Background

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

		Overview

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

		The Shale Oil and Gas Development Process

The process to develop shale oil and gas is similar to the process for  conventional onshore oil and gas, but shale formations may rely on the  use of horizontal drilling and hydraulic fracturing—which may or may not  be used on conventional wells. Horizontal drilling and hydraulic fracturing  are not new technologies, as seen in figure 1, but advancements,  refinements, and new uses of these technologies have greatly expanded  oil and gas operators’ abilities to use these processes to economically  develop shale oil and gas resources. For example, the use of multistage  hydraulic fracturing within a horizontal well has only been widely used in  the last decade.
First, operators locate suitable shale oil and gas targets using seismic  methods of exploration, negotiate contracts or leases that allow mineral  development, identify a specific location for drilling, and obtain necessary  permits; then, they undertake a number of activities to develop shale oil  and gas. The specific activities and steps taken to extract shale oil and  gas vary based on the characteristics of the formation, but the  development phase generally involves the following stages: (1) well pad  preparation and construction, (2) drilling and well construction, and (3)  hydraulic fracturing.
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.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.
Then operators must transport the equipment that mixes the  The next stage in the development process is drilling and well  construction. Operators drill a hole (referred to as the wellbore) into the  earth through a combination of vertical and horizontal drilling techniques.  At several points in the drilling process, the drill string and bit are  removed from the wellbore so that casing and cement may be inserted.  Casing is a metal pipe that is inserted inside the wellbore to prevent high- pressure fluids outside the formation from entering the well and to prevent  drilling mud inside the well from fracturing fragile sections of the wellbore.  As drilling progresses with depth, casings that are of a smaller diameter  than the hole created by the drill bit are inserted into the wellbore and  bonded in place with cement, sealing the wellbore from the surrounding  formation.
Drilling mud (a lubricant also known as drilling fluid) is pumped through  the wellbore at different densities to balance the pressure inside the  wellbore and bring rock particles and other matter cut from the formation  back to the rig. A blowout preventer is installed over the well as a safety  measure to prevent any uncontrolled release of oil or gas and help  maintain control over pressures in the well. Drill cuttings, which are made  up of ground rock coated with a layer of drilling mud or fluid, are brought  to the surface. Mud pits provide a reservoir for mixing and holding the  drilling mud. At the completion of drilling, the drilling mud may be recycled  for use at another drilling operation.
Instruments guide drilling operators to the “kickoff point”—the point that  drilling starts to turn at a slight angle and continues turning until it nears  the shale formation and extends horizontally. Production casing and  cement are then inserted to extend the length of the borehole to maintain  wellbore integrity and prevent any communication between the formation  fluids and the wellbore. After the casing is set and cemented, the drilling  operator may run a cement evaluation log by lowering an electric probe  into the well to measure the quality and placement of the cement. The  purpose of the cement evaluation log is to confirm that the cement has  the proper strength to function as designed—preventing well fluids from  migrating outside the casing and infiltrating overlying formations. After  vertical drilling is complete, horizontal drilling is conducted by slowly  angling the drill bit until it is drilling horizontally. Horizontal stretches of the  well typically range from 2,000 to 6,000 feet long but can be as long as  12,000 feet long, in some cases.
Throughout the drilling process, operators may vent or flare some natural  gas, often intermittently, in response to maintenance needs or equipment  failures. This natural gas is either released directly into the atmosphere  (vented) or burned (flared). In October 2010, we reported on venting and  flaring of natural gas on public lands. 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.
The next stage in the development process is stimulation of the shale  formation using hydraulic fracturing. Before operators or service  companies perform a hydraulic fracture treatment of a well, a series of  tests may be conducted to ensure that the well, wellhead equipment, and  fracturing equipment can safely withstand the high pressures associated  with the fracturing process. Minimum requirements for equipment  pressure testing can be determined by state regulatory agencies for  operations on state or private lands. In addition, fracturing is conducted  below the surface of the earth, sometimes several thousand feet below,  and can only be indirectly observed. Therefore, operators may collect   and natural fault  subsurface data—such as information on rock stressesstructures—needed to develop models that predict fracture height, length,  and orientation prior to drilling a well. The purpose of modeling is to  design a fracturing treatment that optimizes the location and size of  induced fractures and maximizes oil or gas production.
To prepare a well to be hydraulically fractured, a perforating tool may be  inserted into the casing and used to create holes in the casing and  cement. Through these holes, fracturing fluid—that is injected under high  pressures—can flow into the shale (fig. 2 shows a used 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.
The operator pumps the fracturing fluid into the wellbore at pressures  high enough to force the fluid through the perforations into the  surrounding formation—which can be shale, coalbeds, or tight  sandstone—expanding existing fractures and creating new ones in the  process. After the fractures are created, the operator reduces the  pressure. The proppant stays in the formation to hold open the fractures  and allow the release of oil and gas. Some of the fracturing fluid that was  injected into the well will return to the surface (commonly referred to as  flowback) along with water that occurs naturally in the oil- or gas-bearing  formation—collectively referred to as produced water. The produced  water is brought to the surface and collected by the operator, where it can  be stored on-site in impoundments, injected into underground wells,  transported to a wastewater treatment plant, or reused by the operator in  other ways. Given the length of horizontal wells, hydraulic fracturing is  often conducted in stages, where each stage focuses on a limited linear  section and may be repeated numerous times.
Once a well is producing oil or natural gas, equipment and temporary  infrastructure associated with drilling and hydraulic fracturing operations  is no longer needed and may be removed, leaving only the parts of the  infrastructure required to collect and process the oil or gas and ongoing  produced water. Operators may begin to reclaim the part of the site that  will not be used by restoring the area to predevelopment conditions.  Throughout the producing life of an oil or gas well, the operator may find it  necessary to periodically restimulate the flow of oil or gas by repeating  the hydraulic fracturing process. The frequency of such activity depends  on the characteristics of the geologic formation and the economics of the  individual well. If the hydraulic fracturing process is repeated, the site and  surrounding area will be further affected by the required infrastructure,  truck transport, and other activity associated with this process.

		Regulatory Framework

Shale oil and gas development, like conventional onshore oil and gas  production, is governed by a framework of federal, state, and local laws  and regulations. Most shale development in the near future is expected to  occur on nonfederal lands and, therefore, states will typically take the  lead in regulatory activities. However, in some cases, federal agencies  oversee shale oil and gas development. For example, BLM oversees  shale oil and gas development on federal lands. In large part, the federal  laws, regulations, and permit requirements that apply to conventional  onshore oil and gas exploration and production activities also apply to  shale oil and gas development.
Federal. A number of federal agencies administer laws and  regulations that apply to various phases of shale oil and gas  development. For example, BLM manages federal lands and  approximately 700 million acres of federal subsurface minerals, also  known as the federal mineral estate. EPA administers and enforces  key federal laws, such as the Safe Drinking Water Act, to protect  human health and the environment. Other federal land management  agencies, such as the U.S. Department of Agriculture’s Forest Service  and the Department of the Interior’s Fish and Wildlife Service, also  manage federal lands, including shale oil and gas development on  those lands.
State. State agencies implement and enforce many of the federal  environmental regulations and may also have their own set of state  laws covering shale oil and gas development.
Other. Additional requirements regarding shale oil and gas operations  may be imposed by various levels of government for specific  locations. Entities such as cities, counties, tribes, and regional water  authorities may set additional requirements that affect the location and  operation of wells.
GAO is conducting a separate and more detailed review of the federal  and state laws and regulations that apply to unconventional oil and gas  development, including shale oil and gas.

		Location of Shale Oil and Gas in the United States

Shale oil and gas are found in shale plays—a set of discovered or  undiscovered oil and natural gas accumulations or prospects that exhibit  similar geological characteristics—on private, state-owned, and federal  lands across the United States. Shale plays are located within basins,  which are large-scale geological depressions, often hundreds of miles  across, that also may contain other oil and gas resources. Figure 4 shows  the location of shale plays and basins in the contiguous 48 states.
A shale play can be developed for oil, natural gas, or both. In addition, a  shale gas play may contain “dry” or “wet” natural gas. Dry natural gas is a  mixture of hydrocarbon compounds that exists as a gas both underground  in the reservoir and during production under standard temperature and  pressure conditions. Wet natural gas contains natural gas liquids, or the  portion of the hydrocarbon resource that exists as a gas when in natural  underground reservoir conditions but that is liquid at surface conditions.  The natural gas liquids are typically propane, butane, and ethane and are  separated from the produced gas at the surface in lease separators, field  facilities, or gas processing plants. Operators may then sell the natural  gas liquids, which may give wet shale gas plays an economic advantage  over dry gas plays. Another advantage of liquid petroleum and natural  gas liquids is that they can be transported more easily than natural gas.  This is because, to bring natural gas to markets and consumers,  companies must build an extensive network of gas pipelines. In areas  where gas pipelines are not extensive, natural gas produced along with  liquids is often vented or flared.

		Estimating the Size of Shale Oil and Gas Resources

Estimating the size of shale oil and gas resources serves a variety of  needs for consumers, policymakers, land and resource managers,  investors, regulators, industry planners, and others. For example, federal  and state governments may use resource estimates to estimate future  revenues and establish energy, fiscal, and national security policies. The  petroleum industry and the financial community use resource estimates to  establish corporate strategies and make investment decisions.
A clear understanding of some common terms used to generally describe  the size and scope of oil and gas resources is needed to determine the  relevance of a given estimate. For an illustration of how such terms  describe the size and scope of shale oil and gas, see figure 5.
The most inclusive term is in-place resource. The in-place resource  represents all oil or natural gas contained in a formation without regard to  technical or economic recoverability. In-place resource estimates are  sometimes very large numbers, but often only a small proportion of the  total amount of oil or natural gas in a formation may ever be recovered.  Oil and gas resources that are in-place, but not technically recoverable at  this time may, in the future, become technically recoverable.
Technically recoverable resources are a subset of in-place resources that  include oil or gas, including shale oil and gas that is producible given  available technology. Technically recoverable resources include those  that are economically producible and those that are not. Estimates of  technically recoverable resources are dynamic, changing to reflect the  potential of extraction technology and knowledge about the geology and  composition of geologic formations. According to the National Petroleum  Council, technically recoverable resource estimates usually increase  over time because of the availability of more and better data, or  knowledge of how to develop a new play type (such as shale formations).
Proved reserve estimates are more precise than technically recoverable  resources and represent the amount of oil and gas that have been  discovered and defined, typically by drilling wells or other exploratory  measures, and which can be economically recovered within a relatively  short time frame. Proved reserves may be thought of as the “inventory”  that operators hold and define the quantity of oil and gas that operators  estimate can be recovered under current economic conditions, operating  methods, and government regulations. Estimates of proved reserves  increase as oil and gas companies make new discoveries and report  them to the government; oil and gas companies can increase their  reserves as they develop already-discovered fields and improve  production technology. Reserves decline as oil and gas reserves are  produced and sold. In addition, reserves can change as prices and  technologies change. For example, technology improvements that enable  operators to extract more oil or gas from existing fields can increase  proved reserves. Likewise, higher prices for oil and gas may increase the  amount of proved reserves because more resources become financially   Conversely, lower prices may diminish the amount of  viable to extract.resources likely to be produced, reducing proved reserves.
Historical production refers to the total amount of oil and gas that has  been produced up to the present. Because these volumes of oil and gas  have been measured historically, this is the most precise information  available as it represents actual production amounts.
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.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   USGS has  the location and size of different geological formations across the United  States. In addition to EIA and USGS, experts from industry, academia,  federal advisory committees, private consulting firms, and professional  societies also estimate the size of the resource.

	Domestic Shale Oil and Gas Estimates and Production

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

		Estimates of Technically Recoverable Shale Oil and Gas Resources

EIA, USGS, and the Potential Gas Committee have increased their  estimates of the amount of technically recoverable shale oil and gas over  the last 5 years, which could mean an increase in the nation’s energy  portfolio; however, less is known about the amount of technically  recoverable shale oil than shale gas, in part because large-scale  production of shale oil has been under way for only the past few years.  The estimates are from different organizations and vary somewhat  because they were developed at different times and using different data,  methods, and assumptions, but estimates from all of these organizations  have increased over time, indicating that the nation’s shale oil and gas  resources may be substantial. For example, according to estimates and  reports we reviewed, assuming current consumption levels without  consideration of a specific market price for future gas supplies, the  amount of domestic technically recoverable shale gas could provide  enough natural gas to supply the nation for the next 14 to 100 years. The  increases in estimates can largely be attributed to improved geological  information about the resources, greater understanding of production  levels, and technological advancements.
In the last 2 years, EIA and USGS provided estimates of technically  recoverable shale oil.as follows:   Each of these estimates increased in recent years  In 2012, EIA estimated that the United States possesses 33 billion   mostly located in four barrels of technically recoverable shale oil, shale formations—the Bakken in Montana and North Dakota; Eagle  Ford in Texas; Niobrara in Colorado, Kansas, Nebraska, and  Wyoming; and the Monterey in California.
In 2011, USGS estimated that the United States possesses just over  7 billion barrels of technically recoverable oil in shale and tight  sandstone formations. The estimate represents a more than threefold  increase from the agency’s estimate in 2006. However, there are  several shale plays that USGS has not evaluated for shale oil  because interest in these plays is relatively new. According to USGS  officials, these shale plays have shown potential for production in  recent years and may contain additional shale oil resources. Table 1  shows USGS’ 2006 and 2011 estimates and EIA’s 2011 and 2012  estimates.
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.increase of 280 percent from EIA’s 2008 estimate.
In 2011, USGS reported that the total of its estimates for the shale  formations the agency evaluated in all previous years  shows the amount of technically recoverable shale gas in the United States at  about 336 trillion cubic feet. This represents an increase of about 600  percent from the agency’s 2006 estimate.
In 2011, the Potential Gas Committee estimated the amount of  technically recoverable shale gas in the United States at about 687  trillion cubic feet. This represents an increase of 240 percent from  the committee’s 2007 estimate.
In addition to the estimates from the three organizations we reviewed,  operators and energy forecasting consultants prepare their own estimates  of technically recoverable shale gas to plan operations or for future  investment. In September 2011, the National Petroleum Council  aggregated data on shale gas resources from over 130 industry,  government, and academic groups and estimated that approximately  1,000 trillion cubic feet of shale gas is available for production  domestically. In addition, private firms that supply information to the oil  and gas industry conduct assessments of the total amount of technically  recoverable natural gas. For example, ICF International, a consulting firm  that provides information to public- and private-sector clients, estimated in  March 2012 that the United States possesses about 1,960 trillion cubic  feet of technically recoverable shale gas.
Based on estimates from EIA, USGS, and the Potential Gas Committee,  five shale plays—the Barnett, Haynesville, Fayetteville, Marcellus, and  Woodford—are estimated to possess about two-thirds of the total  estimated technically recoverable gas in the United States (see table 2).
The Sustainable Investments Institute (Si2) is a nonprofit membership organization  founded in 2010 to conduct research and publish reports on organized efforts to influence  corporate behavior. The Investor Responsibility Research Center Institute is a nonprofit  organization established in 2006 that provides information to investors. then level off, continuing to produce gas for decades, according to the  Sustainable Investments Institute and the Investor Responsibility  Research Center Institute.

		Estimates of Proved Reserves of Shale Oil and Gas

Estimates of proved reserves of shale oil and gas increased from 2007 to  2009. Operators determine the size of proved reserves based on  information collected from drilling, geological and geophysical tests, and  historical production trends. These are also the resources operators  believe they will develop in the short term—generally within the next 5  years—and assume technological and economic conditions will remain  unchanged.
Estimates of proved reserves of shale oil. EIA does not report proved  reserves of shale oil separately from other oil reserves; however, EIA and  others have noted an increase in the proved reserves of oil in the nation,  and federal officials attribute the increase, in part, to oil from shale and  tight sandstone formations. For example, EIA reported in 2009 that the  Bakken Shale in North Dakota and Montana drove increases in oil  reserves, noting that North Dakota proved reserves increased over 80  percent from 2008 through 2009.
Estimates of proved reserves of shale gas. According to data EIA collects  from about 1,200 operators, proved reserves of shale gas have grown  from 23 trillion cubic feet in 2007 to 61 trillion cubic feet in 2009, or an   More than 75 percent of the proved shale gas  increase of 160 percent.reserves are located in three shale plays—the Barnett, Fayetteville, and  the Haynesville.

		Shale Oil and Gas Production

From 2007 through 2011, annual production of shale oil and gas has  experienced significant growth. Specifically, shale oil production  increased more than fivefold, from 39 to about 217 million barrels over  this 5-year period, and shale gas production increased approximately  fourfold, from 1.6 to about 7.2 trillion cubic feet, over the same period. To  put this shale production into context, the annual domestic consumption  of oil in 2011 was about 6,875 million barrels of oil, and the annual  consumption of natural gas was about 24 trillion cubic feet. The increased  shale oil and gas production was driven primarily by technological  advances in horizontal drilling and hydraulic fracturing that made more  shale oil and gas development economically viable.
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). 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.
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). 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.
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).
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  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.
The growth in production of shale gas has increased the overall supply of  natural gas in the U.S. energy market. Since 2007, increased shale gas  production has contributed to lower prices for consumers, according to  EIA and others. These lower prices create incentives for wider use of  natural gas in other industries. For example, several reports by  government, industry, and others have observed that if natural gas prices  remain low, natural gas is more likely to be used to power cars and trucks  in the future. In addition, electric utilities may build additional natural gas- fired generating plants as older coal plants are retired. At the same time,  some groups have expressed concern that greater reliance on natural  gas may reduce interest in developing renewable energy.
The greater availability of domestic shale gas has also decreased the  need for natural gas imports. For example, EIA has noted that volumes of  natural gas imported into the United States have fallen in recent years—in  2007, the nation imported 16 percent of the natural gas consumed and in  2010, the nation imported 11 percent—as domestic shale gas production  has increased. This trend is also illustrated by an increase in applications  for exporting liquefied natural gas to other countries. In its 2012 annual  energy outlook, EIA predicted that, under certain scenarios, the United  States will become a net exporter of natural gas by about 2022.

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

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

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

Oil and gas development, which includes development from shale  formations, poses inherent risks to air quality, water quantity, water  quality, and land and wildlife.
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. 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. 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.
The researcher expects to publish the results of research on public health  risks from proppant later in 2012.
Use of diesel engines to supply power to drilling sites also degrades air  quality. Shale oil and gas drilling rigs require substantial power to drill and  case wellbores to the depths of shale formations. This power is typically  provided by transportable diesel engines, which generate exhaust from  the burning of diesel fuel. After the wellbore is drilled to the target  formation, additional power is needed to operate the pumps that move  large quantities of water, sand, or chemicals into the target formation at  high pressure to hydraulically fracture the shale—generating additional  exhaust. In addition, other equipment used during operations—including  pneumatic valves and dehydrators—contribute to air emissions. For  example, natural gas powers switches that turn valves on and off in the  production system. Each time a valve turns on or off, it “bleeds” a small  amount of gas into the air. Some of these pneumatic valves vent gas  continuously. A dehydrator circulates the chemical glycol to absorb  moisture in the gas but also absorbs small volumes of gas. The absorbed  gas vents to the atmosphere when the water vapor is released from the  glycol.
Methane and other chemical compounds found in the earth’s atmosphere create a  greenhouse effect. Under normal conditions, when sunlight strikes the earth’s surface,  some of it is reflected back toward space as infrared radiation or heat. Greenhouse gases  such as carbon dioxide and methane impede this reflection by trapping heat in the  atmosphere. While these gases occur naturally on earth and are emitted into the  atmosphere, the expanded industrialization of the world over the last 150 years has  increased the amount of emissions from human activity (known as anthropogenic  emissions) beyond the level that the earth’s natural processes can handle. 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.
The studies and publications we reviewed provide information on air  quality conditions at a specific site at a specific time but do not provide  the information needed to determine the overall cumulative effect that  shale oil and gas activities have on air quality.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.
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. 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.
According to a 2012 University of Texas study, 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.  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. Further,  groundwater withdrawal could affect the amount of water available for  other uses, including public and private water supplies.
Freshwater is a limited resource in some arid and semiarid regions of the  country where an expanding population is placing additional demands on  water. The potential demand for water is further complicated by years of  drought in some parts of the country and projections of a warming  climate. According to a 2011 Massachusetts Institute of Technology  study, the amount of water used for shale gas development is small in comparison to other water uses, such as agriculture and other industrial  purposes. However, the cumulative effects of using surface water or  groundwater at multiple oil and gas development sites can be significant  at the local level, particularly in areas experiencing drought conditions.
Similar to shale oil and gas development, development of gas from  coalbed methane formations poses a risk of aquifer depletion. To develop  natural gas from such formations, water from the coal bed is withdrawn to  lower the reservoir pressure and allow the methane to desorb from the  coal. According to a 2001 USGS report, dewatering coalbed methane  formations in the Powder River Basin in Wyoming can lower the  groundwater table and reduce water available for other uses, such as  livestock and irrigation.
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.
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.
Naturally occurring radioactive materials (NORM) are present at varying degrees in  virtually all environmental media, including rocks and soils. According to a DOE report,  human exposure to radiation comes from a variety of sources, including naturally  occurring radiation from space, medical sources, consumer products, and industrial  sources. Normal disturbances of NORM-bearing rock formations by activities such as  drilling do not generally pose a threat to workers, the general public or the environment,  according to studies and publications we reviewed. 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.
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. 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, but is not limited to  salts, which include chlorides, bromides, and sulfides of calcium,  magnesium, and sodium; metals, which include barium, manganese, iron, and strontium, among oil, grease, and dissolved organics, which include benzene and  toluene, among others; 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.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.
The composition of pit lining depends on regulatory requirements, which vary from state  to state. were to be used for temporary storage—to a proper disposal site before  the spring thaw.
Unlike shale oil and gas formations, water permeates coalbed methane  formations, and its pressure traps natural gas within the coal. To produce  natural gas from coalbed methane formations, water must be extracted to  lower the pressure in the formation so the natural gas can flow out of the  coal and to the wellbore. In 2000, USGS reported that water extracted  from coalbed methane formations is commonly saline and, if not treated  and disposed of properly, could adversely affect streams and threaten  fish and aquatic resources.
According to several reports, handling and transporting toxic fluids or  contaminants poses a risk of environmental contamination for all  industries, not just oil and gas development; however, the large volume of  fluids and contaminants—fracturing fluid, drill cuttings, and produced  water—that is associated with the development of shale oil and gas  poses an increased risk for a release to the environment and the potential  for greater effects should a release occur in areas that might not  otherwise be exposed to these chemicals.
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. 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.sediment clouds water, decreases photosynthetic activity, and destroys  organisms and their habitat.
As we reported in February 2005,  According to a number of studies and publications we reviewed,  underground migration of gases and chemicals poses a risk of  contamination to water quality. Underground migration can occur as a  result of improper casing and cementing of the wellbore as well as the  intersection of induced fractures with natural fractures, faults, or  improperly plugged dry or abandoned wells. Moreover, there are  concerns that induced fractures can grow over time and intersect with  drinking water aquifers. Specifically:  Improper casing and cementing. A well that is not properly isolated  through proper casing and cementing could allow gas or other fluids to  contaminate aquifers as a result of inadequate depth of casing, 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.  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.
The depth for casing and cementing may be determined by state regulations.
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,  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   Fractures created during the hydraulic fracturing  than 1,000 feet deep.process are generally unable to span the distance between the targeted  shale formation and freshwater bearing zones. According to a 2011  industry report, fracture growth is stopped by natural subsurface barriers  and the loss of hydraulic fracturing fluid.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.
When a fracture grows, it  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. 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.
Kevin Fisher, Norm Warpinski, Pinnacle—A Haliburton Service, “Hydraulic Fracture- Height Growth: Real Data” (presented at the Society of Petroleum Engineers Technical  Conference and Exhibition, Denver, Colorado, October 2011).
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. The analysis compared  predrilling samples to postdrilling samples to identify any changes to  water quality. The analysis showed that there were no statistically  significant increases in pollutants prominent in drilling waste fluids— such as total dissolved solids, chloride, sodium, sulfate, barium, and  strontium—and no statistically significant increases in methane. The  study concluded that gas well drilling had not had a significant effect  on the water quality of nearby drinking water wells.
In 2011, researchers from Duke University studied shale gas drilling  and hydraulic fracturing and the potential effects on shallow  groundwater systems near the Marcellus Shale in Pennsylvania and  the Utica Shale in New York. Sixty drinking water samples were  collected in Pennsylvania and New York from bedrock aquifers that  overlie the Marcellus or Utica Shale formations—some from areas  with shale gas development and some from areas with no shale gas  development. The study found that methane concentrations were  detected generally in 51 drinking water wells across the region— regardless of whether shale gas drilling occurred in the area—but that  concentrations of methane were substantially higher closer to shale  gas wells. However, the researchers reported that a source of the  contamination could not be determined. Further, the researchers  reported that they found no evidence of fracturing fluid in any of the  samples.
In 2011, the Ground Water Protection Council evaluated state agency  groundwater investigation findings in Texas and categorized the  determinations regarding causes of groundwater contamination  resulting from the oil and gas industry. During the study period— from 1993 through 2008—multistaged hydraulic fracturing stimulations  were performed in over 16,000 horizontal shale gas wells. The  evaluation of the state investigations found that there were no  incidents of groundwater contamination caused by hydraulic  fracturing.
In addition, regulatory officials we met with from eight states—Arkansas,  Colorado, Louisiana, North Dakota, Ohio, Oklahoma, Pennsylvania, and  Texas—told us that, based on state investigations, the hydraulic  fracturing process has not been identified as a cause of groundwater  contamination within their states.
A number of studies discuss the potential contamination of water from the  hydraulic fracturing process in shale formations. However, according to  several studies we reviewed, there are insufficient data for  predevelopment (or baseline) conditions for groundwater. Without data to  compare predrilling conditions to postdrilling conditions, it is difficult to  determine if adverse effects were the result of oil and gas development,  natural occurrences, or other activities. In addition, while researchers  have evaluated fracture growth, the widespread development of shale oil  and gas is relatively new. As such, little data exist on (1) fracture growth  in shale formations following multistage hydraulic fracturing over an  extended time period, (2) the frequency with which refracturing of  horizontal wells may occur, (3) the effect of refracturing on fracture growth  over time, and (4) the likelihood of adverse effects on drinking water  aquifers from a large number of hydraulically fractured wells in close  proximity to each other.
Ongoing studies 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.
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.
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. In  August 2003, we reported that oil and gas infrastructure on federal wildlife  refuges can reduce the quality of habitat by fragmenting it.Fragmentation increases disturbances from human activities, provides  pathways for predators, and helps spread nonnative plant species.
In addition, spills of oil, gas, or other toxic chemicals have harmed wildlife  and habitat. Oil and gas can injure or kill wildlife by destroying the  insulating capacity of feathers and fur, depleting oxygen available in  water, or exposing wildlife to toxic substances. Long-term effects of oil  and gas contamination on wildlife are difficult to determine, but studies  suggest that effects of exposure include reduced fertility, kidney and liver  damage, immune suppression, and cancer. In August 2003, we reported  that even small spills may contaminate soil and sediments if they occur  frequently. 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. The  results of the study found that the chickens were not adversely affected  by the diesel engine generator’s noise but that the presence of the rig  caused the animals to temporarily disperse and avoid the area.
A number of studies we reviewed identified risks to habitat and wildlife as  a result of shale oil and gas activities. However, because shale oil and  gas development is relatively new in some areas, the long-term effects— after operators are to have restored portions of the land to  predevelopment conditions—have not been evaluated. Without these  data, the cumulative effects of shale oil and gas development on habitat  and wildlife are largely unknown.
According to several studies and publications we reviewed, the hydraulic  fracturing process releases energy deep beneath the surface to break  rock but the energy released is not large enough to trigger a seismic  event that could be felt on the surface. However, a process commonly  used by operators to dispose of waste fluids—underground injection—has  been associated with earthquakes in some locations. For example, a  2011 Oklahoma Geological Survey study reported that underground  injection can induce seismicity. In March 2012, the Ohio Department of  Natural Resources reported that “there is a compelling argument” that the  injection of produced water into underground injection wells was the  cause of the 2011 earthquakes near Youngstown, Ohio. In addition, the  National Academy of Sciences released a study in June 2012 that  concluded that underground injection of wastes poses some risk for  induced seismicity, but that very few events have been documented over  the past several decades relative to the large number of disposal wells in  operation.
The available research does not identify a direct link between hydraulic  fracturing and increased seismicity, but there could be an indirect effect to  the extent that increased use of hydraulic fracturing produces increased  amounts of water that is disposed of through underground injection. In  addition, according to the National Academy of Science’s 2012 report,  accurately predicting magnitude or occurrence of seismic events is  generally not possible, in part, because of a lack of comprehensive data  on the complex natural rock systems at energy development sites.

		Extent of Risks Is Unknown and Depends on Many Factors

The extent and severity of environmental and public health risks identified  in the studies and publications we reviewed may vary significantly across  shale basins and also within basins because of location- and process- specific factors, including the location and rate of development; geological  characteristics, such as permeability, thickness, and porosity of the  formations in the basin; climatic conditions; business practices; and  regulatory and enforcement activities.
Location and rate of development. The location of oil and gas operations  and the rate of development can affect the extent and severity of  environmental and public health risks. For example, as we reported in  October 2010, while much of the natural gas that is vented and flared is  considered to be unavoidably lost, certain technologies and practices can  be applied throughout the production process to capture some of this gas,  according to the oil and gas industry and EPA. The technologies’  technical and economic feasibility varies and sometimes depends on the  location of operations. For example, some technologies require a  substantial amount of electricity, which may be less feasible for remote  production sites that are not on the electrical grid. In addition, the extent  and severity of environmental risks may vary based on the location of oil  and gas wells. For example, in areas with high population density that are  already experiencing challenges adhering to federal air quality limits,  increases in ozone levels because of emissions from oil and gas  development may compound the problem.
Geological characteristics. Geological characteristics can affect the extent  and severity of environmental and public health risks associated with  shale oil and gas development. For example, geological differences  between tight sandstone and shale formations are important because,  unlike shale, tight sandstone has enough permeability to transmit  groundwater to water wells in the region. In a sense, the tight sandstone  formation acts as a reservoir for both natural gas and for groundwater. In  contrast, shale formations are typically not permeable enough to transmit  water and are not reservoirs for groundwater. According to EPA officials,  hydraulic fracturing in a tight sandstone formation that is a reservoir for  both natural gas and groundwater poses a greater risk of contamination  than the same activity in a deep shale formation.
Climatic conditions. Climatic factors, such as annual rainfall and surface  temperatures, can also affect the environmental risks for a specific region  or area. For example, according to a 2007 study funded by DOE, average  rainfall amounts can be directly related to soil erosion. Specifically,  areas with higher precipitation levels may be more susceptible to soil  compaction and rutting during the well pad construction phase. In another  example, risk of adverse effects from exposures to toxic air contaminants  can vary substantially between drilling sites, in part, because of the  specific mix of emissions and climatic conditions that affect the transport  and dispersion of emissions. Specifically, wind speed and direction,  temperature, as well as other climatic conditions, can influence exposure  levels of toxic air contaminants. For example, according to a 2012 study  from the Sustainable Investments Institute and the Investor Responsibility  Research Center Institute, the combination of air emissions from gas  operations, snow on the ground, bright sunshine, and temperature  inversions during winter months have contributed to ozone creation in  Sublette County, Wyoming.
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. 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.
United States Department of the Interior and United States Department of Agriculture.  Surface Operating Standards and Guidelines for Oil and Gas Exploration and  Development. BLM/WO/ST-06/021+3071/REV 07 (Denver, CO: 2007). activities and can therefore affect the risks or level of risks associated  with shale oil and gas development. Shale oil and gas development is  regulated by multiple levels of government—including federal, state, and  local. Many of the laws and regulations applicable to shale oil and gas  development were put in place before the increase in operations that has  occurred in the last few years, and various levels of government are  evaluating and, in some cases, revising laws and regulations to respond  to the increase in shale oil and gas development. For example, in April  2012, EPA promulgated New Source Performance Standards for the oil  and gas industry that, when fully phased-in by 2015, will require  emissions reductions at new or modified oil and gas well sites, including  wells using hydraulic fracturing. Specifically, these new standards, in part,  focus on reducing the venting of natural gas and volatile organic  compounds during the flowback process. In addition, areas without prior  experience with oil and gas development are just now developing new  regulations. These governments’ effectiveness in implementing and  enforcing this framework will affect future activities and the level of  associated risk.

	Agency Comments

We provided a draft of this report to the Department of Energy, the  Department of the Interior, and the Environmental Protection Agency for  review and comment. We received technical comments from Interior’s  Assistant Secretary, Policy, Management, and Budget, and from  Environmental Protection Agency officials, which we have incorporated as  appropriate. In an e-mail received August 27, 2012, the Department of  Energy liaison stated the agency had no comments on the report.
As agreed with your offices, unless you publicly announce the contents of  this report earlier, we plan no further distribution until 30 days from the  report date. At that time, we will send copies of this report to the  appropriate congressional committees, the Secretary of Energy, the  Secretary of the Interior, the EPA Administrator, and other interested  parties. In addition, the report will be available at no charge on the GAO  website at http://www.gao.gov.
If you or your staff members have any questions about this report, please  contact me at (202) 512-3841 or ruscof@gao.gov. Contact points for our  Offices of Congressional Relations and Public Affairs may be found on  the last page of this report. GAO staff who made key contributions to this  report are listed in appendix IV.

Appendix I: Scope and Methodology

Our objectives for this review were to determine what is known about (1)  the size of shale oil and gas resources in the United States and the  amount produced from 2007 through 2011—the years for which data  were available—and (2) the environmental and public health risks  associated with development of shale oil and gas.
To determine what is known about the size of shale oil and gas  resources, we collected data from federal agencies, state agencies,  private industry, and academic organizations. Specifically, to determine  what is known about the size of these resources, we obtained information  for technically recoverable and proved reserves estimates for shale oil  and gas from the Energy Information Administration (EIA), the U.S.  Geological Survey (USGS), and the Potential Gas Committee––a  nongovernmental organization composed of academic and industry  officials. We interviewed key officials about the assumptions and  methodologies used to estimate the resource size. Estimates of proved  reserves of shale oil and gas are based on data provided to EIA by  operators. In addition to the estimates provided by these three  organizations, we also obtained and presented technically recoverable  shale oil and gas estimates from two private organizations—IHS Inc., and  ICF International—and one national advisory committee representing the  views of the oil and gas industry and other stakeholders—the National  Petroleum Council. For all estimates we report, we conducted a review of  the methodologies used in these estimates for fatal flaws; we did not find  any fatal flaws in these methodologies.
To determine what is known about the amount of produced shale oil and  gas from 2007 through 2011, we obtained data from EIA—the federal  agency responsible for estimating and reporting this and other energy  information. EIA officials provided us with estimated oil and gas  production data, including data estimating shale oil and gas estimates  from states and two private firms—HPDI, LLC and Lippman Consulting,  Inc. To assess the reliability of these data, we examined EIA’s published  methodology for collecting this information and interviewed key EIA  officials regarding the agency’s data collection and validation efforts. We  also interviewed officials from three state agencies, representatives from  five private companies, and researchers from three academic institutions  who are familiar with these data and EIA’s methodology and discussed  the sources and reliability of the data. We determined that these data  were sufficiently reliable for the purposes of this report.
To determine what is known about the environmental and public health  risks associated with the development of shale oil and gas, we identified  and reviewed more than 90 studies and other publications from federal  agencies and laboratories, state agencies, local governments, the  petroleum industry, academic institutions, environmental and public  health groups, and other nongovernmental associations. The studies and  publications we reviewed included scientific and industry periodicals,  government-sponsored research, reports or other publications from  nongovernmental organizations, and presentation materials. We identified  these studies by conducting a literature search and by asking for  recommendations during our interviews with stakeholders. For a number  of studies, we interviewed the author or authors to discuss the study’s  findings and limitations, if any. We believe we have identified the key  studies through our literature review and interviews, and that the studies  included in our review have accurately identified potential risks for shale  oil and gas development. However, given our methodology, it is possible  that we may not have identified all of the studies with findings relevant to  our objectives, and the risks we present may not be the only issues of  concern. The widespread use of horizontal drilling and hydraulic fracturing  to develop shale oil and gas is relatively new. Studying the effects of an  activity and completing a formal peer-review process can take numerous  months or years. Because of the relative short time frame for operations  and the lengthy time frame for studying effects, we did not limit the review  to peer-reviewed publications.
The risks identified in the studies and publications we reviewed cannot, at  present, be quantified, and the magnitude of potential adverse affects or  likelihood of occurrence cannot be determined for several reasons. First,  it is difficult to predict how many or where shale oil and gas drilling  operations may be constructed. Second, operators’ use of effective best  practices to mitigate risk may vary. Third, based on the studies we  reviewed, there are relatively few that are based on evaluating  predevelopment conditions to postdevelopment conditions—making it  difficult to detect or attribute adverse changes to shale oil and gas  development. In addition, changes to the federal, state, and local  regulatory environment and the effectiveness in implementation and  enforcement will affect operators’ future activities. Moreover, risks of  adverse events, such as spills or accidents, may vary according to  business practices, which in turn, may vary across oil and gas companies  making it difficult to distinguish between risks that are inherent to the  development of shale oil and gas from risks that are specific to particular  business practices.
To obtain additional perspectives on issues related to environmental and  public health risks, we interviewed a nonprobability sample of  stakeholders representing numerous agencies and organizations. (See  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

	Federal Agencies

	State Agencies

	Academic Institutions

	Environmental Organizations

	Public Health Organizations

	Industry

	Others

Appendix III: Additional Information on USGS Estimates

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

Appendix IV: GAO Contact and Staff Acknowledgments

	GAO Contact

	Staff Acknowledgments

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

Summary:
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. 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.