Air Quality Issues in Natural Gas Systems
Congressional research reportApr 16, 2013
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Air Quality Issues in Natural Gas Systems
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R42833
CRS Report for Congress
Prepared for Members and Committees of Congress
Air Quality Issues in Natural Gas Systems
Summary
Natural Gas Systems and Air Pollution
Congressional interest in U.S. energy policy has focused in part on ways through which the
United States could secure more economical and reliable fossil fuel resources both domestically
and internationally. Recent expansion in natural gas production, primarily as a result of new or
improved technologies (e.g., hydraulic fracturing, directional drilling) used on unconventional
resources (e.g., shale, tight sands, and coal-bed methane), has made natural gas an increasingly
significant component in the U.S. energy supply. This expansion, however, has prompted renewed
questions about the potential impacts of natural gas systems on human health and the
environment, including impacts on air quality. Unlike the debate over groundwater contamination
or induced seismicity—where questions exist as to whether or not production activities contribute
significantly to these impacts—there is little question that natural gas systems emit air pollutants.
The concerns, instead, are the following:
•
Which pollutants?
•
How much of each pollutant?
•
From which sources?
•
What are the impacts of the emissions?
•
How much is the cost of abatement?
•
What are the respective roles of federal, state, and local governments?
Air pollutants are released by natural gas systems through the leaking, venting, and combustion of
natural gas; the combustion of other fossil fuel resources; and the discharge of particulate matter
during associated operations. Emission sources include pad, road, and pipeline construction; well
drilling, completion, and flowback activities; and gas processing and transmission equipment
such as controllers, compressors, dehydrators, pipes, and storage vessels. Pollutants include, most
prominently, methane and volatile organic compounds—of which the natural gas industry is one
of the highest-emitting industrial sectors in the United States—as well as nitrogen oxides, sulfur
dioxide, particulate matter, and various forms of hazardous air pollutants.
EPA’s 2012 Air Standards
The U.S. Environmental Protection Agency (EPA), in response to a consent decree issued by the
U.S. Court of Appeals, D.C. Circuit, promulgated air standards for several source categories in
the crude oil and natural gas sector on August 16, 2012. These standards—effective October 15,
2012—revised existing rules and promulgated new ones to regulate emissions of volatile organic
compounds (VOCs), sulfur dioxide, and hazardous air pollutants (HAPs) from many production
and processing activities that had never before been covered by federal oversight. The standards
control air pollution, in part, through the capture of fugitive releases of natural gas. Thus,
compliance with the standards has the potential to translate into economic benefits, as producers
may be able to offset abatement costs with the value of product recovered and sold. Using this
assumption, EPA estimated the annual benefits of the standards to be VOC reductions of 190,000
tons, HAP reductions of 12,000 tons, methane reductions of 1.0 million tons, and a net cost
savings of $11 million to $19 million after the sale of recovered product. Industry and other
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Air Quality Issues in Natural Gas Systems
stakeholders have disputed these figures as both too high and too low. Moreover, the expansion of
both industry production and government regulation of natural gas has sparked discussion on a
number of outstanding issues, including the following:
•
defining the roles of local, state, and federal governments,
•
determining the proper coverage of pollutants and sources,
•
establishing comprehensive emissions data,
•
understanding the human health and environmental impacts of emissions, and
•
estimating the costs of pollution abatement.
Scope and Purpose of This Report
The report begins by briefly outlining the production, processing, transmission, and distribution
phases of the natural gas industry, then characterizes the types and sources of pollutants in the
sector. It then turns to the role of the federal government in regulating these emissions, including
the provisions in the Clean Air Act and the regulatory activities of the EPA. It concludes with an
extended discussion of the aforementioned outstanding issues. For an abbreviated version of this
report, see CRS Report R42986, Air Quality Issues in Natural Gas Systems: In Brief.
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Contents
Background ...................................................................................................................................... 1
The Natural Gas Industry................................................................................................................. 3
Air Quality Issues in Natural Gas Systems ...................................................................................... 5
Emissions................................................................................................................................... 5
Sources ...................................................................................................................................... 7
Pollutants ................................................................................................................................... 9
The Clean Air Act and the Federal Role in Air Quality Issues in Natural Gas Systems ................ 13
Prior Federal Air Standards and Other Rules for Crude Oil and Natural Gas Systems ........... 13
2012 Federal Air Standards for Crude Oil and Natural Gas Systems ...................................... 16
2012 NSPS for Crude Oil and Natural Gas Systems......................................................... 17
2012 NESHAPs for Crude Oil and Natural Gas Systems ................................................. 19
Effects of the 2012 Federal Air Standards on State Attainment Planning and
Permitting ....................................................................................................................... 19
Reported Costs and Benefits of the 2012 Federal Air Standards ...................................... 20
Agency Reconsideration of the 2012 Federal Air Standards............................................. 21
Issues for Congressional Consideration ......................................................................................... 22
The Regulatory Role of Federal, State, and Local Governments ............................................ 22
Covered Sources and Pollutants .............................................................................................. 25
Major Source Aggregation ...................................................................................................... 26
Measurement of Emissions...................................................................................................... 28
Impacts of Emissions ............................................................................................................... 34
Ozone ................................................................................................................................ 36
Air Toxics .......................................................................................................................... 38
Greenhouse Gases ............................................................................................................. 40
Cost Benefit Analysis of Federal Standards ............................................................................ 43
Relevant Legislation in the 113th Congress ............................................................................. 45
Conclusion ..................................................................................................................................... 46
Figures
Figure 1. The Natural Gas Industry ................................................................................................. 4
Figure 2. Selected Emissions Inventories for U.S. Industrial Sectors ........................................... 12
Figure 3. Reduced Emissions Completion Equipment .................................................................. 18
Tables
Table 1. Methane Emissions in the U.S. Natural Gas Industry ...................................................... 31
Table A-1. New Source Performance Standards for Volatile Organic Compounds in Crude
Oil and Natural Gas Systems ...................................................................................................... 48
Table A-2. New Source Performance Standards for Sulfur Dioxide in Crude Oil and
Natural Gas Systems ................................................................................................................... 57
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Table A-3. National Emissions Standards for Hazardous Air Pollutants in Crude Oil and
Natural Gas Systems ................................................................................................................... 58
Table A-4. Comparison of 2012 Federal Air Standards for Crude Oil and Natural Gas
Systems to Selected State Regulations ....................................................................................... 62
Table B-1. Composition of Raw Natural Gas ................................................................................ 68
Table B-2. Air Pollution Emissions by Combusted Fuel Type ...................................................... 69
Table C-1. Glossary of Terms Related to Crude Oil and Natural Gas Systems ............................. 70
Appendixes
Appendix A. Federal Air Standards for Crude Oil and Natural Gas Systems................................ 48
Appendix B. Composition of Fugitive and Combusted Natural Gas Emissions ........................... 68
Appendix C. Glossary of Terms..................................................................................................... 70
Contacts
Author Contact Information........................................................................................................... 72
Acknowledgments ......................................................................................................................... 72
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Background
Congressional interest in U.S. energy policy has focused in part on ways through which the
United States could secure more economical and reliable fossil fuel resources both domestically
and internationally. Recent expansion in natural gas production, primarily as a result of new or
improved technologies (e.g., hydraulic fracturing)1 used on unconventional resources (e.g., shale,
tight sands, and coal-bed methane),2 has made natural gas an increasingly significant component
in the U.S. energy supply. While the practice of hydraulic fracturing is not new, relatively recent
innovations have incorporated processes such as directional drilling, high-volume slick-water
injection, and multistage fractures to get to previously unrecoverable resources. As a result, the
United States has again become the largest producer of natural gas in the world.3 The U.S. Energy
Information Administration (EIA) projects unconventional gas activity to more than double from
2010 to 2040, and forecasts that it will make up almost 80% of total U.S. natural gas production
by 2040.4 In addition, some analysts believe that by significantly expanding the domestic gas
supply, the exploitation of new unconventional resources has the potential to reshape energy
policy at national and international levels—altering geopolitics and energy security, recasting the
economics of energy technology investment decisions, and shifting trends in greenhouse gas
(GHG) emissions.5
Many in both the public and private sector have advocated for the increased production and use of
natural gas because the resource is domestically available, economically recoverable, and
considered a potential “bridge” fuel to a less polluting and lower GHG-intensive economy.6
Natural gas is cleaner burning than its hydrocarbon rivals, emitting, on average, about half as
1
Hydraulic fracturing (hydrofracking, fracking, or fracing) is commonly defined as an oil or gas well completion
process that directs pressurized fluids typically containing any combination of water, proppant, and any added
chemicals to penetrate tight rock formations, such as shale or coal formations, in order to stimulate the oil or gas
residing in the formation, and that subsequently requires high-rate, extended flowback to expel fracture fluids and
solids. The National Petroleum Council estimates that hydraulic fracturing will account for nearly 70% of natural gas
development within the next decade, see National Petroleum Council, “Prudent Development: Realizing the Potential
of North America’s Abundant Natural Gas and Oil Resources,” September 15, 2011. For more discussion on this
technology, see the section on “Hydraulic Fracturing” in CRS Report R42333, Marcellus Shale Gas: Development
Potential and Water Management Issues and Laws, by (name redacted) et al.
2
These unconventional resources are commonly defined as follows: Tight sands gas is natural gas trapped in low
permeability and nonporous sandstones. Shale gas is natural gas trapped in shale deposits, a very fine-grained
sedimentary rock that is easily breakable into thin, parallel layers. Coal-bed methane is natural gas trapped in coal
seams. These resources are referred to as “unconventional” because, in the broadest sense, they are more difficult
and/or less economical to extract than “conventional” natural gas, usually because the technology to reach them has not
been developed fully, or has been too expensive. For a more detailed discussion of these definitions, see the Natural
Gas Supply Association’s website, http://www.naturalgas.org/overview/unconvent_ng_resource.asp.
3
The United States surpassed Russia as the world’s leading producer of dry natural gas beginning in 2009. See U.S.
Energy Information Administration, “Today in Energy,” March 13, 2012, http://www.eia.gov/todayinenergy/
detail.cfm?id=5370.
4
U.S. Energy Information Administration, Annual Energy Outlook, 2013, http://www.eia.gov/energy_in_brief/article/
about_shale_gas.cfm.
5
For more discussion on natural gas resources, see CRS Report R42814, Natural Gas in the U.S. Economy:
Opportunities for Growth , by (name redacted) and (name redacted).
6
Support for the natural gas industry has come also from the Obama Administration. In his 2012 State of the Union
speech, President Obama stated, “We have a supply of natural gas that can last America nearly 100 years, and my
administration will take every possible action to safely develop this energy.” President Barack Obama, “Remarks by
the President in State of the Union Address,” Washington, DC, January 24, 2012, http://www.whitehouse.gov/thepress-office/2012/01/24/remarks-president-state-union-address.
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much carbon dioxide as coal and one-quarter less than oil when consumed in a typical electric
utility plant.7 Further, natural gas combustion emits no mercury—a persistent, bioaccumulative
neurotoxin—virtually no particulate matter, and less sulfur dioxide and nitrogen oxides, on
average, than either coal or oil. For these reasons, pollution control measures in natural gas
systems have traditionally received less attention relative to those in other hydrocarbon industries.
However, the recent increase in natural gas production, specifically from unconventional
resources, has raised a new set of concerns regarding environmental impacts. These concerns
centered initially on water quality issues, including the potential contamination of groundwater
and surface water from hydraulic fracturing and related production activities. They have since
incorporated other issues, such as water management practices (both consumption and discharge),
land use changes, induced seismicity, and air pollution. The new set of questions about hydraulic
fracturing in unconventional reservoirs has led, in part, to various grassroots movements, some
political opposition, and calls for additional regulatory actions, moratoria, and/or bans at the
local, state, and federal levels.
Currently, the development of natural gas in the United States is regulated under a complex set of
local, state, and federal laws that addresses many—but not all—aspects of exploration,
production, and distribution. State and local authorities are responsible for virtually all of the dayto-day regulation and oversight of natural gas systems. The organization of this oversight within
each gas-producing jurisdiction varies considerably. In general, each state has one or more
regulatory agencies that may permit wells, including their design, location, spacing, operation,
and abandonment, and may regulate for environmental compliance. With respect to pollution
controls, state laws may address many aspects of water management and disposal, air emissions,
underground injection, wildlife impacts, surface disturbance, and worker health and safety.
Furthermore, several federal statutes address pollution control measures in natural gas systems;
and, where applicable, these controls are largely implemented by state and local authorities. For
example, the Clean Water Act (CWA) regulates surface discharges of water associated with
natural gas drilling and production, as well as contaminated storm water runoff from production
sites.8 The Safe Drinking Water Act (SDWA) regulates the underground injection of wastewater
from crude oil and natural gas production, and the underground injection of fluids used in
hydraulic fracturing if the fluids contain diesel fuel.9 The Clean Air Act (CAA) limits emissions
from associated engines and gas processing equipment, as well as some natural gas extraction,
production, and processing activities.
7
These values are averages based on carbon dioxide emitted per unit of energy generated. See Energy Information
Administration (EIA), Office of Oil and Gas. Carbon Monoxide: derived from EIA, Emissions of Greenhouse Gases in
the United States 1997, Table B1, p. 106, ftp://ftp.eia.doe.gov/pub/oiaf/1605/cdrom/pdf/gg98rpt/057397.pdf. Other
pollutants derived from U.S. Environmental Protection Agency, Compilation of Air Pollutant Emission Factors, Vol. 1,
Stationary Point and Area Sources, 1998, http://www.epa.gov/ttn/chief/ap42/.
8
For more discussion, see CRS Report R42333, Marcellus Shale Gas: Development Potential and Water Management
Issues and Laws, by (name redacted) et al.
9
For more discussion, see CRS Report R41760, Hydraulic Fracturing and Safe Drinking Water Act Regulatory Issues,
by (name redacted) and (name redacted).
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The Natural Gas Industry
Natural gas is a nonrenewable fossil fuel that is used both as an energy source (for heating,
transportation, and electricity generation) and as a chemical feedstock (for such varied products
as plastic, fertilizer, antifreeze, and fabrics). Raw natural gas is commonly recovered from
geologic formations in the ground through drilling and extraction activities by the oil and gas
industry.10 This industry includes operations in the extraction and production of crude oil and
natural gas, as well as the processing, transmission, and distribution of natural gas. For both
operational and regulatory reasons, the sector is commonly separated into four major segments:
(1) crude oil and natural gas production, (2) natural gas processing,11 (3) natural gas transmission
and storage, and (4) natural gas distribution (see Figure 1). This report uses these basic categories
to track the various activities in natural gas systems, including the operations, emissions, and
regulations discussed below. While the focus of this report is on the production sector, it also
highlights air quality issues in other sectors, where appropriate. Below is a brief outline of the
crude oil and natural gas industry.12 For more detail regarding specific activities or equipment, see
the glossary of terms provided in Table C-1.
Production (Upstream). Production operations include the wells and all related processes used
in the extraction, production, recovery, lifting, stabilization, separation, and treating of oil and/or
natural gas (including condensate). Production operations span the initial well drilling, hydraulic
fracturing, well completion, and workover activities and cover all the portable non-self-propelled
apparatus associated with those operations. Production sites include not only the ‘‘pads’’ where
the wells are located, but also the stand-alone sites where oil, condensate, produced water, and
gas from several wells may be separated, stored, and treated, as well as the low pressure, small
diameter, gathering pipelines and related components that collect and transport the oil, gas, and
other materials and wastes from the wells to the refineries or natural gas processing plants.
Processing (Midstream). Natural gas is primarily made up of methane. However, in its raw state,
natural gas is a mixture of various hydrocarbons and may contain trace amounts of other chemical
substances that must be removed before distribution. The additional hydrocarbons are often
referred to as natural gas liquids (NGL). They are sold separately and have a variety of different
uses. Raw natural gas may also contain water vapor, nonhydrocarbon compounds, and other
chemical substances. Processing operations are used to separate out the additional components
from raw natural gas to produce ‘‘pipeline quality’’ or “dry” natural gas for consumption.
Transmission and Storage (Downstream). Dry natural gas leaves the processing segment and
enters the transmission segment. Pipelines in the natural gas transmission segment can be
interstate pipelines, that carry natural gas across state boundaries, or intrastate pipelines, that
10
Natural gas can also be recovered as a byproduct from various other sources including mining, industrial, or
agricultural processes. These secondary sources are not discussed in this report. For a more detailed description of the
oil and gas industry, see CRS Report R40872, U.S. Fossil Fuel Resources: Terminology, Reporting, and Summary, by
(name redacted), (name redacted), and (name redacted).
11
Crude oil after the production phase (i.e., beginning with petroleum refining) is classified as a different industrial
sector for most regulatory purposes. Petroleum refining is not discussed in this report. See CRS Report R41478, The
U.S. Oil Refining Industry: Background in Changing Markets and Fuel Policies, by (name redacted) et al.
12
The description of the natural gas sector is drawn from the U.S. Environmental Protection Agency, “Oil and Natural
Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants
Reviews,” 76 Federal Register 52738, August 23, 2011.
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transport the gas within a single state. While interstate pipelines may be of a larger diameter and
operate at a higher pressure, the basic components are the same. To ensure that the natural gas
flowing through any pipeline remains pressurized, compressor stations are required at regular
intervals. Further, to ensure proper load balancing during the delivery and receipt of natural gas,
the transmission segment often includes storage facilities, typically consisting of both man-made
and natural sites, such as depleted gas reservoirs and/or salt dome caverns.
Distribution. The distribution segment is the final step in delivering natural gas to customers.
The natural gas enters the distribution segment from delivery points located on interstate and
intrastate transmission pipelines and then flows to business and household customers.
Nationwide, natural gas distribution systems consist of thousands of miles of pipes, including
mains and service lines to the customers. Distribution systems also include compressor and
metering stations, which allow companies to both move and monitor the natural gas in the
system. The delivery point where the natural gas leaves the transmission segment and enters the
distribution segment is often called the ‘‘citygate.’’ Typically, the citygate serves as the transfer
point of ownership from producers to utilities.
Figure 1. The Natural Gas Industry
Source: U.S. Environmental Protection Agency.
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Air Quality Issues in Natural Gas Systems
Raw natural gas is a mixture of various hydrocarbons (primarily methane) and may contain trace
amounts of other chemical substances that must be removed before distribution. Air pollutants
associated with the natural gas industry may be emitted through the release of natural gas vapors
(either purposefully or accidently), the combustion of natural gas (either for use or for
safety/disposal), the combustion of other fuel resources (for process heat, power, and electricity),
and the discharge of particulate matter during construction, transportation, and associated
operations. Sources of emissions include pad, road, and pipeline construction; drilling,
completion, and flowback activities that occur during the development of a well; and gas
processing and transmission equipment such as controllers, compressors, dehydrators, pipelines,
and storage vessels. Pollutants include, most prominently, methane and volatile organic
compounds, of which the natural gas industry is one of the highest emitting industrial sectors in
the United States.13 Pollutants also include nitrogen oxides, sulfur dioxide, particulate matter, and
various forms of hazardous air toxics, including n-hexane, the BTEX compounds (i.e., benzene,
toluene, ethylbenzene, and xylene), and hydrogen sulfide.
Emissions
Natural gas systems release air emissions in several ways. This report categorizes these emissions
into three types: fugitive, combusted, and associated.14
Fugitive. Fugitive refers to the natural gas vapors that are released to the atmosphere during
industry operations. Fugitive emissions can be either intentional (i.e., vented) or unintentional
(i.e., leaked).15 Intentional emissions are releases that are designed specifically into the system:
for example, emissions from vents or blow-downs used to guard against over-pressuring; or gasdriven equipment used to regulate pressure, store, or transport the resource. Conversely,
unintentional emissions are releases that result from uncontrolled leaks in the system: for
example, emissions from routine wear, tear, and corrosion; improper installation or maintenance
of equipment; or the overpressure of gases or liquids in the system. Fugitive natural gas is
primarily a mixture of low molecular-weight hydrocarbon compounds that are gaseous in form at
normal conditions. While the principal component of natural gas is methane (CH4), it may contain
smaller amounts of other hydrocarbons, such as ethane, propane, and butane, as well as heavier
hydrocarbons. These nonmethane hydrocarbons include types of volatile organic compounds
(VOCs), classified as ozone (i.e., smog) precursors, as well as, in some cases, hazardous (i.e.,
toxic) air pollutants (HAPs). Nonhydrocarbon gases, such as carbon dioxide (CO2), helium (He),
hydrogen sulfide (H2S), nitrogen (N2), and water vapor (H2O), may also be present in any
proportion to the total hydrocarbon content. The chemical composition of raw natural gas varies
greatly across resource reservoirs, and the gas may or may not be “associated” with crude oil
resources. When natural gas is found to be primarily methane, it is referred to as “dry” or
13
For more discussion, see section “Pollutants” of this report.
EPA categorizes emissions as either “equipment leaks and vented emissions” or “combustion-related emissions.” See
U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009,
Washington, DC, EPA 430-R-11-005, April 2011.
15
For further definitions of fugitive emissions, see U.S. Environmental Protection Agency, Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2010, Washington, DC, EPA 430-R-12-001, April 15, 2012,
http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2012-Main-Text.pdf.
14
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“pipeline quality” gas. When natural gas is found bearing higher percentages of heavier
hydrocarbons, nonhydrocarbon gases, and/or water vapor, it is commonly referred to as “wet,”
“rich,” or “hot” gas. Similarly, quantities of VOCs, HAPs, and H2S can vary significantly
depending upon the resource reservoir. VOC and HAP compositions typically account for only a
small percentage of natural gas mixtures; however, this ratio increases the “wetter” the gas.
Natural gas mixtures with a higher percentage of H2S are generally referred to as “sour” or “acid”
gas.16
Combusted. Combusted refers to the byproducts that are formed from the burning of natural gas
during industry operations. Combusted emissions are commonly released through either the
flaring of natural gas for safety and health precautions or the combustion of natural gas for
process heat, power, and electricity in the system (e.g., for compressors, dehydrators, and other
machinery). The chemical process of combusting natural gas releases several different kinds of
air pollutants, including carbon dioxide (CO2), carbon monoxide (CO), nitrogen oxides (NOx),
and trace amounts of sulfur dioxide (SO2) and particulate matter (PM). Flaring is a means to
eliminate natural gas that may be impracticable to use, capture, or transport. As with venting, the
primary purpose of flaring is to act as a safety device to minimize explosive conditions. Gas may
be flared at many points in the system; however, it is most common during the drilling and well
completion phases. Natural gas combustion is generally considered a greater pollution control
mechanism than the venting of natural gas, because the process serves to incinerate many of the
VOCs and HAPs that would otherwise be released directly into the atmosphere. Similarly, natural
gas combustion is generally considered as “cleaner” than other fossil fuel combustion with
respect to various criteria pollutants and greenhouse gas (GHG) emissions.17
Associated. Associated refers to secondary sources of emissions that arise from associated
operations in natural gas systems. Associated emissions may result from the combustion of other
fossil fuels (i.e., other than the natural gas stream) to power equipment, machinery, and
transportation, as well as the associated release of dust and particulate matter from construction
and road use. Associated emissions have the potential to contribute significantly to air pollution.
The focus of this report is on fugitive and combusted natural gas emissions. While there may be
significant emissions from the natural gas sector as a result of the combustion of other fossil fuels
for process heat, power, and transportation, as well as the associated release of particulate matter
from construction and road use, the primary focus of this report is on air quality issues related to
the resource itself (i.e., the fugitive release of natural gas and its combustion during operations). It
is this release of natural gas—and the pollutants contained within it—that makes air quality
considerations in the crude oil and natural gas sector unique from other industrial-, construction-,
and transportation-intensive sectors.
16
For more discussion on the chemical composition of raw natural gas emissions, see Appendix B.
For more discussion on emissions from combusted fossil fuel resources, see Appendix B. While there is general
agreement that the combustion of natural gas produces less GHG emissions than other combusted fossil fuels, the GHG
emission intensity for the full fuel life-cycle of natural gas (i.e., from extraction through combustion), compared to
petroleum and coal is under greater debate. For further discussion on the comparable impacts of the natural gas industry
on GHG emissions, see section “Greenhouse Gases.”
17
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Sources
Natural gas systems include many activities and pieces of equipment that have the potential to
emit air pollutants. Most of these emissions sources are common to both conventional and
unconventional natural gas development.
Drilling. Fugitive natural gas and other air pollutants may escape to the atmosphere during initial
drilling operations through the circulation of drilling fluids back to the surface. Further, emissions
from combusted natural gas—including CO2, NOx, and potentially SO2—may also be released at
the well site due to both engine combustion and flaring activities. These include “well test
flaring,” which occurs during the drilling and testing of oil and gas wells, and “solution gas
flaring,” which occurs during the disposal of associated gas produced along with crude oil (as is
the case currently with oil production in the Bakken formation).
Well Completions. Well completions contain several processes which have the potential to emit
air pollutants. For example, hydraulic fracturing uses pressurized fluids containing any
combination of water, proppant, and added chemicals to penetrate and produce natural gas from
tight formations (e.g., shale, sand, or coal formations). The process requires a high rate, extended
flowback period to expel fracture fluids and solids from the well. Gas may escape with these
fluids during flowback or impoundment, allowing emissions of methane and VOCs to be released
to the atmosphere. Conversely, if the flowback gas is captured, separated from the fluids, and
flared, emissions of nitrous oxides and carbon dioxide may be released to the atmosphere. EPA
estimates that well completions involving hydraulic fracturing can vent substantially more natural
gas—approximately 230 times more—than well completions not involving hydraulic fracturing,18
if not controlled by reduction equipment.19 Other sources from industry and academia estimate
these emissions levels differently, in part because the data are limited.20
Compressors. There are many locations throughout the natural gas sector where compression is
required to move gas along the pipeline. This is accomplished by different machinery such as
combustion turbines, reciprocating internal combustion engines, and electric motors. Both the
turbine-powered centrifugal compressors and the reciprocating internal combustion compressors
may use a small portion of the natural gas they compress to fuel the turbine. Both are potential
sources of fugitive VOCs and methane emissions as well as significant sources of combusted
emissions. Centrifugal compressors require seals around the rotating shaft to prevent gases from
escaping where the shaft exits the casing. The seals in some compressors use oil (e.g., “wet seal
compressors”), and they commonly vent the absorbed gas to the atmosphere when they are
purged. Reciprocating compressors, on the other hand, leak natural gas throughout the course of
their normal operation, with the highest volume of gas loss associated with worn down piston rod
packing systems. Using dry-seal centrifugal systems or periodically replacing worn down rod
18
Specifically, EPA estimates uncontrolled well completion emissions for a hydraulically fractured well at about 23
tons of VOCs, and emissions for a conventional gas well completion at around 0.1 ton VOCs. See EPA, “Oil and
Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants
Reviews,” 76 Federal Register 52738, August 23, 2011.
19
Reduced emission completions (REC), which are sometimes referred to as “green completions” or “flareless
completions,” use equipment at the well site to capture and treat gas so it can be directed into the sales line and avoid
emissions from venting. Based on information provided to EPA Natural Gas STAR program, over 90% of gas
potentially vented during a completion can be recovered during a reduced emission completion. For more discussion of
REC and a schematic, see Figure 3.
20
For further discussion, see section “Measurement of Emissions” of this report.
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packing systems are the most effective ways of controlling emissions from gas-driven
compressors. Conversely, where available, electric motors can be used to operate compressors.
This type of compression does not require the use of any of the natural gas from the pipeline, but
it does require a source of electricity.
Controllers. Pneumatic controllers are automated instruments widely used in the natural gas
sector for maintaining pressure, temperature, and flow rate conditions in the system. In many
situations, the pneumatic controllers make use of the available high-pressure natural gas in the
system to regulate these conditions. In these “gas-driven” pneumatic controllers, natural gas may
be released intermittently with every valve movement or continuously from the valve control
pilot. Gas driven pneumatic controllers are typically characterized as either “high-bleed” or “lowbleed,” where a high-bleed device releases at least 6 cubic feet of gas per hour. Conversely, “nongas driven” pneumatic controllers use sources of power other than pressurized natural gas, greatly
reducing levels of emissions. Examples include solar, electric, and instrument air.
Storage Vessels. After being separated from the natural gas stream, crude oil, condensate, and
produced water are typically stored in fixed-roof storage vessels. These vessels, which are
operated at or near atmospheric pressure conditions, can release various emissions to the
atmosphere as a result of working, breathing, and flash losses. Working losses occur due to the
emptying and filling of storage tanks. Breathing losses are the release of gas associated with daily
temperature fluctuations and other equilibrium effects. Flash losses occur when a liquid is
transferred from a vessel with higher pressure to a vessel with lower pressure, thus allowing
entrained gases or a portion of the liquid to vaporize or flash. Typically, the larger the pressure
drop, the more flash emissions will occur in the storage stage. The two ways of controlling tanks
with significant emissions are to install vapor recovery units (VRU) or to route the emissions
from the tanks to control devices (i.e., flares).
Dehydrators. Once natural gas has been separated from any liquid materials or products (e.g.,
crude oil, condensate, or produced water), residual entrained water is removed from the natural
gas by dehydration. One of the most widely used natural gas dehydration processes is glycol
dehydration. Glycol dehydration is an absorption process in which a liquid absorbent (glycol)
directly contacts the natural gas stream and absorbs both the entrained water vapor as well as a
number of selected hydrocarbons, including BTEX, n-hexane, and other HAPs. During the
recirculation stages, the hydrocarbons are boiled off along with the water and are either vented to
the atmosphere or directed to a control device.
General Equipment and Pipeline Leaks. Fugitive emissions can emanate from valves, pump
seals, flanges, compressor seals, pressure relief valves, open-ended lines, and other process and
operation components at any point during operations. Leaks may be due to routine wear, tear, and
corrosion; improper installation or maintenance; or the overpressure of gases or liquids in the
system. Because of the large number of valves, pumps, and other components within a natural gas
production, processing, or transmission facility, equipment leaks collectively can be a significant
source of emissions. Further, there are over 300,000 miles of transmission pipelines alone in the
United States, and these pieces of equipment exist throughout the system.
Workovers, Maintenance, and Upsets. Periodically, wells require restimulation workovers or
routine maintenance—such as the unloading of liquids or blowdowns—in order to reestablish
productive gas flows. These activities, depending upon their methods, may release significant
amounts of fugitives into the atmosphere. Further, all activities are susceptible to occasional
upsets and accidental losses.
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Pollutants
Through provisions in the Clean Air Act (CAA),21 the U.S. Environmental Protection Agency
(EPA) classifies air pollutants under several different categories, including the following:
•
Criteria Pollutants. Common emissions that can harm human health or the
environment, or cause property damage, including ground-level ozone (i.e.,
smog), nitrogen oxides, sulfur dioxide, carbon monoxide, particulate matter, and
lead,22
•
Hazardous Air Pollutants. Toxic chemicals that are known or suspected to
cause cancer or other serious health effects, such as reproductive diseases or birth
defects,23
•
Greenhouse Gas Pollutants. Chemical compounds that trap heat in the
atmosphere and contribute to the forcing of climate change.24
The “Criteria” and “Hazardous Air Pollutant” categories are identified and regulated under
specific provisions of the CAA. In contrast, greenhouse gases may be regulated under several
different ones.25 The natural gas industry produces emissions from each of these categories, some
of which may overlap (e.g., benzene is a volatile organic compound [VOC]; and it is considered
both a ground-level ozone-producing criteria pollutant and a carcinogenic hazardous air pollutant
[HAP]). See Figure 2 for a comparison of air pollution emissions from the natural gas industry
against those of other U.S. industrial sectors.
Methane (CH4). Methane—the principal component of natural gas—is both a precursor to
ground-level ozone formation (i.e., smog)26 and a potent greenhouse gas (GHG), albeit with a
shorter climate-affecting time horizon than carbon dioxide.27 Every process in natural gas systems
has the potential to emit methane. EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks:
21
42 U.S.C. 7401 et seq.
See authorities as defined in 42 U.S.C. 7409.
23
See authorities as defined in 42 U.S.C. 7402.
24
See authorities as defined in U.S. Environmental Protection Agency, “Endangerment and Cause or Contribute
Findings for Greenhouse Gases,” 74 Federal Register 66496-66516, December 15, 2009.
25
The “endangerment” language in §§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.
26
While methane is a precursor to ground-level ozone formation, it is less reactive than other hydrocarbons. Thus, EPA
has officially excluded it from the definition of regulated hydrocarbons called volatile organic compounds (VOCs). See
U.S. Environmental Protection Agency, Conversion Factors for Hydrocarbon Emission Components, Washington, DC,
EPA-420-R-10-015, July 2010, http://www.epa.gov/otaq/models/nonrdmdl/nonrdmdl2010/420r10015.pdf.
27
As a greenhouse gas, methane emitted into the atmosphere absorbs terrestrial infrared radiation, which contributes to
increased global warming and continuing climate change. According to the Intergovernmental Panel on Climate
Change (IPCC) Fourth Assessment Report (2007), in 2004 the cumulative changes in methane concentrations since
preindustrial times contributed about 14% to global warming due to anthropogenic GHG sources, making methane the
second-leading long-lived climate forcer after CO2 globally. While the perturbation lifetime for methane is 12 years,
CO2’s is considerably longer and does not undergo a simple decline over a single predictable timescale. Instead, the
excess carbon is first diluted by the carbon cycle as it mixes into the oceans and biosphere (e.g., plants) over a period of
a few hundred years, and then it is slowly removed over hundreds of thousands of years as it is gradually incorporated
into carbonate rocks. For further discussion on climate change and its potential impacts, see CRS Report RL34266,
Climate Change: Science Highlights, by (name redacted).
22
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1990-2011 (published April 15, 2013) estimates 2011 methane emissions from “Natural Gas
Systems” to be 358 billion standard cubic feet (bscf), or 1.5% of the industry’s gross national
production that year.28 In 2011, natural gas systems represented nearly 25% of the total methane
emissions from all domestic sources and accounted for about 2% of all GHG emissions in the
United States. In each year since 1990, natural gas systems were cited as being the single largest
contributor to U.S. anthropogenic (i.e., man-made) methane emissions. Because of methane’s
effects on climate, EPA has found that it, along with five other well-mixed greenhouse gases,
endangers public health and welfare within the meaning of the Clean Air Act.29
Volatile Organic Compounds (VOCs)—A Ground-Level Ozone (O3) Precursor. The crude oil
and natural gas sector is currently one of the largest sources of VOC emissions in the United
States, accounting for approximately 12% of VOC emissions nationwide (and representing 67%
of VOC emissions released by industrial source categories).30 VOCs—in the form of various
hydrocarbons—are emitted throughout a wide range of natural gas operations and equipment. The
interaction between VOCs and NOx in the atmosphere contributes to the formation of ozone (i.e.,
smog). EPA quantifies several health effects associated with exposure to ozone, including
premature death, heart failure, chronic respiratory damage, and premature aging of the lungs.
Ozone may also exacerbate existing respiratory illnesses, such as asthma and emphysema, or
cause chest pain, coughing, throat irritation, and congestion.31
Nitrogen Oxides (NOx)—A Ground-Level Ozone (O3) Precursor. Significant amounts of NOx
are emitted at natural gas sites through the combustion of natural gas and other fossil fuels (e.g.,
diesel). This combustion occurs during several activities, including (1) the flaring of natural gas
during drilling and well completions, (2) the combustion of natural gas to drive the compressors
that move the product through the system, and (3) the combustion of fuels in engines, drills,
28
EPA reported 2011 GHG emissions from natural gas systems as 177.0 million metric tons of carbon dioxide
equivalent (MMtCO2e). EPA reported 2011 GHG emissions from all sources as 6702.3 MMtCO2e. U.S. Environmental
Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011, Washington, DC, EPA 430-R13-001, April 15, 2013, http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-MainText.pdf. Here, as elsewhere in the report, Greenhouse gases are quantified using a unit measurement called carbon
dioxide equivalent (CO2e), wherein gases are indexed and aggregated against one unit of CO2. CRS used a conversion
factor of 0.4045 MMtCO2e = 1000 bscf CH4 at 60 degrees Fahrenheit (15.6 degrees Celsius) and 14.696 psi (1 atm or
101.325 kPa) of pressure. The U.S. Energy Information Administration reports 2011 U.S. natural gas marketed
production as 24,036 bscf, see http://www.eia.gov/dnav/ng/hist/n9050us2a.htm. EPA’s 2011 emission estimates were
revised, in part, by industry information released under the Greenhouse Gas Reporting Program (GHGRP) (for more
information about the program, see section on GHG Reporting under “Prior Federal Air Standards and Other Rules for
Crude Oil and Natural Gas Systems” of this report). The first GHGRP report by the crude oil and natural gas sector was
released in February 2013. Some 1,800 facilities reported 225 MMtCO2e of total GHG emissions, of which 83
MMtCO2e were methane (substantially lower than EPA’s 2010 estimate of 215.4 MMtCO2e). Notwithstanding, the
industry-reported emissions from the crude oil and natural gas sector accounted for almost 40% of total U.S.
anthropogenic methane emissions reported by the GHGRP. For discussion, see section “Measurement of Emissions” of
this report.
29
U.S. Environmental Protection Agency, “Endangerment and Cause or Contribute Findings for Greenhouse Gases,”
74 Federal Register 66496-66516, December 15, 2009.
30
The 2008 National Emissions Inventory estimated the crude oil and natural gas sector’s VOC emissions at 1.7
million tons. Mobile sources are the highest category for VOC emissions domestically, at 45.2% in 2008. Data for
VOCs, as well as the other criteria and HAP pollutants, are derived from EPA’s National Emissions Inventory, and can
be found at http://www.epa.gov/ttn/chief/eiinformation.html. These figures have been contested by some sources. For
further discussion, see the section “Measurement of Emissions” of this report.
31
U.S. Environmental Protection Agency, Regulatory Impact Analysis: Final National Ambient Air Quality Standards
for Ozone, Research Triangle Park, NC, July 2011.
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heaters, boilers, and other production, construction, and transportation equipment.32 In addition to
ozone formation (see VOCs description above), current scientific evidence links short-term NOx
exposures with adverse respiratory effects including airway inflammation in healthy people and
increased respiratory symptoms in people with asthma.
Carbon Monoxide (CO). Similar to NOx, CO is emitted from combustion processes in stationary
and mobile sources. CO can cause harmful health effects by reducing oxygen delivery to the
body’s organs (like the heart and brain) and tissues.
Sulfur Dioxide (SO2). SO2 is emitted from crude oil and natural gas production and processing
operations that handle and treat sulfur-rich, or “sour,” gas. Current scientific evidence links shortterm exposures to SO2 with an array of adverse respiratory effects including bronchoconstriction
and increased asthma symptoms.
Particulate Matter (PM). PM may occur from dust or soil entering the air during well-pad
construction, traffic on access roads, and diesel exhaust from drilling machinery, vehicles, and
other engines. PM is linked to respiratory and cardiovascular problems, including aggravated
asthma attacks, chronic bronchitis, decreased lung function, heart attacks, and premature death.33
Hazardous Air Pollutants (HAPs). HAPs, also known as air toxics, are those pollutants that are
known or suspected to cause cancer or other serious health effects, such as reproductive diseases,
or birth defects. Of the HAPs emitted from natural gas systems, VOCs are the largest group, and
typically evaporate easily into the air. The most common HAPs in natural gas systems are nhexane, the BTEX compounds (benzene, toluene, ethylbenzene, and xylenes), and hydrogen
sulfide.34 HAPs are found primarily in natural gas itself, and are emitted from equipment leaks
and from various processing, compressing, transmission, distribution, or storage operations. They
are also a byproduct of fuel combustion and may be components in various chemical additives.
32
NOx emissions from engines and turbines are covered by 40 C.F.R. §60, subpart JJJJ and KKKK respectively.
U.S. Environmental Protection Agency, Particulate Matter Health website, http://www.epa.gov/pm/health.html. For
more discussion, see CRS Report R40096, 2006 National Ambient Air Quality Standards (NAAQS) for Fine Particulate
Matter (PM2.5): Designating Nonattainment Areas, by (name redacted).
34
Hydrogen sulfide was on the original list of hazardous air pollutants in the CAA, Section 112(b), but was
subsequently removed by Congress. Currently, hydrogen sulfide is regulated under the CAA’s Accidental Release
Program, Section 112(r)(3). According to EPA, there are 14 major areas found in 20 different states where hydrogen
sulfide is commonly found in natural gas deposits. As a result of drilling in these areas, “the potential for routine
[hydrogen sulfide] emissions is significant.” See U.S. Environmental Protection Agency, Report to Congress on
Hydrogen Sulfide Air Emissions Associated with the Extraction of Oil and Natural Gas, EPA-453/R-93-045, Research
Triangle Park, NC, October 1993, at ii, III-35; see also ii, II-5 to II-11.
33
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Figure 2. Selected Emissions Inventories for U.S. Industrial Sectors
Source: EPA, National Emissions Inventory 2008, v.1.5 GPR, http://www.epa.gov/ttnchie1/net/
2008inventory.html; National Air Toxics Assessment, 2005, http://www.epa.gov/ttn/atw/natamain/; Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2009, http://www.epa.gov/climatechange/ghgemissions/
usinventoryreport/archive.html.
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The Clean Air Act and the Federal Role in
Air Quality Issues in Natural Gas Systems
The Clean Air Act (CAA)35 seeks to protect human health and the environment from emissions
that pollute ambient, or outdoor, air.36 It requires the U.S. Environmental Protection Agency
(EPA) to establish minimum national standards for air emissions from various source categories
(sources in the “Crude Oil and Natural Gas Production,” and the “Natural Gas Transmission and
Storage” sectors are included under these categories), and assigns primary responsibility to the
states to assure compliance with the standards. EPA has largely delegated day-to-day
responsibility for CAA implementation to all 50 states, including permitting, monitoring,
inspections, and enforcement; and in many cases, states have further delegated program
implementation to local governments. Sections of the CAA which are most relevant to air quality
issues in the natural gas industry are discussed below. Some of the regulations implementing
these sections have been revised by federal air standards promulgated by EPA on August 16,
2012. The paragraphs below summarize relevant sections of the CAA prior to these revisions. For
a summary of the 2012 air standards and their relationship to the prior ones, see the subsequent
section, “2012 Federal Air Standards for Crude Oil and Natural Gas Systems,” as well as
Appendix A.
Prior Federal Air Standards and Other Rules for Crude Oil and
Natural Gas Systems
National Ambient Air Quality Standards (NAAQS). Section 109 of the CAA requires EPA to
establish NAAQS for air pollutants that may reasonably be anticipated to endanger public health
or welfare, and whose presence in ambient air results from numerous or diverse sources. Using
this authority, EPA has promulgated NAAQS for sulfur dioxide (SO2), particulate matter (PM2.5
and PM10), nitrogen dioxide (NO2), carbon monoxide (CO), ozone, and lead. States are required
to implement specified air pollution control plans to monitor these pollutants and ensure the
NAAQS are met, or “attained.” Additional measures are required in areas not meeting the
standards, referred to as “nonattainment areas.” “Nonattainment” findings for ground-level ozone,
nitrogen oxides, and sulfur dioxide in areas with crude oil and natural gas production may result
in states establishing specific pollution controls that could affect the industry.
Permits. The 1990 CAA Amendments add Title V (i.e., “5”),37 which requires major sources of
air pollution to obtain operating permits. Primary responsibility for Title V permitting has been
delegated by EPA to state and local authorities. Sources subject to the permit requirements
generally include new or modified sources that emit or have the potential to emit 100 tons per
year of any regulated pollutant, plus new or existing “area sources” that emit or have the potential
to emit lesser specified amounts of hazardous air pollutants. In “nonattainment” areas, the permit
requirements may include sources which emit as little as 50, 25, or 10 tons per year of VOCs,
35
42 U.S.C. 7401 et seq. For a summary of the CAA and EPA’s air and radiation activities and its authorities, see
EPA’s website at http://www.epa.gov/air/basic.html; and CRS Report RL30853, Clean Air Act: A Summary of the Act
and Its Major Requirements, by (name redacted), (name redacted), and (name redacted).
36
“Outdoor” is defined as that to which the public has access (see 40 C.F.R. §50.1(e)).
37
42 U.S.C. §§7661-7661f; 40 C.F.R. §§71, 72.
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depending on the severity of the region’s nonattainment status (“serious,” “severe,” or “extreme”
respectively). A Title V permit must, among other things, list all emissions limitations and
standards applicable to the source, ensure that monitoring and recordkeeping are sufficient to
demonstrate compliance, and require the payment of fees. Currently, most crude oil and natural
gas production activities upstream from the processing plant are not classified as “major sources”
under EPA Title V operating permits.38
Greenhouse Gas Reporting. In the FY2008 Consolidated Appropriations Act (H.R. 2764; P.L.
110-161), Congress directs EPA to develop regulations that establish a mandatory GHG reporting
program that applies to emissions that are “above appropriate thresholds in all sectors of the
economy.” EPA issued the Mandatory Reporting of Greenhouse Gases Rule (MRR)39 which
became effective on December 29, 2009, and included reporting requirements for facilities and
suppliers in 32 source categories.40 Affected facilities in the petroleum and natural gas industry
include onshore petroleum and natural gas production, offshore petroleum and natural gas
production, natural gas processing, natural gas transmission compressor stations, underground
natural gas storage, liquefied natural gas (LNG) storage, LNG import and export terminals, and
natural gas distribution. The rule requires petroleum and natural gas facilities that emit 25,000
metric tons or more of carbon dioxide (CO2) equivalent per year to report annual fugitive
emissions of methane and CO2 from equipment leaks and venting, and annual combusted
emissions of CO2, methane, and nitrous oxide from gas flaring, from stationary and portable
equipment involved in onshore petroleum and natural gas production, and from stationary
equipment involved in natural gas distribution. Since methane is the most prominent emission
from upstream oil and gas activities, and since the rule requires producers to aggregate emissions
from all commonly controlled wells and their associated equipment (e.g., compressors,
generators, piping, and storage tanks), many facilities may likely be required to report GHG
emissions in coming years.41 EPA estimates that the rule covers 85% of the total GHG emissions
from most of the U.S. petroleum and natural gas industry with approximately 2,800 facilities
reporting. On February 5, 2013, EPA released for the first time GHG data for crude oil and
natural gas systems collected under industry reporting.42 Further to this, many states have their
own GHG reporting requirements independent of the 2009 federal rules (e.g., the Regional GHG
Initiative, the Western Climate Initiative, and California).
38
EPA’s guidance for “major source” determinations includes consideration of proximity, ownership, and industrial
grouping. For further discussion, see section “Major Source Aggregation.”
39
U.S. Environmental Protection Agency, “Mandatory Reporting of Greenhouse Gases,” 74 Federal Register 56260,
October 30, 2009.
40
U.S. Environmental Protection Agency, “Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas
Systems,” 75 Federal Register 74458, November 30, 2010, see final rule revision to Subpart W—Petroleum and
Natural Gas Systems—amending 40 C.F.R. §98 (i.e., the regulatory requirements for the Program).
41
In the final rule (40 C.F.R. §98.238), EPA defined “facility” with respect to onshore petroleum and natural gas
production to mean “all petroleum or natural gas equipment on a well pad or associated with a well pad and CO2 EOR
[enhanced oil recovery] operations that are under common ownership or common control including leased, rented, or
contracted activities by an onshore petroleum and natural gas production owner or operator and that are located in a
single hydrocarbon basin [i.e., as defined on a county level and by geologic formation]. Where a person or entity owns
or operates more than one well in a basin, then all onshore petroleum and natural gas production equipment associated
with all wells that the person or entity owns or operates in the basin would be considered one facility.”
42
See EPA’s GHGRP 2011 data on the agency’s website, http://www.epa.gov/ghgreporting/ghgdata/reported/
petroleum.html. The data show 2011 GHG emissions from over 1,800 facilities in the crude oil and natural gas sector,
accounting for 225 MMtCO2e. For a discussion of these measurements in relation to other reported estimates, see
section “Measurement of Emissions” of this report.
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New Source Performance Standards (NSPS). Section 111 of the CAA requires EPA to
promulgate regulations establishing emissions standards that are applicable to new, modified, and
reconstructed sources—if such sources cause or contribute significantly to air pollution that may
reasonably be anticipated to endanger public health or welfare. A performance standard reflects
the degree of emission limitation achievable through the application of the ‘‘best system of
emission reduction’’ (BSER) which EPA determines has been adequately demonstrated. As new
technology advances are made, EPA is required to revise and update NSPS applicable to
designated sources.
The following federal NSPS may apply to crude oil and natural gas systems (some parts have
been rewritten by the August 16, 2012, standards; see the next section and Appendix A for
further discussion):
•
40 C.F.R. Part 60, Subpart JJJJ—Standards of Performance for Stationary Spark
Ignition (SI) Internal Combustion Engines (ICE). Subpart JJJJ applies to
manufacturers, owners, and operators of SI ICE, which affects new, modified,
and reconstructed stationary SI ICE (i.e., generators, pumps, and compressors),
combusting any fuel (i.e., gasoline, natural gas, LPG, landfill gas, digester gas
etc.), except combustion turbines. The applicable emissions standards are based
on engine type, fuel type, and manufacturing date. The regulated pollutants are
NOx, CO, and VOCs, and there is a sulfur limit on gasoline. Subpart JJJJ applies
to facilities operating spark ignition engines at compressor stations;
•
40 C.F.R. Part 60, Subpart IIII—Standards of Performance for Stationary
Compression Ignition (CI) ICEs. Subpart IIII applies to manufacturers, owners,
and operators of CI ICE (diesel), which affects new, modified, and reconstructed
(commencing after July 11, 2005) stationary CI ICE (i.e., generators, pumps, and
compressors), except combustion turbines. The applicable emissions standards
(phased in Tiers with increasing levels of stringency) are based on engine type
and model year. The regulated pollutants are NOx, PM, CO, and non-methane
hydrocarbons (NMHC), while the emissions of sulfur oxides (SOx) are reduced
through the use of low sulfur fuel. Particulate emissions are also reduced by
standards. Subpart IIII applies to facilities operating compression ignition
engines at compressor stations;
•
40 C.F.R. Part 60, Subpart KKK—Standards of Performance for Equipment
Leaks of VOCs from Onshore Natural Gas Processing Plants. Subpart KKK
applies to gas processing plants that are engaged in the extraction of natural gas
liquids from field gas and contains provisions for VOCs leak detection and repair
(LDAR) (this section was revised by the 2012 air standards);
•
40 C.F.R. Part 60, Subpart LLL—Standards of Performance for Onshore Natural
Gas Processing: SO2 Emissions. Subpart LLL governs emissions of SO2 from gas
processing plants, specifically gas sweetening units (which remove H2S and CO2
from sour gas) and sulfur recovery units (which recover elemental sulfur) (this
section was revised by the 2012 air standards); and
•
40 C.F.R. Part 60 Subpart Kb—Standards of Performance for Volatile Organic
Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for which
construction, reconstruction, or modification commenced after July 23, 1984.
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National Emission Standards for Hazardous Air Pollutants (NESHAPs). Section 112 of the
CAA requires EPA to promulgate regulations establishing standards to control emissions of
hazardous air pollutants (HAPs). NESHAPs are applicable to both new and existing sources of
HAPs, and there are NESHAPs for both “major” sources and “area” sources of HAPs. A “major”
source of HAPs is one with the potential to emit in excess of 10 tons per year (tpy) of any single
HAPs or 25 tpy of two or more HAPs combined. Conversely, an “area” source of HAPs is a
stationary source of HAPs that is not major. The aim is to develop technology-based standards
which require levels met by the best existing facilities (commonly referred to as maximum
achievable control technology, or MACT, standards). The pollutants of concern in the oil and gas
sector are primarily the BTEX compounds, formaldehyde, and n-hexane.
The following federal NESHAPs may apply to crude oil and natural gas systems (some parts have
been rewritten by the August 16, 2012, standards; see the next section and Appendix A for
further discussion):
•
40 C.F.R. Part 63, Subpart ZZZZ—National Emission Standards for Hazardous
Air Pollutants for Reciprocating Internal Combustion Engines (RICE);
•
40 C.F.R. Part 63, Subpart H—National Emission Standards for Organic
Hazardous Air Pollutants for Equipment Leaks. Subpart H applies to equipment
that contacts fluids with a HAPs concentration of 5%;
•
40 C.F.R. Part 63, Subpart HH—NESHAPs from Oil and Natural Gas Production
Facilities. Subpart HH controls air toxics from oil and natural gas production
operations and contains provisions for both major sources and area sources of
HAPs. Emission sources affected by this regulation are tanks with flash
emissions (major sources only), equipment leaks (major sources only), and glycol
dehydrators (major and area sources) (this section was revised by the 2012 air
standards);
•
40 C.F.R. Part 63, Subpart HHH—NESHAPs from Natural Gas Transmission
and Storage Facilities. Subpart HHH controls air toxics from natural gas
transmission and storage operations. It affects glycol dehydrators located at major
sources of HAPs (this section was revised by the 2012 air standards); and
•
40 C.F.R. Part 61, Subpart V—National Emission Standard for Equipment Leaks
(Fugitive Emission Sources). Subpart V applies to equipment that contacts fluids
with a volatile HAPs concentration of 10%.
2012 Federal Air Standards for Crude Oil and Natural Gas Systems
On January 14, 2009, two non-governmental organizations filed a complaint under the citizen suit
provision of the CAA, alleging that EPA failed to meet its obligations under CAA Sections
111(b)(1)(B), 112(d)(6) and 112(f)(2) to take actions relative to the review/revision of the NSPS
and the NESHAPs with respect to the “Crude Oil and Natural Gas Production” source category.43
On February 4, 2010, the U.S. Court of Appeals for the D.C. Circuit entered a consent decree
requiring EPA to sign proposed standards and/or determinations not to issue standards by January
31, 2011 (modified to July 28, 2011), and to take final action by November 30, 2011 (modified to
43
WildEarth Guardians, et al. v. Jackson, No. 1:09-CV-00089-CKK (D. D.C.), https://www.federalregister.gov/
articles/2009/12/17/E9-30044/proposed-consent-decree-clean-air-act-citizen-suit.
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April 17, 2012). EPA proposed a new set of air standards for the “Crude Oil and Natural Gas
Production” sector and the “Natural Gas Transmission and Storage” sector on July 28, 2011,44 and
held three public hearings for the proposal. After several court-agreed extensions, the final rules
establishing the new standards were signed by the Administrator on April 17, 2012, were
published in the Federal Register on August 16, 2012,45 and became effective on October 15,
2012. A summary of the 2012 federal air standards is provided below. For a detailed comparison
of the 2012 federal air standards against the prior federal air standards, see Appendix A.
2012 NSPS for Crude Oil and Natural Gas Systems
The 2012 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 source category regulated at the federal level.
The 2012 standards include the following:
•
Gas Wells. The rule covers any gas well that is “an onshore well drilled
principally for production of natural gas” and is “hydraulically fractured.” Oil
wells (i.e., wells drilled principally for the production of crude oil) or
conventional gas wells (i.e., wells drilled without hydraulic fracturing for the
production of natural gas) are not subject to the rule. For fractured and
refractured gas wells, the rule requires owners/operators to use “reduced
emissions completions”—also known as “REC” or “green completions”—to
reduce VOCs emissions during well completions. A REC is defined by EPA as “a
well completion following fracturing or refracturing where gas flowback that is
otherwise vented is captured, cleaned, and routed to the flow line or collection
system, re-injected into the well or another well, used as an on-site fuel source, or
used for other useful purpose that a purchased fuel or raw material would serve,
with no direct release to the atmosphere” (see graphic in Figure 3). To provide
industry enough time to order and manufacture the necessary REC equipment,
the NSPS establishes two phases for compliance. Owners and/or operators may
use either REC or completion combustion devices (e.g., flaring) until January 1,
2015. After January 1, 2015, REC will be required. The rule exempts exploratory,
delineation, and low-pressure gas wells from the REC requirement, stipulating
the use of completion combustion devices instead.46
44
U.S. Environmental Protection Agency, “Oil and Natural Gas Sector: New Source Performance Standards and
National Emission Standards for Hazardous Air Pollutants Reviews,” 76 Federal Register 52738, August 23, 2011.
45
U.S. Environmental Protection Agency, “Oil and Natural Gas Sector: New Source Performance Standards and
National Emission Standards for Hazardous Air Pollutants Reviews, Final Rule,” 77 Federal Register 49489, August
16, 2012, https://www.federalregister.gov/articles/2012/08/16/2012-16806/oil-and-natural-gas-sector-new-sourceperformance-standards-and-national-emission-standards-for.
46
Exploratory well is defined as a well outside known fields or the first well drilled in an oil or gas field where no other
oil and gas production exists; delineation well is defined as a well drilled in order to determine the boundary of a field
or producing reservoir; and low pressure well is defined as a well with reservoir pressure and vertical well depth such
that 0.445 times the reservoir pressure (in psia) minus 0.038 times the vertical well depth (in feet) minus 67.578 psia is
less than the flow line pressure at the sales meter.
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Figure 3. Reduced Emissions Completion Equipment
Source: U.S. Environmental Protection Agency.
Graphic: Dave Merrill/BGOVgraphics, Bloomberg Government, http://www.bgov.com.
•
Storage Vessels. The rule requires individual storage vessels in the crude oil and
natural gas production segment and the natural gas processing, transmission, and
storage segments with emissions equal to or greater than 6 tons per year (tpy) to
achieve at least 95% reduction of uncontrolled VOCs emissions.47
•
Certain Controllers. The rule sets a natural gas bleed rate limit of 6 standard
cubic feet per hour (scfh) for individual, continuous bleed, natural gas-driven
pneumatic controllers located between the wellhead and the point at which the
gas enters the transmission and storage segment. For individual, continuous
bleed, natural gas-driven pneumatic controllers located at natural gas processing
plants, the rule sets a natural gas bleed limit of zero scfh.
•
Certain Compressors. The rule requires a 95% reduction of VOCs emissions
from wet seal centrifugal compressors located between the wellhead and the
point at which the gas enters the transmission and storage segment. The rule also
requires measures intended to reduce VOCs emissions from reciprocating
compressors located between the wellhead and the point where natural gas enters
the natural gas transmission and storage segment. Owners and/or operators of
these compressors must replace the rod packing systems within the compressors
based on specified usage or time.
•
Onshore Natural Gas Processing Plants. The rule revises the existing NSPS
requirements for leak detection and repair (LDAR) to reflect the procedures and
leak thresholds established in the NSPS for equipment leaks of VOCs emissions
in the synthetic organic chemicals manufacturing industry. This rule also revises
the existing NSPS requirements for SO2 emission reductions based on sulfur feed
rate and sulfur content of gas.
47
This section is currently under reconsideration in a proposed rule, U.S. Environmental Protection Agency, “Oil and
Natural Gas Sector: Reconsideration of Certain Provisions of New Source Performance Standards,” 78 Federal
Register 22125, April 12, 2013.
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2012 NESHAPs for Crude Oil and Natural Gas Systems
The 2012 rules revise the NESHAPs for glycol dehydration unit process vents and leak detection
and repair (LDAR) requirements and retain the existing NESHAPs for storage vessels. The 2012
standards include the following:
•
Glycol Dehydration Units. The rule establishes MACT standards for “small”
glycol dehydration units, which were unregulated under the initial NESHAPs.
Covered glycol dehydrators now include those with an actual annual average
natural gas flow rate less than 85,000 standard cubic meters per day (scmd) or
actual average benzene emissions less than 0.9 megagrams per year (Mg/yr), and
they must meet unit-specific limits for benzene, toluene, ethylbenzene, and
xylene (collectively, “BTEX”).48
•
Leak Detection and Repair. The rule lowers the leak definition for valves at
natural gas processing plants from 10,000 parts per million (ppm) to 500 ppm for
major sources at crude oil and natural gas production facilities, thus requiring the
application of LDAR procedures at this level.
Effects of the 2012 Federal Air Standards on State Attainment Planning and
Permitting
With the release of the 2012 air standards for the crude oil and natural gas production,
transmission, and storage sectors, EPA constituted a federally required minimum level of control
for various source categories. States have the flexibility to put their own programs in place or
implement existing programs as long as they are at least as protective as the federal standards.
Attainment Planning. EPA has designated attainment and nonattainment areas for the 2008
ozone National Ambient Air Quality Standards (NAAQS). Some of these areas have significant
crude oil and natural gas activities. States with ozone nonattainment areas are required to submit
modified state implementation plans (SIP) in 2015 and to attain the standard by 2015 and 2018
for areas classified as “marginal” and “moderate,” respectively. A few areas classified as
“serious” nonattainment must attain by 2021. As the 2012 air standards may likely help states
make progress in attaining the ozone NAAQS in nonattainment areas where there is significant
well development, states are allowed to include the federal NSPS as a federally enforceable
strategy in their nonattainment SIP. States may “take credit” for the NSPS in their SIP towards
meeting two requirements: (1) the 2012 standards are expected to achieve 95% control of VOCs
emissions from new gas wells, making it easier for states to obtain the overall reduction in
emissions they need to attain the ozone NAAQS without adding any federal or state permitting
requirements; and (2) SIPs in “moderate” and “serious” areas must also show “reasonable further
progress” in controlling emissions in the years before they attain the ozone NAAQS. In most
areas, states may choose to measure this progress relative to emissions in 2011. In areas that had
wells drilled in 2011 and will continue to have more wells drilled in the years ahead, the 95%
control from the NSPS may provide emission reductions that can be credited toward the
reasonable further progress requirement. In areas that had no or few wells drilled in 2011 but that
48
The final MACT standards for small dehydrators at crude oil and natural gas production facilities require that
existing affected sources at a major source meet a unit-specific BTEX limit of 3.28 × 10−4 grams BTEX/standard cubic
meters (scm)-parts per million by volume (ppmv) and that new affected sources meet a BTEX limit of 4.66 × 10−6
grams BTEX/scm-ppmv.
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will see drilling activity in the future, the 95% control from the NSPS may ensure that emissions
from new well development do not impede meeting the reasonable further progress requirement.
Permitting. The 2012 NSPS regulates all new and modified gas wells whether or not they attain
existing thresholds that define a “major source” for pre-construction permit and Title V operating
permit purposes. In the absence of the NSPS, some hydraulically fractured gas wells could have
emissions above these thresholds in some ozone nonattainment areas. Wells complying with the
2012 NSPS, however, most likely will not trigger major source permitting thresholds. Wells
complying with the 2012 NSPS may also have emissions low enough to avoid needing a minor
source permit from the state, as the NSPS provides a path (i.e., REC) for existing wells that are
refractured to avoid falling under the scope of the NSPS at all, thereby avoiding any automatic
requirement to get a state minor source permit. Nevertheless, states may still include modified
wells in their minor source permitting rules if they choose.
Reported Costs and Benefits of the 2012 Federal Air Standards
Natural gas is a product of—and thus a source of revenue for—the oil and gas industry. It is also a
main source of pollution for the industry when it is emitted into the atmosphere. Due to this
unique linkage, pollution abatement has the potential to translate into economic benefits for the
industry, as producers can offset compliance costs with the value of natural gas and condensate
recovered and sold at market. EPA reports the environmental and the economic benefits of the
2012 air standards as follows:49
•
VOCs Reductions of 190,000 to 290,000 Tons Annually. VOCs emissions
reductions of nearly 95% from hydraulically fractured gas wells are expected to
help reduce ground-level ozone (i.e., smog) in areas where crude oil and natural
gas production occurs.
•
Air Toxics Reductions of 12,000 to 20,000 Tons Annually. The 2012 rules are
intended to protect against potential cancer risks from emissions of several air
toxics, including the BTEX compounds.
•
Methane Reductions of 1.0 Million to 1.7 Million Short Tons Annually.
(Equivalent to 19 to 33 million metric tons of CO2 equivalent (CO2e).) While not
targeted by the 2012 rules, methane reductions from new and modified well
completions and other activities would yield an additional environmental cobenefit.
•
Industry Costs of $170 Million Annually. EPA estimates the rule will cost
producers about $170 million annually in 2015 (in 2008$). Industry and third
party sources have estimated anywhere from $450 million to over $2.8 billion,
depending upon assumptions regarding the number of wells subject to
compliance, the cost of REC equipment and rentals, and the number and cost of
completion combustion requirements.50
49
As reported in U.S. Environmental Protection Agency, “Oil and Natural Gas Sector: New Source Performance
Standards and National Emission Standards for Hazardous Air Pollutants Reviews, Final Rule,” 77 Federal Register
49489, August 16, 2012.
50
For reference, U.S. natural gas producers sold about 24 trillion cubic feet of gas in 2011, with a value of $72.5 billion
at $3/Mcf. Energy Information Administration, U.S. Natural Gas Wellhead Value and Marketed Production,
http://www.eia.gov/dnav/ng/ng_prod_whv_dcu_nus_a.htm.
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•
Net Cost Savings for Industry of $11 Million to $19 Million. EPA estimates
that compliance costs would be offset by the sales of the captured methane and
natural gas liquids, resulting in a net gain of $11 million to $19 million in 2015.
EPA’s cost-benefit analysis, as put forth in its Regulatory Impact Analysis for the
proposed air standards, has been critiqued as both too high and too low by
industry and environmental stakeholders, respectively.51 Industry stresses that the
economic analyses must include the full variety of conditions (e.g., the full range
of VOCs content found across different reservoirs) in upstream production
activities to support all the costs of compliance with the proposed rule; and that
the analysis does not fully take into account the effect that operational standards
(i.e., the requirements for additional green completions and other abatement
equipment) will have on the production and growth of the industry in the near
term.52 Industry claims that fluctuations in the market price of recovered products
may also serve to further depress EPA’s revenue estimates. Conversely,
environmental stakeholders argue that the costs of control used by EPA are
conservative estimates and do not properly account for the full social and
environmental benefits created by the capture of methane.53
Agency Reconsideration of the 2012 Federal Air Standards
On April 12, 2013, EPA announced proposed amendments to the 2012 federal air standards for
the oil and gas sector.54 The proposed rule reconsiders certain issues related to implementation of
the storage vessel provisions and adjusts compliance dates to allow more time for the availability
of control devices. In summary, the proposed rule grants reconsideration of the following: (1) an
extension to the implementation date for the storage vessel provisions (from October 15, 2013, to
April 15, 2014, for new and modified sources after April 12, 2013); (2) definition of “storage
vessel” (to clarify that it refers only to vessels containing crude oil, condensate, intermediate
hydrocarbon liquids, or produced water); (3) definition of “storage vessel affected facility” (to
include the 6 tpy VOC emission threshold); (4) requirements for storage vessels constructed,
modified, or reconstructed during the period from the NSPS proposal date, August 23, 2011, to
April 12, 2013 (to remove the requirement for control devices and to require instead notification
to regulatory agencies by October 15, 2013, of the existence and location of the vessels); (5) an
alternative mass-based standard for storage vessels after extended periods of low uncontrolled
emissions (to include a sustained uncontrolled VOC emission rate of less than 4 tpy as an
alternative emission limit to the 95% control in the final NSPS under specified circumstances).
51
For further discussion on costs, see section “Cost Benefit Analysis of Federal Standards.”
For an example of industry comments on the cost analysis, see comments to “Oil and Natural Gas Sector: New
Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews,” submitted by
Howard J. Feldman, Director, Regulatory and Scientific Affairs, American Petroleum Institute, November 30, 2011,
accessed on http://www.regulations.gov.
53
For an example of environmental stakeholder comments on the cost analysis, see comments to “Oil and Natural Gas
Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews,”
submitted by Sierra Club, et al., November 30, 2011, accessed on http://www.regulations.gov.
54
U.S. Environmental Protection Agency, “Oil and Natural Gas Sector: Reconsideration of Certain Provisions of New
Source Performance Standards,” 78 Federal Register 22125, April 12, 2013.
52
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Issues for Congressional Consideration
The expansion of both industry production and government regulation of natural gas systems has
sparked discussion on a number of outstanding issues. Some of the more significant debates
involving air quality concerns are outlined in the sections below.
The Regulatory Role of Federal, State, and Local Governments
According to EPA, the 2012 federal air standards are designed to provide minimum requirements
for emissions of air pollutants from the crude oil and natural gas sector that can both protect
human health and the environment and allow for continued growth in production. However, some
believe that state and local governments are better positioned to develop these emission standards.
They claim that states can more readily address the regional and state-specific character of many
crude oil and natural gas activities, including differences in geology, hydrology, climate,
topography, industry characteristics, development history, state legal structures, population
density, and local economics, and the effects these components have on air quality. They argue
that federal rules add unnecessary and often repetitive requirements on the industry, which may
increase project costs and delays with little added benefit. Others, attesting to the “patchwork” of
state and local requirements, support the need for the federal government to institute minimum
standards for emissions that are consistent, predictable, and reach across state lines. They claim a
federal standard would extend regulatory certainties to the industry and would best ensure health
and environmental protections for all stakeholders. They also contend that many state laws and
state agencies are still gaining experience with unconventional oil and natural gas development,
and that industry is operating under insufficient and outdated rules. In light of these
considerations, Congress may choose to re-examine proposed and/or existing federal
requirements apropos of existing state and local regulations, or introduce new federal
requirements if deemed necessary.
Currently, states lead the day-to-day permitting, monitoring, and enforcement of crude oil and
natural gas development, and any federal requirements that might apply have typically been
delegated to the states. In general, each state has one or more regulatory agencies that may permit
wells, including their design, location, spacing, operation, and abandonment, and may regulate for
environmental compliance, including water management and disposal, air emissions,
underground injection, wildlife impacts, surface disturbance, and worker health and safety. The
organization of regulatory agencies within the various oil and gas producing states varies
considerably. In many cases, state agencies were established initially to provide a structure to
facilitate—not regulate—oil and gas development. These facilitatory agencies served primarily to
provide a central state system for administering resource claims and mediating disputes. In some
instances, these agencies have taken on oversight activities for environmental protection. In other
instances, they have operated alongside a separate agency that has been mandated to prevent
environmental pollution and public health impacts.
For example, Colorado provides multiple state agencies with different authorities to regulate
industry operations. The Colorado Department of Public Health and Environment (CDPHE) and
the Colorado Department of Natural Resources maintain separate but complementary oversight of
industry operations. Colorado’s Air Quality Control Commission (under CDPHE) has regulations
to address emissions from tanks, engines, compressors, and associated equipment. Colorado’s Oil
and Gas Conservation Commission has regulations pertaining to such issues as well completions,
odors, noise, and drill rig setbacks. Conversely, Pennsylvania’s Department of Environmental
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Protection (DEP) Office of Oil and Gas Management is responsible for all statewide oil and gas
programs. The office manages activities both to facilitate the exploration, development, and
recovery of Pennsylvania’s oil and gas reservoirs while also overseeing the protection of the
commonwealth’s natural resources and environment. The office develops policy and programs for
the regulation of oil and gas development pursuant to the commonwealth’s Oil and Gas Act, the
Coal and Gas Resource Coordination Act, and the Oil and Gas Conservation Law. It oversees the
oil and gas permitting and inspection programs, develops statewide regulation and standards,
conducts training programs for industry, and works with the Interstate Oil and Gas Compact
Commission and the Technical Advisory Board.
All crude oil and natural gas producing states have laws in place related to oil and gas
development. Most state requirements are written into rules or regulations. Requirements may
also be added to permits on a case-by-case basis as a result of findings from environmental
reviews, on-the-ground inspections, public comments, or commission hearings. For example,
emissions from oil and gas development in Colorado are governed primarily by statutory
provisions of the Oil and Gas Conservation Act (Colo. Rev. Stat. §34-60-100, et seq.), Colorado’s
Air Pollution and Prevention Control Act (§25-7-100, et seq.), and Water Quality Control Act
(§25-8-100, et seq.). In other states, such as Montana or Texas, emissions from oil and gas
development are addressed most prominently during permitting, registration, and authorization
activities (e.g., Montana Department of Environmental Quality, Air Quality Permits [MAQP],
under Rule 17.8.752, and Montana Registration Requirements, under Rule 17.8.1711[1][a]; or
Texas Commission on Environmental Quality, Permit by Rule [PBR], Standard Permit, and New
Source Review [NSR] Permit, under Title 30, Texas Administration Code, Chapter 116, et seq.).
Most state oil and gas regulations were written well before unconventional natural gas
development became widespread. A number of major gas producing states have recently revised
regulations, with particular focus on emerging areas of concern, including disclosure of hydraulic
fracturing chemicals, well construction and operation to prevent aquifer contamination, and
management of waste from flowback and produced water. Similarly, many states and counties
have some regulatory structures to address air quality issues based on each jurisdiction’s
individual circumstance. Some states and counties have adopted relatively stringent standards,
while others have not. Some have rules proposed or are in the process of revising or
implementing them. Others are considering rolling back existing regulations.55 EPA’s 2012
federal air standards were drawn primarily from existing requirements found in the state codes of
Colorado and Wyoming. For a comparison of EPA’s 2012 air standards for source categories in
the crude oil and natural gas industry to those from selected states, see Table A-4 of this report.
Critics of federal oversight maintain that the states have long regulated oil and gas exploration
and production and are best positioned to continue to do so as they have established governing
structures and trained staff in place. They argue that a distant federal bureaucracy unfamiliar with
local conditions is rarely the best entity to ensure environmental needs are balanced with
economic growth and job creation. They claim that states can more readily address the regional
and state-specific character of many crude oil and natural gas activities, including differences in
geology, hydrology, climate, topography, industry characteristics, development history, state legal
structures, population density, and local economics. Critics argue that federal rules add
55
For example, see New Mexico’s current efforts to loosen regulations on pits for waste or drill cuttings and the use of
steel tanks as part of a “closed loop” system, Mike Soraghan, “N.M. is loosening drilling rules, bucking trends and
riling ranchers,” E&E News, Thursday, November 15, 2012, http://www.eenews.net/energywire/2012/11/15/1.
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unnecessary and often repetitive requirements on the industry, which may increase project costs
and delays with little added benefit. They claim federal rules would require increased federal
resources and skilled staff to administer regulations for oil and gas development (or, as is
sometimes the case, to administer federal requirements redundantly alongside existing state
programs). They contend that a well-run state permitting and regulatory program can adjust more
quickly, is better positioned to meet the challenges presented by constantly developing
technologies, and can effectively administer rules across private, state, and federal lands.56
Others note that it has neither been the practice nor the intention of EPA to administer regulations
for oil and gas development at the state level. However, seeing the patchwork mix of state and
local requirements, they have called for the federal government to institute a minimum
nationwide standard for emissions from the crude oil and natural gas sector. Proponents of federal
oversight contend that many state laws and state agencies are still gaining experience with
unconventional oil and natural gas development, and that industry is operating under insufficient
and outdated rules.57 They claim that many of the agencies that regulate development at the state
level are underfunded and understaffed, are tasked with the dual purposes of developing the
state’s resources and protecting the state’s environment, and thus, are caught between policing
and promoting the industry. They suggest that state agencies and state regulators are often
overwhelmed by oil and gas companies, which are generally national or international in scope,
and start with the advantage of sheer size. They point to examples where state regulators have
failed to seek large penalties for violations or track enforcement data, and cite statistics that show
40% of state drilling regulators have industry ties.58 A 2012 report, released by a nongovernmental environmental organization, surveyed active oil and gas wells in six states and
summarized the findings as follows: (1) over half (or close to 350,000 active wells in 2010) are
operating with no independent inspections to determine whether they are in compliance with state
rules; (2) when inspections do uncover rule violations, the violations often are not formally
recorded; (3) when violations are recorded, they result in few penalties; (4) when penalties are
assessed, they provide little incentive for companies to not offend again (noting that no state
assessed annual fines that added up to the average value of a single gas well, about $2.9
million).59
56
For example, see the comments made by Wyoming governor Matthew Mead, as reported in the Washington Times:
Matthew Mead, “Commentary: Hydro-fracking regulations should be left to states,” Washington Times, September 17,
2012, http://www.washingtontimes.com/news/2012/sep/17/hydro-fracking-regulations-should-be-left-to-state/
#ixzz26uwFzyr3.
57
For example, see the comments made by Peter Zalzal, Environmental Defense Fund, “National Clean Air Standards
For The Oil And Gas Industry Provide a Trifecta,” EDF Energy Exchange, March 20, 2012, http://blogs.edf.org/
energyexchange/2012/03/20/national-clean-air-standards-for-the-oil-and-gas-industry-provide-a-trifecta/.
58
As reported in Mike Soraghan, “Puny fines, scant enforcement leave drilling violators with little to fear,” E&E News,
Monday, November 14, 2011, http://www.eenews.net/Greenwire/2011/11/14/archive/1; Mike Soraghan, “40% of state
drilling regulators have industry ties,” E&E News, Monday, December 19, 2011, http://www.eenews.net/Greenwire/
ground_rules/2011/12/19/1. The reporting found that in Texas, 96% of the 80,000 violations by oil and gas drillers in
2009 resulted in no enforcement action. West Virginia, a state with 56,000 wells, issued 19 penalties last year. And
Wyoming, the center of Rocky Mountain development, collected $15,500 in fines in 2010. Pennsylvania sought
penalties for more than a quarter of the violations found last year, but levied fines for only 4% of the violations, with
the penalties totaling $3.7 million. Further, the reporting reviewed the backgrounds of 95 oil and gas commissioners,
board members and agency heads in the top 27 oil and gas states, and found, 39 had an oil and gas background, or 41%.
59
Lisa Sumi, Breaking All the Rules: The Crisis in Oil & Gas Regulatory Enforcement, Earthworks, Washington, DC,
September 25, 2012, http://www.earthworksaction.org/library/detail/
breaking_all_the_rules_the_crisis_in_oil_and_gas_regulatory_enforcement.
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Covered Sources and Pollutants
The 2012 federal air standards focus primarily on the upstream sectors of the oil and gas industry
and cover only some of the pollutants and potential sources of emissions. The standards regulate
emissions of VOCs from some, but not all, of the equipment and activities at onshore natural gas
well sites, gathering and boosting stations, and processing plants. Similarly, the standards regulate
emissions of SO2 from sweetening units at some natural gas processing plants, as well as HAPs
from some dehydration units and storage facilities in the sector. Some pollutants from natural gas
systems remain uncovered by any federal law or regulation, and critics point specifically to
methane emissions from the midstream and downstream sectors, as well as hydrogen sulfide, as
the most significant omissions. The scope of the 2012 federal standards are the result of several
factors, including (1) EPA-conducted cost-benefit and risk analyses, (2) stakeholder comments
provided to the agency during rulemaking, and (3) statutory limitations placed upon the agency
by provisions in the CAA. In light of these considerations, Congress may decide to re-examine
ways in which oversight activities address the most significant pollutants and point sources.
While the 2012 air standards for crude oil and natural gas systems are more detailed and
comprehensive than previous standards, several pollutants and sources in the sector remain
uncovered.
The 2012 standards do not directly cover emissions of the following pollutants in the sector:
methane, nitrogen oxides, particulate matter, and hydrogen sulfide (although reductions in some
of these pollutants may occur as a co-benefit of VOCs and SO2 reductions). Many observers have
noted, however, that the 2012 standards, as written, use natural gas emissions as a surrogate for
VOCs and H2S/SO2 emissions. Some argue that basing standards on the volume of natural gas
emissions as opposed to the content of VOCs in the gas does not adequately account for the
geographic variability of VOCs within the resource (e.g., EPA calculated cost effectiveness based
on a national average of 3.7% VOCs by volume [18% by weight] for natural gas streams;
however, many streams may produce little or no VOCs). Critics of the rule maintain that
requiring standards for natural gas emissions as opposed to VOCs content essentially regulates
the industry for methane as opposed to VOCs. From this perspective, requiring an operational
standard (e.g., reduced emissions completions) instead of a performance standard (e.g., a VOCs
threshold) may impose unnecessary compliance costs in some instances.60 The 2012 standards do
address the smaller volume of VOCs in natural gas streams after the processing stage by
exempting many activities and pieces of equipment in the transmission, storage, and distribution
sectors of the industry.
Further, the 2012 standards do not cover emissions from the following sources in the sector: all
oil wells; all off-shore sources; all coal-bed methane production facilities; all field engines,
drilling rig engines, and turbines; well-head and transmission and storage segment compressors;
well-head activities such as liquids unloading; all heater-treaters; all pneumatic devices other than
controllers; storage vessels such as skid-mounted, mobile, well cellars, sumps, and produced
water ponds; and LDAR for non-processing plant facilities. Additionally, the 2012 standards do
not cover VOCs or SO2 emissions from existing sources, unless they are classified as HAPs.
Finally, the 2012 standards assume non-gas-driven controllers cannot replace gas-driven
controllers as “best system of emission reduction” (BSER) for regulatory purposes; low-bleed
controllers cannot replace high-bleed controllers as BSER; centrifugal compressors cannot
60
See comments submitted by Howard J. Feldman, API, op cit.
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replace reciprocating compressors as BSER; and vapor recovery units cannot replace combustion
devices as BSER. Many of these sources may still emit significant quantities of pollutants;
however, EPA has determined that standards on these sources are either technically or
economically unfeasible.61
Major Source Aggregation
The 2012 federal air standards exempt well completions, pneumatic controllers, compressors, and
storage vessels from “major source” determination with respect to CAA Title V permit
requirements. Viewed at the component level, these smaller “emissions units” at natural gas
facilities may not generate enough pollution on their own to be classified as “major sources.”
However, it may be possible that an entire natural gas operation (e.g., a well site, a field, or a
station) is a “major source” (i.e., one that emits typically 10 tons to 250 tons per year, depending
upon the pollutant and the area’s attainment status). Determining which equipment and activities
should be grouped together, or “aggregated,” in the crude oil and natural gas sector for permitting
purposes remains an open issue for the states, the courts, EPA, and the regulated entities. In light
of these considerations, Congress may further assess EPA’s requirements for major source
categories in upstream oil and gas activities.
The past few decades have seen several developments in the evaluation of crude oil and natural
gas facilities at multiple locations for possible aggregation into a single source for permitting
purposes. The ability of EPA and the state permitting authorities to aggregate multiple operations
into a single major source permit is founded upon the definition of “stationary source” within the
CAA. The CAA defines a “stationary source” as “any building, structure, facility, or installation
which emits or may emit any air pollutant.”62 Alabama Power Co. v. Costle63 established
boundaries on the scope of a source such that “(1) it must carry out reasonably the purposes of
New Source Review/Prevention of Significant Deterioration (NSR/PSD); (2) it must approximate
a common sense notion of ‘plant’; and (3) it must avoid aggregating pollutant-emitting activities
that as a group would not fit within the ordinary meaning of ‘building,’ ‘structure,’ ‘facility,’ or
‘installation.’”64 In response, in the 1980 revisions to the PSD regulations, EPA clarified that
emissions from operations may be aggregated and considered a single major source for PSD
permitting if they meet each of the following three criteria: (1) the sources are located on one or
more “contiguous or adjacent” properties, (2) the sources are under common control of the same
person (or persons under common control), and (3) the sources belong to a single major industrial
grouping (same two digit major Standard Industrial Classification (SIC) code). Only if all three
criteria are met will the CAA permitting authority aggregate the operations into a single
NSR/PSD permit. After the 1990 CAA Amendments created the Title V Operating Permit
Program, this three-factor analysis was extended to Title V major source permitting.
The source definition established by EPA was intended to aggregate only “major projects that
would cause air quality deterioration” but “avoid review of projects that would not increase
deterioration significantly.”65 EPA has recently addressed the issue of CAA source determinations
61
See comments submitted by Sierra Club, op cit.
42 U.S.C. §7411 (a)(3).
63
Alabama Power Co. v. Costle, 636 F.2d 323 (D.C. Cir. 1979).
64
45 Federal Register 52676, August 7, 1980.
65
45 Federal Register 52676, August 7, 1980.
62
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in the oil and gas industry in a 2009 guidance document from the EPA Office of Air and Radiation
(the “McCarthy Memo”).66 The McCarthy Memo withdrew earlier guidance from EPA which
concluded that the three prong aggregation analysis for oil and gas activities should begin by
looking at and focusing most heavily on the proximity of the surface locations. This emphasis on
proximity may have been a result of previous actions by EPA that interpreted “contiguous and
adjacent” as meaning “functionally interdependent” (e.g., sources connected by pipelines,
conveyors, roads, and other means by which materials and products or intermediate products are
transferred between them). The McCarthy Memo attempted to negotiate a path between the broad
mandate of “functional interdependence” and the more narrow use of “proximity.” It recognized
that source determinations in the oil and gas industry continue to be complex, and re-emphasized
that the regulations list all three criteria to be used in the analysis. It then acknowledged that there
would be cases in which proximity is the “overwhelming factor,” but the agency is not going to
pre-judge that by using a simplified approach, and that “reasoned decision-making” of each of the
relevant factors needs to occur on a case-by-case basis.
EPA’s three prong aggregation analysis for oil and gas activities was recently challenged in the
case of Summit Petroleum Corp. v. EPA before the U.S. Court of Appeals for the 6th Circuit.67 In
an August 7, 2012, decision, the 6th Circuit rejected 2-1 the agency’s “functional
interrelationship” analysis used to support its definition of “adjacency,” vacating EPA’s
determination that a Michigan natural gas plant and its production wells constitute a single major
source. Further, on October 29, the court issued an order denying EPA’s motion to rehear the case.
The denial cements the appellate court’s ruling, remanding the issue back to EPA, and ordering
the agency to conduct a new analysis of the Michigan facilities using physical proximity as the
sole basis for determining adjacency. In response, EPA has stated that relying on physical
proximity alone may lead both to “absurd results” and increased regulatory burdens under the
NSR and PSD programs.68 The agency announced that it plans to implement the 6th Circuit’s
ruling solely in the 6th Circuit states of Michigan, Ohio, Tennessee, and Kentucky.69
Contrary to this, source determinations for NESHAPs in the sector are clearly outlined in the
CAA. In Section 112(n)(4), Congress specifically exempted upstream oil and gas operations from
aggregation in several ways. First, with respect to the “major source” category, Section 112(n)(4)
of the CAA provides that, notwithstanding the general definition of “major source,”
emissions from any oil or gas exploration or production well (with its associated equipment)
and emissions from any pipeline compressor or pump station shall not be aggregated with
emissions from other similar units, whether or not such units are in a contiguous area or
66
See “Withdrawal of Source Determinations for Oil and Gas Industries,” memorandum from Gina McCarthy to
Regional Administrators, September 22, 2009, withdrawing the 2007 EPA memo “Source Determinations for Oil and
Gas Industries,” memorandum from William L. Wehrum to Regional Administrators, January, 12, 2007.
67
Summit Petroleum Corp. v. EPA, 6th Cir., Nos. 09-4348, 10-4572, 8/7/12.
68
For example, the agency argues that the Summit ruling could actually lead to increased regulatory burdens under the
NSR and PSD programs because permitting obligations are triggered by modifications at a source that result in net
emission increases. Under the program, facilities can reduce emissions from another unit at that source to balance out
emissions increases and avoid the trigger. EPA also says that relying on physical proximity alone will lead to “absurd
results,” saying that regulators as a result of the vacatur would have to consider a group of oil wells that are located
near a series of gas wells and owned by the same operator to be one source although they emit different streams of
pollutants.
69
See “Applicability of the Summit Decision to EPA Title V and NSR Source Determinations,” memorandum from
Stephen Page, Director of the Office of Air Quality Planning and Standards, to Regional Administrators, December 21,
2012, http://cleanenergyreport.com/iwpfile.html?file=jan2013%2Fepa2013_0040.pdf.
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under common control, to determine whether such units or stations are major sources, and in
the case of any oil or gas exploration or production well (with its associated equipment),
such emissions shall not be aggregated for any purpose under this section.
Second, with respect to the “area source” category, Section 112(n)(4) provides that
the Administrator shall not list oil and gas production wells (with its associated equipment)
as an area source category under subsection (c), except that the Administrator may establish
an area source category for oil and gas production wells located in any metropolitan
statistical area or consolidated metropolitan statistical area with a population in excess of 1
million, if the Administrator determines that emissions of hazardous air pollutants from such
wells present more than a negligible risk of adverse effects to public health.
At the time, the 101st Congress (1990) found that
oil and gas wells, and associated equipment and gas processing, have generally very low
emissions of air toxics. Furthermore, these operations are typically located in remote areas,
with wells and equipment widely dispersed geographically, rather than concentrated in a
single area. For these reasons, it is very unlikely that oil and gas sources would present a
significant risk to human health and it is not expected that this source category would need to
be a listed category designated for regulation.70
In response, EPA wrote in the 1999 preamble that the definition of facility should “lead to an
aggregation of emissions in major source determinations that is reasonable, consistent with the
intent of the Act, and easily implementable.” Consequently, EPA determined it was not
appropriate to aggregate crude oil and natural gas facilities at that time.71
Measurement of Emissions
The 2012 federal air standards are based on EPA’s emission estimates for the crude oil and natural
gas sector. While emissions from certain activities and equipment lend themselves to credible
estimates, others—specifically fugitive emissions from production activities such as hydraulically
fractured well completions, flowback, and produced water ponds—are more difficult to evaluate,
have fewer data available, and remain under considerable debate. Currently, the primary source of
information on emissions from the sector is a methane study published in 1996 by EPA and the
Gas Research Institute (GRI). EPA annually calculates industry emissions using the methodology
derived from this report, and while many of the factors have been representative over the period
of 1992 to the present, several have been recalculated due to new information. EPA’s inventory
has been criticized by industry groups and other sources, many of which have put forth
competing, and sometimes conflicting, estimates over the past few years. At this time, a
comprehensive national inventory that directly measures the quantity and composition of fugitive
emissions from natural gas systems does not exist. Until there is an adequate and reliable
assessment of industry-wide emissions, the benefits, costs, and basis for regulation may remain
70
Representative Jack Fields (R-TX-08), Conference Report on S. 1630, Clean Air Act Amendments of 1990 (House
of Representatives - October 26, 1990), Congressional Record, vol. 136, p. H12868.
71
U.S. Environmental Protection Agency, “National Emission Standards for Hazardous Air Pollutants: Oil and Natural
Gas Production and National Emission Standards for Hazardous Air Pollutants: Natural Gas Transmission and
Storage,” 64 Federal Register 32610, June 17, 1999.
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uncertain. In light of these considerations, Congress may examine ways in which to best facilitate
more comprehensive and technically accurate emissions estimates.
By definition, “fugitive” emissions are those which are elusive and transitory. Thus, the single
greatest difficulty in estimating emissions from natural gas systems is acquiring comprehensive
and consistent measurement data. Currently, the most comprehensive study of emissions in the
industry is more than a decade old, uses emissions factors and activity levels to calculate data,
and focuses primarily on methane. EPA has initiated a more detailed inventory of the oil and gas
sector’s GHG emissions (i.e., methane and CO2) under the agency’s GHG Reporting Rule, and
the first data for major sources were released in February 2013.72 National emissions inventories
for criteria and hazardous air pollutants, however, are distinct from GHG inventories and are
complicated by the fact that concentrations of these chemicals vary geographically across
resource reservoirs. A few states have begun the process of acquiring emissions inventories from
upstream production activities (e.g., Texas,73 Pennsylvania,74 California,75 and Colorado,76 as well
as a national survey to be conducted by the University of Texas at Austin),77 but few have
presented or harmonized this information. There are also many examples of local emissions
inventories, commissioned by a range of stakeholders—from regional and municipal agencies to
community groups and academic institutions. None are fully consistent with shared measurement
practices and each use different techniques for their data collection. It is for these reasons that the
first recommendation in the report released by the U.S. Secretary of Energy Advisory Board
Shale Gas Production Subcommittee is to “immediately launch projects to design and rapidly
implement measurement systems to collect comprehensive methane and other emissions data.”78
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).79 At the time, the EPA/GRI
study was conducted to assess the GHG emissions from various U.S. industrial sectors to assist in
72
See EPA’s GHGRP 2011 data on the agency’s website, http://www.epa.gov/ghgreporting/ghgdata/reported/
petroleum.html.
73
See Texas Commission on Environmental Quality, Barnett Shale Special Inventory, http://www.tceq.texas.gov/
assets/public/implementation/air/ie/pseiforms/summarydatainfo.pdf.
74
See Pennsylvania Department of Environmental Protection announced protocol, http://files.dep.state.pa.us/Air/
AirQuality/AQPortalFiles/Long-Term_Marcellus_Ambient_Air_Monitoring_Project-Protocol_for_Web_2012-0723.pdf.
75
See California Environmental Protection Agency, Air Resources Board, 2007 Oil and Gas Industry Survey Results,
Final Report, December 2011, and other relevant documents on the ARB website, http://www.arb.ca.gov/cc/oil-gas/oilgas.htm.
76
See Colorado Department of Natural Resources press release, “State to undertake major study on oil and gas
emissions,” January 9, 2013, http://dnr.state.co.us/Media/Pages/PressReleases.aspx.
77
The University of Texas at Austin, along with two environmental engineering firms, URS and Aerodyne Research,
announced on October 10, 2012, the launch of a comprehensive study of methane emissions around gas wells.
Researchers are to focus on gas production sites in the Marcellus, Eagle Ford, Haynesville, Barnett, Fayetteville, and
Niobrara shale formations. Nine oil and gas companies have agreed to allow sampling teams onto their sites: Anadarko
Petroleum Corp., BG Group PLC, Chevron Corp., Encana Oil & Gas (USA) Inc., Pioneer Natural Resources Co., Shell
Oil Co., Southwestern Energy, Talisman Energy and XTO Energy, a subsidiary of Exxon Mobil Corp. The announced
study is part of a broader five-part investigation to measure methane leakage across the natural gas supply chain,
http://www.utexas.edu/news/2012/10/10/university-of-texas-at-austin-study-measures-methane-emissions-releasedfrom-natural-gas-production/.
78
Secretary of Energy Advisory Board Shale Gas Production Subcommittee, Shale Gas Production Subcommittee 90Day Report, p.16.
79
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.
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data analysis for the Intergovernmental Panel on Climate Change and emissions reporting for
U.S. commitments to the United Nations Framework Convention on Climate Change.80 The study
focuses on 1992 (as a base year) and uses three primary methodologies to generate emissions
factors from over 100 different sources within the industry. The methods include (1) “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; (2) “tracer
gas,” wherein facility-wide emissions are calculated by releasing a tracer gas at a known and
constant rate near the facility and measuring the downwind concentrations of the tracer and
methane; and (3) “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. The EPA/GRI study estimates that the industry emitted
314 ± 105 billion standard cubic feet (bscf) of methane in 1992 (i.e., 127 ± 42 million metric tons
of carbon dioxide equivalent [MMtCO2e], or 1.42% ± 0.47% of the industry’s gross national
production that year).81 Roughly 60% of the industry’s methane emissions are estimated to be
from fugitive sources, about 30% from venting, and about 8% from combustion. Results of the
EPA/GRI study, by source categories, are reported in Table 1.
EPA annually calculates emissions estimates for the industry using the methodology from the
1996 EPA/GRI study. Since its publication, activity data for some of the components in the
system have been updated based on publicly available information. For other sources where
annual activity data are not available or have not been reported by industry, EPA has developed a
set of industry activity factor drivers to assist in modeling. While many of the emissions factors
modeled by the EPA/GRI study were considered representative over the period of 1992 to the
present, several factors have been re-calculated since publication. Most notably, emissions factors
for gas well cleanups, condensate storage tanks, and centrifugal compressors have been revised
due to new information. Emissions factors for gas well completions in unconventional resources
with hydraulic fracturing—which were not industry practice at the time of the EPA/GRI study—
have also been added to the inventory. With these revisions, EPA estimates that the industry
emitted 247.7 million metric tons of carbon dioxide equivalent (MMtCO2e) greenhouse gases in
2010, of which 215.4 MMtCO2e was methane (i.e., 532 bscf of methane, or 2.4% of the
industry’s gross national production that year).82
80
UNFCCC, Treaty Number: 102-38, October 7, 1992, the resolution of advice and consent to ratification agreed to in
the Senate by Division Vote. For more discussion of U.S. commitments, see CRS Report R40001, A U.S.-Centric
Chronology of the International Climate Change Negotiations, by (name redacted).
81
314 bscf of methane is equivalent to approximately 127 million metric tons of carbon dioxide equivalent (MMtCO2e)
greenhouse gases, using the conversion 1000 bscf CH4 = 0.4045 MMtCO2e at 60 degrees Fahrenheit (15.6 degrees
Celsius) and either 14.696 psi (1 atm or 101.325 kPa) or 14.73 psi (30 inHg or 101.6 kPa) of pressure.
82
U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010,
Washington, DC, EPA 430-R-12-001, April 15, 2012, http://www.epa.gov/climatechange/Downloads/ghgemissions/
US-GHG-Inventory-2012-Main-Text.pdf. Conversion factor of 1000 bscf CH4 = 0.4045 MMtCO2e at 60 degrees
Fahrenheit (15.6 degrees Celsius) and either 14.696 psi (1 atm or 101.325 kPa) or 14.73 psi (30 inHg or 101.6 kPa) of
pressure. The U.S. Energy Information Administration reports 2010 U.S. natural gas marketed production as 22,402
bscf, see http://www.eia.gov/dnav/ng/hist/n9050us2a.htm.
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Table 1. Methane Emissions in the U.S. Natural Gas Industry
For the base year 1992
Annual Methane
Emissions (Bscf)
% of Total
195.3
62.1
Production Facilities
17.4
5.5
Gas Plants
24.4
7.8
Compressor Stations (transmission and storage)
67.5
21.5
Metering and Pressure Regulating Stations
31.8
10.1
Customer Meter Sets
5.8
1.8
48.4
15.4
94.2
30.0
Pneumatic Devices
45.7
14.6
Blow and Purge
30.2
9.6
Dehydrator Glycol Pumps
11.1
3.5
Dehydrator Vents
4.8
1.5
Chemical Injection Pumps
1.5
0.5
Other
0.9
0.3
24.9
7.9
24.9
7.9
314.0
100.0
Source
Fugitive Emissions
Subtotal
Equipment Leaks
Underground Pipeline Leaks (all segments)
Vented Emissions
Combusted Emissions
Subtotal
Subtotal
Compressor Exhaust
Total
Source: David A. Kirchgessner et al., Estimate of Methane Emissions from the U.S. Natural Gas Industry, U.S.
Environmental Protection Agency, Air Pollution Prevention and Control Division, Research Triangle Park, NC,
1996, p. 12.
Notes: Emissions from meter and pressure regulating stations result from both pneumatic and fugitive
emissions. Since these components cannot be separated using the tracer measurement method, emissions are
shown as fugitive by default.
The emissions estimates EPA uses for hydraulically fractured well completions and recompletions come from data provided by industry sources at several EPA Natural Gas STAR
technology transfer workshops between 2004 and 2007.83 Using the reported data in its 2010
Background Technical Support Document, Greenhouse Gas Emissions Reporting from the
Petroleum and Natural Gas Industry,84 EPA creates separate categories for conventional and
83
The figures were drawn from four studies over two workshops that included data from over 1,000 wells completed
between 2002 and 2006. U.S. Environmental Protection Agency, “Green Completions,” Natural Gas STAR Producers’
Technology Transfer Workshop, September 21, 2004, and U.S. EPA, “Reducing Methane Emissions During
Completion Operations,” Natural Gas STAR Producers’ Technology Transfer Workshop, September 11, 2007. The
presentations included a Devon case study from the Fort Worth Basin (30 wells, 11,900 Mcf/completion), a Williams
case study from the Piceance Basin (1,064 wells, 24,449 Mcf/completion), a Weatherford coal bed methane case study
(3 wells, 667 Mcf/completion), and a nationwide industry data set (106 wells, 5,820 Mcf/completion). For more on the
EPA Natural Gas STAR program, see http://www.epa.gov/gasstar/.
84
U.S. Environmental Protection Agency, Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas
(continued...)
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unconventional well completions, and increases its estimate of methane emissions from both
categories from 0.02 metric tons per well completion to 0.71 metric tons per conventional well
and 177 metric tons per unconventional well (or 37 thousand cubic feet [Mcf]/completion and
9,175 Mcf/completion respectively). EPA assumes a 3-10 day flowback period with an
uncontrolled release of methane. Further, EPA assumes that 51% of the fugitive emissions from
hydraulically fractured well completions are flared—and the rest vented—based upon state and
local regulations for control devices that are currently in place.
EPA’s methodology for estimating methane emissions from hydraulically fractured well
completions has been criticized by a number of sources. A detailed critique of EPA’s numbers can
be found in IHS CERA’s 2011 report, Mismeasuring Methane: Estimating Greenhouse Gas
Emissions from Upstream Natural Gas Development.85 CERA’s main concerns involve the small
sample size for emissions data and the unsupported assumptions on venting practices. Further,
several industry sources have reported competing emissions estimates, including the American
Petroleum Institute and the America’s Natural Gas Alliance (which list total industry emissions at
half of EPA’s estimate due to a re-calculation of emissions factors and activity levels for liquids
unloading86 and re-fractured well completions),87 URS (which estimates emissions of 765 Mcf of
gas on a per well basis compared to EPA’s 9,175 Mcf),88 and Devon Energy Company (which
reports data from eight of its operators demonstrating that flowback periods last on average only
3.5 days compared to EPA’s estimated 3-10 days).89 As with any self-selected and self-reported
survey, it is difficult to determine how representative these samples are of overall industry
practice.
(...continued)
Industry: Background Technical Support Document, Climate Change Division, Washington, DC, 2010,
http://www.epa.gov/ghgreporting/documents/pdf/2010/Subpart-W_TSD.pdf.
85
IHS CERA estimates methane emissions from the oil and gas “production” sector to be 43 MMtCO2e as opposed to
EPA’s estimate of 130 MMtCO2e from “field production.” See Mary Barcella, Samantha Gross, and Surya Rajan,
Mismeasuring Methane: Estimating Greenhouse Gas Emissions from Upstream Natural Gas Development, IHS CERA,
Private Report, Cambridge, MA, 2011, http://press.ihs.com/press-release/recent-estimates-greenhouse-gas-emissionsshale-gas-production-are-likely-significantl.
86
“Liquids unloading” is a maintenance activity in depleted conventional reservoirs where water produced with the gas
has accumulated to the point where it stops gas flow. In order to reestablish gas flow, the well is blown to the
atmosphere, causing the vented release of emissions. The 2011 GHG Inventory has this category listed for contributing
approximately 34% of all methane emissions from the natural gas industry for that year.
87
Terri Shires and Miriam Lev-On, Characterizing Pivotal Sources of Methane Emissions from Unconventional
Natural Gas Production: Summary and Analysis of API and ANGA Survey Responses, Final Report, June 1, 2012,
http://www.api.org/news-and-media/news/newsitems/2012/oct-2012/~/media/Files/News/2012/12-October/APIANGA-Survey-Report.pdf. The authors present data reported by over 20 of their industry partners from over 91,000
wells (or 20% of known wells in operation) demonstrating that a re-calculation of two of EPA’s source categories—
liquids unloading and unconventional gas re-fracture rates—returned a 50% reduction in industry emissions compared
to EPA’s estimate. The study did not report any new estimates for the quantity of emissions from hydraulically
fractured well completions or re-completions, only estimates on the rates of re-fracture.
88
URS, “Gas Well Completion Data,” Attachment 3 of the American Exploration and Production Council and
America’s Natural Gas Alliance, Comments – Proposed Rule – Oil and Natural Gas Sector Consolidated Rulemaking,
NSPS and NESHAP Reviews, November 30, 2011, http://epa.gov/quality/informationguidelines/documents/12003attB.pdf.
89
Darren Smith, Devon Energy Corporation, Testimony before the Senate Environment and Public Works
Subcommittee on Clean Air and Nuclear Safety, Washington, DC, June 19, 2012, http://epw.senate.gov/public/
index.cfm?FuseAction=Files.View&FileStore_id=5a14d73e-36d6-4f5b-8985-98a506e3cbab.
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Other published studies use different methodologies for the calculation of leakage (e.g., satellite
observations, ambient measurements, and dispersion modeling). A National Oceanographic and
Atmospheric Administration (NOAA) study analyzes daily air samples collected at the Boulder
Atmospheric Observatory in Weld County in northeastern Colorado and concludes that fugitive
natural gas emissions from drilling operations range from 2.3% to 7.7% of industry’s gross annual
production.90 The study uses an extensive data set of ambient concentrations of methane and
related hydrocarbons in the vicinity of oil and gas operations in the region, along with the known
emissions profiles for these gases from oil and gas operations, to infer the emissions from the
industry. In December 2012, the research team reported updated Colorado data that support the
earlier work, as well as preliminary results from a field study in the Uinta Basin of Utah
suggesting even higher rates of methane leakage at 9% of the total production.91
On February 5, 2013, the industry-reported dataset for GHG emissions collected under EPA’s
Greenhouse Gas Reporting Program (GHGRP) was released for the first time for crude oil and
natural gas systems.92 The data show 2011 GHG emissions from over 1,800 facilities in the crude
oil and natural gas sector, including production, processing, transmission, and distribution. In
total, these facilities accounted for GHG emissions of 225 MMtCO2e. Of note in the reporting:
(1) The crude oil and natural gas sector is the second-largest stationary source of U.S. GHG
emissions, behind power plants; (2) CO2 emissions from the crude oil and natural gas sector
account for 142 MMtCO2e, and methane emissions account for 83 MMtCO2e; (3) Onshore crude
oil and natural gas production is the largest contributor, covering approximately 41% of reported
emissions; (4) Emissions from onshore production facilities are primarily methane (such as leaks
from equipment and vented emissions) while emissions from natural gas transmission and
processing facilities are primarily CO2 (such as combustion emissions associated with
compressors); and (5) While the total emissions of CO2e reported by industry is consistent with
the total emissions previously reported by EPA’s national inventory, the ratio of CO2 to methane
emissions is notably different, with more CO2 (and less methane) reported by the industry than
estimated by EPA. The agency has instituted a multi-step data verification process for the
GHGRP and intends to review the data on an ongoing basis, anticipating that the overall data
quality will increase over time as facilities become familiar with the calculation methods and
begin using more direct measurement.
Using the data reported by industry under comments to the 2012 air standards as well as under the
GHG Reporting Program, EPA again revised its calculations for the sector in its Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2011, released April 15, 2013.93 For the 2011
inventory, EPA revisits its calculations for liquid unloading—the process of flushing excess water
from a drilling well which the agency had estimated contributed as much as 51% of the total CH4
emissions from the sector (an estimate that was disputed by many industry operators) and makes
other changes, including its count of the number of active wells and its methodology for
estimating emissions from hydraulic fracturing and refracturing well completions. With these
90
Gabrielle Pétron et al., “Hydrocarbon Emissions Characterization in the Colorado Front Range: A Pilot Study,”
Journal of Geophysical Research, vol. 117 (2012).
91
As reported by Jeff Tollefson, “Methane leaks erode green credentials of natural gas,” Nature, 493:12, January 2,
2013, http://www.nature.com/news/methane-leaks-erode-green-credentials-of-natural-gas-1.12123#auth-1.
92
See EPA’s GHGRP 2011 data on the agency’s website, http://www.epa.gov/ghgreporting/ghgdata/reported/
petroleum.html.
93
U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011,
Washington, DC, EPA 430-R-13-001, April 15, 2013, http://www.epa.gov/climatechange/Downloads/ghgemissions/
US-GHG-Inventory-2013-Main-Text.pdf.
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revisions, EPA estimates that the industry emitted 177.0 MMtCO2e greenhouse gases in 2011, of
which 144.7 MMtCO2e was methane (i.e., 358 bscf of methane, or 1.5% of the industry’s gross
national production that year).
As debate continues over the level of methane emissions from natural gas production activities, a
full assessment of VOCs, HAPs, hydrogen sulfide, and other aromatic hydrocarbons becomes
even more complicated, since the concentrations of these chemicals can vary greatly from
reservoir to reservoir. Thus, an accurate assessment of the levels of VOCs, SO2, and HAPs
emissions from various production activities would require not only an accurate measurement of
natural gas emissions but a full accounting of the component compositions of the gas across the
geographic variability of the resource.
Impacts of Emissions
The 2012 federal air standards are based on EPA’s expectations that the avoided emissions under
the rules would result in improvements in air quality and reductions in health effects associated
with exposure to HAPs, ozone, and methane. However, the relationship between air pollution
from natural gas systems and its impacts on human health and the environment has never been
fully quantified and assessed. EPA acknowledges this shortcoming in the rule’s proposal, stating
that a full quantification of health benefits for the 2012 standards could not be accomplished due
to the “unavailability of data and the lack of published epidemiological studies correlating crude
oil and natural gas production to respective health outcomes.”94 Various stakeholders assert that
the lack of published and peer-reviewed literature makes it challenging to scientifically assess the
impacts of natural gas operations. Some contend that this uncertainty argues against additional
pollution controls at this time. Others maintain that the relevant question for determining whether
pollution controls are necessary is whether natural gas systems impact an area’s ability to attain
air quality standards (NAAQS). In light of these considerations, Congress may wish to evaluate
whether existing requirements are adequate to address concerns over the human health and
environmental impacts of oil and gas activities, or, if different requirements are necessary.
Quantifying the extent to which crude oil and natural gas systems contribute to air pollution is a
complicated task, due in part to the difficulties in modeling the direct and indirect impacts of
emissions reductions from a single industrial sector on the greater environment. Although there
are many different methodologies that can be used to assess emissions from the industry, each is
burdened with unique disadvantages.95 Thus, while science has demonstrated that emissions of
VOCs and NOx contribute to the generation of ground-level ozone (i.e., smog), emissions of
various organic air toxics can pose a threat to human health, and emissions of methane produce
94
U.S. Environmental Protection Agency, Regulatory Impact Analysis: Proposed New Source Performance Standards
and Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas
Industry, Research Triangle Park, NC, July 2011, p. 4-1.
95
Scientists typically use two different methods when trying to understand how a given air pollution source affects
local air quality. One approach is to conduct ambient air monitoring, which directly measures air pollution levels that
people breathe. However, in using this method, the presence of a pollutant likely reflects contributions from many
different sources, such as motor vehicles, gasoline stations, and industrial plants. Another approach is to use dispersion
modeling, which estimates air pollution levels using models that predict how pollutants move through the air from the
point where they are released. However, in using this method, measurements of the initial outputs must be completed
and verified in order to make accurate dispersion assessments. Satellite modeling and direct component measurements
are other ways of quantifying emissions. These top-down and bottom-up approaches to assessments also have their
specific drawbacks, including source attribution and data availability.
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ground-level ozone and force climate change, comprehensive epidemiological studies correlating
the emissions from natural gas systems to specific long-range and cumulative health outcomes are
virtually nonexistent. It should be noted that such studies are generally difficult, rare, and
expensive to conduct, requiring data that are typically absent or inadequate for assessment (e.g.,
precise and accurate estimates of emissions, fate and transport, and exposure levels, as well as
impacts data on relatively large populations of exposed individuals over long durations of time).
More common, instead, are localized studies or anecdotal reports—by stakeholders who live and
work near oil and gas operations—of general air quality issues such as haze, odor, or ill health.
These studies are countered by industry and/or agency reports that present information on
recommended practices, regulatory compliance, and a history of monitored and reported
environmental stewardship.
Various stakeholders assert that the lack of published and peer-reviewed literature makes it
challenging to scientifically assess the impacts of oil and gas drilling operations. The Centers for
Disease Control and Prevention warns that the science on the impacts of natural gas drilling on
health and the environment is “not yet clear,” stating that there is “not enough information to say
with certainty whether shale gas drilling poses a threat to public health,” and that “more research
is needed for us to understand public health impacts from natural gas drilling and new gas drilling
technologies.”96 Similarly, a recent report by GAO97 examines the available studies of air quality
at shale gas development sites and finds that they are “generally anecdotal, short-term, and
focused on a particular site or geographic location.” Thus, they “do not provide the information
needed to determine the overall cumulative effect that shale oil and gas activities have on air
quality.” GAO concludes that “the cumulative effect shale oil and gas activities have on air
quality will be largely determined by the amount of development and the rate at which it occurs,
and the ability to measure this will depend on the availability of accurate information on emission
levels. However ... data on the severity or amount of pollutants released by oil and gas
development, including the amount of fugitive emissions, are limited.” It is for these reasons that
the final recommendation in the report released by the U.S. Secretary of Energy Advisory Board
Shale Gas Production Subcommittee is to advise federal, regional, state, and local jurisdictions
“to place greater effort on examining [the] cumulative impacts” from “drilling and production
operations, support infrastructure (pipelines, road networks, etc.) and related activities [which]
can overwhelm ecosystems and communities.”98
Some federal, state, and local agencies have embarked upon or are considering further
investigation into the human health and environmental impacts of oil and gas production. These
include the U.S. Department of Health and Human Services, and the states of Colorado99 and
96
Comments by Dr. Christopher Portier, head of CDC’s National Center for Environmental Health and Agency for
Toxic Substances and Disease Registry (ATSDR), as covered on January 5, 2012, by Kevin Begos of the Associated
Press quoting excerpts of an email. Publication of the full text of the email, as released by the CDC press office, can be
found at http://www.slopefarms.com/2012/01/08/shale-gas-drilling-and-public-health-first-publication-of-full-textemail-on-public-health-risks-of-from-cdcs-national-center-for-environmental-health-and-agency-for-toxic-substancesand-dis/.
97
U.S. Government Accountability Office, Oil and Gas: Information on Shale Resources, Development, and
Environmental and Public Health Risks, GAO-12-732, September 2012, pp. 33-37, http://www.gao.gov/assets/650/
647791.pdf.
98
Secretary of Energy Advisory Board Shale Gas Production Subcommittee, Shale Gas Production Subcommittee 90Day Report, p.25. For example, as a part of New York state’s ongoing review of hydraulic fracturing, the New York
State Department of Environmental Conservation (NY DEC) has asked New York State Department of Health (NY
DOH) to undertake a review of the NY DEC health impact analysis, see http://www.dec.ny.gov/press/85071.html.
99
See Colorado Department of Public Health and the Environment news release, “State to undertake major study on oil
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Maryland,100 among others. Examples of published studies on the human health and
environmental impacts of oil and gas production are as follows:
Ozone
Many studies report that at each stage of natural gas production, VOCs—including BTEX and
other hydrocarbons—and methane can escape and mix with nitrogen oxides from the exhaust of
diesel-fueled equipment, and, in the presence of sunlight, produce ground-level ozone (i.e.,
smog). Several areas of the country with heavy concentrations of drilling suffer from serious
ozone problems.
For example, new oil and gas development has begun across sections of the Rocky Mountains
that may be connected to the rise in ozone pollution. A 2005 Western Governors’ Association
report finds that crude oil and natural gas production operations released more than 430,000 tons
of VOCs in Colorado, New Mexico, Utah, Wyoming, and Montana in 2002. The report projects
that operations in these states would more than double their VOCs emissions in 15 years,
releasing more than 965,000 tons annually by 2018.101 This release would equal the average
amount of VOCs emitted annually from approximately 50,000 gas stations or by more than 25
million passenger cars, each driven 12,500 miles.102 A 2008 analysis by the Colorado Department
of Public Health and Environment concludes that smog forming emissions from Colorado’s crude
oil and natural gas operations exceed vehicle emissions for the entire state.103 In 2009, the
governor of Wyoming recommended that the state designate Wyoming’s Upper Green River
Basin as an ozone nonattainment area.104 An extended assessment by the Wyoming Department of
Environmental Quality finds the state’s ozone pollution problems are “primarily due to local
emissions from oil and gas ... development activities: drilling, production, storage, transport, and
treating.”105 Recently, northeastern Utah recorded unprecedented ozone levels in the Uintah
Basin, with more than 68 exceedances of the federal health standard during the first three months
of 2010, and over 24 exceedances during the winter of 2011.106 The Bureau of Land Management
(...continued)
and gas emissions,” January 9, 2012, http://www.colorado.gov/cs/Satellite/CDPHE-Main/CBON/1251590280071.
100
See Maryland, Department of the Environment, Marcellus Shale Safe Drilling Initiative Study: Part I (December
2011), http://www.mde.state.md.us/programs/Land/mining/marcellus/Pages/index.aspx.
101
Russell and Pollack, Oil and Gas Emission Inventories for the Western States, Environ International Corporation
study prepared for the Western Governors’ Association, December 27, 2005, http://www.wrapair.org/forums/ssjf/
documents/eictts/OilGas/WRAP_Oil&Gas_Final_Report.122805.pdf.
102
See EPA Clearinghouse for Inventories and Emissions Factors, Compilation of Air Pollutant Emission Factors AP42, Fifth Edition, Volume I: Stationary Point and Area Sources, January 1995, http://www.epa.gov/ttn/chief/ap42/ch05/
final/c05s02.pdf.
103
Colorado Dept. of Public Health & Environment, Air Pollution Control Division, Oil and Gas Emission Sources
Presentation for the Air Quality Control Commission Retreat, May 15, 2008, at pages 3-4.
104
See Letter from Wyoming Governor Dave Freudenthal to Carol Rushin, Acting Regional Administrator, USEPA
Region 8, (Mar. 12, 2009) (“Wyoming 8 Hour Ozone Designation Recommendations”), http://deq.state.wy.us/out/
downloads/Rushin%20Ozone.pdf.
105
Wyoming Department of Environmental Quality, Technical Support Document I for Recommended 8-hour Ozone
Designation of the Upper Green River Basin, March 26, 2009 (“Wyoming Nonattainment Analysis”),
http://deq.state.wy.us/out/downloads/Ozone%20TSD_Outside%20UGRB%20%282%29.pdf.
106
Randal Martin, et al., Final Report: Uinta Basin Winter Ozone and Air Quality Study, December 2010-March 2011,
Energy Dynamics Laboratory, Utah State University, for Uintah Impact Mitigation Special Service District, June 14,
2011, http://rd.usu.edu/files/uploads/ubos_2010-11_final_report.pdf.
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identifies oil and gas activities in the region as the primary cause of the ozone pollution.107
Further, a 2009 study concludes that numerous “Class I areas” in the Rocky Mountain region—a
designation reserved for national parks, wilderness areas, and other such lands—are likely to be
impacted by increased ozone pollution as a result of oil and gas development, including Mesa
Verde National Park and Weminuche Wilderness Area in Colorado and San Pedro Parks
Wilderness Area, Bandelier Wilderness Area, Pecos Wilderness Area, and Wheeler Peak
Wilderness Area in New Mexico. These areas are all near concentrated oil and gas development
in the San Juan Basin.108 However, the evidence linking oil and gas development directly to high
ozone levels in the region remains inconclusive. Researchers caution that many factors can
contribute to the Rocky Mountains’ ozone problems. For example, uniform snow cover reflects
and concentrates sunlight, boosting ozone levels, as do temperature inversions that trap pollutants
in mountain basins.109 In support of this point, the interim findings of the 2012 Uintah Basin
Winter Ozone & Air Quality Study, released in August 2012, report that there were no
exceedances of the eight-hour ozone standard for the basin in 2012, even though higher levels of
ozone precursors and VOCs were measured in the region (the lack of sunlight-reflecting
snowpack in 2012 is suggested as a possible reason).110
As another example, the Dallas-Fort Worth area in Texas is home to substantial oil and gas
development. Of the nine counties surrounding the Dallas-Fort Worth area that EPA has
designated as “nonattainment” for ozone, five contain significant oil and gas development.111 A
2009 study finds summertime emissions of smog-forming pollutants from oil and gas operations
in the Dallas-Fort Worth area exceed emissions from all motor vehicles in the area.112 A 2012
study finds that emissions from natural gas compressor stations and flares contribute to
significant amounts of ground-level ozone and formaldehyde in the Dallas-Fort Worth area,
estimating that a single natural gas processing facility in the Barnett shale area could add as much
as 3 parts per billion (ppb) to the hourly average ambient ozone.113 Still, the evidence linking oil
and gas development directly to high ozone levels in the region remains inconclusive. In 2009
and 2010, the Texas Commission on Environmental Quality (TCEQ) conducted several large, indepth surveys of air quality in the six counties surrounding Fort Worth. The TCEQ study
identifies a 15% drop in the 8-hour ozone design value, despite a 10-fold increase in natural gas
107
BLM, GASCO Energy Inc. Uinta Basin Natural Gas Development Draft Environmental Impact Statement
(“GASCO DEIS”), p. 3-13, http://www.blm.gov/ut/st/en/fo/vernal/planning/nepa_/gasco_energy_eis.html.
108
Marco Rodriguez, et al., “Regional Impacts of Oil and Gas Development on Ozone Formation in the Western
United States,” Journal of the Air and Waste Management Association, 111 (Sept. 2009), http://www.wrapair.org/
forums/amc/meetings/091111_Nox/Rodriguez_et_al_OandG_Impacts_JAWMA9_09.pdf.
109
See comments made by Keith Guille, spokesman for Wyoming DEQ, in Charles W. Schmidt, “Blind Rush?: Shale
Gas Boom Proceeds amid Human Health Questions,” Environmental Health Perspectives, vol. 119, no. 8 (August
2011), p. A352.
110
See 2012 Uintah Basin Winter Ozone & Air Quality Study-Summary of Interim Findings, Ongoing Analyses, and
Additional Recommended Research, August 7, 2012, at http://op.bna.com/env.nsf/id/smiy-8x9rv3/
$File/UintahWinter.pdf.
111
Texas Railroad Commission, http://www.rrc.state.tx.us/data/fielddata/barnettshale.pdf.
112
Al Armendariz, Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for CostEffective Improvements, January 26, 2009, http://www.edf.org/documents/9235_Barnett_Shale_Report.pdf. It should
be noted that Al Armendariz is the former EPA Region 6 Administrator who resigned on April 30, 2012, after remarks
made in 2010 regarding EPA’s enforcement policy.
113
Eduardo P. Olaguer, “The Potential Near-source Ozone Impacts of Upstream Oil and Gas Industry Emissions,”
Journal of the Air & Waste Management Association, vol. 62, no. 8 (2012), http://www.tandfonline.com/doi/abs/
10.1080/10962247.2012.688923.
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production in the region over the past decade. TCEQ attributes at least part of this reduction to the
state’s NOx control strategies as well as the prevailing winds.114
Air Toxics
Other studies (e.g., epidemiological studies) focus on the human health impacts of hazardous air
pollutants (HAPs) known or suspected to be released by crude oil and natural gas operations. A
2011 survey of existing literature on the topic reported that of the known chemicals used and/or
found in natural gas operations, approximately 37% of the chemicals are volatile and may
become airborne. The study further noted that if exposures exceed certain levels, over 89% of
these chemicals can harm the eyes, skin, sensory organs, respiratory tract, gastrointestinal tract, or
liver; 81% can cause harm to the brain and nervous system; 71% can harm the cardiovascular
system and blood; and 66% can harm the kidneys. Overall, the hazardous air pollutants produce a
profile that displays a higher frequency of health effects than the water soluble chemicals. In
addition, because they vaporize, not only can they be inhaled, but they can be ingested or
absorbed through the skin, increasing the chance of exposures.115
Several studies report that sources of HAPs in the oil and gas industry may be numerous. Data
from the State of Colorado suggest that there may be more than 26 individual sources of HAPs in
the oil and gas sector, including “venting, dehydration, gas processing, compression, leaks from
equipment (fugitive emissions), open-pit waste ponds, and land application of volatile wastes.”116
A study of HAPs emissions from natural gas related sources within the city of Fort Worth, TX,
documents the following for HAPs emissions: 0.02 to 2 tons per year (tpy) from well pads
(including emissions from equipment leaks, produced water and condensate storage and loading,
and lift compressors); 0.9 to 8.8 tpy from well pads with compressors; 10 to 25 tpy from
compressor stations (including emissions from combustion at the compressor engines or turbines,
equipment leaks, storage tanks, glycol dehydrators, flares, and condensate and/or wastewater
loading); 47 tpy on average from processing facilities (including emissions from equipment leaks,
storage tanks, separator vents, glycol dehydrators, flares, condensate and wastewater loading,
compressors, amine treatment and sulfur recovery units); and 0.4 tpy on average from saltwater
treatment facilities.117
Although oil and gas development generally has not occurred in densely populated areas, this is
not always the case, particularly with respect to recent expansion in unconventional resources.
Several local, state, and national health agencies have expressed concerns about the health
impacts of HAPs emissions from oil and gas facilities, including the Center for Disease Control
and Prevention (CDC),118 the Agency for Toxic Substances and Disease Registry (ATSDR),119 the
114
Texas Commission on Environmental Quality, “A Commitment to Air Quality in the Barnett Shale,” Natural
Outlook Newsletter, Fall 2010, http://www.tceq.state.tx.us/publications/pd/020/10-04/a-commitment-to-air-quality-inthe-barnett-shale.
115
Theo Colborn, Carol Kwiatkowski, Kim Schultz, Mary Bachran, “Natural Gas Operations from a Public Health
Perspective,” Human and Ecological Risk Assessment, vol. 17, no. 5, 2011, pp. 1039-1056,
http://www.endocrinedisruption.com/chemicals.journalarticle.php.
116
Amy Mall et al., Drilling Down: Protecting Western Communities from the Health and Environmental Effects of Oil
and Gas Production, NRDC, October 2007, (citing CDPHE data), http://www.nrdc.org/land/use/down/down.pdf
117
Eastern Research Group, City of Fort Worth Natural Gas Air Quality Study, 2011, at http://fortworthtexas.gov/
gaswells/?id=87074.
118
Comments by Dr. Christopher Portier, CDC, op cit.
119
ATSDR, Health Consultation: Public Health Implications of Ambient Air Exposures to Volatile Organic
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Association of Occupational and Environmental Clinics (AOEC) and the Pediatric Environmental
Health Specialty Unit (PEHSU),120 the Colorado School of Public Health,121 the Town of Dish,
Texas,122 the City of Fort Worth, Texas,123 and the City of Houston, Texas.124 In particular, the
ATSDR investigation was spurred by community health complaints such as dizziness, nausea,
respiratory problems, and eye and skin irritation to more severe concerns including cancer. The
investigation identifies elevated cancer risk at one site and recommends further investigation into
HAPs emissions and risks at all the sites. Similarly, the Colorado School of Public Health
identifies air pollution from the crude oil and natural gas activities as contributing to acute and
chronic health problems for those living near natural gas drilling sites, stating that “exposures to
air pollutants during well completion activities present the greatest potential for health effects.”125
The CSPH analysis, based on three years of monitoring, finds a number of air toxics near the
wells including benzene, toluene, ethylbenzene, and xylene.
However, critics have taken issue with the Colorado School of Public Health and other studies for
a number of reasons including the use of (1) out of date data, (2) unrealistic estimates of
emissions from sources, (3) overly conservative risk assessments when viewed in context, and (4)
poor study design and input assumptions (e.g., the use of ambient collection methodology in a
region populated with other emission sources such as roads, highways, and other industries).126 In
support of this point, other studies have reported little or no health effects from the sector. For
example, in 2012, the Houston-based Plains Exploration and Production Company (PXP)
released a report that said hydraulic fracturing operations at the Inglewood oil field in the
Baldwin Hills area in Los Angeles County posed “no public health or environmental threats.”127
Similarly, in a review of health studies conducted by the Energy Institute at the University of
Texas at Austin and published in February 2012, the authors conclude that “none of the studies
reviewed ... showed a clear link between shale gas activities and documented adverse health
effects, [and] that the gas industry has been using hydraulic fracturing for over 50 years, but the
studies examined ... did not find any direct evidence for health impacts on workers in the industry
(...continued)
Compounds as Measured in Rural, Urban, and Oil & Gas Development Areas Garfield County, Colorado, 2008,
http://www.cdphe.state.co.us/dc/ehs/GarfieldCounty.pdf.
120
PEHSU, Information on Natural Gas Extraction and Hydraulic Fracturing for Health Professionals, 2011,
http://aoec.org/pehsu/documents/hydraulic_fracturing_and_children_2011_health_prof.pdf.
121
Roxana Witter, et al., Draft Health Impact Assessment for Battlement Mesa, Garfield County, Colorado, Colorado
School of Public Health, 2011, http://www.garfield-county.com/index.aspx?page=1408; Lisa McKenzie, et al., Human
Health Risk Assessment of Air Emissions from Development of Unconventional Natural Gas Resources, Colorado
School of Public Health, 2012, http://www.energyindepth.org/
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