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United States Government Accountability Office: 
GAO: 

Report to Congressional Requesters: 

September 2012: 

Oil and Gas: 

Information on Shale Resources, Development, and Environmental and 
Public Health Risks: 

GAO-12-732: 

GAO Highlights: 

Highlights of GAO-12-732, a report to congressional requesters. 

Why GAO Did This Study: 

applications of horizontal drilling techniques and hydraulic 
fracturing-—in which water, sand, and chemical additives are injected 
under high pressure to create and maintain fractures in underground 
formations-—allow oil and natural gas from shale formations (known as 
“shale oil” and “shale gas”) to be developed. As exploration and 
development of shale oil and gas have increased––including in areas of 
the country without a history of oil and natural gas development––
questions have been raised about the estimates of the size of these 
resources, as well as the processes used to extract them. 

GAO was asked to determine what is known about the (1) size of shale 
oil and gas resources and the amount produced from 2007 through 2011 
and (2) environmental and public health risks associated with the 
development of shale oil and gas. GAO reviewed estimates and data from 
federal and nongovernmental organizations on the size and production 
of shale oil and gas resources. GAO also interviewed federal and state 
regulatory officials, representatives from industry and environmental 
organizations, oil and gas operators, and researchers from academic 
institutions. 

What GAO Found: 

Estimates of the size of shale oil and gas resources in the United 
States by the Energy Information Administration (EIA), U.S. Geological 
Survey (USGS), and the Potential Gas Committee––three organizations 
that estimate the size of these resources-—have increased over the 
last 5 years, which could mean an increase in the nation’s energy 
portfolio. For example, in 2012, EIA estimated that the amount of 
technically recoverable shale gas in the United States was 482 
trillion cubic feet—an increase of 280 percent from EIA’s 2008 
estimate. However, according to EIA and USGS officials, estimates of 
the size of shale oil and gas resources in the United States are 
highly dependent on the data, methodologies, model structures, and 
assumptions used to develop them. In addition, less is known about the 
amount of technically recoverable shale oil than shale gas, in part 
because large-scale production of shale oil has been under way for 
only the past few years. Estimates are based on data available at a 
given point in time and will change as additional information becomes 
available. In addition, domestic shale oil and gas production has 
experienced substantial growth; shale oil production increased more 
than fivefold from 2007 to 2011, and shale gas production increased 
more than fourfold from 2007 to 2011. 

Oil and gas development, whether conventional or shale oil and gas, 
pose inherent environmental and public health risks, but the extent of 
these risks associated with shale oil and gas development is unknown, 
in part, because the studies GAO reviewed do not generally take into 
account the potential long-term, cumulative effects. For example, 
according to a number of studies and publications GAO reviewed, shale 
oil and gas development poses risks to air quality, generally as the 
result of (1) engine exhaust from increased truck traffic, (2) 
emissions from diesel-powered pumps used to power equipment, (3) gas 
that is flared (burned) or vented (released directly into the 
atmosphere) for operational reasons, and (4) unintentional emissions 
of pollutants from faulty equipment or impoundments—temporary storage 
areas. Similarly, a number of studies and publications GAO reviewed 
indicate that shale oil and gas development poses risks to water 
quality from contamination of surface water and groundwater as a 
result of erosion from ground disturbances, spills and releases of 
chemicals and other fluids, or underground migration of gases and 
chemicals. For example, tanks storing toxic chemicals or hoses and 
pipes used to convey wastes to the tanks could leak, or impoundments 
containing wastes could overflow as a result of extensive rainfall. 
According to the New York Department of Environmental Conservation’s 
2011 Supplemental Generic Environmental Impact Statement, spilled, 
leaked, or released chemicals or wastes could flow to a surface water 
body or infiltrate the ground, reaching and contaminating subsurface 
soils and aquifers. In addition, shale oil and gas development poses a 
risk to land resources and wildlife habitat as a result of 
constructing, operating, and maintaining the infrastructure necessary 
to develop oil and gas; using toxic chemicals; and injecting fluids 
underground. However, the extent of these risks is unknown. For 
example, the studies and publications GAO reviewed on air quality 
conditions provide information for a specific site at a specific time 
but do not provide the information needed to determine the overall 
cumulative effects that shale oil and gas activities may have on air 
quality. Further, the extent and severity of environmental and public 
health risks identified in the studies and publications GAO reviewed 
may vary significantly across shale basins and also within basins 
because of location- and process-specific factors, including the 
location and rate of development; geological characteristics, such as 
permeability, thickness, and porosity of the formations; climatic 
conditions; business practices; and regulatory and enforcement 
activities. 

What GAO Recommends: 

GAO is not making any recommendations in this report. We provided a 
draft of this report to the Department of Energy, the Department of 
the Interior, and the Environmental Protection Agency for review. The 
Department of the Interior and the Environmental Protection Agency 
provided technical comments, which we incorporated as appropriate. The 
Department of Energy did not provide comments. 

View [hyperlink, http://www.gao.gov/products/GAO-12-732]. For more 
information, contact Frank Rusco at (202) 512-3841 or ruscof@gao.gov. 

[End of section] 

Contents: 

Letter: 

Background: 

Domestic Shale Oil and Gas Estimates and Production: 

Shale Oil and Gas Development Pose Environmental and Public Health 
Risks, but the Extent is Unknown and Depends on Many Factors: 

Agency Comments: 

Appendix I: Scope and Methodology: 

Appendix II: List of Agencies and Organizations Contacted: 

Appendix III: Additional Information on USGS Estimates: 

Appendix IV: GAO Contact and Staff Acknowledgments: 

Tables: 

Table 1: USGS and EIA Estimates of Total Remaining Technically 
Recoverable U.S. Oil Resources: 

Table 2: Estimated Technically Recoverable Shale Gas Resources, by 
Play: 

Table 3: Average Freshwater Use per Well for Drilling and Hydraulic 
Fracturing: 

Table 4: Shale Formation and Treatable Water Depth: 

Table 5: USGS Estimates: 

Figures: 

Figure 1: History of Horizontal Drilling and Hydraulic Fracturing: 

Figure 2: Perforating Tool: 

Figure 3: Examples of Common Ingredients Found in Fracturing Fluid: 

Figure 4: Shale Plays and Basins in the Contiguous 48 States: 

Figure 5: Common Terminology to Describe the Size and Scope of Shale 
Oil and Gas: 

Figure 6: Estimates of Technically Recoverable Shale Gas from EIA, 
USGS, and the Potential Gas Committee (2006 through 2012): 

Figure 7: Estimated Production of Shale Oil from 2007 through 2011 (in 
millions of barrels of oil): 

Figure 8: Shale Oil Production, by Shale Play (from 2007 through 2011): 

Figure 9: Estimated Production of Shale Gas from 2007 through 2011 (in 
trillions of cubic feet): 

Figure 10: Shale Gas Production, by Shale Play (from 2007 through 
2011): 

Figure 11: Silica Sand Proppant: 

Figure 12: Storage Tank for Produced Water in the Barnett Shale: 

Abbreviations: 

BLM: Bureau of Land Management: 

Btu: British thermal unit: 

DOE: Department of Energy: 

EIA: Energy Information Administration: 

EPA: Environmental Protection Agency: 

NORM: naturally occurring radioactive materials: 

Tcf: technically recoverable gas: 

USGS: U.S. Geological Survey: 

[End of section] 

United States Government Accountability Office: 
Washington, DC 20548: 

September 5, 2012: 

Congressional Requesters: 

For decades, the United States has relied on imports of oil and 
natural gas to meet domestic needs. As recently as 2007, the 
expectation was that the nation would increasingly rely on imports of 
natural gas to meet its growing demand. However, recent improvements 
in technology have allowed companies that develop petroleum resources 
to extract oil and natural gas from shale formations,[Footnote 1] 
known as "shale oil" and "shale gas," respectively, which were 
previously inaccessible because traditional techniques did not yield 
sufficient amounts for economically viable production. In particular, 
as we reported in January 2012, new applications of horizontal 
drilling techniques and hydraulic fracturing--a process that injects a 
combination of water, sand, and chemical additives under high pressure 
to create and maintain fractures in underground rock formations that 
allow oil and natural gas to flow--have prompted a boom in shale oil 
and gas production.[Footnote 2] According to the Department of Energy 
(DOE), America's shale gas resource base is abundant, and development 
of this resource could have beneficial effects for the nation, such as 
job creation.[Footnote 3] According to a report by the Baker 
Institute, domestic shale gas development could limit the need for 
expensive imports of these resources--helping to reduce the U.S. trade 
deficit.[Footnote 4] In addition, replacing older coal burning power 
generation with new natural gas-fired generators could reduce 
greenhouse gas emissions and result in fewer air pollutants for the 
same amount of electric power generated.[Footnote 5] Early drilling 
activity in shale formations was centered primarily on natural gas, 
but with the falling price of natural gas companies switched their 
focus to oil and natural gas liquids, which are a more valuable 
product.[Footnote 6] 

As exploration and development of shale oil and gas have increased in 
recent years--including in areas of the country without a history of 
oil and natural gas activities--questions have been raised about the 
estimates of the size of domestic shale oil and gas resources, as well 
as the processes used to extract them.[Footnote 7] For example, some 
organizations have questioned the accuracy of the estimates of the 
shale gas supply. In particular, some news organizations have reported 
concerns that such estimates may be inflated. In addition, concerns 
about environmental and public health effects of the increased use of 
horizontal drilling and hydraulic fracturing, particularly on air 
quality and water resources, have garnered extensive public attention. 
According to the International Energy Agency, some questions also 
exist about whether switching from coal to natural gas will lead to a 
reduction in greenhouse gas emissions--based, in part, on uncertainty 
about additional emissions from the development of shale gas. These 
concerns and other considerations have led some communities and 
certain states to impose restrictions or moratoriums on drilling 
operations to allow time to study and better understand the potential 
risks associated with these practices. 

In this context, you asked us to provide information on shale oil and 
gas. This report describes what is known about (1) the size of shale 
oil and gas resources in the United States and the amount produced 
from 2007 through 2011--the years for which data were available--and 
(2) the environmental and public health risks associated with 
development of shale oil and gas.[Footnote 8] 

To determine what is known about the size of shale oil and gas 
resources and the amount of shale oil and gas produced, we collected 
data from federal agencies, state agencies, private industry, and 
academic organizations. Specifically, to determine what is known about 
the size of these resources, we obtained information for technically 
recoverable and proved reserves estimates for shale oil and gas from 
the EIA, the U.S. Geological Survey (USGS), and the Potential Gas 
Committee--a nongovernmental organization composed of academics and 
industry representatives. We interviewed key officials from these 
agencies and the committee about the assumptions and methodologies 
used to estimate the resource size. Estimates of proved reserves of 
shale oil and gas are based on data provided to EIA by operators--
companies that develop petroleum resources to extract oil and natural 
gas.[Footnote 9] To determine what is known about the amount of shale 
oil and gas produced from 2007 through 2011, we obtained data from 
EIA--which is responsible for estimating and reporting this and other 
energy information. To assess the reliability of these data, we 
examined EIA's published methodology for collecting this information 
and interviewed key EIA officials regarding the agency's data 
collection efforts. We also met with officials from states, 
representatives from private industry, and researchers from academic 
institutions who are familiar with these data and EIA's methodology. 
We discussed the sources and reliability of the data with these 
officials and found the data sufficiently reliable for the purposes of 
this report. For all estimates we report, we reviewed the 
methodologies used to derive them and also found them sufficiently 
reliable for the purposes of this report. 

To determine what is known about the environmental and public health 
risks associated with the development of shale oil and gas,[Footnote 
10] we reviewed studies and other publications from federal agencies 
and laboratories, state agencies, local governments, the petroleum 
industry, academic institutions, environmental and public health 
groups, and other nongovernmental associations. We identified these 
studies by conducting a literature search, and by asking for 
recommendations during interviews with federal, state, and tribal 
officials; representatives from industry, trade organizations, 
environmental, and other nongovernmental groups; and researchers from 
academic institutions. For a number of studies, we interviewed the 
author or authors to discuss the study's findings and limitations, if 
any. We believe we have identified the key studies through our 
literature review and interviews, and that the studies included in our 
review have accurately identified currently known potential risks for 
shale oil and gas development. However, it is possible that we may not 
have identified all of the studies with findings relevant to our 
objectives, and the risks we present may not be the only issues of 
concern. 

The risks identified in the studies and publications we reviewed 
cannot, at present, be quantified, and the magnitude of potential 
adverse affects or likelihood of occurrence cannot be determined for 
several reasons. First, it is difficult to predict how many or where 
shale oil and gas wells may be constructed. Second, the extent to 
which operators use effective best management practices to mitigate 
risk may vary. Third, based on the studies we reviewed, there are 
relatively few studies that are based on comparing predevelopment 
conditions to postdevelopment conditions--making it difficult to 
detect or attribute adverse conditions to shale oil and gas 
development. In addition, changes to the federal, state, and local 
regulatory environments and the effectiveness of implementing and 
enforcing regulations will affect operators' future activities and, 
therefore, the level of risk associated with future development of oil 
and gas resources. Moreover, risks of adverse events, such as spills 
or accidents, may vary according to business practices which, in turn, 
may vary across oil and gas companies, making it difficult to 
distinguish between risks associated with the process to develop shale 
oil and gas from risks that are specific to particular business 
practices. To obtain additional perspectives on issues related to 
environmental and public health risks, we interviewed federal 
officials from DOE's National Energy Technical Laboratory, the 
Department of the Interior's Bureau of Land Management (BLM) and 
Bureau of Indian Affairs, and the Environmental Protection Agency 
(EPA); state regulatory officials from Arkansas, Colorado, Louisiana, 
North Dakota, Ohio, Oklahoma, Pennsylvania, and Texas;[Footnote 11] 
tribal officials from the Osage Nation; shale oil and gas operators; 
representatives from environmental and public health organizations; 
and other knowledgeable parties with experience related to shale oil 
and gas development, such as researchers from the Colorado School of 
Mines, the University of Texas, Oklahoma University, and Stanford 
University. Appendix I provides additional information on our scope 
and methodology. 

We conducted this performance audit from November 2011 to September 
2012 in accordance with generally accepted government auditing 
standards. Those standards require that we plan and perform the audit 
to obtain sufficient, appropriate evidence to provide a reasonable 
basis for our findings and conclusions based on our audit objectives. 
We believe that the evidence obtained provides a reasonable basis for 
our findings and conclusions based on our audit objectives. 

Background: 

This section includes (1) an overview of oil and natural gas, (2) the 
shale oil and gas development process, (3) the regulatory framework, 
(4) the location of shale oil and gas in the United States, and (5) 
information on estimating the size of these resources. 

Overview: 

Oil and natural gas are found in a variety of geologic formations. 
Conventional oil and natural gas are found in deep, porous rock or 
reservoirs and can flow under natural pressure to the surface after 
drilling. In contrast to the free-flowing resources found in 
conventional formations, the low permeability of some formations, 
including shale, means that oil and gas trapped in the formation 
cannot move easily within the rock. On one extreme--oil shale, for 
example--the hydrocarbon trapped in the shale will not reach a liquid 
form without first being heated to very high temperatures--ranging 
from about 650 to 1,000 degrees Fahrenheit--in a process known as 
retorting. In contrast, to extract shale oil and gas from the rock, 
fluids and proppants (usually sand or ceramic beads used to hold 
fractures open in the formation) are injected under high pressure to 
create and maintain fractures to increase permeability, thus allowing 
oil or gas to be extracted. Other formations, such as coalbed methane 
formations and tight sandstone formations,[Footnote 12] may also 
require stimulation to allow oil or gas to be extracted.[Footnote 13] 

Most of the energy used in the United States comes from fossil fuels 
such as oil and natural gas. Oil supplies more than 35 percent of all 
the energy the country consumes, and almost the entire U.S. 
transportation fleet--cars, trucks, trains, and airplanes--depends on 
fuels made from oil. Natural gas is an important energy source to heat 
buildings, power the industrial sector, and generate electricity. 
Natural gas provides more than 20 percent of the energy used in the 
United States,[Footnote 14] supplying nearly half of all the energy 
used for cooking, heating, and powering other home appliances, and 
generating almost one-quarter of U.S. electricity supplies. 

The Shale Oil and Gas Development Process: 

The process to develop shale oil and gas is similar to the process for 
conventional onshore oil and gas, but shale formations may rely on the 
use of horizontal drilling and hydraulic fracturing--which may or may 
not be used on conventional wells. Horizontal drilling and hydraulic 
fracturing are not new technologies, as seen in figure 1, but 
advancements, refinements, and new uses of these technologies have 
greatly expanded oil and gas operators' abilities to use these 
processes to economically develop shale oil and gas resources. For 
example, the use of multistage hydraulic fracturing within a 
horizontal well has only been widely used in the last decade.[Footnote 
15] 

Figure 1: History of Horizontal Drilling and Hydraulic Fracturing: 

[Refer to PDF for image: timeline] 

1930s: 
First horizontal well is drilled.  

1940s: 
Hydraulic fracturing first introduced to the petroleum industry.  

1947: 
The first experimental hydraulic fracturing treatment conducted in 
Grant County, Kansas.  

1949: 
The first commercial hydraulic fracturing treatment conducted in 
Stephens County, Oklahoma.  

1950s: 
Hydraulic fracturing becomes a commercially accepted process.  

1955: 
More than 100,000 individual hydraulic fracturing treatments 
performed.  

Late 1970s and early 1980s: 
Shale formations, such as the Barnett in Texas and Marcellus in 
Pennsylvania, are known but believed to have essentially zero 
permeability 1980s to early 1990s and thus are not considered 
economic.  

Federally sponsored research seeks to improve ways to extract gas from 
unconventional formations, such as shale.  

1979: 
Exploration begins in the Barnett Shale in Texas.  

1980s to early 1990s: 
Mitchell Energy combines larger fracture designs, rigorous reservoir 
characterization, horizontal drilling, and lower cost approaches to 
hydraulic fracturing to make the Barnett Shale economic.  

2004: 
Operators begin exploring in the Marcellus Shale in Pennsylvania.  

Source: GAO. 

[End of figure] 

First, operators locate suitable shale oil and gas targets using 
seismic methods of exploration,[Footnote 16] negotiate contracts or 
leases that allow mineral development, identify a specific location 
for drilling, and obtain necessary permits; then, they undertake a 
number of activities to develop shale oil and gas. The specific 
activities and steps taken to extract shale oil and gas vary based on 
the characteristics of the formation, but the development phase 
generally involves the following stages: (1) well pad preparation and 
construction, (2) drilling and well construction, and (3) hydraulic 
fracturing.[Footnote 17] 

Well Pad Preparation and Construction: 

The first stage in the development process is to prepare and construct 
the well pad site. Typically, operators must clear and level surface 
vegetation to make room for numerous vehicles and heavy equipment--
such as the drilling rig--and to build infrastructure--such as roads--
needed to access the site.[Footnote 18] Then operators must transport 
the equipment that mixes the additives, water, and sand needed for 
hydraulic fracturing to the site--tanks, water pumps, and blender 
pumps, as well as water and sand storage tanks, monitoring equipment, 
and additive storage containers. Based on the geological 
characteristics of the formation and climatic conditions, operators 
may (1) excavate a pit or impoundment to store freshwater, drilling 
fluids, or drill cuttings--rock cuttings generated during drilling; 
(2) use tanks to store materials; or (3) build temporary transfer 
pipes to transport materials to and from an off-site location. 

Drilling and Well Construction: 

The next stage in the development process is drilling and well 
construction. Operators drill a hole (referred to as the wellbore) 
into the earth through a combination of vertical and horizontal 
drilling techniques. At several points in the drilling process, the 
drill string and bit are removed from the wellbore so that casing and 
cement may be inserted. Casing is a metal pipe that is inserted inside 
the wellbore to prevent high-pressure fluids outside the formation 
from entering the well and to prevent drilling mud inside the well 
from fracturing fragile sections of the wellbore. As drilling 
progresses with depth, casings that are of a smaller diameter than the 
hole created by the drill bit are inserted into the wellbore and 
bonded in place with cement, sealing the wellbore from the surrounding 
formation. 

Drilling mud (a lubricant also known as drilling fluid) is pumped 
through the wellbore at different densities to balance the pressure 
inside the wellbore and bring rock particles and other matter cut from 
the formation back to the rig. A blowout preventer is installed over 
the well as a safety measure to prevent any uncontrolled release of 
oil or gas and help maintain control over pressures in the well. Drill 
cuttings, which are made up of ground rock coated with a layer of 
drilling mud or fluid, are brought to the surface. Mud pits provide a 
reservoir for mixing and holding the drilling mud. At the completion 
of drilling, the drilling mud may be recycled for use at another 
drilling operation. 

Instruments guide drilling operators to the "kickoff point"--the point 
that drilling starts to turn at a slight angle and continues turning 
until it nears the shale formation and extends horizontally. 
Production casing and cement are then inserted to extend the length of 
the borehole to maintain wellbore integrity and prevent any 
communication between the formation fluids and the wellbore. After the 
casing is set and cemented, the drilling operator may run a cement 
evaluation log by lowering an electric probe into the well to measure 
the quality and placement of the cement. The purpose of the cement 
evaluation log is to confirm that the cement has the proper strength 
to function as designed--preventing well fluids from migrating outside 
the casing and infiltrating overlying formations. After vertical 
drilling is complete, horizontal drilling is conducted by slowly 
angling the drill bit until it is drilling horizontally. Horizontal 
stretches of the well typically range from 2,000 to 6,000 feet long 
but can be as long as 12,000 feet long, in some cases. 

Throughout the drilling process, operators may vent or flare some 
natural gas, often intermittently, in response to maintenance needs or 
equipment failures. This natural gas is either released directly into 
the atmosphere (vented) or burned (flared). In October 2010, we 
reported on venting and flaring of natural gas on public lands. 
[Footnote 19] We reported that vented and flared gas on public lands 
represents potential lost royalties for the federal government and 
contributes to greenhouse gas emissions. Specifically, venting 
releases methane and volatile organic compounds, and flaring emits 
carbon dioxide, both greenhouse gases that contribute to global 
climate change. Methane is a particular concern since it is a more 
potent greenhouse gas than carbon dioxide. 

Hydraulic Fracturing: 

The next stage in the development process is stimulation of the shale 
formation using hydraulic fracturing. Before operators or service 
companies perform a hydraulic fracture treatment of a well, a series 
of tests may be conducted to ensure that the well, wellhead equipment, 
and fracturing equipment can safely withstand the high pressures 
associated with the fracturing process. Minimum requirements for 
equipment pressure testing can be determined by state regulatory 
agencies for operations on state or private lands. In addition, 
fracturing is conducted below the surface of the earth, sometimes 
several thousand feet below, and can only be indirectly observed. 
Therefore, operators may collect subsurface data--such as information 
on rock stresses[Footnote 20] and natural fault structures--needed to 
develop models that predict fracture height, length, and orientation 
prior to drilling a well. The purpose of modeling is to design a 
fracturing treatment that optimizes the location and size of induced 
fractures and maximizes oil or gas production. 

To prepare a well to be hydraulically fractured, a perforating tool 
may be inserted into the casing and used to create holes in the casing 
and cement. Through these holes, fracturing fluid--that is injected 
under high pressures--can flow into the shale (figure 2 shows a used 
perforating tool). 

Figure 2: Perforating Tool: 

[Refer to PDF for image: photograph] 

Source: GAO. 

[End of figure] 

Fracturing fluids are tailored to site specific conditions, such as 
shale thickness, stress, compressibility, and rigidity. As such, the 
chemical additives used in a fracture treatment vary. Operators may 
use computer models that consider local conditions to design site-
specific hydraulic fluids. The water, chemicals, and proppant used in 
fracturing fluid are typically stored on-site in separate tanks and 
blended just before they are injected into the well. Figure 3 provides 
greater detail about some chemicals commonly used in fracturing. 

Figure 3: Examples of Common Ingredients Found in Fracturing Fluid: 

[Refer to PDF for image: pie-chart with information] 

Vast majority of ingredients: Water and sand; 
Other ingredients: 

Additive type: Acid; 
Use: Removes near well damage; 
Main compound: Hydrochloric acid. 

Additive type: Biocide; 
Use: Controls bacterial growth; 
Main compound: Glutaraldehyde. 

Additive type: Breaker; 
Use: Delays breakdown of the geling agent; 
Main compound: Ammonium persulfate. 

Additive type: Corrosion inhibitor; 
Use: Prevent corrosion of pipe; 
Main compound: N,n-dimethyl formamide. 

Additive type: Crosslinker; 
Use: Maintains fluid viscosity as temperature increases; 
Main compound: Borate salts 

Additive type: Friction reducers; 
Use: Decreases pumping friction; 
Main compound: Polyacrylamide. 

Additive type: Gelling agents; 
Use: Improves proppant placement; 
Main compound: Guar gum. 

Additive type: KCI; 
Use: Creates a brine carrier fluid; 
Main compound: Potassium chloride. 

Additive type: Oxygen scavenger; 
Use: Prevents corrosion of well tubulars; 
Main compound: Ammonium bisulfite. 

Additive type: pH adjusting agent; 
Use: Adjusts the pH of fluid to maintain the effectiveness of other 
components; 
Main compound: Sodium carbonate. 

Additive type: Scale inhibitor; 
Use: Prevents scale deposits in the pipe; 
Main compound: Ethylene glycol. 

Additive type: Surfactant; 
Use: Winterizing agent; 
Main compound: Isopropanol. 

Source: Department of Energy and Groundwater Protection Council. 

[End of figure] 

The operator pumps the fracturing fluid into the wellbore at pressures 
high enough to force the fluid through the perforations into the 
surrounding formation--which can be shale, coalbeds, or tight 
sandstone--expanding existing fractures and creating new ones in the 
process. After the fractures are created, the operator reduces the 
pressure. The proppant stays in the formation to hold open the 
fractures and allow the release of oil and gas. Some of the fracturing 
fluid that was injected into the well will return to the surface 
(commonly referred to as flowback) along with water that occurs 
naturally in the oil-or gas-bearing formation--collectively referred 
to as produced water. The produced water is brought to the surface and 
collected by the operator, where it can be stored on-site in 
impoundments, injected into underground wells, transported to a 
wastewater treatment plant, or reused by the operator in other ways. 
[Footnote 21] Given the length of horizontal wells, hydraulic 
fracturing is often conducted in stages, where each stage focuses on a 
limited linear section and may be repeated numerous times. 

Once a well is producing oil or natural gas, equipment and temporary 
infrastructure associated with drilling and hydraulic fracturing 
operations is no longer needed and may be removed, leaving only the 
parts of the infrastructure required to collect and process the oil or 
gas and ongoing produced water. Operators may begin to reclaim the 
part of the site that will not be used by restoring the area to 
predevelopment conditions. Throughout the producing life of an oil or 
gas well, the operator may find it necessary to periodically 
restimulate the flow of oil or gas by repeating the hydraulic 
fracturing process. The frequency of such activity depends on the 
characteristics of the geologic formation and the economics of the 
individual well. If the hydraulic fracturing process is repeated, the 
site and surrounding area will be further affected by the required 
infrastructure, truck transport, and other activity associated with 
this process. 

Regulatory Framework: 

Shale oil and gas development, like conventional onshore oil and gas 
production, is governed by a framework of federal, state, and local 
laws and regulations. Most shale development in the near future is 
expected to occur on nonfederal lands and, therefore, states will 
typically take the lead in regulatory activities. However, in some 
cases, federal agencies oversee shale oil and gas development. For 
example, BLM oversees shale oil and gas development on federal lands. 
In large part, the federal laws, regulations, and permit requirements 
that apply to conventional onshore oil and gas exploration and 
production activities also apply to shale oil and gas development. 

* Federal. A number of federal agencies administer laws and 
regulations that apply to various phases of shale oil and gas 
development. For example, BLM manages federal lands and approximately 
700 million acres of federal subsurface minerals, also known as the 
federal mineral estate. EPA administers and enforces key federal laws, 
such as the Safe Drinking Water Act, to protect human health and the 
environment. Other federal land management agencies, such as the U.S. 
Department of Agriculture's Forest Service and the Department of the 
Interior's Fish and Wildlife Service, also manage federal lands, 
including shale oil and gas development on those lands. 

* State. State agencies implement and enforce many of the federal 
environmental regulations and may also have their own set of state 
laws covering shale oil and gas development. 

* Other. Additional requirements regarding shale oil and gas 
operations may be imposed by various levels of government for specific 
locations. Entities such as cities, counties, tribes, and regional 
water authorities may set additional requirements that affect the 
location and operation of wells. 

GAO is conducting a separate and more detailed review of the federal 
and state laws and regulations that apply to unconventional oil and 
gas development, including shale oil and gas. 

Location of Shale Oil and Gas in the United States: 

Shale oil and gas are found in shale plays--a set of discovered or 
undiscovered oil and natural gas accumulations or prospects that 
exhibit similar geological characteristics--on private, state-owned, 
and federal lands across the United States. Shale plays are located 
within basins, which are large-scale geological depressions, often 
hundreds of miles across, that also may contain other oil and gas 
resources. Figure 4 shows the location of shale plays and basins in 
the contiguous 48 states. 

Figure 4: Shale Plays and Basins in the Contiguous 48 States: 

[Refer to PDF for image: illustrated U.S. map] 

Map depicts the locations of the following: 
Shale plays; 
Basins. 

Source: Energy Information Administration (shale location data); map 
copyright Corel Corp., all rights reserved. 

[End of figure] 

A shale play can be developed for oil, natural gas, or both. In 
addition, a shale gas play may contain "dry" or "wet" natural gas. Dry 
natural gas is a mixture of hydrocarbon compounds that exists as a gas 
both underground in the reservoir and during production under standard 
temperature and pressure conditions. Wet natural gas contains natural 
gas liquids, or the portion of the hydrocarbon resource that exists as 
a gas when in natural underground reservoir conditions but that is 
liquid at surface conditions. The natural gas liquids are typically 
propane, butane, and ethane and are separated from the produced gas at 
the surface in lease separators, field facilities, or gas processing 
plants. Operators may then sell the natural gas liquids, which may 
give wet shale gas plays an economic advantage over dry gas plays. 
Another advantage of liquid petroleum and natural gas liquids is that 
they can be transported more easily than natural gas. This is because, 
to bring natural gas to markets and consumers, companies must build an 
extensive network of gas pipelines. In areas where gas pipelines are 
not extensive, natural gas produced along with liquids is often vented 
or flared. 

Estimating the Size of Shale Oil and Gas Resources: 

Estimating the size of shale oil and gas resources serves a variety of 
needs for consumers, policymakers, land and resource managers, 
investors, regulators, industry planners, and others. For example, 
federal and state governments may use resource estimates to estimate 
future revenues and establish energy, fiscal, and national security 
policies. The petroleum industry and the financial community use 
resource estimates to establish corporate strategies and make 
investment decisions. 

A clear understanding of some common terms used to generally describe 
the size and scope of oil and gas resources is needed to determine the 
relevance of a given estimate. For an illustration of how such terms 
describe the size and scope of shale oil and gas, see figure 5. 

The most inclusive term is in-place resource. The in-place resource 
represents all oil or natural gas contained in a formation without 
regard to technical or economic recoverability. In-place resource 
estimates are sometimes very large numbers, but often only a small 
proportion of the total amount of oil or natural gas in a formation 
may ever be recovered. Oil and gas resources that are in-place, but 
not technically recoverable at this time may, in the future, become 
technically recoverable. 

Technically recoverable resources are a subset of in-place resources 
that include oil or gas, including shale oil and gas that is 
producible given available technology. Technically recoverable 
resources include those that are economically producible and those 
that are not. Estimates of technically recoverable resources are 
dynamic, changing to reflect the potential of extraction technology 
and knowledge about the geology and composition of geologic 
formations. According to the National Petroleum Council,[Footnote 22] 
technically recoverable resource estimates usually increase over time 
because of the availability of more and better data, or knowledge of 
how to develop a new play type (such as shale formations). 

Proved reserve estimates are more precise than technically recoverable 
resources and represent the amount of oil and gas that have been 
discovered and defined, typically by drilling wells or other 
exploratory measures, and which can be economically recovered within a 
relatively short time frame. Proved reserves may be thought of as the 
"inventory" that operators hold and define the quantity of oil and gas 
that operators estimate can be recovered under current economic 
conditions, operating methods, and government regulations. Estimates 
of proved reserves increase as oil and gas companies make new 
discoveries and report them to the government; oil and gas companies 
can increase their reserves as they develop already-discovered fields 
and improve production technology. Reserves decline as oil and gas 
reserves are produced and sold. In addition, reserves can change as 
prices and technologies change. For example, technology improvements 
that enable operators to extract more oil or gas from existing fields 
can increase proved reserves. Likewise, higher prices for oil and gas 
may increase the amount of proved reserves because more resources 
become financially viable to extract.[Footnote 23] Conversely, lower 
prices may diminish the amount of resources likely to be produced, 
reducing proved reserves. 

Historical production refers to the total amount of oil and gas that 
has been produced up to the present. Because these volumes of oil and 
gas have been measured historically, this is the most precise 
information available as it represents actual production amounts. 

Figure 5: Common Terminology to Describe the Size and Scope of Shale 
Oil and Gas: 

[Refer to PDF for image: inverted pyramid, with segments described] 
  

Unrecoverable oil and gas in-place (Technically nonrecoverable 
resources). 

Technically recoverable: 
Less economical recovery to: 
More economical recovery.  

Proved reserves: 

Historical production. 

Sources: GAO; based on illustration by the Congressional Research 
Service. 

Note: This illustration is not necessarily to scale because all 
volumes, except historical production, are subject to significant 
uncertainty. 

[End of figure] 

Certain federal agencies have statutory responsibility for collecting 
and publishing authoritative statistical information on various types 
of energy sources in the United States. EIA collects, analyzes, and 
disseminates independent and impartial energy information, including 
data on shale oil and gas resources. Under the Energy Policy and 
Conservation Act of 2000, as amended, USGS estimates onshore 
undiscovered technically recoverable oil and gas resources in the 
United States.[Footnote 24] USGS has conducted a number of national 
estimates of undiscovered technically recoverable oil and natural gas 
resources over several decades. USGS geologists and other experts 
estimate undiscovered oil and gas--that is, oil and gas that has not 
been proven to be present by oil and gas companies--based on 
geological survey data and other information about the location and 
size of different geological formations across the United States. In 
addition to EIA and USGS, experts from industry, academia, federal 
advisory committees, private consulting firms, and professional 
societies also estimate the size of the resource. 

Domestic Shale Oil and Gas Estimates and Production: 

Estimates of the size of shale oil and gas resources in the United 
States have increased over time as has the amount of such resources 
produced from 2007 through 2011. Specifically, over the last 5 years, 
estimates of (1) technically recoverable shale oil and gas and (2) 
proved reserves of shale oil and gas have increased, as technology has 
advanced and more shale has been drilled. In addition, domestic shale 
oil and gas production has experienced substantial growth in recent 
years. 

Estimates of Technically Recoverable Shale Oil and Gas Resources: 

EIA, USGS, and the Potential Gas Committee have increased their 
estimates of the amount of technically recoverable shale oil and gas 
over the last 5 years, which could mean an increase in the nation's 
energy portfolio; however, less is known about the amount of 
technically recoverable shale oil than shale gas, in part because 
large-scale production of shale oil has been under way for only the 
past few years. The estimates are from different organizations and 
vary somewhat because they were developed at different times and using 
different data, methods, and assumptions, but estimates from all of 
these organizations have increased over time, indicating that the 
nation's shale oil and gas resources may be substantial. For example, 
according to estimates and reports we reviewed, assuming current 
consumption levels without consideration of a specific market price 
for future gas supplies, the amount of domestic technically 
recoverable shale gas could provide enough natural gas to supply the 
nation for the next 14 to 100 years. The increases in estimates can 
largely be attributed to improved geological information about the 
resources, greater understanding of production levels, and 
technological advancements. 

Estimates of Technically Recoverable Shale Oil Resources: 

In the last 2 years, EIA and USGS provided estimates of technically 
recoverable shale oil.[Footnote 25] Each of these estimates increased 
in recent years as follows: 

* In 2012, EIA estimated that the United States possesses 33 billion 
barrels of technically recoverable shale oil,[Footnote 26] mostly 
located in four shale formations--the Bakken in Montana and North 
Dakota; Eagle Ford in Texas; Niobrara in Colorado, Kansas, Nebraska, 
and Wyoming; and the Monterey in California. 

* In 2011, USGS estimated that the United States possesses just over 7 
billion barrels of technically recoverable oil in shale and tight 
sandstone formations. The estimate represents a more than threefold 
increase from the agency's estimate in 2006. However, there are 
several shale plays that USGS has not evaluated for shale oil because 
interest in these plays is relatively new. According to USGS 
officials, these shale plays have shown potential for production in 
recent years and may contain additional shale oil resources. Table 1 
shows USGS' 2006 and 2011 estimates and EIA's 2011 and 2012 estimates. 

Table 1: USGS and EIA Estimates of Total Remaining Technically 
Recoverable U.S. Oil Resources: 

Barrels of oil: 

Estimated technically recoverable shale oil and tight sandstone 
resources: 
USGS: 2006: 2 billion; 
USGS: 2011: 7 billion; 
EIA: 2011: 32 billion; 
EIA: 2012: 33 billion. 

Estimated technically recoverable oil resources other than shale[A]: 
USGS: 2006: 142 billion; 
USGS: 2011: 133 billion; 
EIA: 2011: 187 billion; 
EIA: 2012: 201 billion. 

Source: GAO analysis of EIA and USGS data. 

[A] Includes estimates for conventional offshore oil and gas, as well 
as natural gas liquids. In addition, the USGS estimates for 2006 and 
2011 include a 2006 estimate of technically recoverable offshore 
conventional oil resources totaling 86 billion barrels of oil and 
natural gas liquids from the former Minerals Management Service, which 
has since been reorganized into the Bureau of Ocean Energy Management 
and the Bureau of Safety and Environmental Enforcement. 

[End of table] 

Overall, estimates of the size of technically recoverable shale oil 
resources in the United States are imperfect and highly dependent on 
the data, methodologies, model structures, and assumptions used. As 
these estimates are based on data available at a given point in time, 
they may change as additional information becomes available. Also 
these estimates depend on historical production data as a key 
component for modeling future supply. Because large-scale production 
of oil in shale formations is a relatively recent activity, their long-
term productivity is largely unknown. For example, EIA estimated that 
the Monterey Shale in California may possess about 15.4 billion 
barrels of technically recoverable oil. However, without a longer 
history of production, the estimate has greater uncertainty than 
estimates based on more historical production data. At this time, USGS 
has not yet evaluated the Monterey Shale play. 

Estimates of Technically Recoverable Shale Gas Resources: 

The amount of technically recoverable shale gas resources in the 
United States has been estimated by a number of organizations, 
including EIA, USGS, and the Potential Gas Committee (see figure 6). 
Their estimates were as follows: 

* In 2012, EIA estimated the amount of technically recoverable shale 
gas in the United States at 482 trillion cubic feet.[Footnote 27] This 
represents an increase of 280 percent from EIA's 2008 estimate. 

* In 2011, USGS reported that the total of its estimates for the shale 
formations the agency evaluated in all previous years[Footnote 28] 
shows the amount of technically recoverable shale gas in the United 
States at about 336 trillion cubic feet. This represents an increase 
of about 600 percent from the agency's 2006 estimate. 

* In 2011, the Potential Gas Committee estimated the amount of 
technically recoverable shale gas in the United States at about 687 
trillion cubic feet.[Footnote 29] This represents an increase of 240 
percent from the committee's 2007 estimate. 

Figure 6: Estimates of Technically Recoverable Shale Gas from EIA, 
USGS, and the Potential Gas Committee (2006 through 2012): 

[Refer to PDF for image: 3 vertical bar graphs] 

EIA Estimates: 
Year: 2006: 83 trillion cubic feet; 
Year: 2007: 126 trillion cubic feet; 
Year: 2008: 125 trillion cubic feet; 
Year: 2009: 267 trillion cubic feet; 
Year: 2010: 347 trillion cubic feet; 
Year: 2011: 827 trillion cubic feet; 
Year: 2012: 482 trillion cubic feet. 

USGS Estimates[A]: 
Year: 2006: 47.9 trillion cubic feet; 
Year: 2011: 336.1 trillion cubic feet. 

Potential Gas Committee Estimates: 
Year: 2007: 200 trillion cubic feet; 
Year: 2009: 615.9 trillion cubic feet; 
Year: 2011: 686.6 trillion cubic feet. 

Source: GAO analysis of EIA, Potential Gas Committee, and USGS 
estimates. 

Notes: Natural gas is generally priced and sold in thousand cubic feet 
(abbreviated Mcf, using the Roman numeral for 1,000). Units of a 
trillion cubic feet (Tcf) are often used to measure large quantities, 
as in resources or reserves in the ground, or annual national energy 
consumption. One Tcf is enough natural gas to heat 15 million homes 
for 1 year or fuel 12 million natural gas-fired vehicles for 1 year. 
In 2012, EIA reduced its estimate of technically recoverable shale gas 
in the Marcellus Shale by about 67 percent. According to EIA 
officials, the decision to revise the estimate was based primarily on 
the availability of new production data, which was highlighted by the 
release of the USGS estimate. In 2011, EIA used data from a contractor 
to estimate that the Marcellus Shale possessed about 410 trillion 
cubic feet of technically recoverable gas. After EIA released its 
estimates in 2011, USGS released its first estimate of technically 
recoverable gas in the Marcellus in almost 10 years. USGS estimated 
that there were 84 trillion cubic feet of natural gas in the 
Marcellus--which was 40 times more than its previous estimate reported 
in 2002 but significantly less than EIA's estimate. In 2012, EIA 
announced that it was revising its estimate of the technically 
recoverable gas in the Marcellus Shale from 410 to 141 trillion cubic 
feet. EIA reported additional details about its methodology and data 
in June 2012. See U.S. Department of Energy, Energy Information 
Administration, Annual Energy Outlook 2012, With Projections to 2035 
(DOE/EIA-0383 [2012], Washington, D.C., June 25, 2012). 

[A] The 2006 USGS estimate of about 54 trillion cubic feet represents 
those assessments that had been done up to the end of 2006. As such, 
the estimate is partially dependent on how the agency scheduled basin 
studies and assessments from 2000 through 2006, rather than purely on 
changes in USGS views of resource potential since 2006. 

[B] The Potential Gas Committee did not report separate estimates of 
shale gas until 2007 and has updated this estimate every 2 years since 
then. 

[End of figure] 

In addition to the estimates from the three organizations we reviewed, 
operators and energy forecasting consultants prepare their own 
estimates of technically recoverable shale gas to plan operations or 
for future investment. In September 2011, the National Petroleum 
Council aggregated data on shale gas resources from over 130 industry, 
government, and academic groups and estimated that approximately 1,000 
trillion cubic feet of shale gas is available for production 
domestically. In addition, private firms that supply information to 
the oil and gas industry conduct assessments of the total amount of 
technically recoverable natural gas. For example, ICF International, a 
consulting firm that provides information to public-and private-sector 
clients, estimated in March 2012 that the United States possesses 
about 1,960 trillion cubic feet of technically recoverable shale gas. 

Based on estimates from EIA, USGS, and the Potential Gas Committee, 
five shale plays--the Barnett, Haynesville, Fayetteville, Marcellus, 
and Woodford--are estimated to possess about two-thirds of the total 
estimated technically recoverable gas in the United States (see table 
2). 

Table 2: Estimated Technically Recoverable Shale Gas Resources, by 
Play: 

Shale play: Barnett; 
Location: North Texas; 
Technically recoverable gas, in trillion cubic feet (Tcf): 43-53. 

Shale play: Fayetteville; 
Location: Arkansas; 
Technically recoverable gas, in trillion cubic feet (Tcf): 13-110. 

Shale play: Haynesville; 
Location: Louisiana and East Texas; 
Technically recoverable gas, in trillion cubic feet (Tcf): 66-110. 

Shale play: Marcellus; 
Location: Northeast United States; 
Technically recoverable gas, in trillion cubic feet (Tcf): 84-227[A]. 

Shale play: Woodford; 
Location: Oklahoma; 
Technically recoverable gas, in trillion cubic feet (Tcf): 11-27. 

Sources: GAO analysis of EIA, USGS, and Potential Gas Committee data. 

Note: The estimated technically recoverable gas shown here represents 
the range of estimates for these plays determined by EIA, USGS, and 
the Potential Gas Committee. 

[A] This estimate of the Marcellus also includes estimated shale gas 
from other nearby lands in the Appalachian area; but, according to an 
official for the estimating organization, the Marcellus Shale is the 
predominant source of gas in the basin. 

[End of table] 

As with estimates for technically recoverable shale oil, estimates of 
the size of technically recoverable shale gas resources in the United 
States are also highly dependent on the data, methodologies, model 
structures, and assumptions used and may change as additional 
information becomes available. These estimates also depend on 
historical production data as a key component for modeling future 
supply. Because most shale gas wells generally were not in place until 
the last few years, their long-term productivity is untested. 
According to a February 2012 report released by the Sustainable 
Investments Institute and the Investor Responsibility Research Center 
Institute, production in emerging shale plays has been concentrated in 
areas with the highest known gas production rates, and many shale 
plays are so large that most of the play has not been extensively 
tested.[Footnote 30] As a result, production rates achieved to date 
may not be representative of future production rates across the 
formation. EIA reports that experience to date shows production rates 
from neighboring shale gas wells can vary by as much as a factor of 3 
and that production rates for different wells in the same formation 
can vary by as much as a factor of 10. Most gas companies estimate 
that production in a given well will drop sharply after the first few 
years and then level off, continuing to produce gas for decades, 
according to the Sustainable Investments Institute and the Investor 
Responsibility Research Center Institute. 

Estimates of Proved Reserves of Shale Oil and Gas: 

Estimates of proved reserves of shale oil and gas increased from 2007 
to 2009. Operators determine the size of proved reserves based on 
information collected from drilling, geological and geophysical tests, 
and historical production trends. These are also the resources 
operators believe they will develop in the short term--generally 
within the next 5 years--and assume technological and economic 
conditions will remain unchanged. 

Estimates of proved reserves of shale oil. EIA does not report proved 
reserves of shale oil separately from other oil reserves; however, EIA 
and others have noted an increase in the proved reserves of oil in the 
nation, and federal officials attribute the increase, in part, to oil 
from shale and tight sandstone formations. For example, EIA reported 
in 2009 that the Bakken Shale in North Dakota and Montana drove 
increases in oil reserves, noting that North Dakota proved reserves 
increased over 80 percent from 2008 through 2009. 

Estimates of proved reserves of shale gas. According to data EIA 
collects from about 1,200 operators, proved reserves of shale gas have 
grown from 23 trillion cubic feet in 2007 to 61 trillion cubic feet in 
2009, or an increase of 160 percent.[Footnote 31] More than 75 percent 
of the proved shale gas reserves are located in three shale plays--the 
Barnett, Fayetteville, and the Haynesville. 

Shale Oil and Gas Production: 

From 2007 through 2011, annual production of shale oil and gas has 
experienced significant growth. Specifically, shale oil production 
increased more than fivefold, from 39 to about 217 million barrels 
over this 5-year period, and shale gas production increased 
approximately fourfold, from 1.6 to about 7.2 trillion cubic feet, 
over the same period. To put this shale production into context, the 
annual domestic consumption of oil in 2011 was about 6,875 million 
barrels of oil, and the annual consumption of natural gas was about 24 
trillion cubic feet. The increased shale oil and gas production was 
driven primarily by technological advances in horizontal drilling and 
hydraulic fracturing that made more shale oil and gas development 
economically viable. 

Shale Oil Production: 

Annual shale oil production in the United States increased more than 
fivefold, from about 39 million barrels in 2007 to about 217 million 
barrels in 2011, according to data from EIA (see figure 7).[Footnote 
32] This is because new technologies allowed more oil to be produced 
economically, and because of recent increases in the price for liquid 
petroleum that have led to increased investment in shale oil 
development. 

Figure 7: Estimated Production of Shale Oil from 2007 through 2011 (in 
millions of barrels of oil): 

[Refer to PDF for image: line graph] 

Year: 2007: 38.5 million barrels; 
Year: 2008: 60.6 million barrels; 
Year: 2009: 84.4 million barrels; 
Year: 2010: 132.0 million barrels; 
Year: 2011: 217.2 million barrels. 

Source: GAO analysis of EIA data. 

[End of figure] 

In total, during this period, about 533 million barrels of shale oil 
was produced. More than 65 percent of the oil was produced in the 
Bakken Shale (368 million barrels; see figure 8).[Footnote 33] The 
remainder was produced in the Niobrara (62 million barrels), Eagle 
Ford (68 million barrels), Monterey (18 million barrels), and the 
Woodford (9 million barrels). To put this in context, shale oil 
production from these plays in 2011 constituted about 8 percent of 
U.S. domestic oil consumption, according to EIA data.[Footnote 34] 

Figure 8: Shale Oil Production, by Shale Play (from 2007 through 2011): 

[Refer to PDF for image: illustrated U.S. map and associated data] 

Shale plays depicted: 
Bakken; 
Eagle Ford; 
Monterey; 
Niobara; 
Woodford. 

Percentage of total production by shale play: 
Bakken: 67%; 
Eagle Ford: 13%; 
Niobara: 12%; 
Monterey: 3%; 
Woodford: 2%; 
Rest of U.S.: 1%. 

Source: GAO analysis of EIA data; (map) copyright Corel Corp., all 
rights reserved. 

[End of figure] 

Shale Gas Production: 

Shale gas production in the United States increased more than 
fourfold, from about 1.6 trillion cubic feet in 2007 to about 7.2 
trillion cubic feet in 2011, according to estimated data from EIA (see 
figure 9).[Footnote 35] 

Figure 9: Estimated Production of Shale Gas from 2007 through 2011 (in 
trillions of cubic feet): 

[Refer to PDF for image: line graph] 

Year: 2007: 1.6 trillion cubic feet; 
Year: 2008: 2.4 trillion cubic feet; 
Year: 2009: 3.5 trillion cubic feet; 
Year: 2010: 5.2 trillion cubic feet; 
Year: 2011: 7.2 trillion cubic feet. 

Source: GAO analysis of EIA data. 

[End of figure] 

In total, during this period, about 20 trillion cubic feet of shale 
gas was produced--representing about 300 days of U.S. consumption, 
based on 2011 consumption rates. More than 75 percent of the gas was 
produced in four shale plays--the Barnett, Marcellus, Fayetteville, 
and Haynesville (see figure10). From 2007 through 2011, shale gas' 
contribution to the nation's total natural gas supply grew from about 
6 percent in 2007 to approximately 25 percent in 2011 and is 
projected, under certain assumptions, to increase to 49 percent by 
2035, according to an EIA report. Overall production of shale gas 
increased from calendar years 2007 through 2011, but production of 
natural gas on federal and tribal lands--including shale gas and 
natural gas from all other sources--decreased by about 17 percent, 
according to an EIA report. EIA attributes this decrease to several 
factors, including the location of shale formations--which, according 
to an EIA official, appear to be predominately on nonfederal lands. 

Figure 10: Shale Gas Production, by Shale Play (from 2007 through 
2011): 

[Refer to PDF for image: illustrated U.S. map and associated data] 

Shale plays depicted: 
Antrim; 
Bakken; 
Barnett; 
Eagle Ford; 
Fayetteville; 
Haynesville; 
Marcellus; 
Woodford. 

Percentage of total production by shale play: 
Barnett: 35%; 
Haynesville: 21%; 
Fayetteville: 13%; 
Marcellus: 11%; 
Woodford: 6%; 
Antrim: 3%; 
Eagle Ford: 2%; 
Bakken: 1%; 
Rest of U.S.: 8%. 

Source: GAO analysis of EIA data; (map) copyright Corel Corp., all 
rights reserved. 

[End of figure] 

The growth in production of shale gas has increased the overall supply 
of natural gas in the U.S. energy market. Since 2007, increased shale 
gas production has contributed to lower prices for consumers, 
according to EIA and others.[Footnote 36] These lower prices create 
incentives for wider use of natural gas in other industries. For 
example, several reports by government, industry, and others have 
observed that if natural gas prices remain low, natural gas is more 
likely to be used to power cars and trucks in the future. In addition, 
electric utilities may build additional natural gas-fired generating 
plants as older coal plants are retired. At the same time, some groups 
have expressed concern that greater reliance on natural gas may reduce 
interest in developing renewable energy. 

The greater availability of domestic shale gas has also decreased the 
need for natural gas imports. For example, EIA has noted that volumes 
of natural gas imported into the United States have fallen in recent 
years--in 2007, the nation imported 16 percent of the natural gas 
consumed and in 2010, the nation imported 11 percent--as domestic 
shale gas production has increased. This trend is also illustrated by 
an increase in applications for exporting liquefied natural gas to 
other countries. In its 2012 annual energy outlook, EIA predicted 
that, under certain scenarios, the United States will become a net 
exporter of natural gas by about 2022.[Footnote 37] 

[Side bar: Development of Wet Gas: 
EIA reported that operators have recently moved away from the 
development of shale plays that are primarily dry gas in favor of 
developing plays with higher concentrations of natural gas liquids. At 
current natural gas prices, natural gas liquids are a much more 
valuable product than dry gas. This is because the end products and 
byproducts of natural gas liquids contain more energy per unit of 
volume and have uses beyond heating and power generation and may be 
converted into products that can be more easily transported and traded 
in the global market. Shale plays with significant natural gas liquids 
include the Eagle Ford and Marcellus. End of side bar] 

Shale Oil and Gas Development Pose Environmental and Public Health 
Risks, but the Extent is Unknown and Depends on Many Factors: 

Developing oil and gas resources--whether conventional or from shale 
formations--poses inherent environmental and public health risks, but 
the extent of risks associated with shale oil and gas development is 
unknown, in part, because the studies we reviewed do not generally 
take into account potential long-term, cumulative effects. In 
addition, the severity of adverse effects depend on various location-
and process-specific factors, including the location of future shale 
oil and gas development and the rate at which it occurs, geology, 
climate, business practices, and regulatory and enforcement activities. 

Shale Oil and Gas Development Pose Risks to Air, Water, Land and 
Wildlife: 

Oil and gas development, which includes development from shale 
formations, poses inherent risks to air quality, water quantity, water 
quality, and land and wildlife. 

Air Quality: 

According to a number of studies and publications we reviewed, shale 
oil and gas development pose risks to air quality. These risks are 
generally the result of engine exhaust from increased truck traffic, 
emissions from diesel-powered pumps used to power equipment, 
intentional flaring or venting of gas for operational reasons, and 
unintentional emissions of pollutants from faulty equipment or 
impoundments. 

Construction of the well pad, access road, and other drilling 
facilities requires substantial truck traffic, which degrades air 
quality. According to a 2008 National Park Service report, an average 
well, with multistage fracturing, can require 320 to 1,365 truck loads 
to transport the water, chemicals, sand, and other equipment--
including heavy machinery like bulldozers and graders--needed for 
drilling and fracturing. The increased traffic creates a risk to air 
quality as engine exhaust that contains air pollutants such as 
nitrogen oxides and particulate matter that affect public health and 
the environment are released into the atmosphere.[Footnote 38] Air 
quality may also be degraded as fleets of trucks traveling on newly 
graded or unpaved roads increase the amount of dust released into the 
air--which can contribute to the formation of regional haze.[Footnote 
39] In addition to the dust, silica sand (see figure 11)--commonly 
used as proppant in the hydraulic fracturing process--may pose a risk 
to human health, if not properly handled. According to a federal 
researcher from the Department of Health and Human Services, 
uncontained sand particles and dust pose threats to workers at 
hydraulic fracturing well sites. The official stated that particles 
from the sand, if not properly contained by dust control mechanisms, 
can lodge in the lungs and potentially cause silicosis.[Footnote 40] 
The researcher expects to publish the results of research on public 
health risks from proppant later in 2012. 

Figure 11: Silica Sand Proppant: 

[Refer to PDF for image: photograph] 

Source: GAO. 

[End of figure] 

Use of diesel engines to supply power to drilling sites also degrades 
air quality. Shale oil and gas drilling rigs require substantial power 
to drill and case wellbores to the depths of shale formations. This 
power is typically provided by transportable diesel engines, which 
generate exhaust from the burning of diesel fuel. After the wellbore 
is drilled to the target formation, additional power is needed to 
operate the pumps that move large quantities of water, sand, or 
chemicals into the target formation at high pressure to hydraulically 
fracture the shale--generating additional exhaust. In addition, other 
equipment used during operations--including pneumatic valves and 
dehydrators--contribute to air emissions. For example, natural gas 
powers switches that turn valves on and off in the production system. 
Each time a valve turns on or off, it "bleeds" a small amount of gas 
into the air. Some of these pneumatic valves vent gas continuously. A 
dehydrator circulates the chemical glycol to absorb moisture in the 
gas but also absorbs small volumes of gas. The absorbed gas vents to 
the atmosphere when the water vapor is released from the glycol. 
[Footnote 41] 

Releases of natural gas during the development process also degrade 
air quality. As part of the process to develop shale oil and gas 
resources, operators flare or vent natural gas for a number of 
operational reasons, including lowering the pressure to ensure safety 
or when operators purge water or hydrocarbon liquids that collect in 
wellbores to maintain proper well function. Flaring emits carbon 
dioxide, and venting releases methane and volatile organic compounds. 
Venting and flaring are often a necessary part of the development 
process but contribute to greenhouse gas emissions.[Footnote 42] 
According to EPA analysis, natural gas well completions involving 
hydraulic fracturing vent approximately 230 times more natural gas and 
volatile organic compounds than natural gas well completions that do 
not involve hydraulic fracturing.[Footnote 43] As we reported in July 
2004, in addition to the operational reasons for flaring and venting, 
in areas where the primary purpose of drilling is to produce oil, 
operators flare or vent associated natural gas because no local market 
exists for the gas and transporting to a market may not be 
economically feasible.[Footnote 44] For example, according to EIA, in 
2011, approximately 30 percent of North Dakota's natural gas 
production from the Bakken Shale was flared by operators due to 
insufficient natural gas gathering pipelines, processing plants, and 
transporting pipelines. The percentage of flared gas in North Dakota 
is considerably higher than the national average; EIA reported that, 
in 2009, less than 1 percent of natural gas produced in the United 
States was vented or flared. 

Storing fracturing fluid and produced water in impoundments may also 
pose a risk to air quality as evaporation of the fluids have the 
potential to release contaminants into the atmosphere. According to 
the New York Department of Environmental Conservation's 2011 
Supplemental Generic Environmental Impact Statement, analysis of air 
emission rates of some of the compounds used in the fracturing fluids 
in the Marcellus Shale reveals the potential for emissions of 
hazardous air pollutants, in particular methanol, from the fluids 
stored in impoundments. 

As with conventional oil and gas development, emissions can also occur 
as faulty equipment or accidents, such as leaks or blowouts, release 
concentrations of methane and other gases into the atmosphere. For 
example, corrosion in pipelines or improperly tightened valves or 
seals can be sources of emissions. In addition, according to EPA 
officials, storage vessels for crude oil, condensate, or produced 
water are significant sources of methane, volatile organic compounds 
and hazardous air pollutant emissions. 

A number of studies we reviewed evaluated air quality at shale gas 
development sites. However, these studies are generally anecdotal, 
short-term, and focused on a particular site or geographic location. 
For example, in 2010, the Pennsylvania Department of Environmental 
Protection conducted short-term sampling of ambient air concentrations 
in north central Pennsylvania. The sampling detected concentrations of 
natural gas constituents including methane, ethane, propane, and 
butane in the air near Marcellus Shale drilling operations, but 
according to this state agency, the concentration levels were not 
considered significant enough to cause adverse health effects. 
[Footnote 45] 

The studies and publications we reviewed provide information on air 
quality conditions at a specific site at a specific time but do not 
provide the information needed to determine the overall cumulative 
effect that shale oil and gas activities have on air quality.[Footnote 
46] The cumulative effect shale oil and gas activities have on air 
quality will be largely determined by the amount of development and 
the rate at which it occurs, and the ability to measure this will 
depend on the availability of accurate information on emission levels. 
However, the number of wells that will ultimately be drilled cannot be 
known in advance--in part because the productivity of any particular 
formation at any given location and depth is not known until drilling 
occurs. In addition, as we reported in 2010, data on the severity or 
amount of pollutants released by oil and gas development, including 
the amount of fugitive emissions, are limited. 

Water Quantity: 

According to a number of studies and publications we reviewed, shale 
oil and gas development poses a risk to surface water and groundwater 
because withdrawing water from streams, lakes, and aquifers for 
drilling and hydraulic fracturing could adversely affect water 
sources.[Footnote 47] Operators use water for drilling, where a 
mixture of clay and water (drilling mud) is used to carry rock 
cuttings to the surface, as well as to cool and lubricate the drill 
bit. Water is also the primary component of fracturing fluid. Table 3 
shows the average amount of freshwater used to drill and fracture a 
shale oil or gas well. 

Table 3: Average Freshwater Use per Well for Drilling and Hydraulic 
Fracturing: 

Shale play: Barnett; 
Average freshwater used (in gallons): 
For drilling: 250,000; 
For hydraulic fracturing: 4,600,000. 

Shale play: Eagle Ford; 
Average freshwater used (in gallons): 
For drilling: 125,000; 
For hydraulic fracturing: 5,000,000. 

Shale play: Haynesville; 
Average freshwater used (in gallons): 
For drilling: 600,000; 
For hydraulic fracturing: 5,000,000. 

Shale play: Marcellus; 
Average freshwater used (in gallons): 
For drilling: 85,000; 
For hydraulic fracturing: 5,600,000. 

Shale play: Niobrara; 
Average freshwater used (in gallons): 
For drilling: 300,000; 
For hydraulic fracturing: 3,000,000. 

Source: GAO analysis of data reported by George King, Apache 
Corporation (2011). 

Note: The amount of water required to hydraulically fracture a single 
well varies considerably as fracturing of shale oil and gas becomes 
dominated by more complex, multistaged fracturing activities. 

[End of table] 

According to a 2012 University of Texas study,[Footnote 48] water for 
these activities is likely to come from surface water (rivers, lakes, 
ponds), groundwater aquifers, municipal supplies, reused wastewater 
from industry or water treatment plants, and recycling water from 
earlier fracturing operations.[Footnote 49] As we reported in October 
2010, withdrawing water from nearby streams and rivers could decrease 
flows downstream, making the streams and rivers more susceptible to 
temperature changes--increases in the summer and decreases in the 
winter. Elevated temperatures could adversely affect aquatic life 
because many fish and invertebrates need specific temperatures for 
reproduction and proper development. Further, decreased flows could 
damage or destroy riparian vegetation. Similarly, withdrawing water 
from shallow aquifers--an alternative water source--could temporarily 
affect groundwater resources. Withdrawals could lower water levels 
within these shallow aquifers and the nearby streams and springs to 
which they are connected. Extensive withdrawals could reduce 
groundwater discharge to connected streams and springs, which in turn 
could damage or remove riparian vegetation and aquatic life. 
Withdrawing water from deeper aquifers could have longer-term effects 
on groundwater and connected streams and springs because replenishing 
deeper aquifers with precipitation generally takes longer.[Footnote 
50] Further, groundwater withdrawal could affect the amount of water 
available for other uses, including public and private water supplies. 

Freshwater is a limited resource in some arid and semiarid regions of 
the country where an expanding population is placing additional 
demands on water. The potential demand for water is further 
complicated by years of drought in some parts of the country and 
projections of a warming climate. According to a 2011 Massachusetts 
Institute of Technology study,[Footnote 51] the amount of water used 
for shale gas development is small in comparison to other water uses, 
such as agriculture and other industrial purposes. However, the 
cumulative effects of using surface water or groundwater at multiple 
oil and gas development sites can be significant at the local level, 
particularly in areas experiencing drought conditions. 

Similar to shale oil and gas development, development of gas from 
coalbed methane formations poses a risk of aquifer depletion. To 
develop natural gas from such formations, water from the coal bed is 
withdrawn to lower the reservoir pressure and allow the methane to 
desorb from the coal. According to a 2001 USGS report, dewatering 
coalbed methane formations in the Powder River Basin in Wyoming can 
lower the groundwater table and reduce water available for other uses, 
such as livestock and irrigation.[Footnote 52] 

The key issue for water quantity is whether the total amount of water 
consumed for the development of shale oil and gas will result in a 
significant long-term loss of water resources within a region, 
according to a 2012 University of Texas study. This is because water 
used in shale oil and gas development is largely a consumptive use and 
can be permanently removed from the hydrologic cycle, according to EPA 
and Interior officials. However, it is difficult to determine the long-
term effect on water resources because the scale and location of 
future shale oil and gas development operations remains largely 
uncertain. Similarly, the total volume that operators will withdraw 
from surface water and aquifers for drilling and hydraulic fracturing 
is not known until operators submit applications to the appropriate 
regulatory agency. As a result, the cumulative amount of water 
consumed over the lifetime of the activity--key information needed to 
assess the effects of water withdrawals--remains largely unknown. 

Water Quality: 

According to a number of studies and publications we reviewed, shale 
oil and gas development pose risks to water quality from contamination 
of surface water and groundwater as a result of spills and releases of 
produced water, chemicals, and drill cuttings; erosion from ground 
disturbances; or underground migration of gases and chemicals. 

Spills and Releases: 

Shale oil and gas development poses a risk to water quality from 
spills or releases of toxic chemicals and waste that can occur as a 
result of tank ruptures, blowouts, equipment or impoundment failures, 
overfills, vandalism, accidents (including vehicle collisions), ground 
fires, or operational errors. For example, tanks storing toxic 
chemicals or hoses and pipes used to convey wastes to the tanks could 
leak, or impoundments containing wastes could overflow as a result of 
extensive rainfall. According to New York Department of Environmental 
Conservation's 2011 Supplemental Generic Environmental Impact 
Statement, spilled, leaked, or released chemicals or wastes could flow 
to a surface water body or infiltrate the ground, reaching and 
contaminating subsurface soils and aquifers. In August 2003, we 
reported that damage from oil and gas related spills on National 
Wildlife Refuges varied widely in severity, ranging from infrequent 
small spills with no known effect on wildlife to large spills causing 
wildlife death and long-term water and soil contamination.[Footnote 53] 

Drill cuttings, if improperly managed, also pose a risk to water 
quality. Drill cuttings brought to the surface during oil and gas 
development may contain naturally occurring radioactive materials 
(NORM),[Footnote 54] along with other decay elements (radium-226 and 
radium-228), according to an industry report presented at the Society 
of Petroleum Engineers Annual Technical Conference and Exhibition. 
[Footnote 55] According to the report, drill cuttings are stored and 
transported through steel pipes and tanks--which the radiation cannot 
penetrate. However, improper transport and handling of drill cuttings 
could result in water contamination. For example, NORM concentrations 
can build up in pipes and tanks, if not properly disposed, and the 
general public or water could come into contact with them, according 
to an EPA fact sheet.[Footnote 56] 

The chemical additives in fracturing fluid, if not properly handled, 
also poses a risk to water quality if they come into contact with 
surface water or groundwater. Some additives used in fracturing fluid 
are known to be toxic, but data are limited for other additives. For 
example, according to reports we reviewed, operators may include 
diesel fuel--a refinery product that consists of several components, 
possibly including some toxic impurities such as benzene and other 
aromatics--as a solvent and dispersant in fracturing fluid. While some 
additives are known to be toxic, less is known about potential adverse 
effects on human health in the event that a drinking water aquifer was 
contaminated as a result of a spill or release of fracturing fluid, 
according to the 2011 New York Department of Environmental 
Conservation's Supplemental Generic Environmental Impact Statement. 
This is largely because the overall risk of human health effects 
occurring from hydraulic fracturing fluid would depend on whether 
human exposure occurs, the specific chemical additives being used, and 
site-specific information about exposure pathways and environmental 
contaminant levels. 

The produced water and fracturing fluids returned during the flowback 
process contain a wide range of contaminants and pose a risk to water 
quality, if not properly managed.[Footnote 57] Most of the 
contaminants occur naturally, but some are added through the process 
of drilling and hydraulic fracturing. In January 2012, we reported 
that the range of contaminants found in produced water can include, 
[Footnote 58] but is not limited to: 

* salts, which include chlorides, bromides, and sulfides of calcium, 
magnesium, and sodium; 

* metals, which include barium, manganese, iron, and strontium, among 
others; 

* oil, grease, and dissolved organics, which include benzene and 
toluene, among others; 

* NORM; and: 

* production chemicals, which may include friction reducers to help 
with water flow, biocides to prevent growth of microorganisms, and 
additives to prevent corrosion, among others. 

At high levels, exposure to some of the contaminants in produced water 
could adversely affect human health and the environment. For example, 
in January 2012, we reported that, according to EPA, a potential human 
health risk from exposure to high levels of barium is increased blood 
pressure.[Footnote 59] From an environmental standpoint, research 
indicates that elevated levels of salts can inhibit crop growth by 
hindering a plant's ability to absorb water from the soil. 
Additionally, exposure to elevated levels of metals and production 
chemicals, such as biocides, can contribute to increased mortality 
among livestock and wildlife. 

Operators must transport or store produced water prior to disposal. 
According to a 2012 University of Texas report, produced water 
temporarily stored in tanks (see figure 12) or impoundments prior to 
treatment or disposal may be a source of leaks or spills, if not 
properly managed. The risk of a leak or spill is particularly a 
concern for surface impoundments as improper liners can tear, and 
impoundments can overflow.[Footnote 60] For example, according to 
state regulators in North Dakota, in 2010 and 2011, impoundments 
overflowed during the spring melt season because operators did not 
move fluids from the impoundments--which were to be used for temporary 
storage--to a proper disposal site before the spring thaw.[Footnote 61] 

Figure 12: Storage Tank for Produced Water in the Barnett Shale: 

[Refer to PDF for image: photograph] 

Source: GAO. 

[End of figure] 

Unlike shale oil and gas formations, water permeates coalbed methane 
formations, and its pressure traps natural gas within the coal. To 
produce natural gas from coalbed methane formations, water must be 
extracted to lower the pressure in the formation so the natural gas 
can flow out of the coal and to the wellbore. In 2000, USGS reported 
that water extracted from coalbed methane formations is commonly 
saline and, if not treated and disposed of properly, could adversely 
affect streams and threaten fish and aquatic resources. 

According to several reports, handling and transporting toxic fluids 
or contaminants poses a risk of environmental contamination for all 
industries, not just oil and gas development; however, the large 
volume of fluids and contaminants--fracturing fluid, drill cuttings, 
and produced water--that is associated with the development of shale 
oil and gas poses an increased risk for a release to the environment 
and the potential for greater effects should a release occur in areas 
that might not otherwise be exposed to these chemicals. 

Erosion: 

Oil and gas development, whether conventional or shale oil and gas, 
can contribute to erosion, which could carry sediments and pollutants 
into surface waters. Shale oil and gas development require operators 
to undertake a number of earth-disturbing activities, such as 
clearing, grading, and excavating land to create a pad to support the 
drilling equipment. If necessary, operators may also construct access 
roads to transport equipment and other materials to the site. As we 
reported in February 2005, as with other construction activities, if 
sufficient erosion controls to contain or divert sediment away from 
surface water are not established then surfaces are exposed to 
precipitation and runoff could carry sediment and other harmful 
pollutants into nearby rivers, lakes, and streams.[Footnote 62] For 
example, in 2012, the Pennsylvania Department of Environmental 
Protection concluded that an operator in the Marcellus Shale did not 
provide sufficient erosion controls when heavy rainfall in the area 
caused significant erosion and contamination of a nearby stream from 
large amounts of sediment.[Footnote 63] As we reported in February 
2005, sediment clouds water, decreases photosynthetic activity, and 
destroys organisms and their habitat. 

Underground Migration: 

According to a number of studies and publications we reviewed, 
underground migration of gases and chemicals poses a risk of 
contamination to water quality.[Footnote 64] Underground migration can 
occur as a result of improper casing and cementing of the wellbore as 
well as the intersection of induced fractures with natural fractures, 
faults, or improperly plugged dry or abandoned wells. Moreover, there 
are concerns that induced fractures can grow over time and intersect 
with drinking water aquifers. Specifically: 

Improper casing and cementing. A well that is not properly isolated 
through proper casing and cementing could allow gas or other fluids to 
contaminate aquifers as a result of inadequate depth of casing, 
[Footnote 65] inadequate cement in the annular space around the 
surface casing, and ineffective cement that cracks or breaks down 
under the stress of high pressures. For example, according to a 2008 
report by the Ohio Department of Natural Resources, a gas well in 
Bainbridge, Ohio, was not properly isolated because of faulty sealing, 
allowing natural gas to build up in the space around the production 
casing and migrate upward over about 30 days into the local aquifer 
and infiltrating drinking water wells.[Footnote 66] The risk of 
contamination from improper casing and cementing is not unique to the 
development of shale formations. Casing and cementing practices also 
apply to conventional oil and gas development. However, wells that are 
hydraulically fractured have some unique aspects. For example, 
hydraulically fractured wells are commonly exposed to higher pressures 
than wells that are not hydraulically fractured. In addition, 
hydraulically fractured wells are exposed to high pressures over a 
longer period of time as fracturing is conducted in multiple stages, 
and wells may be refractured multiple times--primarily to extend the 
economic life of the well when production declines significantly or 
falls below the estimated reservoir potential. 

Natural fractures, faults, and abandoned wells. If shale oil and gas 
development activities result in connections being established with 
natural fractures, faults, or improperly plugged dry or abandoned 
wells, a pathway for gas or contaminants to migrate underground could 
be created--posing a risk to water quality. These connections could be 
established through either induced fractures intersecting directly 
with natural fractures, faults, or improperly plugged dry or abandoned 
wells or as a result of improper casing and cementing that allow gas 
or other contaminants to make such connections. In 2011, the New York 
State Department of Environmental Conservation reported that operators 
generally avoid development around known faults because natural faults 
could allow gas to escape, which reduces the optimal recovery of gas 
and the economic viability of a well. However, data on subsurface 
conditions in some areas are limited. Several studies we reviewed 
report that some states are unaware of the location or condition of 
many old wells. As a result, operators may not be fully aware of the 
location of abandoned wells and natural fractures or faults. 

Fracture growth. A number of such studies and publications we reviewed 
report that the risk of induced fractures extending out of the target 
formation into an aquifer--allowing gas or other fluids to contaminate 
water--may depend, in part, on the depth separating the fractured 
formation and the aquifer. For example, according to a 2012 Bipartisan 
Policy Center report, [Footnote 67] the fracturing process itself is 
unlikely to directly affect freshwater aquifers because fracturing 
typically takes place at a depth of 6,000 to 10,000 feet, while 
drinking water tables are typically less than 1,000 feet deep. 
[Footnote 68] Fractures created during the hydraulic fracturing 
process are generally unable to span the distance between the targeted 
shale formation and freshwater bearing zones. According to a 2011 
industry report, fracture growth is stopped by natural subsurface 
barriers and the loss of hydraulic fracturing fluid.[Footnote 69] When 
a fracture grows, it conforms to a general direction set by the 
stresses in the rock, following what is called fracture direction or 
orientation. The fractures are most commonly vertical and may extend 
laterally several hundred feet away from the well, usually growing 
upward until they intersect with a rock of different structure, 
texture, or strength. These are referred to as seals or barriers and 
stop the fracture's upward or downward growth. In addition, as the 
fracturing fluid contacts the formation or invades natural fractures, 
part of the fluid is lost to the formation. The loss of fluids will 
eventually stop fracture growth according to this industry report. 

From 2001 through 2010, an industry consulting firm monitored the 
upper and lower limits of hydraulically induced fractures relative to 
the position of drinking water aquifers in the Barnett and Eagle Ford 
Shale, the Marcellus Shale, and the Woodford Shale.[Footnote 70] In 
2011, the firm reported that the results of the monitoring show that 
even the highest fracture point is several thousand feet below the 
depth of the deepest drinking water aquifer. For example, for over 200 
fractures in the Woodford Shale, the typical distance between the 
drinking water aquifer and the top of the fracture was 7,500 feet, 
with the highest fracture recorded at 4,000 feet from the aquifer. In 
another example, for the 3,000 fractures performed in the Barnett 
Shale, the typical distance from the drinking water aquifer and the 
top of the fracture was 4,800 feet, and the fracture with the closest 
distance to the aquifer was still separated by 2,800 feet of rock. 
Table 4 shows the relationship between shale formations and the depth 
of treatable water in five shale gas plays currently being developed. 

Table 4: Shale Formation and Treatable Water Depth: 

Distance in feet: 

Shale play: Barnett; 
Depth to shale: 6,500-8,500; 
Depth to base of treatable water: 1,200; 
Distance between shale and base of treatable water: 5,300-7,300. 

Shale play: Fayetteville; 
Depth to shale: 1,000-7,000; 
Depth to base of treatable water: 500; 
Distance between shale and base of treatable water: 500-6,500. 

Shale play: Haynesville; 
Depth to shale: 10,500-13,500; 
Depth to base of treatable water: 400; 
Distance between shale and base of treatable water: 10,100-13,100. 

Shale play: Marcellus; 
Depth to shale: 4,000-8,500; 
Depth to base of treatable water: 850; 
Distance between shale and base of treatable water: 2,125-7,650. 

Shale play: Woodford; 
Depth to shale: 6,000-11,000; 
Depth to base of treatable water: 400; 
Distance between shale and base of treatable water: 5,600-10,600. 

Source: GAO analysis of data presented in a report prepared at the 
request of the DOE. 

Note: Depths to base of treatable water are approximate. According to 
the report, the depth to base of treatable water was based on data 
from state oil and gas agencies and state geological survey data. 

[End of table] 

Several government, academic, and nonprofit organizations evaluated 
water quality conditions or groundwater contamination incidents in 
areas experiencing shale oil and gas development. Among the studies 
and publications we reviewed that discuss the potential contamination 
of drinking water from the hydraulic fracturing process in shale 
formations are the following: 

* In 2011, the Center for Rural Pennsylvania analyzed water samples 
taken from 48 private water wells located within about 2,500 feet of a 
shale gas well in the Marcellus Shale.[Footnote 71] The analysis 
compared predrilling samples to postdrilling samples to identify any 
changes to water quality. The analysis showed that there were no 
statistically significant increases in pollutants prominent in 
drilling waste fluids--such as total dissolved solids, chloride, 
sodium, sulfate, barium, and strontium--and no statistically 
significant increases in methane. The study concluded that gas well 
drilling had not had a significant effect on the water quality of 
nearby drinking water wells. 

* In 2011, researchers from Duke University studied shale gas drilling 
and hydraulic fracturing and the potential effects on shallow 
groundwater systems near the Marcellus Shale in Pennsylvania and the 
Utica Shale in New York. Sixty drinking water samples were collected 
in Pennsylvania and New York from bedrock aquifers that overlie the 
Marcellus or Utica Shale formations--some from areas with shale gas 
development and some from areas with no shale gas development. 
[Footnote 72] The study found that methane concentrations were 
detected generally in 51 drinking water wells across the region--
regardless of whether shale gas drilling occurred in the area--but 
that concentrations of methane were substantially higher closer to 
shale gas wells. However, the researchers reported that a source of 
the contamination could not be determined. Further, the researchers 
reported that they found no evidence of fracturing fluid in any of the 
samples. 

* In 2011, the Ground Water Protection Council evaluated state agency 
groundwater investigation findings in Texas and categorized the 
determinations regarding causes of groundwater contamination resulting 
from the oil and gas industry.[Footnote 73] During the study period--
from 1993 through 2008--multistaged hydraulic fracturing stimulations 
were performed in over 16,000 horizontal shale gas wells. The 
evaluation of the state investigations found that there were no 
incidents of groundwater contamination caused by hydraulic fracturing. 

In addition, regulatory officials we met with from eight states--
Arkansas, Colorado, Louisiana, North Dakota, Ohio, Oklahoma, 
Pennsylvania, and Texas--told us that, based on state investigations, 
the hydraulic fracturing process has not been identified as a cause of 
groundwater contamination within their states. 

A number of studies discuss the potential contamination of water from 
the hydraulic fracturing process in shale formations. However, 
according to several studies we reviewed, there are insufficient data 
for predevelopment (or baseline) conditions for groundwater. Without 
data to compare predrilling conditions to postdrilling conditions, it 
is difficult to determine if adverse effects were the result of oil 
and gas development, natural occurrences, or other activities. In 
addition, while researchers have evaluated fracture growth, the 
widespread development of shale oil and gas is relatively new. As 
such, little data exist on (1) fracture growth in shale formations 
following multistage hydraulic fracturing over an extended time 
period, (2) the frequency with which refracturing of horizontal wells 
may occur, (3) the effect of refracturing on fracture growth over 
time,[Footnote 74] and (4) the likelihood of adverse effects on 
drinking water aquifers from a large number of hydraulically fractured 
wells in close proximity to each other. 

Ongoing Studies Related to Water Quality: 

Ongoing studies by federal agencies, industry groups, and academic 
institutions are evaluating the effects of hydraulic fracturing on 
water resources so that, over time, better data and information about 
these effects should become available to policymakers and the public. 
For example, EPA's Office of Research and Development initiated a 
study in January 2010 to examine the potential effects of hydraulic 
fracturing on drinking water resources. According to agency officials, 
the agency anticipates issuing a progress report in 2012 and a final 
report in 2014. EPA is also conducting an investigation to determine 
the presence of groundwater contamination within a tight sandstone 
formation being developed for natural gas near Pavillion, Wyoming, 
and, to the extent possible, identify the source of the contamination. 
In December 2011, EPA released a draft report outlining findings from 
the investigation. The report is not finalized, but the agency 
indicated that it had identified certain constituents in groundwater 
above the production zone of the Pavillion natural gas wells that are 
consistent with some of the constituents used in natural gas well 
operations, including the process of hydraulic fracturing. DOE 
researchers are also testing the vertical growth of fractures during 
hydraulic fracturing to determine whether fluids can travel thousands 
of feet through geologic faults into water aquifers close to the 
surface. 

Land and Wildlife: 

Oil and gas development, whether conventional or shale oil and gas, 
poses a risk to land resources and wildlife habitat as a result of 
constructing, operating, and maintaining the infrastructure necessary 
to develop oil and gas; using toxic chemicals; and injecting waste 
products underground. 

Habitat Degradation: 

According to studies and publications we reviewed, development of oil 
and gas, whether conventional or shale oil and gas, poses a risk to 
habitat from construction activities. Specifically, clearing land of 
vegetation and leveling the site to allow access to the resource, as 
well as construction of roads, pipelines, storage tanks, and other 
infrastructure needed to extract and transport the resource can 
fragment habitats.[Footnote 75] In August 2003, we reported that oil 
and gas infrastructure on federal wildlife refuges can reduce the 
quality of habitat by fragmenting it.[Footnote 76] Fragmentation 
increases disturbances from human activities, provides pathways for 
predators, and helps spread nonnative plant species. 

In addition, spills of oil, gas, or other toxic chemicals have harmed 
wildlife and habitat. Oil and gas can injure or kill wildlife by 
destroying the insulating capacity of feathers and fur, depleting 
oxygen available in water, or exposing wildlife to toxic substances. 
Long-term effects of oil and gas contamination on wildlife are 
difficult to determine, but studies suggest that effects of exposure 
include reduced fertility, kidney and liver damage, immune 
suppression, and cancer. In August 2003, we reported that even small 
spills may contaminate soil and sediments if they occur frequently. 
[Footnote 77] Further, noise and the presence of new infrastructure 
associated with shale gas development may also affect wildlife. A 
study by the Houston Advanced Research Center and the Nature 
Conservancy investigated the effects of noise associated with gas 
development on the Attwater's Prairie Chicken--an endangered species. 
The study explored how surface disruptions, particularly construction 
of a rig and noise from diesel generators would affect the animal's 
movement and habitat.[Footnote 78] The results of the study found that 
the chickens were not adversely affected by the diesel engine 
generator's noise but that the presence of the rig caused the animals 
to temporarily disperse and avoid the area. 

A number of studies we reviewed identified risks to habitat and 
wildlife as a result of shale oil and gas activities. However, because 
shale oil and gas development is relatively new in some areas, the 
long-term effects--after operators are to have restored portions of 
the land to predevelopment conditions--have not been evaluated. 
Without these data, the cumulative effects of shale oil and gas 
development on habitat and wildlife are largely unknown. 

Induced Seismicity: 

According to several studies and publications we reviewed, the 
hydraulic fracturing process releases energy deep beneath the surface 
to break rock but the energy released is not large enough to trigger a 
seismic event that could be felt on the surface. However, a process 
commonly used by operators to dispose of waste fluids--underground 
injection--has been associated with earthquakes in some locations. For 
example, a 2011 Oklahoma Geological Survey study reported that 
underground injection can induce seismicity. In March 2012, the Ohio 
Department of Natural Resources reported that "there is a compelling 
argument" that the injection of produced water into underground 
injection wells was the cause of the 2011 earthquakes near Youngstown, 
Ohio. In addition, the National Academy of Sciences released a study 
in June 2012 that concluded that underground injection of wastes poses 
some risk for induced seismicity, but that very few events have been 
documented over the past several decades relative to the large number 
of disposal wells in operation. 

The available research does not identify a direct link between 
hydraulic fracturing and increased seismicity, but there could be an 
indirect effect to the extent that increased use of hydraulic 
fracturing produces increased amounts of water that is disposed of 
through underground injection. In addition, according to the National 
Academy of Science's 2012 report, accurately predicting magnitude or 
occurrence of seismic events is generally not possible, in part, 
because of a lack of comprehensive data on the complex natural rock 
systems at energy development sites. 

Extent of Risks Is Unknown and Depends on Many Factors: 

The extent and severity of environmental and public health risks 
identified in the studies and publications we reviewed may vary 
significantly across shale basins and also within basins because of 
location-and process-specific factors, including the location and rate 
of development; geological characteristics, such as permeability, 
thickness, and porosity of the formations in the basin; climatic 
conditions; business practices; and regulatory and enforcement 
activities. 

Location and rate of development. The location of oil and gas 
operations and the rate of development can affect the extent and 
severity of environmental and public health risks. For example, as we 
reported in October 2010, while much of the natural gas that is vented 
and flared is considered to be unavoidably lost, certain technologies 
and practices can be applied throughout the production process to 
capture some of this gas, according to the oil and gas industry and 
EPA. The technologies' technical and economic feasibility varies and 
sometimes depends on the location of operations. For example, some 
technologies require a substantial amount of electricity, which may be 
less feasible for remote production sites that are not on the 
electrical grid. In addition, the extent and severity of environmental 
risks may vary based on the location of oil and gas wells. For 
example, in areas with high population density that are already 
experiencing challenges adhering to federal air quality limits, 
increases in ozone levels because of emissions from oil and gas 
development may compound the problem. 

Geological characteristics. Geological characteristics can affect the 
extent and severity of environmental and public health risks 
associated with shale oil and gas development. For example, geological 
differences between tight sandstone and shale formations are important 
because, unlike shale, tight sandstone has enough permeability to 
transmit groundwater to water wells in the region. In a sense, the 
tight sandstone formation acts as a reservoir for both natural gas and 
for groundwater. In contrast, shale formations are typically not 
permeable enough to transmit water and are not reservoirs for 
groundwater. According to EPA officials, hydraulic fracturing in a 
tight sandstone formation that is a reservoir for both natural gas and 
groundwater poses a greater risk of contamination than the same 
activity in a deep shale formation. 

Climatic conditions. Climatic factors, such as annual rainfall and 
surface temperatures, can also affect the environmental risks for a 
specific region or area. For example, according to a 2007 study funded 
by DOE, average rainfall amounts can be directly related to soil 
erosion.[Footnote 79] Specifically, areas with higher precipitation 
levels may be more susceptible to soil compaction and rutting during 
the well pad construction phase. In another example, risk of adverse 
effects from exposures to toxic air contaminants can vary 
substantially between drilling sites, in part, because of the specific 
mix of emissions and climatic conditions that affect the transport and 
dispersion of emissions. Specifically, wind speed and direction, 
temperature, as well as other climatic conditions, can influence 
exposure levels of toxic air contaminants. For example, according to a 
2012 study from the Sustainable Investments Institute and the Investor 
Responsibility Research Center Institute, the combination of air 
emissions from gas operations, snow on the ground, bright sunshine, 
and temperature inversions during winter months have contributed to 
ozone creation in Sublette County, Wyoming.[Footnote 80] 

Business practices. A number of studies we reviewed indicate that some 
adverse effects from shale oil and gas development can be mitigated 
through the use of technologies and best practices. For example, 
according to standards and guidelines issued jointly by the 
Departments of the Interior and Agriculture, mitigation techniques, 
such as fencing and covers, should be used around impoundments to 
prevent livestock or wildlife from accessing fluids stored in the 
impoundments.[Footnote 81] In another example, EPA's Natural Gas STAR 
program has identified over 80 technologies and practices that can 
cost effectively reduce methane emissions, a potent greenhouse gas, 
during oil and gas development. However, the use of these technologies 
and business practices are typically voluntary and rely on responsible 
operators to ensure that necessary actions are taken to prevent 
environmental contamination. Further, the extent to which operators 
use these mitigating practices is unknown and could be particularly 
challenging to identify given the significant increase in recent years 
in the development of shale oil and gas by a variety of operators, 
both large and small. 

Regulatory and enforcement activities. Potential changes to the 
federal, state, and local regulatory environment will affect 
operators' future activities and can therefore affect the risks or 
level of risks associated with shale oil and gas development. Shale 
oil and gas development is regulated by multiple levels of government--
including federal, state, and local. Many of the laws and regulations 
applicable to shale oil and gas development were put in place before 
the increase in operations that has occurred in the last few years, 
and various levels of government are evaluating and, in some cases, 
revising laws and regulations to respond to the increase in shale oil 
and gas development. For example, in April 2012, EPA promulgated New 
Source Performance Standards for the oil and gas industry that, when 
fully phased-in by 2015, will require emissions reductions at new or 
modified oil and gas well sites, including wells using hydraulic 
fracturing. Specifically, these new standards, in part, focus on 
reducing the venting of natural gas and volatile organic compounds 
during the flowback process. In addition, areas without prior 
experience with oil and gas development are just now developing new 
regulations. These governments' effectiveness in implementing and 
enforcing this framework will affect future activities and the level 
of associated risk. 

Agency Comments: 

We provided a draft of this report to the Department of Energy, the 
Department of the Interior, and the Environmental Protection Agency 
for review and comment. We received technical comments from Interior's 
Assistant Secretary, Policy, Management, and Budget, and from 
Environmental Protection Agency officials, which we have incorporated 
as appropriate. In an e-mail received August 27, 2012, the Department 
of Energy liaison stated the agency had no comments on the report. 

As agreed with your offices, unless you publicly announce the contents 
of this report earlier, we plan no further distribution until 30 days 
from the report date. At that time, we will send copies of this report 
to the appropriate congressional committees, the Secretary of Energy, 
the Secretary of the Interior, the EPA Administrator, and other 
interested parties. In addition, the report will be available at no 
charge on the GAO website at [hyperlink, http://www.gao.gov. 

If you or your staff members have any questions about this report, 
please contact me at (202) 512-3841 or ruscof@gao.gov. Contact points 
for our Offices of Congressional Relations and Public Affairs may be 
found on the last page of this report. GAO staff who made key 
contributions to this report are listed in appendix IV. 

Signed by: 

Frank Rusco: 
Director, Natural Resources and Environment: 

List of Requesters: 

The Honorable Barbara Boxer:
Chairman:
Committee on Environment and Public Works:
United States Senate: 

The Honorable Sheldon Whitehouse:
Chairman:
Subcommittee on Oversight:
Committee on Environment and Public Works:
United States Senate: 

The Honorable Benjamin L. Cardin:
Chairman:
Subcommittee on Water and Wildlife:
Committee on Environment and Public Works:
United States Senate: 

The Honorable Henry A. Waxman:
Ranking Member:
Committee on Energy and Commerce:
House of Representatives: 

The Honorable Edward J. Markey:
Ranking Member:
Committee on Natural Resources:
House of Representatives: 

The Honorable Diana DeGette:
Ranking Member:
Subcommittee on Oversight and Investigations:
Committee on Energy and Commerce:
House of Representatives: 

The Honorable Robert P. Casey, Jr.
United States Senate: 

[End of section] 

Appendix I: Scope and Methodology: 

Our objectives for this review were to determine what is known about 
(1) the size of shale oil and gas resources in the United States and 
the amount produced from 2007 through 2011--the years for which data 
were available--and (2) the environmental and public health risks 
associated with development of shale oil and gas. 

To determine what is known about the size of shale oil and gas 
resources, we collected data from federal agencies, state agencies, 
private industry, and academic organizations. Specifically, to 
determine what is known about the size of these resources, we obtained 
information for technically recoverable and proved reserves estimates 
for shale oil and gas from the Energy Information Administration 
(EIA), the U.S. Geological Survey (USGS), and the Potential Gas 
Committee--a nongovernmental organization composed of academic and 
industry officials. We interviewed key officials about the assumptions 
and methodologies used to estimate the resource size. Estimates of 
proved reserves of shale oil and gas are based on data provided to EIA 
by operators. In addition to the estimates provided by these three 
organizations, we also obtained and presented technically recoverable 
shale oil and gas estimates from two private organizations--IHS Inc., 
and ICF International--and one national advisory committee 
representing the views of the oil and gas industry and other 
stakeholders--the National Petroleum Council. For all estimates we 
report, we conducted a review of the methodologies used in these 
estimates for fatal flaws; we did not find any fatal flaws in these 
methodologies. 

To determine what is known about the amount of produced shale oil and 
gas from 2007 through 2011, we obtained data from EIA--the federal 
agency responsible for estimating and reporting this and other energy 
information. EIA officials provided us with estimated oil and gas 
production data, including data estimating shale oil and gas estimates 
from states and two private firms--HPDI, LLC and Lippman Consulting, 
Inc. To assess the reliability of these data, we examined EIA's 
published methodology for collecting this information and interviewed 
key EIA officials regarding the agency's data collection and 
validation efforts. We also interviewed officials from three state 
agencies, representatives from five private companies, and researchers 
from three academic institutions who are familiar with these data and 
EIA's methodology and discussed the sources and reliability of the 
data. We determined that these data were sufficiently reliable for the 
purposes of this report. 

To determine what is known about the environmental and public health 
risks associated with the development of shale oil and gas[Footnote 
82], we identified and reviewed more than 90 studies and other 
publications from federal agencies and laboratories, state agencies, 
local governments, the petroleum industry, academic institutions, 
environmental and public health groups, and other nongovernmental 
associations. The studies and publications we reviewed included 
scientific and industry periodicals, government-sponsored research, 
reports or other publications from nongovernmental organizations, and 
presentation materials. We identified these studies by conducting a 
literature search and by asking for recommendations during our 
interviews with stakeholders. For a number of studies, we interviewed 
the author or authors to discuss the study's findings and limitations, 
if any. We believe we have identified the key studies through our 
literature review and interviews, and that the studies included in our 
review have accurately identified potential risks for shale oil and 
gas development. However, given our methodology, it is possible that 
we may not have identified all of the studies with findings relevant 
to our objectives, and the risks we present may not be the only issues 
of concern. The widespread use of horizontal drilling and hydraulic 
fracturing to develop shale oil and gas is relatively new. Studying 
the effects of an activity and completing a formal peer-review process 
can take numerous months or years. Because of the relative short time 
frame for operations and the lengthy time frame for studying effects, 
we did not limit the review to peer-reviewed publications. 

The risks identified in the studies and publications we reviewed 
cannot, at present, be quantified, and the magnitude of potential 
adverse affects or likelihood of occurrence cannot be determined for 
several reasons. First, it is difficult to predict how many or where 
shale oil and gas drilling operations may be constructed. Second, 
operators' use of effective best practices to mitigate risk may vary. 
Third, based on the studies we reviewed, there are relatively few that 
are based on evaluating predevelopment conditions to postdevelopment 
conditions--making it difficult to detect or attribute adverse changes 
to shale oil and gas development. In addition, changes to the federal, 
state, and local regulatory environment and the effectiveness in 
implementation and enforcement will affect operators' future 
activities. Moreover, risks of adverse events, such as spills or 
accidents, may vary according to business practices, which in turn, 
may vary across oil and gas companies making it difficult to 
distinguish between risks that are inherent to the development of 
shale oil and gas from risks that are specific to particular business 
practices. 

To obtain additional perspectives on issues related to environmental 
and public health risks, we interviewed a nonprobability sample of 
stakeholders representing numerous agencies and organizations. (See 
appendix II for a list of agencies and organizations contacted.) We 
selected these agencies and organizations to be broadly representative 
of differing perspectives regarding environmental and public health 
risks. In particular, we obtained views and information from federal 
officials from the Department of Energy's National Energy Technical 
Laboratory, the Department of the Interior's Bureau of Land Management 
and Bureau of Indian Affairs, and the Environmental Protection Agency; 
state regulatory officials from Arkansas, Colorado, Louisiana, North 
Dakota, Ohio, Oklahoma, Pennsylvania, and Texas; tribal officials from 
the Osage Nation; shale oil and gas operators; representatives from 
environmental and public health organizations; and other knowledgeable 
parties with experience related to shale oil and gas development, such 
as researchers from the Colorado School of Mines, the University of 
Texas, Oklahoma University, and Stanford University. The findings from 
our interviews with stakeholders and officials cannot be generalized 
to those we did not speak with. 

We conducted this performance audit from November 2011 to September 
2012 in accordance with generally accepted government auditing 
standards. Those standards require that we plan and perform the audit 
to obtain sufficient, appropriate evidence to provide a reasonable 
basis for our findings and conclusions based on our audit objectives. 
We believe that the evidence obtained provides a reasonable basis for 
our findings and conclusions based on our audit objectives. 

[End of section] 

Appendix II: List of Agencies and Organizations Contacted: 

Federal Agencies: 

Congressional Research Service; 
Department of Energy's National Energy Technology Laboratory; 
Department of Health and Human Services; 
Department of the Interior's Bureau of Indian Affairs; 
Department of the Interior's Bureau of Land Management; 
Department of the Interior's U.S. Geological Survey; 
Environmental Protection Agency. 

State Agencies: 

Arkansas Department of Environmental Quality; 
Arkansas Oil and Gas Commission; 
Colorado Oil and Gas Conservation Commission; 
Louisiana Department of Natural Resources; 
North Dakota Industrial Commission; 
Ohio Department of Natural Resources; 
Ohio Environmental Protection Agency; 
Oklahoma Geological Survey; 
Oklahoma Corporation Commission; 
Texas Railroad Commission. 

Academic Institutions: 

Colorado School of Mines; 
Oklahoma University; 
Stanford University; 
University of Texas at Arlington; 
University of Texas Energy Center and Bureau of Economic Geology. 

Environmental Organizations: 

Clean Water Action Pennsylvania; 
Earthworks Oil and Gas Accountability Project; 
Environmental Defense Fund; 
Subra Consulting; 
Western Resource Advocates. 

Public Health Organizations: 

The Endocrine Disruption Exchange;
National Association of County and City Health Officials; 
Southwest Pennsylvania Environmental Health Project. 

Industry: 

ALL Consulting 
American Exploration and Production Council; 
American Petroleum Institute; 
Apache Corporation; 
Chesapeake Energy; 
Colorado Oil and Gas Association; 
Devon Energy; 
Powell Shale Digest. 

Others: 

Ground Water Protection Council; 
Martin Consulting; 
Red River Watershed Management Institute; 
Osage Tribal Nation. 

[End of section] 

Appendix III: Additional Information on USGS Estimates: 

The USGS estimates potential oil and gas resources in about 60 
geological areas (called "provinces") in the United States. Since 
1995, USGS has conducted oil and gas estimates at least once in all of 
these provinces; about half of these estimates have been updated since 
the year 2000 (see table 5). USGS estimates for an area are updated 
once every 5 years or more, depending on factors such as the 
importance of an area. 

Table 5: USGS Estimates: 

Name of USGS province: Northern Alaska; 
Most recent assessment year: 2006. 

Name of USGS province: Central Alaska; 
Most recent assessment year: 2004. 

Name of USGS province: Southern Alaska; 
Most recent assessment year: 2011. 

Name of USGS province: Western Oregon-Washington; 
Most recent assessment year: 2009. 

Name of USGS province: Eastern Oregon-Washington; 
Most recent assessment year: 2006. 

Name of USGS province: Northern Coastal; 
Most recent assessment year: 1995. 

Name of USGS province: Sonoma-Livermore; 
Most recent assessment year: 1995. 

Name of USGS province: Sacramento Basin; 
Most recent assessment year: 2006. 

Name of USGS province: San Joaquin Basin; 
Most recent assessment year: 2004. 

Name of USGS province: Central Coastal; 
Most recent assessment year: 1995. 

Name of USGS province: Santa Maria Basin; 
Most recent assessment year: 1995. 

Name of USGS province: Ventura Basin; 
Most recent assessment year: 1995. 

Name of USGS province: Los Angeles Basin; 
Most recent assessment year: 1995. 

Name of USGS province: Idaho-Snake River Downwarp; 
Most recent assessment year: 1995. 

Name of USGS province: Western Great Basin; 
Most recent assessment year: 1995. 

Name of USGS province: Eastern Great Basin; 
Most recent assessment year: 2004. 

Name of USGS province: Uinta-Piceance Basin; 
Most recent assessment year: 2002. 

Name of USGS province: Paradox Basin; 
Most recent assessment year: 1995. 

Name of USGS province: San Juan Basin; 
Most recent assessment year: 2002. 

Name of USGS province: Albuquerque-Sante Fe Rift; 
Most recent assessment year: 1995. 

Name of USGS province: Northern Arizona; 
Most recent assessment year: 1995. 

Name of USGS province: S. Ariz.-S.W. New Mexico; 
Most recent assessment year: 1995. 

Name of USGS province: South-Central New Mexico; 
Most recent assessment year: 1995. 

Name of USGS province: Montana Thrust Belt; 
Most recent assessment year: 2002. 

Name of USGS province: Central Montana; 
Most recent assessment year: 2001. 

Name of USGS province: Southwest Montana; 
Most recent assessment year: 1995. 

Name of USGS province: Hanna, Laramie, Shirley; 
Most recent assessment year: 2005. 

Name of USGS province: Williston Basin (includes Bakken Shale 
Formation); 
Most recent assessment year: 2008. 

Name of USGS province: Powder River Basin; 
Most recent assessment year: 2006. 

Name of USGS province: Big Horn Basin; 
Most recent assessment year: 2008. 

Name of USGS province: Wind River Basin; 
Most recent assessment year: 2005. 

Name of USGS province: Wyoming Thrust Belt; 
Most recent assessment year: 2004. 

Name of USGS province: Southwestern Wyoming; 
Most recent assessment year: 2002. 

Name of USGS province: Park Basins; 
Most recent assessment year: 1995. 

Name of USGS province: Denver Basin; 
Most recent assessment year: 2003. 

Name of USGS province: Las Animas Arch; 
Most recent assessment year: 1995. 

Name of USGS province: Raton Basin-Sierra Grande Uplift; 
Most recent assessment year: 2005. 

Name of USGS province: Palo Duro Basin; 
Most recent assessment year: 1995. 

Name of USGS province: Permian Basin (includes Barnett Shale); 
Most recent assessment year: 2007. 

Name of USGS province: Bend Arch-Ft. Worth Basin; 
Most recent assessment year: 2004. 

Name of USGS province: Marathon Thrust Belt; 
Most recent assessment year: 1995. 

Name of USGS province: Western Gulf Coast (includes Eagle Ford Shale); 
Most recent assessment year: 2011. 

Name of USGS province: East Texas Basin Province; 
Most recent assessment year: 2011. 

Name of USGS province: Louisiana-Mississippi Salt Basins Province; 
Most recent assessment year: 2011. 

Name of USGS province: Florida Peninsula; 
Most recent assessment year: 2000. 

Name of USGS province: Superior; 
Most recent assessment year: 1995. 

Name of USGS province: Cambridge Arch-Central Kansas; 
Most recent assessment year: 1995. 

Name of USGS province: Nemaha Uplift; 
Most recent assessment year: 1995. 

Name of USGS province: Forest City Basin; 
Most recent assessment year: 1995. 

Name of USGS province: Anadarko Basin; 
Most recent assessment year: 2011. 

Name of USGS province: Sedgwick Basin/Salina Basin; 
Most recent assessment year: 1995. 

Name of USGS province: Cherokee Platform; 
Most recent assessment year: 1995. 

Name of USGS province: Southern Oklahoma; 
Most recent assessment year: 1995. 

Name of USGS province: Arkoma Basin; 
Most recent assessment year: 2010. 

Name of USGS province: Michigan Basin; 
Most recent assessment year: 2005. 

Name of USGS province: Illinois Basin; 
Most recent assessment year: 2007. 

Name of USGS province: Black Warrior Basin; 
Most recent assessment year: 2002. 

Name of USGS province: Cincinnati Arch; 
Most recent assessment year: 1995. 

Name of USGS province: Appalachian Basin (includes Marcellus Shale); 
Most recent assessment year: 2011. 

Name of USGS province: Blue Ridge Thrust Belt; 
Most recent assessment year: 1995. 

Name of USGS province: Piedmont; 
Most recent assessment year: 1995. 

Source: USGS. 

[End of table] 

[End of section] 

Appendix IV GAO Contact and Staff Acknowledgments: 

GAO Contact: 

Frank Rusco, (202) 512-3841 or ruscof@gao.gov: 

Staff Acknowledgments: 

In addition to the contact named above, Christine Kehr, Assistant 
Director; Lee Carroll; Nirmal Chaudhary; Cindy Gilbert; Alison 
O'Neill; Marietta Revesz; Dan C. Royer; Jay Spaan; Kiki 
Theodoropoulos; and Barbara Timmerman made key contributions to 
this report. 

[End of section] 

Footnotes: 

[1] Shale oil differs from "oil shale." Shale is a sedimentary rock 
that is predominantly composed of consolidated clay-sized particles. 
Oil shale requires a different process to extract. Specifically, to 
extract the oil from oil shale, the rock needs to be heated to very 
high temperatures--ranging from about 650 to 1,000 degrees Fahrenheit--
in a process known as retorting. Oil shale is not currently 
economically viable to produce. For additional information on oil 
shale, see GAO, Energy-Water Nexus: A Better and Coordinated 
Understanding of Water Resources Could Help Mitigate the Impacts of 
Potential Oil Shale Development, [hyperlink, 
http://www.gao.gov/products/GAO-11-35] (Washington, D.C.: Oct. 29, 
2010). 

[2] GAO, Energy-Water Nexus: Information on the Quantity, Quality, and 
Management of Water Produced during Oil and Gas Production, 
[hyperlink, http://www.gao.gov/products/GAO-12-156] (Washington, D.C.: 
Jan. 9, 2012). 

[3] EIA is a statistical agency within DOE that provides independent 
data, forecasts, and analyses. 

[4] The Baker Institute is a public policy think tank located on the 
Rice University campus. 

[5] EIA reported that using natural gas over coal would lower 
emissions in the United States, but some researchers have reported 
that greater reliance on natural gas would fail to significantly slow 
climate change. 

[6] The natural gas liquids include propane, butane, and ethane, and 
are separated from the produced gas at the surface in lease 
separators, field facilities, or gas processing plants. 

[7] For the purposes of this report, resources represent all oil or 
natural gas contained within a formation and can be divided into 
resources and reserves. 

[8] For the purposes of this report, we refer to risk as a threat or 
vulnerability that has potential to cause harm. 

[9] Proved reserves refer to the amount of oil and gas that have been 
discovered and defined. 

[10] Operators may use hydraulic fracturing to develop oil and natural 
gas from formations other than shale, but for the purposes of this 
report we focused on development of shale formations. Specifically, 
coalbed methane and tight sandstone formations may rely on these 
practices and some studies and publications we reviewed identified 
risks that can apply to these formations. However, many of the studies 
and publications we identified and reviewed focused primarily on shale 
formations. 

[11] We selected these states because they are involved with shale oil 
and gas development. 

[12] Conventional sandstone has well-connected pores, but tight 
sandstone has irregularly distributed and poorly connected pores. Due 
to this low connectivity or permeability, gas trapped within tight 
sandstone is not easily produced. 

[13] For coalbed methane formations, the reduction in pressure needed 
to extract gas is achieved through dewatering. As water is pumped out 
of the coal seams, reservoir pressure decreases, allowing the natural 
gas to release (desorb) from the surface of the coal and flow through 
natural fracture networks into the well. 

[14] Ground Water Protection Council and ALL Consulting, Modern Shale 
Gas Development in the United States: A Primer, a special report 
prepared at the request of the Department of Energy (Washington, D.C.: 
April 2009). 

[15] Hydraulic fracturing is often conducted in stages. Each stage 
focuses on a limited linear section and may be repeated numerous times. 

[16] The seismic method of exploration introduces energy into the 
subsurface through explosions in shallow "shot holes" by striking the 
ground forcefully (with a truck-mounted thumper), or by vibration 
methods. A portion of the energy returns to the surface after being 
reflected from the subsurface strata. This energy is detected by 
surface instruments, called geophones, and the information carried by 
the energy is processed by computers to interpret subsurface 
conditions. 

[17] The specific order of activities and steps may vary. 

[18] According to the New York Department of Environmental 
Conservation's 2011 Supplemental Generic Environmental Impact 
Statement, the average size of a well pad is 3.5 acres. 

[19] GAO, Federal Oil and Gas Leases: Opportunities Exist to Capture 
Vented and Flared Natural Gas, Which Would Increase Royalty Payments 
and Reduce Greenhouse Gases, [hyperlink, 
http://www.gao.gov/products/GAO-11-34] (Washington, D.C.: Oct. 29, 
2010). 

[20] Stresses in the formation generally define a maximum and minimum 
stress direction that influence the direction a fracture will grow. 

[21] Underground injection is the predominant practice for disposing 
of produced water. In addition to underground injection, a limited 
amount of produced water is managed by discharging it to surface 
water, storing it in surface impoundments, and reusing it for 
irrigation or hydraulic fracturing. 

[22] The National Petroleum Council is a federally chartered and 
privately funded advisory committee that advises, informs, and makes 
recommendations to the Secretary of Energy on oil and natural gas 
matters. 

[23] For example, secondary recovery operations can be costly (such as 
using a well to inject water into an oil reservoir and push any 
remaining oil to operating wells), but the costs may be justified if 
prices are high enough. 

[24] Pub. L. No. 106-469 § 604 (2000), 114 Stat. 2029, 2041-42, 
codified, as amended, at 42 U.S.C. § 6217. 

[25] As noted previously, for the purposes of this report, we use the 
term "shale oil" to refer to oil from shale and other tight 
formations, which is recoverable by hydraulic fracturing and 
horizontal drilling techniques and is described by others as "tight 
oil." Shale oil and tight oil are extracted in the same way, but 
differ from "oil shale." Oil shale is a sedimentary rock containing 
solid organic material that converts into a type of crude oil only 
when heated. 

[26] Comparatively, the United States currently consumes about 7 
billion barrels of oil per year, about half of which are imported from 
foreign sources. 

[27] EIA estimates are based on natural gas production data from 2 
years prior to the reporting year; for example, EIA's 2012 estimate is 
based on 2010 data; the date cited here reflects the fact that EIA 
reported this latest estimate in 2012. 

[28] USGS estimates are based on updated data in a few--but not all--
individual geological areas, combined with data from other areas from 
all previous years. Each year USGS estimates new information for a few 
individual geological areas. For example, the 2011 USGS estimate 
includes updated 2011 data for the Appalachian Basin, the Anadarko 
Basin, and the Gulf Coast, combined with estimates for all other areas 
developed before 2011. See appendix III for additional information on 
USGS estimates. The date cited here reflects the fact that USGS 
reported this latest estimate in 2011. 

[29] Potential Gas Committee estimates are based on natural gas 
production data from the previous year; for example, committee's 2011 
estimate is based on 2010 data. The date cited here reflects the fact 
that the Potential Gas Committee reported this latest estimate in 2011. 

[30] The Sustainable Investments Institute (Si2) is a nonprofit 
membership organization founded in 2010 to conduct research and 
publish reports on organized efforts to influence corporate behavior. 
The Investor Responsibility Research Center Institute is a nonprofit 
organization established in 2006 that provides information to 
investors. 

[31] Reserves are key information for assessing the net worth of an 
operator. Oil and gas companies traded on the U.S. stock exchange are 
required to report their reserves to the Securities and Exchange 
Commission. According to an EIA official, EIA reports a more complete 
measure of oil and gas reserves because it receives reports of proved 
reserves from both private and publicly held companies. 

[32] As noted previously, for the purposes of this report, we use the 
term "shale oil" to refer to oil from shale and other tight 
formations, which is recovered by hydraulic fracturing and horizontal 
drilling and is described by others as "tight oil." Shale oil and 
tight oil are extracted in the same way, but differ from "oil shale." 
Oil shale is a sedimentary rock containing solid organic material that 
converts into a type of crude oil only when heated. 

[33] EIA provided us with estimated shale oil production data from a 
contractor, HPDI LLC., for 2007 through 2011. EIA uses these data for 
the purposes of estimating recent shale oil production. EIA has not 
routinely reported shale oil production data separately from oil 
production. 

[34] In addition to production from these shale oil plays, EIA 
officials told us that oil was produced from "tight oil" plays such as 
the Austin Chalk. The technology for producing tight oil is the same 
as for shale oil, and EIA uses the term "tight oil" to encompass both 
shale oil and tight oil that are developed with the same type of 
technology. In addition, EIA officials added that the shale oil data 
presented here is approximate because the data comes from a sample of 
similar plays. Overtime, this production data will become more precise 
as more data becomes available to EIA. 

[35] EIA provided us with estimated shale gas production data from a 
contractor, Lippman Consulting, Inc., for 2007 through 2011. EIA uses 
these data for the purposes of estimating recent shale gas production. 
EIA has separately reported shale gas production data using reports 
from states for the years 2008 and 2009. 

[36] According to a 2012 report from the Bipartisan Policy Center, 
natural gas prices declined roughly 37 percent from February 2008 to 
January 2010. 

[37] Department of Energy, Energy Information Administration, Annual 
Energy Outlook 2012, With Projections to 2035, DOE/EIA-0383 
(Washington, D.C.: June 25, 2012). 

[38] Nitrogen oxides are regulated pollutants commonly known as NOx 
that, among other things, contribute to the formation of ozone and 
have been linked to respiratory illness, decreased lung function, and 
premature death. Particulate matter is a ubiquitous form of air 
pollution commonly referred to as soot. GAO, Diesel Pollution: 
Fragmented Federal Programs That Reduce Mobile Source Emissions Could 
Be Improved, [hyperlink, http://www.gao.gov/products/GAO-12-261] 
(Washington, D.C.: Feb. 7, 2012). 

[39] T. Colborn, C. Kwiatkowski, K. Schultz, and M. Bachran, "Natural 
Gas Operations From a Public Health Perspective," International 
Journal of Human & Ecological Risk Assessment 17, no. 5 (2011). 

[40] Silicosis is an incurable lung disease caused by inhaling fine 
dusts of silica sand. 

[41] [hyperlink, http://www.gao.gov/products/GAO-11-34]. 

[42] Methane and other chemical compounds found in the earth's 
atmosphere create a greenhouse effect. Under normal conditions, when 
sunlight strikes the earth's surface, some of it is reflected back 
toward space as infrared radiation or heat. Greenhouse gases such as 
carbon dioxide and methane impede this reflection by trapping heat in 
the atmosphere. While these gases occur naturally on earth and are 
emitted into the atmosphere, the expanded industrialization of the 
world over the last 150 years has increased the amount of emissions 
from human activity (known as anthropogenic emissions) beyond the 
level that the earth's natural processes can handle. 

[43] EPA, Regulatory Impact Analysis: Final New Source Performance 
Standards and Amendments to the National Emissions Standards for 
Hazardous Air Pollutants for the Oil and Natural Gas industry 
(Research Triangle Park, NC: April 2012). 

[44] GAO, Natural Gas Flaring and Venting: Opportunities to Improve 
Data and Reduce Emissions, [hyperlink, 
http://www.gao.gov/products/GAO-04-809] (Washington, D.C.: July 14, 
2004). 

[45] Methane emissions represent a waste of resources and a fractional 
contribution to greenhouse gas levels. 

[46] According to a 2008 National Park Service report, on a site-by-
site basis, emissions may not be significant but on a regional basis 
may prove significant as states and parks manage regional ozone 
transport. 

[47] An aquifer is an underground layer of rock or unconsolidated 
sand, gravel, or silt that will yield groundwater to a well or spring. 

[48] Charles G. Groat, Ph.D. and Thomas W. Grimshaw, Ph.D., Fact-Based 
Regulation for Environmental Protection in Shale Gas Development 
(Austin, Texas: The Energy Institute, The University of Texas at 
Austin, February, 2012). 

[49] Operators are pursuing a variety of techniques and technologies 
to reduce freshwater demand, such as recycling their own produced 
water and hydraulic fracturing fluids. We recently reported that some 
shale gas operators have begun reusing produced water for hydraulic 
fracturing of additional wells (see [hyperlink, 
http://www.gao.gov/products/GAO-12-156]). 

[50] [hyperlink, http://www.gao.gov/products/GAO-11-35]. 

[51] Massachusetts Institute of Technology, The Future of Natural Gas: 
An Interdisciplinary MIT Study (2011) (web: [hyperlink, 
http://mit.edu/mitei/research/studies/report-natural-gas.pdf]). 

[52] USGS, A Field Conference On Impacts of Coalbed Methane 
Development in the Powder River Basin, Wyoming, Open-File Report 01-
126 (Denver, CO: 2001). 

[53] GAO, National Wildlife Refuges: Opportunities to Improve the 
Management and Oversight of Oil and Gas Activities on Federal Lands, 
[hyperlink, http://www.gao.gov/products/GAO-03-517] (Washington, D.C.: 
Aug. 28, 2003). 

[54] Naturally occurring radioactive materials (NORM) are present at 
varying degrees in virtually all environmental media, including rocks 
and soils. According to a DOE report, human exposure to radiation 
comes from a variety of sources, including naturally occurring 
radiation from space, medical sources, consumer products, and 
industrial sources. Normal disturbances of NORM-bearing rock 
formations by activities such as drilling do not generally pose a 
threat to workers, the general public or the environment, according to 
studies and publications we reviewed. 

[55] J. Daniel Arthur, Brian Bohm, David Cornue. "Environmental 
Considerations of Modern Shale Gas Development" (presented at the 
Society of Petroleum Engineers Annual Technical Conference and 
Exhibition, New Orleans, Louisiana, October 2009). 

[56] EPA, Radioactive Waste from Oil and Gas Drilling, EPA 402-F-06-
038 (Washington, D.C.: April 2006). 

[57] A 2009 report from DOE and the Groundwater Protection Council--a 
nonprofit organization whose members consist of state ground water 
regulatory agencies--estimates that from 30 percent to 70 percent of 
the original fluid injected returns to the surface. 

[58] [hyperlink, http://www.gao.gov/products/GAO-12-156]. 

[59] [hyperlink, http://www.gao.gov/products/GAO-12-156]. 

[60] The composition of pit lining depends on regulatory requirements, 
which vary from state to state. 

[61] In response, the state passed a new law that will significantly 
reduce the number of pits. Under the new law, operators can use pits 
for temporary storage of fluid from the flowback process but must 
drain and reclaim the pits no more than 72 hours after hydraulic 
fracturing is complete. 

[62] GAO, Storm Water Pollution: Information Needed on the 
Implications of Permitting Oil and Gas Construction Activities, 
[hyperlink, http://www.gao.gov/products/GAO-05-240] (Washington, D.C.: 
Feb. 9, 2005). 

[63] In response, the state required the operator to install silt 
fences, silt socks, gravel surfacing of the access road, and a storm 
water capture ditch. 

[64] Methane can occur naturally in shallow bedrock and unconsolidated 
sediments and has been known to naturally seep to the surface and 
contaminate water supplies, including water wells. Methane is a 
colorless, odorless gas and is generally considered nontoxic, but 
there could be an explosive hazard if gas is present in significant 
volumes and the water well is not properly vented. 

[65] The depth for casing and cementing may be determined by state 
regulations. 

[66] Ohio Department of Natural Resources, Report on the Investigation 
of the Natural Gas Invasion of Aquifers in Bainbridge Township of 
Geauga County, Ohio (September 2008). 

[67] Bipartisan Policy Center, Shale Gas: New Opportunities, New 
Challenges (Washington, D.C.: January 2012). 

[68] Some coalbed methane formations are much closer to drinking water 
aquifers than are shale formations. In 2004, EPA reviewed incidents of 
drinking water well contamination believed to be associated with 
hydraulic fracturing in coalbed methane formations. EPA found no 
confirmed cases linked to the injection of fracturing fluid or 
subsequent underground movement of fracturing fluids. The report 
states that, although thousands of coalbed methane formations are 
fractured annually, EPA did not find confirmed evidence that drinking 
water wells had been contaminated by the hydraulic fracturing process. 

[69] George E. King, Apache Corporation, "Explaining and Estimating 
Fracture Risk: Improving Fracture Performance in Unconventional Gas 
and Oil Wells" (presented at the Society of Petroleum Engineers 
Hydraulic Fracturing Conference, The Woodlands, Texas, February 2012). 

[70] Kevin Fisher, Norm Warpinski, Pinnacle--A Haliburton Service, 
"Hydraulic Fracture-Height Growth: Real Data" (presented at the 
Society of Petroleum Engineers Technical Conference and Exhibition, 
Denver, Colorado, October 2011). 

[71] The Center for Rural Pennsylvania, The Impact of Marcellus Gas 
Drilling on Rural Drinking Water Supplies (Harrisburg, Pennsylvania: 
October 2011). 

[72] Stephen G. Osborn, Avner Vengosh, Nathaniel R. Warner, and Robert 
B. Jackson, "Methane Contamination of Drinking Water Accompanying Gas-
well Drilling and Hydraulic Fracturing," Proceedings of the National 
Academy of Science 108, no. 20 (2011). 

[73] Ground Water Protection Council, State Oil and Gas Agency 
Groundwater Investigations And Their Role in Advancing Regulatory 
Reforms: A Two-State Review: Ohio and Texas (Oklahoma City, Oklahoma: 
August 2011). 

[74] According to research presented in the New York Department of 
Environmental Conservation's Supplemental Generic Environmental Impact 
Statement, refracturing can restore the original fracture height and 
length, and can often extend the fracture length beyond the original 
fracture dimensions. 

[75] Habitat fragmentation occurs when a network of roads and other 
infrastructure is constructed in previously undeveloped areas. 

[76] [hyperlink, http://www.gao.gov/products/GAO-03-517]. 

[77] [hyperlink, http://www.gao.gov/products/GAO-03-517]. 

[78] James F. Bergan, Richard Haut, Jared Judy, and Liz Price. "Living 
In Harmony--Gas Production and the Attwater's Prairie Chicken" 
(presented at the Society of Professional Engineers Annual Technical 
Conference, Florence, Italy, September 2010). 

[79] ALL Consulting and the Interstate Oil and Gas Compact Commission, 
Improving Access to Onshore Oil and Gas Resources on Federal Lands (a 
special report prepared at the request of the U.S. Department of 
Energy National Energy and Technology Laboratory, March 2007). 

[80] Susan Williams, "Discovering Shale Gas: An Investor Guide to 
Hydraulic Fracturing," Sustainable Investments Institute and Investor 
Responsibility Research Center Institute (New York, NY: February 2012). 

[81] United States Department of the Interior and United States 
Department of Agriculture. Surface Operating Standards and Guidelines 
for Oil and Gas Exploration and Development. BLM/WO/ST-06/021+3071/REV 
07 (Denver, CO: 2007). 

[82] Operators may use hydraulic fracturing to develop oil and natural 
gas from formations other than shale. Specifically, coalbed and tight 
sand formations may rely on these practices, and some studies and 
publications we reviewed identified risks that can apply to these 
formations. However, many of the studies and publications we 
identified and reviewed focused primarily on the development of shale 
formations. 

[End of section] 

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