An Overview of Unconventional Oil and
Natural Gas: Resources and Federal Actions
Michael Ratner
Specialist in Energy Policy
Mary Tiemann
Specialist in Environmental Policy
November 21, 2014
Congressional Research Service
7-5700
www.crs.gov
R43148
An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
Summary
The United States has seen resurgence in petroleum production, mainly driven by technology
improvements—especially hydraulic fracturing and directional drilling—developed for natural
gas production from shale formations. Application of these technologies enabled natural gas to be
economically produced from shale and other unconventional formations, and contributed to the
United States becoming the world’s largest natural gas producer in 2009. Use of these
technologies has also contributed to the rise in U.S. oil production over the last few years. In
2009, annual oil production increased over 2008, the first annual rise since 1991, and has
continued to increase each year since. Between January 2008 and May 2014, U.S. monthly crude
oil production rose by 3.2 million barrels per day, with about 85% of the increase coming from
shale and related tight oil formations in Texas and North Dakota. Other tight oil plays are also
being developed, helping raise the prospect of energy independence, especially for North
America.
The rapid expansion of tight oil and shale gas extraction using high-volume hydraulic fracturing
has raised concerns about its potential environmental and health impacts. These concerns include
potential direct impacts to groundwater and surface water quality, water supplies, and air quality.
In addition, some have raised concerns about potential long-term and indirect impacts from
reliance on fossil fuels and resulting greenhouse gas emissions and influence on broader energy
economics. This report focuses mainly on actions related to controlling potential direct impacts.
States are the primary regulators of oil and gas production on non-federal lands. State laws and
regulations governing oil and gas production have been evolving across the states in response to
changes in production practices as producers have expanded into tight oil, shale gas, and other
unconventional hydrocarbon formations. However, state rules vary considerably, leading to calls
for more federal oversight of unconventional oil and gas extraction activities, and hydraulic
fracturing specifically.
Although provisions of several federal environmental laws can apply to certain activities related
to oil and gas production, proposals to expand federal regulation in this area have been highly
controversial. Some advocates of a larger federal role point to a wide range of differences among
state regulatory regimes, and argue that a national framework is needed to ensure a consistent
minimum level of protection for surface and groundwater resources, and air quality. Others argue
against more federal involvement, and point to the long-established state oil and natural gas
regulatory programs, regional differences in geology and water resources, and concern over
regulatory redundancy.
The federal role in regulating oil and gas extraction activities—and hydraulic fracturing, in
particular—has been the subject of considerable debate and legislative proposals for several
years, but legislation has not been enacted. While congressional debate has continued, the
Administration has pursued a number of regulatory initiatives related to unconventional oil and
gas development under existing statutory authorities.
This report focuses on the growth in U.S. oil and natural gas production driven primarily by tight
oil formations and shale gas formations. It also reviews selected federal environmental regulatory
and research initiatives related to unconventional oil and gas extraction, including the Bureau of
Land Management (BLM) proposed hydraulic fracturing rule and Environmental Protection
Agency (EPA) actions.
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
Contents
Introduction: Change Is Afoot ......................................................................................................... 1
Geology Is What Makes a Resource Unconventional ..................................................................... 2
Price Drives Industrial Innovation ................................................................................................... 2
Technologies Stimulate Shale Gas Production First ........................................................................ 3
Natural Gas Liquids: A Production Driver ................................................................................ 4
Increased Tight Oil Production Raises Independence Possibility .................................................... 5
Environmental Concerns and Responses ......................................................................................... 7
State Regulation of Oil and Gas Development ........................................................................ 10
Debate over the Federal Role .................................................................................................. 12
Selected Federal Responses to Unconventional Resource Extraction ..................................... 13
EPA Study on Hydraulic Fracturing and Drinking Water .................................................. 14
Multiagency Collaboration on Unconventional Oil and Gas Research ............................. 15
BLM Proposed Rule on Hydraulic Fracturing .................................................................. 16
Coast Guard Regulation of Barge Shipments of Shale Gas Wastewater ........................... 18
Legislation in the 113th Congress ................................................................................................... 19
Conclusion: Above- and Below-Ground Issues a Concern ............................................................ 21
Figures
Figure 1. Percentage of U.S. Oil and Natural Gas from Tight Oil and Shale Gas ........................... 1
Figure 2. Monthly U.S. Natural Gas Prices ..................................................................................... 3
Figure 3. Monthly U.S. Natural Gas Production ............................................................................. 4
Figure 4. Natural Gas, Oil, and NGL Prices .................................................................................... 5
Figure 5. Monthly U.S. Oil Production ........................................................................................... 6
Figure 6. Unconventional Shale Plays in the Lower 48 States ...................................................... 10
Tables
Table A-1. Selected Federal Actions Related to Unconventional Oil and Gas Production ............ 22
Appendixes
Appendix. Selected Federal Initiatives Related to Unconventional Oil and Gas Production ........ 22
Contacts
Author Contact Information........................................................................................................... 27
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
Introduction: Change Is Afoot
In the past, the oil and natural gas industry considered resources locked in tight, impermeable
formations such as shale uneconomical to produce. Advances in directional well drilling and
reservoir stimulation, however, have dramatically changed this perspective. It is production from
these unconventional formations that has changed the U.S. energy posture and global energy
markets.
U.S. oil and natural gas production is on the rise, primarily driven by resources from tight
formations. The techniques developed to produce shale gas—directional drilling and hydraulic
fracturing1—have migrated to the oil sector. The United States is the third-largest oil producer in
the world, but also the fastest-growing producer. The United States surpassed Russia in 2009 as
the world’s largest natural gas producer. Production from tight formations is expected to make up
a significant part of production of each commodity well into the future (see Figure 1).
Figure 1. Percentage of U.S. Oil and Natural Gas from Tight Oil and Shale Gas
2005-2040
Source: U.S. Energy Information Administration, Annual Energy Outlook 2014, http://www.eia.gov/oiaf/aeo/
tablebrowser/ and other EIA data.
Note: Prior to 2007, the Energy Information Administration did not report tight oil and shale gas data.
This report focuses on the growth in U.S. oil and natural gas production driven primarily by tight
oil formations and shale gas formations. It does not address other types of unconventional
production such as coalbed methane or tight gas, as their contributions to overall U.S. production
have not changed as dramatically as shale gas.2 There has been continued congressional interest
1 Hydraulic fracturing is an industry technique that uses water, sand, and chemicals under pressure to enhance the
recovering of natural gas and oil. It has taken on new prominence as it has been applied to tight oil and shale gas
formation as an essential method for producing resources from those types of formations.
2 Coalbed methane and tight gas accounted for 33% of U.S. natural gas production in 2011, but are projected to account
(continued...)
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
through the 113th Congress related to unconventional natural gas and oil production. In May
2013, the Senate Energy and Natural Resources Committee held three roundtable discussions on
natural gas supply and use.3 The House Energy and Commerce Committee’s Subcommittee on
Energy and Power held a hearing in June 2013 on U.S. energy abundance.4
Geology Is What Makes a Resource Unconventional
Unconventional formations are fine-grained, organic-rich, sedimentary rocks—usually shales and
similar rocks. The shales and rocks are both the source of and the reservoir for oil and natural gas,
unlike conventional petroleum reservoirs. The Society of Petroleum Engineers describes
“unconventional resources” as petroleum accumulations that are pervasive throughout a large area
and that are not significantly affected by pressure exerted by water (hydrodynamic influences);
they are also called “continuous-type deposits” or “tight formations.” In contrast, conventional oil
and natural gas deposits occur in porous and permeable sandstone and carbonate reservoirs.
Under pressure exerted by water, the hydrocarbons migrated upward from organic sources until
an impermeable cap-rock (such as shale) trapped it in the reservoir rock. Although the
unconventional formations may be as porous as other sedimentary reservoir rocks, their
extremely small pore sizes and lack of permeability make them relatively resistant to hydrocarbon
flow. The lack of permeability means that the oil and gas typically remain in the source rock
unless natural or artificial fractures occur.
Price Drives Industrial Innovation
Historically, natural gas prices in the United States have been volatile. From 1995 to 1999 the
spot price of natural gas averaged $2.23 per million British thermal units (MBtu), but increased to
an average price of $4.68 per MBtu, in nominal dollars, during the 2000-to-2004 period, an
almost 110% rise. Prices hit a peak in December 2005 at $15.38 per MBtu, but remained
relatively high through July 2008, as can be seen in Figure 2. Along with the rise in prices, U.S.
net imports of natural gas also rose, increasing 32% between 1995 and 2000 and 41% between
1995 and 2007.
As U.S. prices and imports continued to trend up, industry undertook two competing solutions to
meet the need for more natural gas—increased liquefied natural gas (LNG) imports and
development of techniques to produce shale gas. The LNG import facilities were much higher-
profile and were cited extensively in industry and popular press. Approximately 50 import
projects were proposed, and eight were eventually constructed during the mid- to late 2000s,
along with the recommissioning of older facilities.
(...continued)
for only 28% in 2040, according to the Energy Information Administration (EIA).
3 Full Committee Forum: Domestic Supply and Exports, Senate Energy and Natural Resources Committee, May 21,
2013, http://www.energy.senate.gov/public/index.cfm/hearings-and-business-meetings?ID=0380bed7-f9ef-4450-bfa0-
a3af60f7a184.
4 “U.S. Energy Abundance: Regulatory, Market, and Legal Barriers to Export,” House Energy and Commerce
Committee, Subcommittee on Energy and Power, June 18, 2013, http://energycommerce.house.gov/hearing/us-energy-
abundance-regulatory-market-and-legal-barriers-export.
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Figure 2. Monthly U.S. Natural Gas Prices
2002-2014
$/mmbtu
$16
$12
Shale gas
$8
$4
$-
Jan
Jan
Jan
Jan
Jan
Jan
Jan
Jan
Jan
Jan
Jan
Jan
Jan
2002 2003 2004 2005 2006 2007 2008
2009 2010 2011 2012 2013 2014
Source: U.S. Energy Information Administration, http://www.eia.gov/dnav/ng/hist/rngwhhdM.htm.
Notes: Units = nominal dollars per million British thermal units (mmBtu). Data for 2014 are through July.
Although horizontal drilling and hydraulic fracturing have been industry techniques for some
time, their application to shale gas formations is relatively new. Advances in directional drilling,
particularly steerable down-hole motors, allowed drilling operators to better keep the well bore in
the hydrocarbon-bearing shale formations. Well stimulation was also required, and improvements
in hydraulic fracturing techniques, particularly multistage hydraulic fracturing and the ability to
better control the fractures, contributed to making shale gas production a profitable venture.
In 2007, the Energy Information Administration (EIA) first recorded shale gas production, when
it accounted for just 7% of U.S. natural gas production. In 2013, shale gas production accounted
for almost 40% of U.S. production (see Figure 1), while almost all the LNG import terminals
were idle and many applied to become export terminals.5
Technologies Stimulate Shale Gas Production First
The application of advances in directional drilling and hydraulic fracturing were first applied to
shale gas formations, particularly as natural gas prices increased in the mid-2000s. Methane
molecules and those of natural gas liquids (NGLs) are smaller than crude oil molecules and
therefore tend to be more responsive to hydraulic fracturing. The success of shale gas
development has driven U.S. natural gas production to increase almost every month on a year-on-
5 For additional information on U.S. natural gas exports, see CRS Report R42074, U.S. Natural Gas Exports: New
Opportunities, Uncertain Outcomes, by Michael Ratner et al.
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year basis (see Figure 3) from 2008 through May 2014. The rise in shale gas development has
also resulted in natural gas prices declining, as shown in Figure 2.
Figure 3. Monthly U.S. Natural Gas Production
2008-2014
billion cubic feed per month (bcf/mo)
2,400
2,200
2014
2,000
2013
2012
1,800
2011
2010
1,600
2009
2008
1,400
1,200
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Source: U.S. Energy Information Administration, http://www.eia.gov/dnav/ng/ng_prod_sum_dcu_NUS_m.htm.
The decline in prices and production in the latter half of 2008 was mainly the result of the
economic downturn. However, as the economy picked up in 2009, natural gas resumed its upward
production trajectory while prices stayed low. Overall U.S. natural gas production grew, as did the
contribution from shale. The continued increase in production can be attributed, in part, to
industry improvements in extracting more of the natural gas from the shale formations. Continued
progress in hydraulic fracturing and directional drilling techniques has enabled companies to
drive down production costs while increasing output.
Natural Gas Liquids: A Production Driver
Natural gas liquids (NGLs) have taken on a new prominence as shale gas production has
increased and prices have fallen. As natural gas prices have stayed low, company interests have
shifted away from dry natural gas production to more liquids-based production. NGL is a general
term for all liquid products separated from natural gas at a gas processing plant, and includes
ethane, propane, butane, and pentanes. When NGLs are present with methane, which is the
primary component of natural gas, the natural gas is referred to as either “hot” or “wet” gas. Once
the NGLs are removed from the methane, the natural gas is referred to as “dry” gas, which is
what most consumers use.
Each NGL has its own market and its own value. As the price for dry gas has dropped because of
the increase in supply and other reasons, such as the warm winter of 2011, the natural gas
industry has turned its attention to producing in areas with more wet gas in order to bolster the
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
value it receives (see Figure 4). Some companies have shifted their production portfolios to tight
oil formations, such as the Bakken in North Dakota and Montana, to capitalize on the experience
they gained in shale gas development. Historically, the individual NGL products have been priced
against oil, except for ethane. As oil prices have remained higher since 2008 relative to natural
gas, they have driven an increase of wet gas production. Because of its low price, dry gas is often
treated as a “by-product” of wet gas and oil production.
Figure 4. Natural Gas, Oil, and NGL Prices
2010-2014
$/mmbtu
$20
$16
$12
Oil
NGL
$8
Gas
$4
$-
Jan
Jan
Jan
Jan
Jan
2010
2011
2012
2013
2014
Source: U.S. Energy Information Administration.
Notes: According to EIA, the NGL composite price is derived from daily Bloomberg spot price data for natural
gas liquids at Mont Belvieu, TX, weighted by gas processing plant production volumes of each product as
reported on Form EIA-816, “Monthly Natural Gas Liquids Report.” The mix of NGLs will vary by source, and
the price will vary by the actual market for the product. The natural gas price is at Henry Hub, and the oil price
is West Texas Intermediate (WTI). Units = nominal dollars per million British thermal units ($/mmBtu). Data for
2014 are through May.
Increased Tight Oil Production Raises
Independence Possibility
The prospect of U.S. energy independence is grounded in the production growth from tight oil
formations such as the Bakken Formation in North Dakota and Montana, and the Eagle Ford
Formation in Texas.6 Relative to other fuels, the United States is more dependent upon imports
for its oil requirements, still accounting for about 47% of consumption.7 Canada is the largest
6 For additional information on the Bakken Formation, see CRS Report R42032, The Bakken Formation: Leading
Unconventional Oil Development, by Michael Ratner et al.
7 BP, BP Statistical Review of World Energy, June 2014, pp. 8-9.
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supplier of U.S. oil imports, which is why energy independence is usually mentioned as North
American energy independence.8 The United States added almost 1 million barrels per day (b/d)
of oil production between 2012 and 2013 (see Figure 5). U.S. oil production has reached levels
not seen in more than a decade, but is almost 2 million b/d short of the highs in the 1970s. Since
2005, when crude oil imports reached a peak, they have dropped almost 2.4 million b/d, or 24%,
through 2013.9 Also since 2005, U.S. consumption of crude oil and petroleum products has been
trending downward, contributing to the decrease in imports.
Figure 5. Monthly U.S. Oil Production
2008-2014
1,000 barrels per month (kb/mo)
300,000
250,000
2014
200,000
2013
2012
150,000
2011
2010
100,000
2009
2008
50,000
-
Jan
Feb Mar Apr May Jun
Jul
Aug Sep
Oct Nov Dec
Source: U.S. Energy Information Administration, http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=
MCRFPUS1&f=M.
The continued shift of industry resources toward oil-rich production has prompted forecasts of
continued growth. Domestic crude oil production is projected to rise through the end of the
decade. The tremendous increases are primarily due to dramatic increases in production from the
previously mentioned Bakken Formation in North Dakota and the Eagle Ford play in Texas, both
tight oil formations.10
8 CRS Report R41875, The U.S.-Canada Energy Relationship: Joined at the Well, by Paul W. Parfomak and Michael
Ratner. Mexico is the third-largest source of U.S. oil imports, but is not always included in discussions of North
American energy independence, as its oil sector is not as integrated with the United States as is Canada’s.
9 U.S. Energy Information Administration, U.S. Imports of Crude Oil and Petroleum Products, July 30, 2014,
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MCRIMUS2&f=A.
10 Adam Sieminski, Outlook for Shale Gas and Tight Oil Development in the U.S., U.S. Energy Information
Administration, Presentation for the American Petroleum Institute, Washington, DC, April 4, 2013, p. 12.
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Environmental Concerns and Responses
As with other energy sources or fuel production, the development of unconventional oil and gas
resources can pose both environmental risks and net benefits, some direct and others indirect.
Potential direct risks may include impacts to groundwater and surface water quality, public and
private water supplies, and air quality. In addition, some have raised concerns about potential
long-term and indirect impacts from reliance on fossil fuels and resulting greenhouse gas
emissions and influence on broader energy economics. On the other hand, natural gas is seen by
many as a “bridge” fuel that can provide more energy per unit of greenhouse gas produced than
some alternatives (e.g., coal), and has only recently been produced in sufficient quantity and at
low enough prices to provide a viable alternative fuel that is widely regarded as relatively cleaner-
burning (i.e., no mercury or sulfur emissions and substantially lower emissions of nitrous oxides
(NOx) and carbon dioxide (CO2) per Btu of energy produced compared to coal). This report
focuses primarily on measures to address potential direct impacts.
Among the variety of potential direct environmental impacts, many may be mitigated with
appropriate safeguards, existing technology, and best practices. For example, management of
wastewater associated with increased unconventional oil and gas production activity has in some
cases placed a strain on water resources, and on wastewater treatment plants that were not
designed to remove salts and other contaminants from hydraulic fracturing flowback and
produced water, and these impacts can be mitigated by investing in additional control
technologies.
Water quality issues have received much attention, and of these, the potential risks associated
with well stimulation by hydraulic fracturing have been at the forefront. Complaints of
contaminated well water have emerged in some areas where unconventional oil and gas
development has occurred, although regulators have not reported a direct connection between
hydraulic fracturing of shale formations at depth and groundwater contamination. In shale
formations, the vertical distance separating the target zone from usable aquifers generally is much
greater than the length of the fractures induced during hydraulic fracturing. Thousands of feet of
rock layers typically overlay the produced portion of shale, and these layers serve as barriers to
flow. In these circumstances, geologists and state regulators generally view as remote the
possibility of creating a fracture that could reach a potable aquifer. If the shallow portions of shale
formations were developed, then the thickness of the overlying rocks would be less and the
distance from the shale to potable aquifers would be shorter, posing more of a risk to
groundwater. In contrast to shale, coalbed methane (CBM) basins often qualify as underground
sources of drinking water. Injection of fracturing fluids directly into or adjacent to such
formations may be more likely to present a risk of contamination, and this is where initial
regulatory attention and study was focused.11
State regulators have expressed more concern about the groundwater contamination risks
associated with developing a natural gas or oil well (drilling through an overlying aquifer and
casing, cementing, and completing the well), as opposed to hydraulic fracturing per se. The
11 U.S. Environmental Protection Agency, Evaluation of Impacts to Underground Sources of Drinking Water by
Hydraulic Fracturing of Coalbed Methane Reservoirs, Final Report, EPA-816-04-003, Washington, DC, June 2004,
p. 4-1. (EPA reviewed 11 major coalbed methane formations to determine whether coal seams lay within underground
sources of drinking water (USDWs). EPA determined that 10 of the 11 producing coal basins “definitely or likely lie
entirely or partially within USDWs.”)
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challenges of sealing off the groundwater and isolating it from possible contamination are
common to the development of any oil or gas well, and are not unique to hydraulic fracturing.
However, horizontally drilled, hydraulically fractured oil and gas wells pose more development
and production challenges, and are subject to greater pressures than conventional vertical wells.
Identifying the source or cause of groundwater contamination can be difficult for various reasons,
including the complexity of hydrogeologic processes and investigations, a lack of baseline testing
of nearby water wells prior to drilling and fracturing, and the confidential business information
status traditionally provided for fracturing compounds. Investigations by regulators and
researchers generally have found that incidents involving residential water well contamination
(including methane gas migration) have been caused by failure of well-bore casing and cementing
or other well development and operating problems, rather than the hydraulic fracturing process.12
The debate over the groundwater contamination risks associated with hydraulic fracturing
operations has been fueled in part by the lack of scientific studies to assess more thoroughly the
current practices and related complaints and uncertainties. To help address this issue, Congress
has asked the Environmental Protection Agency (EPA) to conduct a study on the relationship
between hydraulic fracturing and drinking water.13 The “hydraulic fracturing” debate also has
been complicated by terminology. Many do not differentiate the well stimulation process of
“fracing” or “fracking” from the full range of activities associated with unconventional oil and
gas exploration and production.14
Other water quality concerns—associated with both conventional and unconventional oil and
natural gas extraction—include the risks of contaminating ground and surface water from surface
spills, leaks from pits, and siltation of streams from drilling and pad construction activities.
Because of the large, but short-term, volumes of water needed for the hydraulic fracturing
operations used to extract shale gas and tight oil, water consumption issues have emerged as well.
Water use issues include the impacts that large water withdrawals might have on groundwater
resources, streams and aquatic life (particularly during low-flow periods), and other competing
uses (e.g., municipal or agricultural uses). Such impacts may be regional or localized, and can
vary seasonally or with longer-term variations in precipitation.
The management of the large volumes of wastewater produced during natural gas production
(including flowback from hydraulic fracturing operations and water produced from source
formations) has emerged in many areas as a significant water quality issue, as well as a cost issue
for producers. In some areas, such as portions of the Marcellus Shale region,15 capacity is limited
12 Avner Vengosh, Robert B. Jackson, and N. Warner, et al., “A Critical Review of the Risks to Water Resources from
Unconventional Shale Gas Development and Hydraulic Fracturing in the United States,” Environmental Science and
Technology, vol. 10, no. 1021 (2014), p. 405118.
13 Department of the Interior, Environment, and Related Agencies Appropriations Act, 2010, P.L. 111-88, H.Rept. 111-
316. The EPA study (expected to be published in 2016) includes five case studies that involve drinking water
contamination incidents in areas where unconventional oil and gas development is occurring.
14 A 2012 Pacific Institute study found that many individuals interviewed for the study defined “hydraulic fracturing”
much more broadly than the industry meaning of the term (i.e., the pressurized injection of fluids into a production
well). These individuals used the term broadly to include well construction, completion, and other associated activities.
Noting the differences, the authors concluded that “additional work is needed to clarify terms and definitions associated
with hydraulic fracturing to support more fruitful and informed dialog and to develop appropriate energy, water, and
environmental policy.” See Hydraulic Fracturing and Water Resources: Separating the Frack from the Fiction, p. 29,
http://www.pacinst.org/reports/fracking/.
15 The Marcellus Shale formation is one of the largest unconventional natural gas resources in the United States,
(continued...)
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for wastewater disposal using underground injection wells (historically, the most common and
preferred produced-water disposal practice in oil and natural gas fields), and surface discharge of
wastewater is an increasingly restricted option.16 Additionally, the injection of large volumes of
wastewater into disposal wells has been associated with instances of induced seismicity.17
Air emissions associated with unconventional oil and natural gas production also have raised
public health concerns and have drawn regulatory scrutiny. Air pollutants can be released during
various stages of oil and natural gas production. Emission sources include pad, road, and pipeline
construction; well drilling and completion, and flowback activities; and natural gas processing,
storage, and transmission equipment. Key pollutants include methane (the main component of
natural gas and a potent greenhouse gas), volatile organic compounds (VOCs), nitrogen oxides,
sulfur dioxide, particulate matter, and various hazardous air pollutants.18 According to EPA, the
oil and gas industry is a significant source of methane and VOC emissions, which react with
nitrogen oxides to form ozone (smog). EPA has identified hydraulically fractured gas wells during
flowback as an additional source of these emissions in the natural gas industry.19
Releases of methane and other pollutants also can occur where natural gas is produced in
association with oil, and natural gas gathering pipelines and other infrastructure are lacking. In
such cases, the natural gas generally must be flared or vented. Flaring reduces VOC emissions
compared to venting, but like venting, it contributes to greenhouse gas emissions without
producing an economic value or displacing other fuel consumption.20 Natural gas flaring has
become an issue with the rapid and intense development of tight oil from the Eagle Ford
Formation in Texas and the Bakken Formation in North Dakota, which have significant amounts
of associated gas.21 Other areas that have experienced large increases in tight oil production also
have had increases in the amount of natural gas being flared.
(...continued)
underlying much of West Virginia and Pennsylvania, southern New York, eastern Ohio, western Maryland, and
western Virginia.
16 For a discussion of water management issues associated with shale energy development, see CRS Report R43635,
Shale Energy Technology Assessment: Current and Emerging Water Practices, by Mary Tiemann, Peter Folger, and
Nicole T. Carter. See also Jeffrey Logan, Garvin Heath, and Jordan Macknick, et al., Natural Gas and the
Transformation of the U.S. Energy Sector: Electricity, National Renewable Energy Laboratory, NREL Report No. TP-
6A50-55538, November 2012, 225 pp., http://www.nrel.gov/docs/fy13osti/55538.pdf.
17 William L. Ellsworth, “Injection-Induced Earthquakes,” Science, vol. 341, July 12, 2013,
http://www.sciencemag.org/content/341/6142/1225942.full.
18 For a detailed discussion of air pollution issues associated with oil and gas exploration and development and recent
EPA regulations, see CRS Report R42833, Air Quality Issues in Natural Gas Systems, by Richard K. Lattanzio.
19 U.S. Environmental Protection Agency, Overview of Final Amendments to Air Regulations for the Oil and Natural
Gas Industry: Fact Sheet, EPA, October 2012, http://www.epa.gov/airquality/oilandgas/pdfs/20120417fs.pdf.
20 When vented, natural gas (largely methane) is released to the air without being burned. In contrast, when natural gas
is flared (burned), the main by-product is carbon dioxide. Flaring is preferred to venting for safety reasons, but also
because methane is several times more potent than carbon dioxide as a greenhouse gas (although more short-lived in
the atmosphere). Flaring also reduces emissions of ozone-forming pollutants, compared to venting.
21 See CRS Report R42032, The Bakken Formation: Leading Unconventional Oil Development, by Michael Ratner et
al. See also U.S. Energy Information Administration, “North Dakota Aims to Reduce Natural Gas Flaring,” Today in
Energy, October 20, 2014, http://www.eia.gov/todayinenergy/detail.cfm?id=18451.
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State Regulation of Oil and Gas Development
Oil and natural gas development is occurring in at least 32 states.22 Shale gas, tight oil, or other
unconventional resources (such as coalbed methane) are found in many of these states, primarily
on non-federal lands (see Figure 6). States are the principal regulators of oil and gas production
activities on state and private lands.23 The federal government, through the Department of the
Interior’s Bureau of Land Management (BLM), has responsibility for overseeing oil and gas
development on federally managed lands; however, some states require operators on federal
public lands within state boundaries to comply with the state’s oil and gas rules.24
Figure 6. Unconventional Shale Plays in the Lower 48 States
(with federal lands shown)
Source: CRS, compiled from U.S. Energy Information Administration sources.
Notes: No information had been reported on active shale plays in Alaska at the time of this report. Hawaii’s
volcanic origin does not support the geologic process leading to the deposition of shale.
22 U.S. Energy Information Administration, Rankings: Natural Gas Marketed Production, 2012, http://www.eia.gov/
state/rankings/#/series/47. EIA reports gas production in 32 states and oil production in 31 states. Five states (Texas,
North Dakota, California, Alaska, and Oklahoma) accounted for the bulk of oil and gas production in 2012. The biggest
gains in oil production were in North Dakota and Texas, due in large part to increased horizontal drilling and hydraulic
fracturing activity.
23 For a review of federal laws and regulations addressing leasing of federal lands for exploration and production of oil,
gas, and coal, see CRS Report R40806, Energy Projects on Federal Lands: Leasing and Authorization, by Adam Vann.
24 States often enter into memoranda of understanding with BLM to coordinate administration and enforcement of
various regulatory requirements on public lands within the state.
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Hydraulic fracturing, traditionally without horizontal drilling, has been used for decades to
stimulate increased production from existing oil or gas wells. This technique, along with other
well stimulation techniques, has been regulated to varying degrees through state oil and gas
codes. The detail and scope of applicable regulations vary across the states, and some states have
regulated “well stimulation” broadly without addressing hydraulic “fracturing” explicitly.25 State
regulators have noted that hydraulic fracturing operations have been regulated through provisions
that address various production activities, including requirements regarding well construction
(e.g., casing and cementing), well stimulation (e.g., hydraulic fracturing), well operation (e.g.,
pressure testing and blowout prevention), and wastewater management.26
Nonetheless, drilling and fracturing methods and technologies have changed significantly over
time as they have been applied to more challenging formations, greatly increasing the amount of
water, fracturing fluids, and well pressures involved in oil and gas production operations. State
groundwater protection officials have reported that development of shale gas and tight oil using
high-volume hydraulic fracturing, in combination with directional drilling, has posed new
challenges for the management and protection of water resources.27 Consequently, many of the
major producing states have revised or are in the process of revising their oil and gas laws and
regulations to respond to these advances in oil and natural gas production technologies and
related changes in the industry.28
When revising laws and regulations, states have added provisions to address hydraulic fracturing
specifically, such as requirements for disclosure of chemicals used in hydraulic fracturing.
Additionally, various states have adopted measures on water resources protection (including
casing, cementing and pressure testing, well spacing, setbacks, water withdrawal, flowback, and
wastewater storage and disposal requirements).29 The Ground Water Protection Council reports
that the number of states that have regulations governing hydraulic fracturing specifically
25 For state-specific information, see the Interstate Oil and Gas Compact Commission, Summary of State Statutes and
Regulations, available at http://www.iogcc.state.ok.us/state-statutes.
26 For example, before the state enacted hydraulic fracturing legislation (SB 4) in September 2013, California regulators
noted that requirements for protecting underground resources and well construction standards “provide a first line of
protection from potential damage caused by hydraulic fracturing.” However, the state noted “There is a gap between
the requirements placed on oil and gas operators to safely construct and maintain their wells, and the information they
provide to the Division about hydraulic fracturing operations and steps taken to protect resources and the environment.
The Department’s pending regulatory process is intended to close that gap.” California Department of Conservation,
Hydraulic Fracturing in California, http://www.conservation.ca.gov/dog/general_information/Pages/
HydraulicFracturing.aspx. Among other provisions, the California law requires public disclosure of chemicals, baseline
and follow-up testing of nearby water wells, notification to nearby property owners and tenants, and groundwater
monitoring plans, and directs the state to conduct a comprehensive environmental study of impacts associated with
hydraulic fracturing. Also, SB 4 directs regulators to make any needed revisions to rules governing construction of
wells and well casings to ensure well integrity.
27 See, for example, Ground Water Protection Council, State Oil and Natural Gas Regulations Designed to Protect
Water Resources, 2014, http://www.gwpc.org/state-oil-gas-regulations-designed-protect-water-resources-2014-edition.
28 Alabama, Alaska, Arkansas, California, Colorado, Michigan, Montana, North Dakota, New Mexico, Ohio,
Pennsylvania, Texas, Utah, West Virginia, and Wyoming are among the states that in recent years have revised oil and
gas laws and/or rules that address unconventional oil and gas development, and hydraulic fracturing specifically.
Among states currently revising oil and gas rules are California, Indiana, Maryland, New York, and North Carolina.
29 For a comparison of state requirements for specific activities (e.g., wastewater disposal, chemical disclosure, and
cementing), see Resources for the Future, A Review of Shale Gas Regulations by State, Center for Energy Economics
and Policy, July 2012, http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale_Maps.aspx.
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increased from four in 2009 to 13 in 2013, and that the number of states requiring reporting of
hydraulic fracturing chemicals grew from nine in 2009 to 21 in 2013.30
Taking a different approach, New York State has imposed a de facto moratorium on high-volume
hydraulic fracturing pending completion of environmental and public health reviews and
development of new rules. Similarly, Maryland regulators, pursuant to executive order, have
studied the risks associated with deep drilling and hydraulic fracturing to identify new safeguards
that may be needed in permits. In 2013, North Carolina lawmakers enacted legislation prohibiting
the issuance of permits for oil and gas development using hydraulic fracturing and horizontal
drilling until new regulations were in place and the legislature took affirmative action to allow
permits to be issued, and in 2014, the state enacted legislation authorizing a regulatory permitting
program for shale gas development.31
Debate over the Federal Role
While states continue to adopt and implement varying frameworks for oversight and regulation of
unconventional gas and oil development, numerous citizen and environmental groups and
Members of Congress have pressed for greater environmental oversight of shale energy
development at the federal level. Some advocates of a larger federal role point to a wide range of
differences in substance, scope, and enforcement among state regulatory regimes, and assert that
a national framework is needed to ensure a consistent baseline level of environmental and human
health protection and transparency.32 Such advocates further argue that greater regulatory
uniformity would reduce risks and uncertainties to both the industry and the public.33 Others
argue against greater federal involvement, and point to established state oil and gas programs and
regulatory structures (which include a range of structures involving commissions, boards, or
divisions within natural resource agencies working to varying degrees with, or within, state
environmental agencies). In this view, experience lies with the states, and in addition to the
relative nimbleness of states to review and revise laws and rules, the states are better able to
consider regional differences in geology, topography, climate, and water resources.
In the 113th Congress, as in recent Congresses, the federal role in regulating oil and gas
production generally, and hydraulic fracturing specifically, has been the subject of hearings,
seminars, and legislation.34 A number of bills have been proposed to broaden the federal role,
while others have proposed to further limit federal involvement in regulating oil and gas
30 Ground Water Protection Council, State Oil and Natural Gas Regulations Designed to Protect Water Resources,
2014, p. 8.
31 General Assembly of North Carolina, Session Law 2013-365, Senate Bill 76. Also, Vermont banned hydraulic
fracturing (DOE’s EIA does not list Vermont as an oil- or gas-producing state). The New Jersey legislature passed a
ban on shale gas drilling; however, the governor vetoed the bill and imposed a one-year ban, which has expired.
32 See, for example, Matthew McFeeley, State Hydraulic Fracturing Disclosure Rules and Enforcement: A
Comparison, Natural Resources Defense Council, NRDC Issue Brief IB: 12-06-A, July 2012.
33 For further discussion, see Jeffrey Logan, Garvin Heath, and Elizabeth Paranhos et al., Natural Gas and the
Transformation of the U.S. Energy Sector: Electricity, Joint Institute for Strategic Energy Analysis, NREL/TP-6A50-
57702, Golden, CO, January 2013, http://www.nrel.gov/docs/fy13osti/55538.pdf.
34 The 113th Congress has explored the role of states and the federal government in oil and gas production, specifically,
and in environmental protection broadly. In February 2013, the House Committee on Energy and Commerce,
Subcommittee on Environment and the Economy, held a hearing, The Role of the States in Protecting the Environment
Under Current Law. The Senate Committee on Energy and Natural Resources held a series of Natural Gas
Roundtables, including a May 2013 forum on Shale Development: Best Practices and Environmental Concerns.
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development. Such proposals have been contentious, and Congress has not enacted such
legislation since amending the Safe Drinking Water Act (SDWA) in the Energy Policy Act
(EPAct) of 2005 (P.L. 109-58) to explicitly exclude from the SDWA definition of underground
injection the injection of fluids (other than diesel fuels) related to hydraulic fracturing
operations.35
Selected Federal Responses to Unconventional Resource Extraction
Provisions of several federal environmental laws and related regulations currently apply to certain
activities associated with oil and natural gas production. 36 The Clean Water Act (CWA), for
example, prohibits the discharge of pollutants from point sources into surface waters without a
permit,37 and the Safe Drinking Water Act (SDWA) requires an Underground Injection Control
(UIC) permit for wastewater disposal through deep well injection.38 Additionally, a SDWA UIC
permit is required for the underground injection of fluids or propping agents pursuant to hydraulic
fracturing if the injected fracturing fluids contain diesel fuels.39 In 2012, EPA promulgated
regulations under the authority of the Clean Air Act that require reductions in emissions related to
oil and natural gas production, including emissions of volatile organic compounds (VOCs) from
hydraulically fractured natural gas wells.40
While congressional debate has continued on legislative proposals, the Administration has been
pursuing additional initiatives to regulate or otherwise manage activities related to
unconventional oil and gas production. EPA has been most active, and is considering actions
under several pollution control statutes. Among these efforts, EPA is working to (1) establish
pretreatment standards to control discharges of wastewater from shale gas extraction to publicly
owned wastewater treatment plants; (2) revise water quality criteria to protect aquatic life from
discharges of brine produced during oil and gas extraction to surface waters; and (3) subject
hydraulic fracturing chemicals to toxic substance reporting requirements.41 In February 2014,
35 The Safe Drinking Water Act requires regulation of underground injection activities to protect underground sources
of drinking water. EPA has long regulated underground injections related to oil and gas field wastewater disposal and
enhanced oil recovery. Historically, EPA had not regulated injection of fluids for hydraulic fracturing of oil or gas
production wells. In 1997, the U.S. Court of Appeals for the 11th Circuit ruled that injections for fracturing for coalbed
methane production in Alabama constituted underground injection and must be regulated under the SDWA. For more
information, see CRS Report R41760, Hydraulic Fracturing and Safe Drinking Water Act Regulatory Issues, by Mary
Tiemann and Adam Vann.
36 See CRS Report R43152, Hydraulic Fracturing: Selected Legal Issues, by Adam Vann, Brandon J. Murrill, and
Mary Tiemann.
37 CWA Section 301 prohibits the discharge of pollutants into the nation’s waters except in compliance with the
provisions of the law, which include obtaining a discharge permit. 33 U.S.C. §1311. For information on applicable
CWA requirements, see Environmental Protection Agency, “Natural Gas Drilling in the Marcellus Shale, NPDES
Program Frequently Asked Questions,” March 16, 2011, http://www.epa.gov/npdes/pubs/hydrofracturing_faq.pdf.
38 The Safe Drinking Water Act of 1974 (P.L. 93-523) authorized the Underground Injection Control (UIC) program at
EPA. UIC provisions, as amended, are contained in SDWA Part C, §§1421-1426; 42 U.S.C. §§300h-300h-5.
39 EPAct 2005 (P.L. 109-58, §322), amended SDWA to exempt from the definition of underground injection the
injection of fluids or propping agents (other than diesel fuel) for hydraulic fracturing purposes.
40 The rules regulate VOC emissions from hydraulically fractured natural gas wells, compressors, pneumatic
controllers, storage vessels, and leaking components at onshore natural gas processing plants, as well as sulfur dioxide
emissions from onshore natural gas processing plants. The new standards require producers to capture about 90% of the
natural gas that escapes into the atmosphere as a result of production using hydraulic fracturing. For further discussion,
see CRS Report R42986, An Overview of Air Quality Issues in Natural Gas Systems, by Richard K. Lattanzio.
41 For details, see CRS Report R43152, Hydraulic Fracturing: Selected Legal Issues, by Adam Vann, Brandon J.
(continued...)
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EPA finalized permitting guidance for the use of diesel in hydraulic fracturing operations. The
Appendix of this report provides a brief overview of selected federal environmental research and
regulatory activities related to the production of tight oil and gas resources. Several of these
initiatives are reviewed below.
EPA Study on Hydraulic Fracturing and Drinking Water
In 2009, the 111th Congress urged EPA to conduct a study on the relationship between hydraulic
fracturing and drinking water to gain a better understanding of potential contamination risks.42 In
2011, EPA published a final study plan that identified research projects that would address the full
life cycle of water in hydraulic fracturing, from water acquisition to chemical mixing and
injection through wastewater treatment and/or disposal. The study is intended to (1) examine
conditions that may be associated with potential contamination of drinking water sources, and (2)
identify factors that may lead to human exposure and risks.43 As part of the study, EPA is
investigating five reported incidents of drinking water contamination in areas where hydraulic
fracturing has occurred. The purpose of the retrospective case studies is to determine the potential
relationship between reported impacts and hydraulic fracturing activities.44
In December 2012, EPA released a status report presenting the agency’s efforts through FY2012
on 18 research projects being conducted for the study.45 No data or findings were included. EPA
plans to synthesize the results from the research projects in a draft “report of results” in 2015.
EPA has designated the report of results as a “highly influential scientific assessment” (HISA),46
which will undergo peer review by EPA’s independent Science Advisory Board.47 In June 2013,
an agency researcher stated that the final report will not be completed before 2016.
(...continued)
Murrill, and Mary Tiemann.
42 The Department of the Interior, Environment, and Related Agencies Appropriations Act, 2010 (P.L. 111-88, H.Rept.
111-316):
Hydraulic Fracturing Study.—The conferees urge the Agency to carry out a study on the
relationship between hydraulic fracturing and drinking water, using a credible approach that relies
on the best available science, as well as independent sources of information. The conferees expect
the study to be conducted through a transparent, peer-reviewed process that will ensure the validity
and accuracy of the data. The Agency shall consult with other Federal agencies as well as
appropriate State and interstate regulatory agencies in carrying out the study, which should be
prepared in accordance with the Agency’s quality assurance principles.
43 U.S. Environmental Protection Agency, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking
Water Sources, Office of Research and Development, EPA/600/R-11/122, November 2011, http://www2.epa.gov/
hfstudy.
44 EPA is conducting retrospective case studies at five sites to develop information about the potential impacts of
hydraulic fracturing on drinking water resources under different circumstances. The case studies include (1) the Bakken
Shale in Dunn County, ND; (2) the Barnett Shale in Wise County, TX; (3) the Marcellus Shale in Bradford County,
PA; (4) the Marcellus Shale in Washington County, PA; and (5) coalbed methane in the Raton Basin, CO.
45 U.S. Environmental Protection Agency, Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water
Resources: Progress Report, Office of Research and Development, EPA 601/R-12/011, December 2012.
46 Ibid., p. 4.
47 Because EPA has designated the “report of results” as a “highly influential scientific assessment,” the agency is to
follow the peer review planning requirements described in the Office of Management and Budget’s Information
Quality Bulletin for Peer Review, 2004. The Bulletin states that important scientific information must be peer reviewed
by qualified specialists before being disseminated by the federal government. The EPA Science Advisory Board is an
external federal advisory committee that conducts peer reviews of significant EPA research products and activities.
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Multiagency Collaboration on Unconventional Oil and Gas Research
In March 2011, the White House issued a broad Blueprint for a Secure Energy Future, which
identified a need to “expand safe and responsible domestic oil and gas development and
production.” Additionally, the President directed the Secretary of Energy to identify steps that
could be taken to improve the safety and environmental performance of shale gas production, and
to develop consensus recommendations on practices to ensure the protection of public health and
the environment.48
In response, the Secretary of Energy’s Advisory Board (SEAB) convened the Shale Gas
Production Subcommittee to identify and evaluate issues and make recommendations to mitigate
possible impacts of shale gas development. The final report included recommendations for the
states, federal government, and industry. The subcommittee recommended, among other actions,
that companies and regulators—to the extent that such actions had not been undertaken—adopt
further measures to protect water quality and to manage water use and wastewater disposal,
publicly report the composition of water and flow throughout the fracturing and cleanup process,
disclose fracturing fluid composition, and adopt best practices for well development and
construction (especially casing, cementing, and pressure management).49 The committee also
recommended actions to protect air quality through reduction of emissions of air toxics, ozone
precursors, methane, and other pollutants.
In 2012, the President issued Executive Order (E.O.) 13605, Supporting Safe and Responsible
Development of Unconventional Domestic Natural Gas Resources, to coordinate the efforts of
federal agencies overseeing the development of unconventional domestic natural gas resources
and associated infrastructure. The order states “Because efforts to promote safe, responsible, and
efficient development of unconventional domestic natural gas resources are underway at a
number of executive departments and agencies, close interagency coordination is important for
effective implementation of these programs and activities.”50
E.O. 13605 established an interagency working group to coordinate agency activities and to
engage in long-term planning to ensure coordination on research, resource assessment, and
infrastructure development. In April 2012, the lead agencies—the Department of Energy (DOE),
EPA, and the Department of the Interior (DOI/U.S. Geological Survey)—signed a Memorandum
of Agreement to develop a multiagency research plan “to address the highest priority research
questions associated with safely and prudently developing unconventional shale gas and tight oil
reserves.” In July 2014, the three agencies released a research and development strategy for
unconventional oil and gas resources.51
48 The White House, “Blueprint for a Secure Energy Future,” March 30, 2011, p. 13, http://www.whitehouse.gov/sites/
default/files/blueprint_secure_energy_future.pdf.
49 U.S. Department of Energy, the Secretary of Energy Advisory Board (SEAB), Shale Gas Production Subcommittee,
Second Ninety Day Report, November 18, 2011, http://www.shalegas.energy.gov/. In November 2013, Secretary Moniz
requested the SEAB to form a task force to review how FracFocus “houses the information Federal and State regulatory
agencies require as part of their regulatory functions with regard to disclosure of the composition and quantities of
fracturing fluids injected into unconventional oil and gas wells.” This review is available at http://energy.gov/seab/
secretary-energy-advisory-board-seab-task-force-fracfocus-20.
50 Executive Order 13605, “Supporting Safe and Responsible Development of Unconventional Domestic Natural Gas
Resources” (Washington: GPO, 2012), http://www.gpo.gov/fdsys/pkg/DCPD-201200269/pdf/DCPD-201200269.pdf.
51 The Memorandum of Agreement and research strategy are available at the Administration website, “Multi-Agency
Collaboration on Unconventional Oil and Gas Research,” http://unconventional.energy.gov/.
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BLM Proposed Rule on Hydraulic Fracturing
While states have predominant regulatory authority for oil and gas development on state and
private lands, the federal government is responsible for managing oil and gas resources on federal
lands. However, some states require oil and gas operators on federal lands within their state to
comply with state rules, and consequently, the debate over the federal role in regulating
unconventional oil and gas production has extended to activities on federal lands.
The Bureau of Land Management (BLM), within the Department of the Interior, is the federal
agency responsible for overseeing oil, natural gas, and coal leasing and production on federal and
Indian lands, including split estate where the federal government owns the subsurface mineral
estate.52 BLM is tasked with leasing subsurface mineral rights not only on BLM-administered
land, but also for lands managed by other federal agencies, including the U.S. Forest Service.53
BLM oversees roughly 700 million subsurface acres of federal mineral estate and 56 million
subsurface acres of Indian mineral estate nationwide. BLM estimates that approximately 3,400
wells have been drilled annually in recent years on federal and Indian lands, and that hydraulic
fracturing is used to stimulate roughly 90% of these wells.54
In May 2012, BLM proposed revisions to its oil and natural gas development rules in response to
the increased use of hydraulic fracturing on federal and Indian lands.55 The proposed rule broadly
addressed “well stimulation, including hydraulic fracturing,” and would revise BLM oil and gas
production regulations that were promulgated in 1982 and last revised in 1988.56 In the 2012
Federal Register notice, BLM noted that the rule would modernize its management of well
stimulation activities, and stated that the “rule is necessary to provide useful information to the
public and to assure that hydraulic fracturing is conducted in a way that adequately protects the
environment.” 57 The preamble further noted that the proposed changes were partly in response to
recommendations made by the aforementioned SEAB Shale Gas Subcommittee.
BLM received more than 177,000 comments on the proposed rule, and in May 2013, BLM
published a Supplemental Notice of Proposed Rulemaking (SNPR) and Request for Comment.
BLM has requested comments on the multiple changes in the proposed rule, and provided 30 days
for public comment. (The comment period was extended for 60 days, to August 23, 2013.)58 The
bureau has responded to the roughly 1,340,000 comments it received on the SNPR, and has a goal
of issuing a final rule in January 2015.
Changes notwithstanding, the 2012 proposed rule and the 2013 SNPR share overarching features
that reflect recommendations of the SEAB subcommittee report. Both proposals would (1) add
reporting and management requirements for water and other fluids used and produced in
52 Mineral Leasing Act of 1920, 30 U.S.C. §181.
53 For a discussion of federal lands leasing authorities and activities, see CRS Report R40806, Energy Projects on
Federal Lands: Leasing and Authorization, by Adam Vann.
54 77 Federal Register 27691-27693.
55 Department of the Interior, Bureau of Land Management, “Oil and Gas; Well Stimulation, Including Hydraulic
Fracturing, on Federal and Indian Lands,” 77 Federal Register 27691, May 11, 2012.
56 The proposed rule would amend existing BLM regulations at 43 C.F.R. Section 316.3-2.
57 77 Federal Register 27692-27693.
58 Department of the Interior, Bureau of Land Management, “Oil and Gas; Hydraulic Fracturing on Federal and Indian
Lands: Supplemental Notice of Proposed Rulemaking,” 78 Federal Register 31636, May 24, 2013.
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hydraulic fracturing operations, with emphasis on managing fluids that flow back to the surface,
(2) require public disclosure of hydraulic fracturing chemicals, and (3) tighten well construction
and operation requirements to help ensure that wellbore integrity is maintained throughout the
hydraulic fracturing process.
Among the changes to the 2012 proposed rule, the BLM 2013 Supplemental Notice would
• narrow the scope of the rule to apply only to hydraulic fracturing and refracturing
(the 2012 proposed rule would have applied to “well stimulation” activities
broadly);59
• provide opportunities for individual states or tribes to work with BLM to craft
variances for specific regulatory provisions that would allow compliance with
state or tribal requirements to be accepted as compliance with the BLM rule (if
the variance would meet or exceed the effectiveness of the rule provision it
would replace);60
• allow operators to report hydraulic fracturing chemical information to BLM
either directly or through the FracFocus website or other specified database,61
and provide more detailed guidance on procedures for handling trade secret
claims;62
• clarify that mechanical integrity testing would be required for all fracturing and
refracturing operations;63
• require that all fracturing operations isolate all usable water formations to protect
them from contamination, and allow operators to use an expanded set of cement
evaluation tools to help ensure that usable water zones have been isolated and
protected;64 and
• allow an advanced Notice of Intent to be submitted for a single well, or group of
wells with the same geological characteristics within a field where hydraulic
fracturing operations are likely to be successful using the same design.65
59 SNPR, §3162.3-3(a) and §3160.0-5. This revision excludes acidizing and enhanced secondary and tertiary recovery
so that the rule would apply only to hydraulic fracturing and not to other “well stimulation” activities.
60 SNPR, §3162.3-3(k). In 2012, BLM proposed to implement on public lands “whichever rules, state or Federal, are
most protective of Federal lands and resources and the environment, consistent with longstanding practice and relevant
statutory authorities.” 77 Federal Register 72694.
61 SNPR, §3162.3-3(i). Operators submitting information through FracFocus would be required to certify that the
information is correct and certify that the operator complied with applicable laws governing notice and permits.
FracFocus was established in 2011 by the Ground Water Protection Council and the Interstate Oil and Gas Compact
Commission (IOGCC). FracFocus is a public registry where oil and gas companies may voluntarily identify chemicals
used in hydraulic fracturing operations at specific wells. Many states allow or require operators to meet state disclosure
requirements by posting information on the FracFocus website (http://www.fracfocus.org).
62 SNPR, §3162.3-3(j)1-4. Modeled on Colorado rules, BLM would instruct operators not to disclose trade secret
information to BLM or on FracFocus. Operators would submit an affidavit stating that withheld information is entitled
to withholding. BLM would retain authority to require operators to submit claimed trade secret information.
63 SNPR, §3162.3-3(f).
64 SNPR, §3162.3-3(b) and §3162.3-3(d).
65 SNPR, §3162.3-3(d).
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BLM also requested comment on whether to require hydraulic fracturing wastewater to be stored
in tanks only, rather than in lined pits or tanks as proposed in 2012. BLM sent the rule to the
Office of Management and Budget (OMB) for review in 2014 and expects to promulgate a final
rule in January 2015. The bureau also has begun taking steps to further revise its oil and gas rules
to address emissions of air pollutants.
Coast Guard Regulation of Barge Shipments of Shale Gas Wastewater
The disposal of the large volumes of wastewater produced during shale gas extraction has posed
challenges for companies, state regulators, and communities—particularly in the Marcellus Shale
region. On-site disposal options are limited, and trucking wastewater to distant injection wells is
costly. In 2012, the Coast Guard received two requests for approval for the bulk shipment of
wastewater resulting from shale gas extraction in the Marcellus Shale to storage or treatment
centers and final disposal sites in Ohio, Texas, and Louisiana.
The Coast Guard regulates the shipment of hazardous materials on the nation’s rivers, and
classifies cargoes for bulk shipment.66 For a cargo that has not been classified in the regulations
or under prior policy, the ship owner must request Coast Guard approval prior to shipping the
cargo.67 The Coast Guard has identified concerns with shipment of shale gas wastewater in
barges. A key Coast Guard concern with the wastewater is “its potential for contamination with
radioactive isotopes such as radium-226 and -228. Radium is of particular concern because it is
chemically similar to calcium and so will easily form surface residues and may lead to radioactive
surface contamination of the barges.”68 Consequently, the Coast Guard currently does not allow
barge shipment of shale gas extraction wastewater (SGEWW), and is developing a policy to
allow SGEWW to be transported for disposal. In March 2013, the Coast Guard submitted for
review to OMB a draft document, “Carriage of Conditionally Permitted Shale Gas Extraction
Waste Water in Bulk.”
In October 2013, the Coast Guard published a notice of availability of a proposed “policy letter”
concerning barge shipments of SGEWW and requested public comment. The Coast Guard
received more than 70,000 comments, and has been reviewing them. After addressing public
comments, the Coast Guard plans to issue a final policy letter that specifies conditions and
information requirements that barge owners would be required to meet to receive approval to
transport shale gas wastewater in bulk on inland waterways.69
66 This action is based on authority in 46 U.S.C. Chapter 37—“Carriage of Liquid Bulk Dangerous Cargoes.”
Implementing regulations are published in 46 C.F.R. Subchapter O—“Certain Bulk Dangerous Cargoes.”
67 See 46 C.F.R. 153.900(c)-(d) or 46 C.F.R. 151.01-15.
68 U.S. Coast Guard, Marine Safety Engineering, Shale Gas Extraction Waste Water, Commercial Regulations and
Standards Directorate, Fall 2012, p. 5, http://www.uscg.mil/hq/cg5/cg52/docs/2012fall.pdf.
69 Department of Homeland Security, Coast Guard, “Carriage of Conditionally Permitted Shale Gas Extraction Waste
Water in Bulk: Notice of Availability and Request for Comments,” 78 Federal Register 64905, October 30, 2013.
http://www.uscg.mil/hq/cg5/cg521/.
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Legislation in the 113th Congress
Contrasting bills have been offered in the 113th Congress addressing unconventional oil and gas
development, and hydraulic fracturing specifically. Several bills would expand federal regulation
of hydraulic fracturing activities, while others would limit federal involvement.70 House-passed
H.R. 2728 would amend the Mineral Leasing Act71 to prohibit the Department of the Interior from
enforcing any federal regulation, guidance, or permit requirement regarding hydraulic fracturing
relating to oil, gas, or geothermal production activities on or under any land in any state that has
regulations, guidance, or permit requirements for hydraulic fracturing. Although this language is
broadly applicable to any federal regulation, guidance, and permit requirements “regarding
hydraulic fracturing,” the prohibition on enforcement applies only to the Department of the
Interior, and therefore would presumably impact only hydraulic fracturing operations on lands
managed by that agency. The bill also would require the Department of the Interior to defer to
state regulations, permitting, and guidance for all activities related to hydraulic fracturing relating
to oil, gas, or geothermal production activities on federal land regardless of whether those rules
were duplicative, more or less restrictive, or did not meet federal guidelines. The bill, as passed,
would further prohibit the department from enforcing hydraulic fracturing regulations on Trust
lands, except with express tribal consent. The House passed H.R. 2728, amended, on November
20, 2013. The same day, S. 1743, a companion bill to H.R. 2728, as introduced, was offered in the
Senate. H.R. 2728 was placed on the Senate Legislative Calendar in December 2013. In
September 2014, the House passed broad energy legislation (H.R. 2), which included the text of
H.R. 2728 in Subdivision D.
Relatedly, the Fracturing Regulations are Effective in State Hands (FRESH) Act, H.R. 2513 and
S. 1234, would establish that a state has sole authority to regulate hydraulic fracturing operations
on lands within the boundaries of the state. The legislation further specifies that hydraulic
fracturing on federal public lands shall be subject to the law of the state in which the land is
located. H.R. 1548 (H.Rept. 113-263) would prohibit the BLM hydraulic fracturing rule from
having any effect on land held in trust or restricted status for Indians, except with the express
consent of its Indian beneficiaries. H.R. 2, Section 25009, includes this language. Similarly, S.
1482, the Empower States Act of 2013 generally would prohibit the Secretary of the Interior from
issuing regulations or guidelines regarding oil and gas production on federal land in a state if the
state has otherwise met the requirements under applicable federal law. Among other provisions,
the bill also would (1) amend the Safe Drinking Water Act to require federal agencies, before
issuing any oil and gas regulation or guideline, to seek comment and consult with each affected
state agency and Indian tribe, and (2) require any future rule requiring disclosure of hydraulic
fracturing chemicals to refer to the FracFocus database.
70 Similar bills were offered in the 112th Congress, but none was enacted. H.R. 1084/S. 587 proposed repealing the
hydraulic fracturing exemption established in the Energy Policy Act (EPAct) of 2005, and amending the term
“underground injection” to include the injection of fluids used in hydraulic fracturing operations, thus authorizing EPA
to regulate this process under the SDWA. The bills also would have required disclosure of the chemicals used in the
fracturing process. In response to rules proposed by BLM in 2012, S. 2248/H.R. 4322 proposed that a state would have
sole authority to regulate hydraulic fracturing on federal lands within state boundaries; H.R. 3973 would have
prohibited the rule from having any effect on Indian lands; and H.R. 6235 would have barred a final rule for 10 years,
pending an impact study.
For further discussion, see CRS Report R41760, Hydraulic Fracturing and Safe Drinking Water Act Regulatory Issues,
by Mary Tiemann and Adam Vann.
71 30 U.S.C. §181 et seq.
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
In contrast to the above bills, several others propose to expand federal regulation of hydraulic
fracturing. In the first session, the Fracturing Responsibility and Awareness of Chemicals Act
(FRAC) of 2013 was introduced in the House (H.R. 1921) and the Senate (S. 1135). The bills
would amend the Safe Drinking Water Act to (1) require disclosure of the chemicals used in the
fracturing process, and (2) repeal the hydraulic fracturing exemption established in EPAct 2005
and amend the term “underground injection” to include the injection of fluids used in hydraulic
fracturing operations, thus authorizing EPA to regulate this process under the SDWA. The
Climate Protection Act of 2013, S. 332, Section 301, contains similar chemical disclosure
provisions. Additionally, S. 332 would repeal SDWA Section 1425, which provides states with an
alternative to meeting the specific requirements contained in EPA UIC regulations promulgated
under Section 1421 by allowing states to demonstrate to EPA that their existing programs for oil
and gas injection wells are effective in preventing endangerment of underground sources of
drinking water.72 S. 332, Section 302, would require EPA to report to Congress on fugitive
methane emissions resulting from natural gas infrastructure.
Legislation also has been introduced to require baseline and follow-up testing of potable
groundwater supplies in the vicinity of hydraulic fracturing operations. H.R. 2983, the Safe
Hydration is an American Right in Energy Development (SHARED) Act of 2013, would amend
the SDWA to prohibit hydraulic fracturing unless the person proposing to conduct the fracturing
operations agreed to testing and reporting requirements regarding underground sources of
drinking water. The legislation would require testing prior to the start of injection operations, and
during and after hydraulic fracturing operations. Testing would be required for any substance EPA
determined would indicate damage associated with hydraulic fracturing operations. H.R. 2983
would require EPA to post on its website all test results, searchable by zip code.
H.R. 2850 (H.Rept. 113-252), the EPA Hydraulic Fracturing Study Improvement Act, would
require EPA to follow certain procedures governing peer review and data presentation in
conducting its study on the relationship between hydraulic fracturing and drinking water. As
reported, the bill would require EPA to release the final report by September 30, 2016. The bill
was included in Division D of H.R. 2, as passed by the House.
Broader oil and gas regulatory bills include H.R. 1154, the Bringing Reductions to Energy’s
Airborne Toxic Health Effects (BREATHE) Act, which would amend the Clean Air Act to
authorize EPA to aggregate emissions from oil and gas wells, pipelines, and related units for
purposes of regulating toxic air pollutants. H.R. 2825, the Closing Loopholes and Ending
Arbitrary and Needless Evasion of Regulations (CLEANER) Act of 2013, would amend the Solid
Waste Disposal Act to require EPA to determine whether wastes associated with oil and gas
production meet the criteria for hazardous waste, and to regulate any such wastes.
72 42 U.S.C. §300h-4.
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
Conclusion: Above- and Below-Ground Issues
a Concern
The prospect that by the end of the decade the United States could become a significant exporter
of natural gas and the world’s leading oil producer is a phenomenal change of circumstances from
just a few years ago. The technological advances that drove the changes in the United States have
also reversed the global perspective of dwindling oil and natural gas resources, and increased the
concern about greenhouse gas emissions. Other countries seek to emulate the U.S. production
success, but have yet to do so. The U.S. oil and gas situation continues to be extremely dynamic,
and many questions remain about how the United States will develop its resources.
Many observers, including U.S. government officials, have only recently recognized the
tremendous resource size and the benefits that will accrue from developing the resources. Even
though shale gas development is still considered very new and tight oil production is even newer,
the industry has continued to improve its efficiency in extracting the resources, particularly of
natural gas. As more industry resources are shifted to tight oil plays, the natural gas sector has had
to produce more with less. Some in industry point out that at the beginning of shale gas
development about 5% of the resource was able to be extracted; now it is closer to 20%, but will
likely increase over time. By comparison, the extraction rate for conventional gas is between 30%
and 60% of the resource.
Development of these resources has generated concern and debate over potential environmental
and human health risks. Concerns include potential impacts to groundwater and surface water
resources from well development and stimulation operations and wastewater management, as
well as air quality impacts from emissions of air pollutants, including methane. These concerns
have drawn scrutiny of regulatory regimes governing this industry, and have led to calls for
greater federal oversight of oil and gas development. Although primary regulatory authority over
oil and natural gas exploration and production on state and private lands generally rests with the
states, provisions of several federal environmental laws currently apply to certain activities
associated with oil and natural gas exploration and production. Moreover, EPA is reviewing other
statutory authorities and pursuing new regulatory initiatives, and BLM has proposed revisions to
its oil and gas rules to address hydraulic fracturing on federal and Indian lands. A broader concern
among some is that the low price of natural gas is having negative consequences for the
development and growth in energy efficiency, renewable energy sources, and nuclear power,
potentially resulting in another generation of greenhouse-gas-producing energy sources.
The 113th Congress has held hearings, roundtables, and other discussions on issues associated
with unconventional oil and gas development broadly, and on the role of the states specifically.
Bills have been introduced to expand and also to constrain federal involvement in oil and gas
development involving hydraulic fracturing. In the meantime, the Administration is pursuing
actions to broaden federal oversight of this industry sector through administrative means.73
73 See the Appendix for a review of federal research and regulatory initiatives related to unconventional oil and gas
production, with emphasis on hydraulic fracturing.
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
Appendix. Selected Federal Initiatives Related to
Unconventional Oil and Gas Production
Table A-1. Selected Federal Actions
Related to Unconventional Oil and Gas Production
(with emphasis on hydraulic fracturing)
Agency: Statute,
as Amended
Regulatory/Guidance
Research
Status
EPA: Clean Air
Air emissions. In 2012, EPA issued regulations that
Rules
were
Act (CAA)
revised existing rules and promulgated new ones to
promulgated in
regulate emissions of volatile organic compounds
August 2012 (77
(VOCs), sulfur dioxide, and hazardous air pollutants
Federal Register
(HAPs) from many production and processing activities
49489);
in the oil and gas sector that had not been subject
requirements phase
previously to federal regulation.
in through 2015.
Particularly pertinent to shale gas production are the
EPA agreed to
New Source Performance Standards (NSPS), which
revisit elements of
require reductions in emissions of VOCs from
the NSPS, and on
hydraulically fractured natural gas wells. The rules
April 12, 2013,
require operators to use reduced emissions
proposed revisions
completions (green completions) for all hydraulically
to the NSPS for
fractured natural gas wells beginning no later than
storage tanks (78
January 2015.
Federal Register
22125).
Applying broadly across the sector, the NSPS require
reductions of VOCs from compressors, pneumatic
controllers, storage vessels, and other emission
sources, and also revise existing standards for sulfur
dioxide emissions from onshore natural gas processing
plants, and HAPs from dehydrators and storage tanks.
In September 2013, EPA updated its 2012 performance
On
September
23,
standards for oil and natural gas to address VOC
2013, EPA finalized
emissions from storage tanks used by the crude oil and
revisions to the
natural gas production industry. The updates are
NSPS for storage
intended to ensure tanks likely to have the highest
tanks (78 Federal
emissions are controlled first, while providing tank
Register 58416).
owners and operators time to purchase and install
VOC controls. The amendments reflect recent
information showing that more storage tanks will be
coming on line than the agency originally estimated
(thus, presumably, producers need more time to
purchase and install emission controls).a
In July 2014, EPA proposed updates and clarifications
On July 17, 2014,
to NSPS requirements for well completions, storage
EPA proposed
tanks, and natural gas processing plants. The proposal
changes to the NSPS
would not change the required emission reductions in
rules. (79 Federal
the rules, including standards applicable to hydraulically
Register 41752).
fractured natural gas wells.
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
Agency: Statute,
as Amended
Regulatory/Guidance
Research
Status
EPA: Clean
Wastewater discharge. Produced water and
Draft
criteria
Water Act
flowback from hydraulic fracturing have high levels of
document expected
(CWA)
total dissolved solids (TDS), largely chlorides, which
in late 2014.
can harm aquatic life and affect receiving water uses
(such as fishing or irrigation). EPA is updating its
chloride water quality criteria for protection of aquatic
life.
CWA Section 304(a)(1) requires EPA to develop
criteria for water quality that reflect the latest scientific
understanding of the effects of pol utants on aquatic life
and human health. States use EPA-recommended
criteria to establish state water quality standards,
which in turn are used to develop enforceable
discharge permits.
If reflected in state water quality standards, the revised
chloride water quality criteria could affect discharges of
produced water from extraction of conventional and
unconventional oil and gas.b
EPA: CWA
Wastewater discharge. In 2011, EPA indicated that
Notice of the final
it was initiating two separate rulemakings to revise the
Effluent Guidelines
Effluent Limitations Guidelines and Standards (ELGs)
Program Plan was
for the Oil and Gas Extraction Point Source Category
published in
to control discharges of wastewater from (1) coalbed
October 2011 (76
methane (CBM) and (2) shale gas extraction. Under
Federal Register
CWA Section 304(m), EPA sets national standards for
66286).
discharges of industrial wastewater based on best
available technologies that are economically achievable
For shale gas
(BAT). States incorporate these limits into discharge
wastewater, EPA
permits. Shale and CBM wastewaters often contain
plans to propose a
high levels of total dissolved solids (TDS—i.e., salts),
rule in February
and shale gas wastewater may contain chemical
2015, and finalize the
contaminants, naturally occurring radioactive materials
rule in March 2016.
(NORM), and metals.
On August 7, 2013,
Discharges to surface water: Currently, shale gas
EPA proposed to
wastewater may not be discharged directly to surface
delist CBM from the
waters.
ELG rulemaking plan
CBM wastewater is not subject to national discharge
based on the
standards; rather, CBM wastewater discharge permits
“declining prevalence
are based on best professional judgments of state or
and economic
EPA permit writers. EPA was working to develop
viability” of the
regulatory options to control direct discharges of CBM
industry. EPA
wastewaters, but determined in 2013 that no
determined that no
economically achievable technology was available.
economically
achievable
Discharges to treatment plants: Current ELGs lack
technology is
pretreatment standards for discharges of shale gas or
available currently
CBM wastewaters to publicly owned wastewater
(78 Federal Register
treatment works (POTWs), which typically are not
48159).
designed to treat this wastewater. EPA is developing
national pretreatment standards that shale gas and
CBM wastewaters would be required to meet before
discharge to a POTW to ensure that the receiving
facility could treat the wastewater effectively.c
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
Agency: Statute,
as Amended
Regulatory/Guidance
Research
Status
EPA: Emergency
Chemical disclosure. EPA has been considering an
Notice of receipt of
Planning and
October 2012 petition by nongovernmental
petition published on
Community
organizations to subject the oil and natural gas
January 3, 2014 (79
Right-to-Know
extraction industry to Toxics Release Inventory (TRI)
Federal Register 393).
Act (EPCRA)
reporting under EPCRA. Section 313 of EPCRA
requires owners or operators of certain industrial
No published
facilities to report on releases of toxic substances to
schedule for EPA’s
the state and EPA. EPA and states are required to
response to petition.
make nonproprietary data publicly available through
the TRI website.
EPA: Safe
Diesel fuels. EPA has issued UIC Program Guidance for
Draft
guidance
Drinking Water
Permitting Hydraulic Fracturing with Diesel Fuels in
issued in May 2012.
Act (SDWA)
response to the revised SDWA definition of
“underground injection” in the Energy Policy Act
Final guidance issued
(EPAct) of 2005 to explicitly exclude the underground
in February 2014.
injection of fluids (other than diesel fuels) used in
hydraulic fracturing. The guidance provides
recommendations for EPA permit writers to use in
writing permits for hydraulic fracturing operations
using diesel fuels. The guidance applies in states where
EPA implements the UIC program for oil and natural
gas related (Class II) injection wells. States are not
required to adopt the guidance, but may do so.d
EPA: SDWA
Study. EPA is
Progress report
studying the
issued in December
relationship
2012.
between
hydraulic
Draft report is
fracturing and
expected to be
drinking water.
submitted for peer
Congress
review in 2015.
requested the
study in EPA’s
A final report is
FY2010
expected in 2016
appropriations
(extended from
act. EPA
2014).
designated the
pending “report
of results” as a
“highly
influential
scientific
assessment”
(HISA), which
requires peer
review by
qualified
specialists.
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
Agency: Statute,
as Amended
Regulatory/Guidance
Research
Status
EPA: Toxic
Chemical reporting. In response to a citizen petition
Initiated in January
Substances
(TSCA Section 21), EPA published an Advance Notice
2012.
Control Act
of Proposed Rulemaking (ANPRM) to get input on the
(TSCA)
design and scope of possible reporting requirements
Advanced Notice of
for hydraulic fracturing chemicals. EPA is considering
Proposed
requiring information reporting under TSCA Section
Rulemaking (ANPR)
8(a), and health and safety data reporting under Section
under TSCA Section
8(d). EPA is seeking comment on the types of chemical
8 published May 9,
information that could be reported and disclosed, and
2014 (79 Federal
approaches to obtaining this information for chemicals
Register 28664).
used in hydraulic fracturing.
Public comment
period closed
September 18, 2014.
EPA: Resource
Storage/disposal pits and ponds. EPA has been
In April 2014, EPA
Conservation and
considering developing guidance to address the design,
issued a Compilation
Recovery Act
operation, maintenance, and closure of pits used to
of Publicly Available
(RCRA)
store hydraulic fracturing fluids for reuse or pending
Sources of Voluntary
final disposal. These wastes are exempt from regulation
Management Practices
as a hazardous waste under RCRA.
for Oil and Gas
Exploration and
In April 2014, EPA issued a document that compiles
Production (E&P)
voluntary management practices for oil and gas
Wastes as They
exploration and production wastes. This non-
Address Pits, Tanks,
regulatory, non-guidance document is intended to
and Land Application.
provide information only, and does not establish
agency policy.
Department of
Hydraulic fracturing on public lands. BLM has
Rule was first
the Interior,
proposed revisions to rules governing oil and natural
proposed in May
Bureau of Land
gas production on federal and Indian lands. BLM
2012; after extensive
Management
proposes to (1) require public disclosure of chemicals
public comment,
(BLM): Mineral
used in hydraulic fracturing, (2) tighten regulations
BLM issued a
Leasing Act,
related to well-bore integrity, and (3) add new
Supplemental Notice
Indian Mineral
reporting and management/storage/disposal
of Proposed
Leasing Act
requirements for water used in hydraulic fracturing.
Rulemaking on May
24, 2013 (78 Federal
Register 31636).
Final rule expected
in January 2015.
Department of
Wastewater shipment. The Coast Guard regulates
On October 30,
Homeland
the shipment of hazardous materials on the nation’s
2013, the Coast
Security, Coast
rivers. Because of the potential for shale gas
Guard published a
Guard:
wastewater in the Marcellus Shale region to contain
notice for a one-
46 U.S.C. Ch. 37
radioactive materials (especially radium, which can
month comment
form surface residues and may lead to radioactive
period on a
surface contamination of the barges), the Coast Guard
proposed policy
currently does not al ow barge shipment of shale gas
letter setting
extraction wastewater. In 2013, the Coast Guard’s
conditions for bulk
Hazardous Materials Division issued a proposed policy
shipment of shale gas
letter establishing requirements for bulk shipment of
wastewater (78
shale gas extraction wastewater by barge for disposal.
Federal Register
The Coast Guard received more than 70,000
64905).
comments, and has been reviewing them.
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions
Agency: Statute,
as Amended
Regulatory/Guidance
Research
Status
DOE/EPA/DOI-
Federal
Multiagency
USGS:
research
Research Strategy
E.O. 13605
coordination.
was issued on July
In 2012, the
18, 2013.e
three agencies
agreed, through
an MOU, to
develop a
multiagency
research plan
“to address the
highest priority
research
questions
associated with
safely and
prudently
developing
unconventional
shale gas and
tight oil
resources.”
Source: Prepared by the Congressional Research Service.
Notes: This table presents selected Administration activities related to unconventional oil and natural gas
extraction. It excludes, for example, regional or site-specific research studies conducted by federal agencies.
More information on EPA initiatives to regulate oil and gas production and hydraulic fracturing is available at
EPA’s website, Natural Gas Extraction—Hydraulic Fracturing, http://www2.epa.gov/hydraulicfracturing.
a. <001These CAA rules, issued under court order, establish new air emissions standards for the “Crude
Oil and Natural Gas Production” and “Natural Gas Transmission and Storage” source categories. For
details, see CRS Report R42986, An Overview of Air Quality Issues in Natural Gas Systems, by Richard K.
Lattanzio.
b. <003For more information, see the EPA Water Quality Criteria web page, http://water.epa.gov/scitech/
swguidance/standards/criteria/.
c. <004EPA explains that “[f]or direct dischargers of unconventional oil and gas wastewaters from onshore
oil and gas facilities—with the exception of coalbed methane—technology-based limitations are based on
the Effluent Limitations Guidelines (ELGs) for the Oil and Gas Extraction Category (40 CFR Part 435).
Permits for onshore oil and gas facilities must include the requirements in Part 435, including a ban on the
discharge of pollutants, except for wastewater that is of good enough quality for use in agricultural and
wildlife propagation for those onshore facilities located in the continental United States and west of the 98th
meridian. . Part 435 does not currently include categorical pretreatment standards for indirect discharges
to publicly owned treatment works (POTWs) for wells located onshore.” Source: U.S. Environmental
Protection Agency, Unconventional Extraction in the Oil and Gas Industry, http://water.epa.gov/scitech/
wastetech/guide/oilandgas/unconv.cfm.
d. <006EPA regulates the underground injection of fluids through SDWA §§1421-1426; 42 U.S.C. §§300h-
300h-5. In February 2014, EPA issued UIC Program Guidance for Permitting Hydraulic Fracturing with Diesel
Fuels, which generally follows EPA Class II underground injection well requirements (i.e., wel construction
standards; mechanical integrity testing; operating, monitoring, and reporting requirements; and public
notification and financial responsibility requirements). The guidance provides recommendations for EPA
permit writers for tailoring requirements for hydraulic fracturing using diesel fuels. The guidance applies in
states where EPA implements the UIC program for Class II wel s (including Pennsylvania, New York,
Michigan, Kentucky, Tennessee, and Virginia).
e. Federal Multiagency Collaboration on Unconventional Oil and Gas Research—A Strategy for Research and
Development, http://unconventional.energy.gov/.
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Author Contact Information
Michael Ratner
Mary Tiemann
Specialist in Energy Policy
Specialist in Environmental Policy
mratner@crs.loc.gov, 7-9529
mtiemann@crs.loc.gov, 7-5937
Congressional Research Service
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