,
and VOCs to carbon dioxide.
• Midstream: Processing and Transmission. Gathering lines, which
connect the wellhead to oil field treatment equipment that separates gas, oil, and
water into product streams, represent another opportunity for fugitive methane
EPA, Natural Gas STAR Program, Reduce Your Methane Emissions, http://www.epa.gov/methane/gasstar/
and gas condensate emissions. Leaking vales, transmission lines, pumps, and
stations add to this sector’s emissions.
• Downstream: Distribution. Emissions from leaking distribution
pipelines are most likely to occur from older pipelines made of cast iron mains
sometimes over a century old and unprotected steel, but only marginally from
non-cast iron pipelines. In 2012, there were more than 1.2 million miles of
distribution mains in the United States. Of this, more than 32,000 miles of mains
were cast iron or wrought iron, and more than 61,000 miles were unprotected
The earliest potential for methane emissions may come from gas encountered when drilling
through the shallower gas-bearing formations that overlie a target production zone. Many of the
new unconventional resources (Pennsylvania’s Marcellus shale, North Dakota’s Bakken
formation, and Texas’s Eagle Ford formation, to name a few) underlie older oil and gas fields that
although played-out or abandoned, still show gas and oil. During drilling, “mud” circulation
brings “cuttings” to the surface and may bring up methane encountered in shallower formations.
In some cases, drilling may encounter gas pockets that can cause a well blowout. As a safety
practice, gas encountered during drilling is “flared” (burned) to prevent explosive conditions from
developing around the drill rig platform.
The well completion and development phase that follows drilling present the next opportunity for
fugitive emissions. Well completion involves perforating the well casing to create a pathway for
formation fluids (oil, gas, and water) to enter the wellbore. Well stimulation, typically by
hydraulic fracturing (“fracking”), improves the flow of formation fluids. The injection of fluid
(water and organic/chemical additives) and proppants (typically sand) under pressure opens and
permanent fractures in the formation. During the well development phase that follows
stimulation, the wellbore “unloads” frac fluids that flowback to the surface under pressure of
natural gas released from the formation. The “flowback” may include entrained natural gas.
Development continues long enough to clear the well of fluid and debris. The well may be
temporarily shut in until gathering lines can be laid to the wellhead to collect the gas. The well
development presents the highest potential for unchecked methane release, but the degree of
release is a subject of debate.
In a 2010 study on methane emitted during “high volume” fracturing of shale formations, Cornell
University authors (Howarth et al.) concluded that from 3.6% to 7.9% of the methane from shale-
gas production escapes to the atmosphere in venting and leaks over the lifetime of a well.
Additionally, from 0.6% to 3.2% of a gas well’s lifetime production is emitted during the flow-
back period that follows well completion and stimulation.23
Furthermore, the study concluded that
the emissions are at least 30% more than and perhaps more than twice as great as those from
However, other Cornell authors (Cathles et al.) argue that the 2010 Howarth study significantly
overestimates the fugitive emissions associated with producing unconventional gas.24
specifically maintain that the 7.9% high-end estimate of methane leakage (from well drilling to
Robert W. Howarth, Renee Santoro, and Anthony Ingraffea, “Methane and the Greenhouse-Gas Footprint of Natural
Gas from Shale Formations,” April 12, 2011.
Lawrence M Cathles, Larry Brown, and Milton Tamm, et al., “A Commentary on ‘The Greenhouse-Gas Footprint of
Natural Gas in Shale Formations,” by R.W. Howarth, R. Santoro, and Anthony Ingaffea,” Climate Change, January 2,
gas delivery) exceeds a reasonable estimate by about a factor of three and lacks documentation
that shale wells vent significantly more gas than conventional wells. Furthermore, they argue that
Howarth et al. “assume that initial production statistics can be extrapolated back to the gas
venting rates during the earlier periods of well completion and drill out. This is incompatible with
the physics of shale gas production, the safety of drilling operations, and the fate of the gas that is
actually indicated in their references.”
An accurate determination of methane emissions would require metering to measure the actual
gas flow during well development. A 2013 University of Texas (Allen) study of 190 natural gas
production sites did measure methane emissions at the well pad during completion operations of
hydraulically fractured wells. The Allen study found that the majority of hydraulically fractured
well completions that were sampled had equipment in place that reduced methane emissions by
99% by capturing the methane.25
Because of this equipment, the University of Texas found that
methane emissions from well completions were 97% lower than EPA’s 2011 national oil and gas
methane-emission estimates. However, Allen also found that emissions from certain types of
pneumatic devices were 30% to several times higher than EPA estimates, but that total methane
emissions measured from all sources studied were comparable to recent EPA estimates.
For both safety and economic reasons high methane emissions are unacceptable conditions. The
catastrophic consequence of the explosive conditions created by methane is illustrated by the
tragic 2010 BP Macondo well blowout. According to Cathles et al., the economic loss of venting
7.9% of a well’s lifetime production may reach $1 million compared to the $8 million or more
cost to drill and hydraulically fracture a well, which would certainly draw the attention of owners
and investors in the well as purposely flaring gas has done in North Dakota.
Poorly sealed, abandoned oil and gas wells also provide a potential pathway for methane to
migrate to the surface or shallow subsurface and escape to the atmosphere, as Kang (et. al)
As many as 3 million abandoned wells may exist throughout the United States,
some dating back to the late 19th
century. States did not begin adopting protocols for abandoning
and plugging wells until much later. Methane emissions from these wells are assumed (Kang et
al.) to be the second largest potential contribution to total U.S. methane emissions (above EPA
emission estimates) but are not included in any emissions inventory. Improperly constructed or
abandoned water wells (some constructed without casing) could also contribute emissions.
Onshore Oil and Natural Gas Production-Related Emissions
EPA estimates methane emissions from the oil and natural gas industry in its annual Inventory of
U.S. Greenhouse Gas Emissions and Sinks.27
EPA reports that onshore natural gas and petroleum
production emitted over 149 billion cubic feet of methane in 2012, worth over $37 million
(assuming a natural gas price of $4 per thousand cubic feet (MCF) at the wellhead). The onshore
segment reportedly represents 35% of the total methane emissions from the oil and natural gas
industry. The chart in Figure 1 shows the distribution of the emission categories in the onshore
David Allen, Methane Emissions in Natural Gas Supply Chain: Production, University of Texas at Austin—Cockrell
School of Engineering, 2013, http://engr.utexas.edu/news/releases/methanestudy.
M. Kang, C. M. Kanno, and M. C. Reid, et al., “Direct Measurements of Methane Emissions form Abandoned Oil
and Gas Wells in Pennsylvania,” Proceedings of the National Academy of Sciences, November 2014,
EPA, National Greenhouse Gas Emissions Data, http://www.epa.gov/climatechange/ghgemissions/
EPA, Emission Reduction Options for the Onshore Natural Gas and Petroleum Production Segment,
Figure 1. Onshore Oil and Natural Gas Production-Related Emissions in 2012
149.2 Billion Cubic Feet
Source: EPA, Emission Reduction Options for the Onshore Natural Gas and Petroleum Production Segment,
Notes: EPA notes that these emission estimates have an uncertainty associated with them. Not all facilities will
have the same distribution of emissions between sources. In addition, some emission sources are only present in
a few facilities and may not be represented in the pie chart.“Other” Emission Sources: uncombusted methane,
equipment fugitives, pipeline leaks, chemical injection pumps, well fugitives, coal bed methane, stripper wells,
blowdowns, process upsets, well drilling, non-hydraulically fractured well workovers, compressor starts, tank
fugitives, and non-hydraulically fractured well completions.
Offshore Oil and Natural Gas Production-Related Emissions
EPA reports that offshore oil and natural gas production emitted 46.7 BCF of methane in 2012,
worth over $11.7 million (assuming a natural gas price of $4 per MCF at the wellhead). The
offshore segment represents roughly 11% of the total methane emissions from the oil and natural
gas industry. Figure 2 shows the distribution of the emission categories in this segment.
Figure 2. Offshore Oil and Natural Gas Production-Related Emissions in 2012
46.7 Billion Cubic Feet
Source: EIA, Emission Reduction Options for the Offshore Natural Gas and Petroleum Production Segment,
Notes: “Flashing Losses”: tanks, heater treaters, and separators.“Other” Emission Sources: uncombusted
methane, pressure/level controllers, mud degassing, well drilling, and amine units.
Natural Gas Venting and Flaring
In its 2010 report29
on natural gas flaring, the U.S. Government Accountability Office (GAO)
concluded that estimates of vented and flared natural gas for federal leases vary considerably.
GAO found that data collected by the U.S. Department of the Interior to track venting and flaring
on federal leases likely underestimate venting and flaring because they do not account for all
sources of lost gas. For onshore federal leases, operators reported to Interior that about 0.13% of
produced gas was vented or flared. Estimates from EPA and the Western Regional Air Partnership
(WRAP) showed volumes as much as 30 times higher. Similarly, for offshore federal leases,
operators reported that 0.5% of the natural gas produced was vented and flared, while data from
an Interior offshore air quality study showed that volume to be about 1.4%, and estimates from
EPA showed it to be about 2.3%. GAO notes that in FY2009, companies that leased these lands
paid about $6 billion in royalties to the federal government on the sale of oil and gas produced
offshore in federal waters, and about $3 billion for production on federal lands, making revenues
from federal oil and gas one of the largest nontax sources of federal government funds. The 126
Bcf of natural gas lost to venting and flaring from onshore federal leases in 2008 would have
equaled approximately $58 million in federal royalty payments. EPA estimates that 40 % of the
U.S. Government Accountability Office, Federal Oil and Gas Leases: Opportunities Exist to Capture Vented and
Flared Natural Gas, Which Would Increase Royalty Payments and Reduce Greenhouse Gases, GAO-11-34: October
lost gas could have been economically captured and sold, increasing federal royalty payments by
as much as $23 million (representing about 1.8% of annual federal royalty payments on natural
GAO found that the volumes operators reported to Interior do not fully account for some ongoing
losses such as the emissions from gas dehydration equipment or from thousands of valves—key
sources in the EPA, WRAP, and Interior offshore air quality studies. Venting and flaring
ultimately depend on the pace of drilling and production, and the market demand for natural gas,
natural gas liquids (NGLs), and condensates. The Energy Information Administration reports that
natural gas venting had generally declined from its peak in the late 1940s, but has shown an
upward trend over the last decade Figure 3).
Figure 3. Natural Gas Withdrawals vs.Vented and Flared Gas
Billion Cubic Feet
Vented and Flared
Source: EIA, U.S. Natural Gas Gross Withdrawals and Production http://www.eia.gov/dnav/ng/
ng_prod_sum_dcu_nus_a.htm; Natural GasVented and Flared http://www.eia.gov/dnav/ng/
Note: On the whole, gross withdrawals are 100 times vented and flared.
The upward trend appears to correlate with both the increase in crude oil production (Figure 4)
and natural gas withdrawal and production. However, reports on North Dakota’s Bakken
formation would suggest that much of the associated gas produced with crude oil is flared for
lack of pipeline infrastructure to transport it to eastern markets. It is important to note that gross
withdrawals in Figure 4 are on the order of 100 times greater than vented and flared. The sharp
drop in vented and flared gas that occurred between 1994 and 1998 appears related to the pace of
drilling activity in the Gulf of Mexico.
Figure 4. U.S. Crude Oil Production
Source: U.S. EIA U.S. Field Production of Crude Oil, http://www.eia.gov/dnav/pet/
Coal Production-Related Emissions
Coalmine methane (CMM) is released from coal and surrounding rock strata because of mining
activity. In some instances, methane that continues to be released from the coal-bearing strata,
once a mine is closed and sealed, may also be referred to as coalmine methane because the
liberated methane is associated with past coal mining activity. This methane is also known as
“abandoned mine methane” (AMM).
Coalbed methane (CBM) extraction (produced by using advance drilling and hydraulic fracturing
technology) had been on the rise until 2008, when it peaked at nearly 2 trillion cubic feet.30
the rise in natural gas production from unconventional shale resources, starting in 2008, coalbed
methane production has been declining; no doubt because of the rise in shale gas. Production in
Colorado, New Mexico, and Wyoming has been the most prolific, with lesser production in
Alabama, Utah, Virginia, and West Virginia. Colorado and New Mexico production is centered in
the San Juan Basin around the Four Corners region (the common state boundaries for Colorado,
New Mexico, Arizona, and Utah).
Energy Information Administration, Coalbed Methane Production, http://www.eia.gov/dnav/ng/
Figure 5. Coalbed Methane Fields, Lower 48 States
Source: Energy Information Administration based on data from USGS and various published studies, updated
April 8, 2009.
Based on recent findings of a large and consistent regional atmospheric methane signal from 2003
onward, researchers (E. A. Kort et. al 2014) conclude that long-established fossil fuel extraction,
at least in the Four Corners region (as shown in Figure 6) likely has larger methane emissions,
and subsequent greenhouse gas footprint, than accounted for in current EPA inventories.31
research cites other studies (Katzenstein et al., 2003; Miller et al., 2013) that have primarily
focused on oil and gas activities in the south central United States but could not resolve localized
features such as Four Corners. When compared, Figure 6 does not correlate well with Figure 5.
The poor comparison raises questions about the emissions contributed from all CBM projects.
E. A. Kort, C. Frankenberg, and K. R. Costigan, et al., “Four Corners: The Largest US Methane Anomaly Viewed
from Space,” AGU Publications—Geophysical Research Letters, vol. 10.1002, no. 2014GL061503 (October 2014).
Figure 6. Methane Anomalies and Emissions over the Conterminous United States
Satellite Methane Signal Averages 2003-2009
Source: American Geophysical Union, vol. 10.1002, no. 2014GL061503 (October 2014).
Gas Processing-Related Emissions
The potential for fugitive emissions from gas and oil processing starts when the raw product
streams leave the wellhead. Leaking wellhead valves; gathering lines that connect the wellhead to
oil, gas, and water separators; heater-treater equipment; and stock tanks offer paths for both
methane and condensate vapors to escape.32
Typically, the product stream from natural gas wells moves to a drying plant that upgrades the gas
to industry standards. The system that gathers, processes, and transmits the natural gas to market
consists of a network of pipelines, compressor stations, valves, meters, and storage terminals, all
having the potential for leaks. Leaking compressor seals are reported as the largest emission
sources from stationary equipment. Wet gas (a mix of methane and gas condensates) is processed
in a fractionation plant that separates each product stream (ethane, propane, butane) by chilling it
to its liquefaction temperature and storing it in pressurized tanks.
The crude oil stream that flows from the wellhead may include associated natural gas and gas
condensate. Fractionation plants use refrigeration to separate condensates into various product
streams (ethane, butane, propane) based on their specific liquefaction temperatures.33
separated from crude oil however, falls under different regulations than the lease condensate and
natural gasoline separated from natural gas, as discussed further below.
Almost 30% of methane emissions from onshore oil and natural gas facilities are from leaks past
static seals on valves, connectors, regulators, or other components, as reported by the consulting
company Carbon Limits.34
See CRS Report R43682, Small Refineries and Oil Field Processors: Opportunities and Challenges, coordinated by
Bentek Energy North American Natural Gasoline and Condensate Outlook. December 2013.
Carbon Limits, Quantifying Cost-Effectiveness of Systematic Leak Detection and Repair Programs Using Infrared
Cameras, CL Report CL-13-27, March 2014, http://catf.us/resources/publications/files/Carbon_Limits_LDAR.pdf.
As of 2009, 493 natural gas processing plants operated in the United States, with a combined
processing capacity of 77.5 BCF per day. The vast majority of these plants were located in
producing areas of the country, including Alaska, the Rocky Mountain region, and the states
along the Gulf of Mexico. (See the to this report for a listing of plants.)
EPA reports that onshore natural gas processing emitted 48.3 BCF in 2012, worth over $12
million (assuming a natural gas price of $4 per MCF at the wellhead). Processing contributes
12% to the total methane emissions from the oil and natural gas industry. The chart in Figure 7
shows the distribution of the emission categories in this segment. As shown, compressor packing
rods and compressor wet-seals are responsible for 60% of emissions from gas processing
equipment. In the recent Carbon Limits report, leaking compressor rod packing was responsible
for the highest emissions from both gas plants and compressor stations. One estimate, placing a
packing replacement cost at $3,000 per compressor rod (parts/labor) and assuming gas at $7 per
MCF (in 2009), would see a replacement payback in less than six months.35
At today’s lower gas
price, the payback may be a longer term.
Processing plants are typically clustered close to major producing areas, with a high number of
plants close to the Federal Gulf of Mexico offshore and the Rocky Mountain production areas. In
terms of both the number of plants and processing capacity, about half of these plants are
concentrated in the states along the Gulf of Mexico. Gulf states have been some of the most
prolific natural gas-producing areas.
International Workshop on Methane Emissions Reduction Technologies in the Oil and Gas Industry, Reducing
Emissions from Reciprocating and Centrifugal Compressors, September 14, 2009, https://www.globalmethane.org/
Figure 7. Onshore Gas Processing in 2012
48.3 Billion Cubic Feet
1.6 BCF (3%)
Source: EPA, Emission Reduction Options for the Onshore Natural Gas Segment, http://www.epa.gov/methane/
Notes:“Other” Emission Sources: uncombusted methane, centrifugal compressors with dry seals, dehydrator
vents, acid gas removal vents, and pneumatic devices.
Transmission and Distribution Pipelines
A 300,000-mile network of large-diameter, high-pressure pipelines transmits natural gas from
producers to local distribution companies (LDC).36
An even larger 1.2 million-mile network of
smaller-diameter, low-pressure mains distributes the gas to service areas. Another 880,000 miles
of customer service lines deliver gas from street connections to the customer meters. Older gas
distribution pipelines constructed from cast iron or uncoated steel (some installed early in the last
century) are increasingly susceptible to corrosion or other material failure and thus prone to leaks.
Over 112,000 miles of U.S. distribution mains in service at the end of 2011 were constructed
using materials and techniques that are the most susceptible to corrosion and leaks, and require
Emissions from leaking distribution pipelines are most likely to occur from older pipelines made
of cast iron and unprotected steel.37
They may be caused by the settlement of earthen backfill
supporting the pipe, failure of pipe joints, corrosion of unprotected steel pipelines, and from the
Yardley Associates, Gas Distribution Infrastructure: Pipeline Replacement and Upgrades—Cost Recovery Issues and
Approaches, American Gas Foundation, July 2012.
U.S. EPA Office of Inspector General, Improvements Needed in EPA Efforts to Address Methane Emissions from
Natural Gas Distribution Pipelines, June 25, 2014.
natural process of “graphitization” of iron pipelines.38
Leaks are much less likely to occur from
plastic and protected steel pipelines. A 2012 study to map methane emissions from urban
pipelines across Boston found leaks primarily from cast iron mains that were sometimes over a
century old, but only marginally from non-cast–iron-mapping.39
Downstream, older gas
distribution pipelines constructed from cast iron or uncoated steel (some installed early in the last
century) are increasingly susceptible to corrosion or other material failure and thus prone to leaks.
Figure 8. Emissions from Natural Gas Distribution System in 2012
66.2 Billion Cubic Feet
Source: Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012,Annex 3,Table A-140,
Notes: EPA cautions that these emission estimates have an uncertainty associated with them. Not all facilities
will have the same distribution of emissions between sources. In addition, some emission sources are only
present in a few facilities and may not be represented in the pie chart.“Other” emission sources: upsets/mishaps,
pipeline blowdown, and PRV releases.
Emission losses from the natural gas distribution system amount to 66.2 BCF,40
worth nearly $17
million per year assuming a natural gas price of $4 per MCF at the wellhead. EPA reports that the
losses represent 16% of the total methane emissions from the oil and natural gas industry. Figure
8 shows the distribution of the emission categories in this segment.
Another indicator of pipeline emission trends is evident in PHMSA’s reporting on pipeline
As Figure 9 shows, pipeline incidents have generally declined in the last two decades,
Graphitization is the process of iron degrading over time to softer elements. This process makes iron pipelines more
prone to cracking.
Nathan G. Phillips, Robert Ackley, and Eric R. Crosson, et al., “Mapping Urban Pipeline Leaks: Methane Leaks
Across Boston,” Environmental Pollution, vol. 173 (2013), no. 1-4 (July 25, 2012).
EPA, Natural Gas STAR Program, http://www.epa.gov/methane/gasstar/methaneemissions/distribution.html.
PHMSA, Pipeline Incident 20 Year Trends, http://www.phmsa.dot.gov/pipeline/library/datastatistics/
but the most problematic system remains gas distribution, which has produced 279 fatalities and
1,059 injuries. Over the last ten years, PHMSA estimates the economic loss from transmission
pipeline incidents at $1.43 billion, and distribution pipeline incidents at $725 million.42
Figure 9. PHMSA Pipeline Incidents
Gas Gathering,Transmission, and Distribution
Source: PHMSA, Pipeline Incident 20Year Trends, Serious Incident 20Year Trend, http://www.phmsa.dot.gov/
Notes: The Offshore Gathering System is not included, but has only produced one incident (1995) over the
reporting period.Also not included, the 2010 BP MacondoWell blowout that occurred when high gas was
PHMSA established new regulations in 2011 that give local distribution companies (LDCs) a
risk-based alternative to pressure testing the integrity of older pipelines, which had been the
standard (49 C.F.R. 195.303). The pipeline operators assign a high-, medium-, or low-risk
classification to each pipeline segment. High-risk pipelines indicators include location (non-rural
areas), product (highly volatile), volume (≥18" diameter), failure (>3 spills in the last 10 years).
While the pipeline operators’ primary concerns in replacing these leak-prone pipelines are
avoiding catastrophic consequences and improving system and service reliability, they also
mitigate major emission sources. The LDCs’ schedule and progress toward replacing pipelines
depends on their ability to recover the replacement costs through their ratepayers, which is
subject to state regulatory authorities.
All Sector Emissions Summary
In 2012, the United States withdrew 29,542.3 BCF of natural gas from a combination of gas
wells, oil wells, shale gas wells, and coalbed wells.43
Of that, producers vented or flared 260.4
BCF. Methane emissions from all sources total 310.4 BCF (see Table 3) or roughly 1% of
production. The emissions represent a loss of $1.25 billion, valuing natural gas at $4 per MCF.
PHMSA, Significant Incident Consequences, http://www.phmsa.dot.gov/pipeline/library/datastatistics/
U.S. Energy Information Administration, Natural Gas Gross Withdrawals and Production, http://www.eia.gov/dnav/
Adding producer-vented or -flared gas raises the loss another $1 billion, bringing the total loss to
over $2.25 billion. Counting coalbed methane production-related emissions could increase the
Table 3. Methane Emissions from Oil and Gas Sectors
Emission Sources BCF %
Onshore Oil and Natural Gas Production 149.2 48
Offshore Oil and Natural Gas Production 46.7 15
Onshore Gas Processing 48.3 16
Natural Gas Distribution System 66.2 21
Subtotal 310.4 100
Vented or Flared 260.4
Source: U.S. EPA.
Notes: Compiled from Figures 1, 2 ,7, and 8.
In a series of five white papers, EPA focuses on potentially significant sources of methane and
volatile organic compounds (VOCs) in the oil and gas sector, covering emissions and mitigation
techniques for both pollutants.44
The papers cover
• well completions,
• liquids unloading phase during well development,
• pneumatic devices, and
• natural gas processing and pipeline transmission.
The mitigation techniques currently available, according to the papers are summarized below.
Reduced Emission Completions45
Reduced emission completions (“green completions”) would use equipment specially designed to
capture and treat gas at the well site to divert it as a separate product stream for sale. The
completion phase of drilling consists of penetrating the well casing to create a pathway for
formation fluids and gas to enter it. The green completion equipment would prevent some natural
gas from venting and result in additional economic benefit from the sale of captured gas and, if
present, gas condensate. Assuming that a pipeline gathering system is already in place, additional
well pad equipment would be required, such as additional stock tanks, gas-liquid-sand separator
traps, and a gas dehydrator. However, gathering line construction typically waits until well
EPA, Hydraulically Fracture Oil Well Completions and Associated Gas during Ongoing Production, April 2014,
completion and development have concluded (as there always a risk that the well could prove
unproductive). Alternatively, the driller can flare (combust) any gas produced during the
completion phase, as is the standard oil field practice, or vent it directly to the atmosphere.
Completion combustion is a high-temperature oxidation process used to burn combustible
components, mostly hydrocarbons, found in gas streams. These devices can be as simple as a pipe
with a basic ignition mechanism and discharge over a pit near the wellhead. Any captured gas
could also be re-injected into the formation to maintain reservoir pressure, but the associated cost
could far outweigh the economic value of the gas
Liquids Unloading Processes46
Newly completed oil and gas wells typically have sufficient reservoir pressure to lift reservoir
fluids (oil, gas, water) to the surface. As reservoir pressure declines, fluid that accumulates in the
well can shut in the production. The accumulated liquid must be unloaded to return the well to
production. Emissions to the atmosphere during liquids unloading events are a potentially
significant source of VOC and methane emissions. Shutting in the well to allow the bottom-hole
pressure to increase, and then venting the gases in the? well to the atmosphere (well blowdown)
offers the most straightforward approach to unloading liquids. Other technologies include
swabbing the well to remove accumulated fluids, installing velocity tubing, a plunger lift system,
or an artificial lift system. Oil wells in decline have artificial lifts systems that pump the fluids to
the surface (the familiar oil well pump jack, for example). An artificial lift system, similarly, can
unload accumulated liquids. The oil and gas industry has developed several technologies that
effectively remove liquids from wells and can result in fewer emissions than blowdowns. Plunger
lifts are the most common of those technologies.
Oil and Natural Gas Sector Compressors47
The oil and natural gas sector uses reciprocating and centrifugal compressors during oil and gas
production (gathering and boosting), processing, transmission, and storage. Emissions occur from
compressor seals (wet seal compressors) or packing surrounding the mechanical compression
components (reciprocating compressors) of the compressor. These emissions typically increase
over time as the compressor components begin to degrade. Mitigating emissions from
reciprocating compressors involves limiting the leaking of natural gas past the piston rod packing,
including replacement of the compressor rod packing, replacement of the piston rod, and the
refitting or realignment of the piston rod. Mitigating emissions from centrifugal compressors
involves limiting natural gas leaking across the rotating shaft by using a mechanical dry seal, or
capturing the gas and routing it to a useful process or to a combustion device.
Oil and Gas Sector Leaks48
In its 2013 Annual Energy Outlook, the Energy Information Administration (EIA) projected
natural gas development to increase by 44% from 2011 through 2040 and crude oil and natural
gas liquids to increase by approximately 25% through 2019.49
The projected growth is primarily
led by the increased development of shale gas, tight gas, and coalbed methane resources using
new production technology and techniques such as horizontal drilling and hydraulic fracturing.
EPA, Liquids Unloading Processes, April 2014, http://www.epa.gov/airquality/oilandgas/whitepapers.html.
EPA, Oil and Natural Gas Sector Compressors, April 2014, http://www.epa.gov/airquality/oilandgas/
EPA, Oil and Gas Sector Leaks, http://www.epa.gov/airquality/oilandgas/whitepapers.html.
U.S. Energy Information Administration, Annual Energy Outlook 2013. http://www.eia.gov/forecasts/aeo/pdf/
EPA expects that along with the increase in number of wells, the amount of related equipment that
has the potential to leak will increase as well. Emission leaks are likely to occur through many
types of pipe connection points (e.g., flanges, seals, and threaded fittings) or through moving
parts of valves, pumps, compressors, and other types of process equipment. There are a number
of technologies available to identify leaks and a number of approaches to repairing those leaks.
Portable monitoring instruments that can detect hydrocarbon leaks from individual pieces of
equipment are intended to locate and classify leaks based on the leak definition of the equipment
as specified in a specific regulation, but are not useful as a direct measure of mass emission rate
from individual sources. After a leak is detected, the owner or operator of the facility must decide
whether to fix the leak, unless they are required to fix the leak due to regulatory or permitting
Oil and Natural Gas Sector Pneumatic Devices50
Natural gas-driven pneumatic controllers and natural gas-driven pneumatic pumps are widespread
in the oil and natural gas industry and emit natural gas, which contains methane and VOCs. In
some applications, pneumatic controllers and pumps used in this industry may be driven by gases
other than natural gas and, therefore, do not emit methane or VOCs. Natural gas-driven
pneumatic controllers are powered by pressurized natural gas. Non-natural gas-driven pneumatic
controllers are actuated using other sources of power than pressurized natural gas; examples
include solar, electric, and instrument air. Several techniques to reduce emissions from pneumatic
controllers have been developed that include replacing high-bleed controllers with low-bleed or
zero-bleed models, driving controllers with instrument air rather than natural gas, using non-gas-
driven controllers, and enhanced maintenance. Manufacturers of pneumatic controllers indicate
that emissions in the field can be higher than the reported gas consumption due to operating
conditions, age, and wear of the device. Maintenance of pneumatics can correct many of these
problems and can be an effective method for reducing emissions.
Federal and State Regulatory Responses
Federal and state regulators have the task of ensuring that pipeline and hazardous materials
operators have risk management programs in place, that those programs are designed in
conformance with state and federal laws and regulations, that the programs are effective in
enhancing public safety, the operator’s and employees’ safety, environmental safety, and that the
safety of the entire system and operation continues to improve.
In July 2014, EPA proposed updates and clarifications to its 2012 New Source Performance
The proposed updates and clarifications to regulations would reduce harmful
air pollution from the oil and natural gas industry, but would not change the emission reductions
in the rules, which include the first federal air standards for natural gas wells that are
hydraulically fractured, along with requirements for storage tanks and other equipment. The
proposed updates would:
• Provide additional detail on requirements for handling liquids during
well completion operations;
• Clarify requirements for storage tanks;
• Define low-pressure wells;
EPA, Oil and Natural Gas Sector Pneumatic Devices, http://www.epa.gov/airquality/oilandgas/whitepapers.html.
U.S. Environmental Protection Agency, “Oil and Natural Gas Sector: Reconsideration of Additional Provisions of
New Source Performance Standards; Proposed Rule,” Vol. 79 No. 137 Federal Register 41752-41768, July 17, 2014.
• Clarify certain requirements for leak detection at natural gas processing
• Update requirements for reciprocating compressors.
On January 14, 2015, the Obama Administration announced additional steps that EPA would take
to address emissions from the oil and gas sector, including (1) a proposal to build on the 2012
NSPS “to set standards for methane and volatile organic compounds (VOC)) emissions from new
and modified oil and gas production sources, and natural gas processing and transmission
(scheduled for release in the summer of 2015), (2) extending VOC reduction
requirements to existing oil and gas sources in ozone nonattainment areas and states in the Ozone
Transport Region, and (3) expanding voluntary efforts under the Natural Gas STAR
Additionally, the U.S. Bureau of Land Management (BLM) has issued rulemakings
that address methane emissions on federal lands under the Mineral Leasing Act (MLA), but do
not require practices to minimize methane emissions.54
The MLA authorizes the Secretary of the
Interior to lease onshore lands owned by the United States that contain fossil fuel deposits, with
the federal government retaining title to the lands. The framework of the MLA provides BLM and
the federal government with flexibility to use federal lands to help satisfy the nation’s energy
needs, while generating revenue for the federal government and protecting environmentally
sensitive areas. Existing BLM rulemakings affecting methane emissions include DOI, “Notice to
Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases (NTL-4A): Royalty or
Compensation for Oil and Gas Loss.” 55
This 1980 notice to operators of oil and gas leases
outlines appropriate payment terms for losses of natural resources under the authority of the
MLA. The notice lists circumstances wherein operators are authorized to vent or flare methane
without incurring royalty obligations. BLM has announced intent to update these standards, with
proposed rulemaking scheduled for release in April 2015.
State Public Utility Commissions (PUCs) have the responsibility to ensure that their states’
natural gas pipeline systems are designed, constructed, operated, and maintained according to
safety standards set by each state’s PUC and the federal government. PUCs conduct operation and
maintenance compliance inspections, accident investigations, and reviews of utilities’ reports and
records. They also conduct construction inspections, special studies, and take action in response
to complaints and inquiries from the public on issues regarding gas pipeline safety. A more
detailed discussion of state PUC programs that minimize methane emissions, however, exceeds
the scope of this report.
EOP, Fact Sheet, op. cit. For a discussion of the source categories under consideration, see U.S. Environmental
Protection Agency, “White Papers on Methane and VOC Emissions,” April 15, 2014, http://www.epa.gov/airquality/
Executive Office of the President, “Fact SheetHEET: Administration Takes Steps Forward on Climate Action Plan by
Announcing Actions to Cut Methane Emissions,” January 14, 2015.
Mineral Leasing Act, as amended and supplemented, 30 U.S.C. 181, et seq. For a summary of the MLA and BLM’s
leasing activities, see BLM’s website and CRS Report R40806, Energy Projects on Federal Lands: Leasing and
Authorization, by Adam Vann.
U.S. Department of the Interior, “Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases
(NTL-4A): Royalty or Compensation for Oil and Gas Loss,” January 1, 1980.
Appendix. Natural Gas Processing Plants
Under the authority of the Clean Air Act (CAA), the U.S. Environmental Protection Agency
promulgated a set of air standards for the oil and gas sector on August 16, 2012. The 2012 New
Source Performance Standards (NSPS) for the “Crude Oil and Natural Gas Production” and the
“Natural Gas Transmission and Storage” source categories regulate volatile organic compounds
(VOCs) emissions from gas wells, centrifugal compressors, reciprocating compressors,
pneumatic controllers, storage vessels, and leaking components at onshore natural gas processing
plants, as well as sulfur dioxide (SO2) emissions from onshore natural gas processing plants. Prior
to the 2012 standards, processing plants were the only methane emission sources regulated at the
federal level. While not targeted by the 2012 rules, methane reductions from new and modified
well completions and other activities were estimated to yield an additional environmental co-
benefit about 1.0 million to 1.7 million short tons annually (equivalent to 19 to 33 million metric
tons of CO2 equivalent (CO2e).
As of 2009, 493 natural gas processing plants operated in the United States, with a combined
processing capacity of 77.5 BCF per day. The vast majority of these plants were located in
producing areas of the country, including Alaska, the Rocky Mountain region, and the states
along the Gulf of Mexico. In terms of both capacity and number of plants, Texas and Louisiana
accounted for nearly half of all U.S. capacity and plants. Alaska, which was not included in
previous Energy Information Administration (EIA) analyses, accounted for the third-highest
processing capacity of 9.4 BCF per day. Although Texas and Louisiana continue to account for
the largest portion of U.S. processing capacity, other states have increased their capacity and thus
their rankings since 2004 as new market factors influence plant expansions. These include the
development of new production areas as well as technology improvements in natural gas
processing, leading to construction of more efficient plants compared to those constructed in
U.S. natural gas processing capacity showed a net increase of about 12% between 2004 and 2009
(not including Alaska), with the largest increase occurring in Texas, where processing capacity
rose by more than 4 BCF per day. In fact, increases in Texas’s processing capacity accounted for
57% of the total lower 48 states’ capacity increase of 7.1 BCF per day between 2004 and 2009.
However, seven states saw their total capacities fall since 2004, including Kansas, New Mexico,
California, and Illinois.
Processing capacity expansion coincided with pipeline capacity additions as well as production
expansions. While the majority of states recorded increases in processing capacity, a few states
stand out in particular. In addition to the substantial expansions in Texas, new capacity additions
occurred in the Rocky Mountain states, especially in Colorado where natural gas processing
capacity more than doubled between 2004 and 2009. Significant increases also occurred in
Arkansas, Utah, and Wyoming.
More than half of all natural gas processing plants operating in the United States in 2009 are
considered “small,” with processing capacity of up to 50 million cubic feet (MMCF) per day.
Although these plants numbered 270, their combined processing capacity totaled 4.5 BCF per day
or about 6% of total U.S. capacity. Larger plants (those over 1,200 MMCF per day) accounted for
about 31% of total processing capacity and totaled 23.6 BCF per day. The largest operating
plants are located in Alaska, Louisiana, and Kansas.
Table A-1. Natural Gas Processing Plant Capacity by State
1. 2009 (latest information available)
Texas 19,740 25.5 163 33.1 121
Louisiana 18,535 23.9 60 12.2 309
Alaska 9,449 12.2 4 0.8 2,362
Wyoming 7,273 9.4 37 7.5 197
Colorado 3,791 4.9 44 8.9 86
Oklahoma 3,740 4.8 58 11.8 64
New Mexico 3,022 3.9 24 4.9 126
Mississippi 2,273 2.9 4 0.8 568
Illinois 2,102 2.7 2 0.4 1,051
Kansas 1,250 1.6 6 1.2 208
Alabama 1,248 1.6 12 2.4 104
Utah 1,185 1.5 12 2.4 99
Michigan 977 1.3 10 2.0 98
California 876 1.1 20 4.1 44
Arkansas 710 0.9 4 0.8 178
WestVirginia 463 0.6 7 1.4 66
Kentucky 288 0.4 5 1.0 58
North Dakota 196 0.3 7 1.4 28
Montana 165 0.2 5 1.0 33
Florida 90 0.1 1 0.2 90
Pennsylvania 52 0.1 7 1.4 7
Tennessee 25 0.0 1 0.2 25
U.S.Total 77,449 100.0 493 100 157
Source: 2009 data: Energy Information Administration, Office of Oil and Gas, Form EIA-757, Natural Gas
Processing Survey. 2004 data: Energy Information Administration, Office of Oil and Gas, GasTran Information
System, Natural Gas Processing Plant Database, compiled from data collected on Form EIA-64A, Form EIA-816,
PentaSul Inc’s LPG Almanac, and various other sources.
Notes: EIA collected processing plant data on Form EIA-757 from 22 states, which are presented in the above
table for 2009.The 2004 data, however, also included Ohio, but not Alaska, which is included in the 2009 data.
As total capacity rose in the country, the number of processing plants fell in 15 states compared
with 2004. At least 34 plants were idled and/or dismantled over the last few years, as new plants
were added and old, less efficient plants were shut down. In Arkansas, where the processing
capacity increased tenfold, the number of plants operating decreased by three.