OIL AND GAS 

Information on Shale 

Resources, 

Development, and 

Environmental and 

Public Health Risks 

Report to Congressional Requesters

September 2012 

GAO-12-732 

United States Government Accountability Office

GAO 
United States Government Accountability Office

Highlights of GAO-12-732, a report to 

congressional requesters

September 2012

OIL AND GAS

Information on Shale Resources, Development, and 

Environmental and Public Health Risks

Why GAO Did This Study

New 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. 

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. 

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.

View GAO-12-732. For more information, 

contact Frank Rusco at (202) 512-3841 or 

ruscof@gao.gov. 
Page i GAO-12-732 Shale Oil and Gas Development

Letter 1 

Background 5

Domestic Shale Oil and Gas Estimates and Production 19

Shale Oil and Gas Development Pose Environmental and Public 

Health Risks, but the Extent is Unknown and Depends on Many 

Factors 32

Agency Comments 55

Appendix I Scope and Methodology 58

Appendix II List of Agencies and Organizations Contacted 61

Appendix III Additional Information on USGS Estimates 63

Appendix IV GAO Contact and Staff Acknowledgments 65

Tables

Table 1: USGS and EIA Estimates of Total Remaining Technically 

Recoverable U.S. Oil Resources 20

Table 2: Estimated Technically Recoverable Shale Gas Resources, 

by Play 24

Table 3: Average Freshwater Use per Well for Drilling and 

Hydraulic Fracturing 37

Table 4: Shale Formation and Treatable Water Depth 48

Table 5: USGS Estimates 63

Figures

Figure 1: History of Horizontal Drilling and Hydraulic Fracturing 7

Figure 2: Perforating Tool 11

Figure 3: Examples of Common Ingredients Found in Fracturing 

Fluid 12

Figure 4: Shale Plays and Basins in the Contiguous 48 States 15

Contents
Page ii GAO-12-732 Shale Oil and Gas Development

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

Shale Oil and Gas 18

Figure 6: Estimates of Technically Recoverable Shale Gas from 

EIA, USGS, and the Potential Gas Committee (2006 

through 2012) 22

Figure 7: Estimated Production of Shale Oil from 2007 through 

2011 (in millions of barrels of oil) 26

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

2011) 28

Figure 9: Estimated Production of Shale Gas from 2007 through 

2011 (in trillions of cubic feet) 29

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

2011) 31

Figure 11: Silica Sand Proppant 34

Figure 12: Storage Tank for Produced Water in the Barnett Shale 43

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

This is a work of the U.S. government and is not subject to copyright protection in the 

United States. The published product may be reproduced and distributed in its entirety 

without further permission from GAO. However, because this work may contain 

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necessary if you wish to reproduce this material separately.
Page 1 GAO-12-732 Shale Oil and Gas Development

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,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.

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.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.4

 

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, 

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 

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, 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. 

 
 

Page 2 GAO-12-732 Shale Oil and Gas Development

for the same amount of electric power generated.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.

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.7

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.

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.

8

 

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. 
 

Page 3 GAO-12-732 Shale Oil and Gas Development

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.9

To determine what is known about the environmental and public health 

risks associated with the development of shale oil and gas,

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.

10

 

9

Proved reserves refer to the amount of oil and gas that have been discovered and 

defined.

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 

10Operators 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.
 

Page 4 GAO-12-732 Shale Oil and Gas Development

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;11

 

11We selected these states because they are involved with shale oil and gas 

development. 

tribal officials from the Osage Nation; shale oil and gas operators; 
 

Page 5 GAO-12-732 Shale Oil and Gas Development

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.

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.

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 

Background 

Overview
 

Page 6 GAO-12-732 Shale Oil and Gas Development

formations and tight sandstone formations,12 may also require stimulation 

to allow oil or gas to be extracted.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,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 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.15

 

12Conventional 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. 

13For 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. 

14Ground 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).

15Hydraulic fracturing is often conducted in stages. Each stage focuses on a limited linear 

section and may be repeated numerous times.

The Shale Oil and Gas 

Development Process
 

Page 7 GAO-12-732 Shale Oil and Gas Development

Figure 1: History of Horizontal Drilling and Hydraulic Fracturing

First, operators locate suitable shale oil and gas targets using seismic 

methods of exploration,16

 

16The 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. 

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 
 

Page 8 GAO-12-732 Shale Oil and Gas Development

preparation and construction, (2) drilling and well construction, and (3) 

hydraulic fracturing.17

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.18

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 highpressure 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.

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 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 

 

17The specific order of activities and steps may vary. 

18According 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. 

Well Pad Preparation and 

Construction

Drilling and Well Construction
 

Page 9 GAO-12-732 Shale Oil and Gas Development

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.19

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 

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.

 

19GAO, Federal Oil and Gas Leases: Opportunities Exist to Capture Vented and Flared 

Natural Gas, Which Would Increase Royalty Payments and Reduce Greenhouse Gases, 

GAO-11-34 (Washington, D.C.: Oct. 29, 2010). 

Hydraulic Fracturing 
 

Page 10 GAO-12-732 Shale Oil and Gas Development

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 stresses20

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 (fig. 2 shows a used perforating tool).

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. 

 

20Stresses in the formation generally define a maximum and minimum stress direction that 

influence the direction a fracture will grow.
 

Page 11 GAO-12-732 Shale Oil and Gas Development

Figure 2: Perforating Tool 

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.
 

Page 12 GAO-12-732 Shale Oil and Gas Development

Figure 3: Examples of Common Ingredients Found in Fracturing Fluid

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 
 

Page 13 GAO-12-732 Shale Oil and Gas Development

other ways.21

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.

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.

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 

 

21Underground 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. 

Regulatory Framework
 

Page 14 GAO-12-732 Shale Oil and Gas Development

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.

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.

Location of Shale Oil and 

Gas in the United States
 

Page 15 GAO-12-732 Shale Oil and Gas Development

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

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 
 

Page 16 GAO-12-732 Shale Oil and Gas Development

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 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,22

 

22The 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.

technically recoverable resource estimates usually increase 

Estimating the Size of 

Shale Oil and Gas 

Resources
 

Page 17 GAO-12-732 Shale Oil and Gas Development

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.23

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.

Conversely, lower prices may diminish the amount of 

resources likely to be produced, reducing proved reserves.

 

23For 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.
 

Page 18 GAO-12-732 Shale Oil and Gas Development

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

Gas

Note: This illustration is not necessarily to scale because all volumes, except historical production, 

are subject to significant uncertainty.

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.

24

 

24Pub. L. No. 106-469 § 604 (2000), 114 Stat. 2029, 2041-42, codified, as amended, at 42 

U.S.C. § 6217. 

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 
 

Page 19 GAO-12-732 Shale Oil and Gas Development

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.

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.

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.

Domestic Shale Oil 

and Gas Estimates 

and Production

Estimates of Technically 

Recoverable Shale Oil and 

Gas Resources
 

Page 20 GAO-12-732 Shale Oil and Gas Development

In the last 2 years, EIA and USGS provided estimates of technically 

recoverable shale oil.25

• In 2012, EIA estimated that the United States possesses 33 billion 

barrels of technically recoverable shale oil,

Each of these estimates increased in recent years 

as follows:

26

• 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.

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.

Table 1: USGS and EIA Estimates of Total Remaining Technically Recoverable 

U.S. Oil Resources

Barrels of oil in billions

USGS EIA 

2006 2011 2011 2012

Estimated technically recoverable shale oil 

and tight sandstone resources

2 7 32 33

Estimated technically recoverable oil 

resources other than shalea 142 133 187 201

Source: GAO analysis of EIA and USGS data. 

 

25As 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. 

26Comparatively, the United States currently consumes about 7 billion barrels of oil per 

year, about half of which are imported from foreign sources. 

Estimates of Technically 

Recoverable Shale Oil 

Resources 
 

Page 21 GAO-12-732 Shale Oil and Gas Development

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.

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.

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 fig. 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.27

• In 2011, USGS reported that the total of its estimates for the shale 

formations the agency evaluated in all previous years

This represents an 

increase of 280 percent from EIA’s 2008 estimate.

28

 

27EIA 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. 

shows the 

28USGS 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.

Estimates of Technically 

Recoverable Shale Gas 

Resources 
 

Page 22 GAO-12-732 Shale Oil and Gas Development

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.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)

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 

 

29Potential 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.
 

Page 23 GAO-12-732 Shale Oil and Gas Development

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

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.

The Potential Gas Committee did not report separate estimates of shale gas until 2007 and has 

updated this estimate every 2 years since then.

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). 
 

Page 24 GAO-12-732 Shale Oil and Gas Development

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

Shale play Location 

Technically recoverable gas, 

in trillion cubic feet (Tcf)

Barnett North Texas 43-53

Fayetteville Arkansas 13-110

Haynesville Louisiana and East Texas 66-110

Marcellus Northeast United States 84-227

Woodford

a

Oklahoma 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

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 longterm 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.

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.

30

 

30The 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. 

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 
 

Page 25 GAO-12-732 Shale Oil and Gas Development

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 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.31 More than 75 percent of the proved shale gas 

reserves are located in three shale plays—the Barnett, Fayetteville, and 

the Haynesville. 

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 

 

31Reserves 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 publically held companies.

Estimates of Proved 

Reserves of Shale Oil and 

Gas

Shale Oil and Gas 

Production 
 

Page 26 GAO-12-732 Shale Oil and Gas Development

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.

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 fig. 7).32

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

barrels of oil)

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.

 

32As 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. 

Shale Oil Production
 

Page 27 GAO-12-732 Shale Oil and Gas Development

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 fig. 8).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.34

 

33EIA 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.

34In 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.
 

Page 28 GAO-12-732 Shale Oil and Gas Development

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

Page 29 GAO-12-732 Shale Oil and Gas Development

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 fig. 9).35

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

cubic feet) 

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 fig.10). 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 

 

35EIA 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.

Shale Gas Production
 

Page 30 GAO-12-732 Shale Oil and Gas Development

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.
 

Page 31 GAO-12-732 Shale Oil and Gas Development

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

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 
 

Page 32 GAO-12-732 Shale Oil and Gas Development

production has contributed to lower prices for consumers, according to 

EIA and others.36

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.

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 gasfired 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. 

37

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.

 

36According to a 2012 report from the Bipartisan Policy Center, natural gas prices declined 

roughly 37 percent from February 2008 to January 2010. 

37Department of Energy, Energy Information Administration, Annual Energy Outlook 2012, 

With Projections to 2035, DOE/EIA-0383 (Washington, D.C.: June 25, 2012). 

Shale Oil and Gas 

Development Pose 

Environmental and 

Public Health Risks, 

but the Extent is 

Unknown and 

Depends on Many 

Factors 
 

Page 33 GAO-12-732 Shale Oil and Gas Development

Oil and gas development, which includes development from shale 

formations, poses inherent risks to air quality, water quantity, water 

quality, and land and wildlife.

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.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.39 In addition 

to the dust, silica sand (see fig. 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.40

 

38Nitrogen 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, 

 

GAO-12-261 

(Washington, D.C.: Feb. 7, 2012). 

39T. 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). 

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

Shale Oil and Gas 

Development Pose Risks 

to Air, Water, Land and 

Wildlife

Air Quality
 

Page 34 GAO-12-732 Shale Oil and Gas Development

The researcher expects to publish the results of research on public health 

risks from proppant later in 2012.

Figure 11: Silica Sand Proppant

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 
 

Page 35 GAO-12-732 Shale Oil and Gas Development

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.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.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.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.44

 

41

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, 

GAO-11-34. 

42Methane 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. 

43EPA, 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). 

44GAO, Natural Gas Flaring and Venting: Opportunities to Improve Data and Reduce 

Emissions, GAO-04-809 (Washington, D.C.: July 14, 2004). 
 

Page 36 GAO-12-732 Shale Oil and Gas Development

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.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 

 

45Methane emissions represent a waste of resources and a fractional contribution to 

greenhouse gas levels. 
 

Page 37 GAO-12-732 Shale Oil and Gas Development

shale oil and gas activities have on air quality.46

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.

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.

47

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

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.

Average freshwater used (in gallons)

Shale play For drilling For hydraulic fracturing 

Barnett 250,000 4,600,000

Eagle Ford 125,000 5,000,000

Haynesville 600,000 5,000,000

Marcellus 85,000 5,600,000

Niobrara 300,000 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.

 

46According 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.

47An aquifer is an underground layer of rock or unconsolidated sand, gravel, or silt that will 

yield groundwater to a well or spring. 

Water Quantity
 

Page 38 GAO-12-732 Shale Oil and Gas Development

According to a 2012 University of Texas study,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.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.50

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,

Further, 

groundwater withdrawal could affect the amount of water available for 

other uses, including public and private water supplies.

51

 

48Charles 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). 

the amount of water used for shale gas development is small in 

49Operators 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 GAO-12-156). 

50GAO-11-35. 

51Massachusetts Institute of Technology, The Future of Natural Gas: An Interdisciplinary 

MIT Study (2011) (web.mit.edu/mitei/research/studies/report-natural-gas.pdf).
 

Page 39 GAO-12-732 Shale Oil and Gas Development

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.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.

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.

 

52USGS, A Field Conference On Impacts of Coalbed Methane Development in the 

Powder River Basin, Wyoming, Open-File Report 01-126 (Denver, CO: 2001). 

Water Quality 
 

Page 40 GAO-12-732 Shale Oil and Gas Development

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.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),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.55

 

53GAO, National Wildlife Refuges: Opportunities to Improve the Management and 

Oversight of Oil and Gas Activities on Federal Lands, 

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 

GAO-03-517 (Washington, D.C.: 

Aug. 28, 2003). 

54Naturally 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.

55J. 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). 
 

Page 41 GAO-12-732 Shale Oil and Gas Development

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.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.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,58

• salts, which include chlorides, bromides, and sulfides of calcium, 

magnesium, and sodium;

but is not limited to

 

56EPA, Radioactive Waste from Oil and Gas Drilling, EPA 402-F-06-038 (Washington, 

D.C.: April 2006). 

57A 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.

58GAO-12-156. 
 

Page 42 GAO-12-732 Shale Oil and Gas Development

• 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.59

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 fig. 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.

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.

60

 

59

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 

GAO-12-156. 

60The composition of pit lining depends on regulatory requirements, which vary from state 

to state. 
 

Page 43 GAO-12-732 Shale Oil and Gas Development

were to be used for temporary storage—to a proper disposal site before 

the spring thaw.61

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

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 

 

61In 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. 
 

Page 44 GAO-12-732 Shale Oil and Gas Development

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.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.63

 

62GAO, Storm Water Pollution: Information Needed on the Implications of Permitting Oil 

and Gas Construction Activities, 

As we reported in February 2005, 

sediment clouds water, decreases photosynthetic activity, and destroys 

organisms and their habitat.

GAO-05-240 (Washington, D.C.: Feb. 9, 2005).

63In response, the state required the operator to install silt fences, silt socks, gravel 

surfacing of the access road, and a storm water capture ditch. 
 

Page 45 GAO-12-732 Shale Oil and Gas Development

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.64

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,

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:

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.66

 

64Methane 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. 

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.

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

66Ohio Department of Natural Resources, Report on the Investigation of the Natural Gas 

Invasion of Aquifers in Bainbridge Township of Geauga County, Ohio (September 2008). 
 

Page 46 GAO-12-732 Shale Oil and Gas Development

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, 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.68

 

67Bipartisan Policy Center, Shale Gas: New Opportunities, New Challenges (Washington, 

D.C.: January 2012).

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 

68Some 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. 
 

Page 47 GAO-12-732 Shale Oil and Gas Development

and the loss of hydraulic fracturing fluid.69

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.

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.

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.

 

69George 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).

70Kevin Fisher, Norm Warpinski, Pinnacle—A Haliburton Service, “Hydraulic FractureHeight Growth: Real Data” (presented at the Society of Petroleum Engineers Technical 

Conference and Exhibition, Denver, Colorado, October 2011). 
 

Page 48 GAO-12-732 Shale Oil and Gas Development

Table 4: Shale Formation and Treatable Water Depth

Distance in feet

Shale play Depth to shale

Depth to base of treatable 

water 

Distance between shale and base of 

treatable water 

Barnett 6,500- 8,500 1,200 5,300- 7,300

Fayetteville 1,000- 7,000 500 500- 6,500

Haynesville 10,500- 13,500 400 10,100- 13,100

Marcellus 4,000- 8,500 850 2,125- 7,650

Woodford 6,000- 11,000 400 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.

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.71

• 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 

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.

 

71The Center for Rural Pennsylvania, The Impact of Marcellus Gas Drilling on Rural 

Drinking Water Supplies (Harrisburg, Pennsylvania: October 2011).
 

Page 49 GAO-12-732 Shale Oil and Gas Development

overlie the Marcellus or Utica Shale formations—some from areas 

with shale gas development and some from areas with no shale gas 

development.72

• 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.

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.

73

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.

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.

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 

 

72Stephen 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).

73Ground 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). 
 

Page 50 GAO-12-732 Shale Oil and Gas Development

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,74

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.

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.

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.

 

74According 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. 

Ongoing Studies Related to 

Water Quality 

Land and Wildlife
 

Page 51 GAO-12-732 Shale Oil and Gas Development

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.75 In 

August 2003, we reported that oil and gas infrastructure on federal wildlife 

refuges can reduce the quality of habitat by fragmenting it.76

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.

Fragmentation increases disturbances from human activities, provides 

pathways for predators, and helps spread nonnative plant species.

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.78

 

75Habitat fragmentation occurs when a network of roads and other infrastructure is 

constructed in previously undeveloped areas.

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.

76GAO-03-517. 

77GAO-03-517. 

78James 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). 
 

Page 52 GAO-12-732 Shale Oil and Gas Development

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.

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 processspecific factors, including the location and rate of development; geological 

characteristics, such as permeability, thickness, and porosity of the 

Extent of Risks Is 

Unknown and Depends on 

Many Factors
 

Page 53 GAO-12-732 Shale Oil and Gas Development

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.79

 

79ALL 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).

Specifically, 
 

Page 54 GAO-12-732 Shale Oil and Gas Development

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.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.81

Regulatory and enforcement activities. Potential changes to the federal, 

state, and local regulatory environment will affect operators’ future 

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.

 

80Susan Williams, “Discovering Shale Gas: An Investor Guide to Hydraulic Fracturing,” 

Sustainable Investments Institute and Investor Responsibility Research Center Institute 

(New York, NY: February 2012). 

81United 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).
 

Page 55 GAO-12-732 Shale Oil and Gas Development

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.

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 http://www.gao.gov. 

Agency Comments
 

Page 56 GAO-12-732 Shale Oil and Gas Development

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.

Frank Rusco

Director, Natural Resources and Environment
 

Page 57 GAO-12-732 Shale Oil and Gas Development

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
Appendix I: Scope and Methodology

Page 58 GAO-12-732 Shale Oil and Gas Development

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.

Appendix I: Scope and Methodology
Appendix I: Scope and Methodology

Page 59 GAO-12-732 Shale Oil and Gas Development

To determine what is known about the environmental and public health 

risks associated with the development of shale oil and gas1

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 

, 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. 

 

1

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.
Appendix I: Scope and Methodology

Page 60 GAO-12-732 Shale Oil and Gas Development

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 

app. 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.
Appendix II: List of Agencies and 

Organizations Contacted

Page 61 GAO-12-732 Shale Oil and Gas Development

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

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

Colorado School of Mines

Oklahoma University

Stanford University

University of Texas at Arlington

University of Texas Energy Center and Bureau of Economic Geology

Clean Water Action Pennsylvania

Earthworks Oil and Gas Accountability Project

Environmental Defense Fund 

Subra Consulting

Western Resource Advocates

The Endocrine Disruption Exchange

National Association of County and City Health Officials

Southwest Pennsylvania Environmental Health Project

ALL Consulting

American Exploration and Production Council

American Petroleum Institute

Apache Corporation

Appendix II: List of Agencies and 

Organizations Contacted

Federal Agencies

State Agencies

Academic Institutions

Environmental 

Organizations

Public Health 

Organizations

Industry 
Appendix II: List of Agencies and 

Organizations Contacted

Page 62 GAO-12-732 Shale Oil and Gas Development

Chesapeake Energy

Colorado Oil and Gas Association

Devon Energy

Powell Shale Digest

Ground Water Protection Council

Martin Consulting

Red River Watershed Management Institute

Osage Tribal Nation

Others
Appendix III: Additional Information on USGS 

Estimates

Page 63 GAO-12-732 Shale Oil and Gas Development

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 

Most recent 

assessment year

Northern Alaska 2006

Central Alaska 2004

Southern Alaska 2011

Western Oregon-Wash. 2009

Eastern Oregon-Wash. 2006

Northern Coastal 1995

Sonoma-Livermore 1995

Sacramento Basin 2006

San Joaquin Basin 2004

Central Coastal 1995

Santa Maria Basin 1995

Ventura Basin 1995

Los Angeles Basin 1995

Idaho-Snake River Downwarp 1995

Western Great Basin 1995

Eastern Great Basin 2004

Uinta-Piceance Basin 2002

Paradox Basin 1995

San Juan Basin 2002

Albuquerque-Sante Fe Rift 1995

Northern Arizona 1995

S. Ariz.-S.W. New Mexico 1995

South-Central New Mexico 1995

Montana Thrust Belt 2002

Central Montana 2001

Southwest Montana 1995

Hanna, Laramie, Shirley 2005

Appendix III: Additional Information on 

USGS Estimates
Appendix III: Additional Information on USGS 

Estimates

Page 64 GAO-12-732 Shale Oil and Gas Development

Name of USGS province 

Most recent 

assessment year

Williston Basin (includes Bakken Shale Formation) 2008

Powder River Basin 2006

Big Horn Basin 2008

Wind River Basin 2005

Wyoming Thrust Belt 2004

Southwestern Wyoming 2002

Park Basins 1995

Denver Basin 2003

Las Animas Arch 1995

Raton Basin-Sierra Grande Uplift 2005

Palo Duro Basin 1995

Permian Basin (includes Barnett Shale) 2007

Bend Arch-Ft. Worth Basin 2004

Marathon Thrust Belt 1995

Western Gulf Coast (includes Eagle Ford Shale) 2011

East Texas Basin Province 2011

Louisiana-Mississippi Salt Basins Province 2011

Florida Peninsula 2000

Superior 1995

Cambridge Arch-Central Kansas 1995

Nemaha Uplift 1995

Forest City Basin 1995

Anadarko Basin 2011

Sedgwick Basin/Salina Basin 1995

Cherokee Platform 1995

Southern Oklahoma 1995

Arkoma Basin 2010

Michigan Basin 2005

Illinois Basin 2007

Black Warrior Basin 2002

Cincinnati Arch 1995

Appalachian Basin (includes Marcellus Shale) 2011

Blue Ridge Thrust Belt 1995

Piedmont 1995

Source: USGS.
Appendix IV: GAO Contact and Staff 

Acknowledgments 

Page 65 GAO-12-732 Shale Oil and Gas Development 

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

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. 

Appendix IV: GAO Contact and Staff 

Acknowledgments 

GAO Contact 

Staff 

Acknowledgments 

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