An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

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An Overview of Unconventional Oil and

Natural Gas: Resources and Federal Actions

-name redactedSpecialist in Energy Policy

-name redactedSpecialist in Environmental Policy

April 22, 2015

Congressional Research Service

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www.crs.gov

R43148

An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Summary

The United States has seen resurgence in petroleum production, mainly driven by technology

improvements—especially hydraulic fracturing and directional drilling—developed for natural

gas production from shale formations. Application of these technologies enabled natural gas to be

economically produced from shale and other unconventional formations and contributed to the

United States becoming the world’s largest natural gas producer in 2009. Use of these

technologies has also contributed to the rise in U.S. oil production over the last few years. In

2009, annual oil production increased over 2008, the first annual rise since 1991, and has

continued to increase each year since. Between January 2008 and May 2014, U.S. monthly crude

oil production rose by 3.2 million barrels per day, with about 85% of the increase coming from

shale and related tight oil formations in Texas and North Dakota. Other tight oil plays are also

being developed, helping raise the prospect of energy independence, especially for North

America.

The rapid expansion of tight oil and shale gas extraction using high-volume hydraulic fracturing

has raised concerns about its potential environmental and health impacts. These concerns include

potential direct impacts to groundwater and surface water quality, water supplies, and air quality.

In addition, some have raised concerns about potential long-term and indirect impacts from

reliance on fossil fuels and resulting greenhouse gas emissions and influence on broader energy

economics. This report focuses mainly on actions related to controlling potential direct impacts.

States are the primary regulators of oil and gas production on non-federal lands. In recent years,

many oil and gas producing states have revised laws and regulations governing oil and gas

production in response to changes in production practices as producers have expanded into tight

oil, shale gas, and other unconventional hydrocarbon formations. However, state rules vary

considerably, leading to calls for more federal oversight of unconventional oil and gas extraction

activities and hydraulic fracturing specifically.

Provisions of several federal environmental laws can apply to certain activities related to oil and

gas production, and proposals to expand federal regulation in this area have been highly

controversial. Some advocates of a larger federal role point to a wide range of differences among

state regulatory regimes and argue that a national framework is needed to ensure a consistent

minimum level of protection for surface and groundwater resources and air quality. Others argue

against more federal involvement and point to the long-established state oil and natural gas

regulatory programs, regional differences in geology and water resources, and concern over

regulatory redundancy.

The federal role in regulating oil and gas extraction activities—and hydraulic fracturing, in

particular—has been the subject of considerable debate and legislative proposals for several

years, but legislation has not been enacted. While congressional debate has continued, the

Administration has pursued a number of regulatory initiatives related to unconventional oil and

gas development under existing statutory authorities.

This report focuses on the growth in U.S. oil and natural gas production driven primarily by tight

oil formations and shale gas formations. It also reviews selected federal environmental regulatory

and research initiatives related to unconventional oil and gas extraction, including the Bureau of

Land Management (BLM) hydraulic fracturing rule (finalized in March 2015) and Environmental

Protection Agency (EPA) actions.

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Contents

Introduction: Change Is Afoot ......................................................................................................... 1

Geology Is What Makes a Resource Unconventional ..................................................................... 2

Price Drives Industrial Innovation ................................................................................................... 2

Technologies Stimulate Shale Gas Production First ........................................................................ 3

Natural Gas Liquids: A Production Driver ................................................................................ 4

Increased Tight Oil Production Raises Independence Possibility.................................................... 5

Environmental Concerns and Responses ......................................................................................... 7

Water Quality Issues .................................................................................................................. 7

Air Emissions ............................................................................................................................ 9

State Regulation of Oil and Gas Development ........................................................................ 10

Debate over the Federal Role .................................................................................................. 13

Selected Federal Responses to Unconventional Resource Extraction ..................................... 14

EPA Study on Hydraulic Fracturing and Drinking Water.................................................. 15

Multiagency Collaboration on Unconventional Oil and Gas Research............................. 16

BLM Regulation of Hydraulic Fracturing ......................................................................... 17

Coast Guard Regulation of Barge Shipments of Shale Gas Wastewater ........................... 19

Legislation ..................................................................................................................................... 20

The 113th Congress .................................................................................................................. 20

The 114th Congress .................................................................................................................. 22

Conclusion: Above- and Below-Ground Issues a Concern............................................................ 23

Figures

Figure 1. Percentage of U.S. Oil and Natural Gas from Tight Oil and Shale Gas ........................... 1

Figure 2. Monthly U.S. Natural Gas Prices ..................................................................................... 3

Figure 3. Monthly U.S. Natural Gas Production ............................................................................. 4

Figure 4. Natural Gas, Oil, and NGL Prices .................................................................................... 5

Figure 5. Monthly U.S. Oil Production ........................................................................................... 6

Figure 6.Unconventional Shale Plays in the Lower 48 States ....................................................... 11

Figure 7.States Requiring Disclosure of Hydraulic Fracturing Chemicals .................................... 12

Tables

Table A-1. Selected Federal Actions Related to Unconventional Oil and Gas Production............ 25

Appendixes

Appendix. Selected Federal Initiatives Related to Unconventional Oil and Gas Production ........ 25

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Contacts

Author Contact Information........................................................................................................... 30

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Introduction: Change Is Afoot

In the past, the oil and natural gas industry considered resources locked in tight, impermeable

formations such as shale uneconomical to produce. Advances in directional well drilling and

reservoir stimulation have dramatically changed this perspective. It is production from these

unconventional formations that has changed the U.S. energy posture and global energy markets.

U.S. oil and natural gas production is on the rise, primarily driven by resources from tight

formations. The techniques developed to produce shale gas—directional drilling and hydraulic

fracturing1—have migrated to the oil sector. The United States is the third-largest oil producer in

the world but also the fastest-growing producer. The United States surpassed Russia in 2009 as

the world’s largest natural gas producer. Production from tight formations is expected to make up

a significant part of production of each commodity well into the future (see Figure 1).

Figure 1. Percentage of U.S. Oil and Natural Gas from Tight Oil and Shale Gas

2005-2040

Source: U.S. Energy Information Administration (EIA), Annual Energy Outlook 2014, http://www.eia.gov/oiaf/aeo/

tablebrowser/ and other EIA data.

Note: Prior to 2007, EIA did not report tight oil and shale gas data.

This report focuses on the growth in U.S. oil and natural gas production driven primarily by tight

oil formations and shale gas formations. It does not address other types of unconventional

production such as coalbed methane or tight gas, as their contributions to overall U.S. production

have not changed as dramatically as shale gas.2 There has been continued congressional interest

Hydraulic fracturing is an industry technique that uses water, sand, and chemicals under pressure to enhance the

recovering of natural gas and oil. It has taken on new prominence as it has been applied to tight oil and shale gas

formation as an essential method for producing resources from those types of formations.

Coalbed methane and tight gas accounted for 33% of U.S. natural gas production in 2011 but are projected to account

for only 28% in 2040, according to the Energy Information Administration (EIA).

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

related to unconventional natural gas and oil production. In March 2015, the House Natural

Resources Committee’s Subcommittee on Energy and Mineral Resources held a hearing

addressing the new Bureau of Land Management (BLM) hydraulic fracturing rule. Among

actions in the 113th Congress, the Senate Energy and Natural Resources Committee held three

roundtable discussions on natural gas supply and use3; the House Natural Resources Committee

held a hearing on hydraulic fracturing legislation and the BLM proposed rule; and the House

Energy and Commerce Committee’s Subcommittee on Energy and Power held a hearing in June

2013 on U.S. energy abundance.4

Geology Is What Makes a Resource Unconventional

Unconventional formations are fine-grained, organic-rich, sedimentary rocks—usually shales and

similar rocks. The shales and rocks are both the source of and the reservoir for oil and natural gas,

unlike conventional petroleum reservoirs. The Society of Petroleum Engineers describes

“unconventional resources” as petroleum accumulations that are pervasive throughout a large area

and are not significantly affected by pressure exerted by water (hydrodynamic influences); they

are also called “continuous-type deposits” or “tight formations.” In contrast, conventional oil and

natural gas deposits occur in porous and permeable sandstone and carbonate reservoirs. Under

pressure exerted by water, the hydrocarbons migrated upward from organic sources until an

impermeable cap-rock (such as shale) trapped it in the reservoir rock. Although the

unconventional formations may be as porous as other sedimentary reservoir rocks, their

extremely small pore sizes and lack of permeability make them relatively resistant to hydrocarbon

flow. The lack of permeability means that the oil and gas typically remain in the source rock

unless natural or artificial fractures occur.

Price Drives Industrial Innovation

Historically, natural gas prices in the United States have been volatile. From 1995 to 1999, the

spot price of natural gas averaged $2.23 per million British thermal units (MBtu, sometimes noted

as mmBtu) but increased to an average price of $4.68 per MBtu, in nominal dollars, during the

2000-2004 period, an almost 110% rise. Prices hit a peak in December 2005 at $15.38 per MBtu

but remained relatively high through July 2008, as can be seen in Figure 2. Along with the rise in

prices, U.S. net imports of natural gas also rose, increasing 32% between 1995 and 2000 and 41%

between 1995 and 2007.

As U.S. prices and imports continued to trend up, the industry undertook two competing solutions

to meet the need for more natural gas—increased liquefied natural gas (LNG) imports and

development of techniques to produce shale gas. The LNG import facilities were much higher

profile and were cited extensively in industry and popular press. Approximately 50 import

U.S. Congress, Senate Committee on Energy and Natural Resources, “Full Committee Forum: Domestic Supply and

Exports,” May 21, 2013, http://www.energy.senate.gov/public/index.cfm/hearings-and-business-meetings?ID=

0380bed7-f9ef-4450-bfa0-a3af60f7a184.

U.S. Congress, House Energy and Commerce Committee, Subcommittee on Energy and Power, “U.S. Energy

Abundance: Regulatory, Market, and Legal Barriers to Export,” June 18, 2013, http://energycommerce.house.gov/

hearing/us-energy-abundance-regulatory-market-and-legal-barriers-export.

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

projects were proposed, and 8 were eventually constructed during the mid- to late 2000s, along

with the recommissioning of older facilities.

Figure 2. Monthly U.S. Natural Gas Prices

2002-2014

$/mmbtu

$16

$12

Shale gas

$Jan

Jan

2002 2003 2004 2005 2006 2007 2008

Jan

2009 2010 2011 2012 2013 2014

Source: U.S. Energy Information Administration, http://www.eia.gov/dnav/ng/hist/rngwhhdM.htm.

Notes: Units = nominal dollars per million British thermal units (mmBtu). Data for 2014 are through July.

Although horizontal drilling and hydraulic fracturing have been industry techniques for some

time, their application to shale gas formations is relatively new. Advances in directional drilling,

particularly steerable down-hole motors, allowed drilling operators to better keep the well bore in

the hydrocarbon-bearing shale formations. Well stimulation was also required, and improvements

in hydraulic fracturing techniques, particularly multistage hydraulic fracturing and the ability to

better control the fractures, contributed to making shale gas production a profitable venture.

In 2007, the Energy Information Administration (EIA) first recorded shale gas production, when

it accounted for just 7% of U.S. natural gas production. In 2013, shale gas production accounted

for almost 40% of U.S. production (see Figure 1), while almost all the LNG import terminals

were idle and many applied to become export terminals.5

Technologies Stimulate Shale Gas Production First

The application of advances in directional drilling and hydraulic fracturing were first applied to

shale gas formations, particularly as natural gas prices increased in the mid-2000s. Methane

molecules and those of natural gas liquids (NGLs) are smaller than crude oil molecules and

For additional information on U.S. natural gas exports, see CRS Report R42074, U.S. Natural Gas Exports: New

Opportunities, Uncertain Outcomes, by (name redacted) et al.

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

therefore tend to be more responsive to hydraulic fracturing. The success of shale gas

development has driven U.S. natural gas production to increase almost every month on a year-onyear basis (see Figure 3) from 2008 through May 2014. The rise in shale gas development has

also resulted in natural gas prices declining, as shown in Figure 2.

Figure 3. Monthly U.S. Natural Gas Production

2008-2014

billion cubic feet per month (bcf/mo)

2,400

2,200

2014

2013

2,000

2012

1,800

2011

2010

1,600

2009

2008

1,400

1,200

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Source: U.S. Energy Information Administration, http://www.eia.gov/dnav/ng/ng_prod_sum_dcu_NUS_m.htm.

The decline in prices and production in the latter half of 2008 was mainly the result of the

economic downturn. However, as the economy picked up in 2009, natural gas resumed its upward

production trajectory while prices stayed low. Overall U.S. natural gas production grew, as did the

contribution from shale. The continued increase in production can be attributed, in part, to

industry improvements in extracting more of the natural gas from the shale formations. Continued

progress in hydraulic fracturing and directional drilling techniques has enabled companies to

drive down production costs while increasing output.

Natural Gas Liquids: A Production Driver

NGLs have taken on a new prominence as shale gas production has increased and prices have

fallen. As natural gas prices have stayed low, company interests have shifted away from dry

natural gas production to more liquids-based production. NGL is a general term for all liquid

products separated from natural gas at a gas processing plant and includes ethane, propane,

butane, and pentanes. When NGLs are present with methane, which is the primary component of

natural gas, the natural gas is referred to as either “hot” or “wet” gas. Once the NGLs are

removed from the methane, the natural gas is referred to as “dry” gas, which is what most

consumers use.

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Each NGL has its own market and its own value. As the price for dry gas has dropped because of

the increase in supply and other reasons, such as the warm winter of 2011, the natural gas

industry has turned its attention to producing in areas with more wet gas in order to bolster the

value it receives (see Figure 4). Some companies have shifted their production portfolios to tight

oil formations, such as the Bakken in North Dakota and Montana, to capitalize on the experience

they gained in shale gas development. Historically, the individual NGL products have been priced

against oil, except for ethane. As oil prices have remained higher since 2008 relative to natural

gas, they have driven an increase of wet gas production. Because of its low price, dry gas is often

treated as a “byproduct” of wet gas and oil production.

Figure 4. Natural Gas, Oil, and NGL Prices

2010-2014

$/mmbtu

$20

$16

$12

Oil

NGL

Gas

$Jan

2010

Jan

2011

Jan

2012

Jan

2013

Jan

2014

Source: U.S. Energy Information Administration.

Notes: According to EIA, the NGL composite price is derived from daily Bloomberg spot price data for natural

gas liquids at Mont Belvieu, TX, weighted by gas processing plant production volumes of each product as

reported on Form EIA-816, “Monthly Natural Gas Liquids Report.” The mix of NGLs will vary by source, and

the price will vary by the actual market for the product. The natural gas price is at Henry Hub, and the oil price

is West Texas Intermediate (WTI). Units = nominal dollars per million British thermal units ($/mmBtu). Data for

2014 are through May.

Increased Tight Oil Production Raises

Independence Possibility

The prospect of U.S. energy independence is grounded in the production growth from tight oil

formations such as the Bakken Formation in North Dakota and Montana and the Eagle Ford

Formation in Texas.6 Relative to other fuels, the United States is more dependent upon imports

For additional information on the Bakken Formation, see CRS Report R42032, The Bakken Formation: Leading

(continued...)

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

for its oil requirements, still accounting for about 47% of consumption.7 Canada is the largest

supplier of U.S. oil imports, which is why energy independence is usually mentioned as North

American energy independence.8 The United States added almost 1 million barrels per day (b/d)

of oil production between 2012 and 2013 (see Figure 5). U.S. oil production has reached levels

not seen in more than a decade but is almost 2 million b/d short of the highs in the 1970s. Since

2005, when crude oil imports reached a peak, they have dropped almost 2.4 million b/d, or 24%,

through 2013.9 Also since 2005, U.S. consumption of crude oil and petroleum products has been

trending downward, contributing to the decrease in imports.

Figure 5. Monthly U.S. Oil Production

2008-2014

1,000 barrels per month (kb/mo)

300,000

250,000

2014

2013

200,000

2012

150,000

2011

2010

100,000

2009

2008

50,000

Jan

Feb Mar Apr May Jun

Jul

Aug Sep

Oct Nov Dec

Source: U.S. Energy Information Administration, http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=

MCRFPUS1&f=M.

The continued shift of industry resources toward oil-rich production has prompted forecasts of

continued growth. Domestic crude oil production is projected to rise through the end of the

decade. The tremendous increases are primarily due to dramatic increases in production from the

(...continued)

Unconventional Oil Development, by (name redacted) et al.

BP, BP Statistical Review of World Energy, June 2014, pp. 8-9.

CRS Report R41875, The U.S.-Canada Energy Relationship: Joined at the Well, by (name redacted) and (name re

dacted). Mexico is the third-largest source of U.S. oil imports but is not always included in discussions of North

American energy independence, as its oil sector is not as integrated with the United States as is Canada’s.

EIA, U.S. Imports of Crude Oil and Petroleum Products, July 30, 2014, http://www.eia.gov/dnav/pet/hist/

LeafHandler.ashx?n=PET&s=MCRIMUS2&f=A.

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previously mentioned Bakken Formation in North Dakota and the Eagle Ford play in Texas, both

tight oil formations.10

Environmental Concerns and Responses

As with other energy sources or fuel production, the development of unconventional oil and gas

resources can pose both environmental risks and net benefits, some direct and others indirect.

Potential direct risks may include impacts to groundwater and surface water quality, public and

private water supplies, and air quality. In addition, some have raised concerns about potential

long-term and indirect impacts from reliance on fossil fuels and resulting greenhouse gas

emissions and influence on broader energy economics. On the other hand, natural gas is seen by

many as a “bridge” fuel that can provide more energy per unit of greenhouse gas produced than

some alternatives (e.g., coal) and has only recently been produced in sufficient quantity and at

low enough prices to provide a viable alternative fuel that is widely regarded as relatively cleanerburning (i.e., no mercury or sulfur emissions and substantially lower emissions of nitrous oxides

and carbon dioxide per Btu of energy produced compared to coal). This report focuses primarily

on measures to address potential direct impacts.

Among the variety of potential direct environmental impacts, many may be mitigated with

appropriate safeguards, existing technology, and best practices. For example, management of

wastewater associated with increased unconventional oil and gas production activity has in some

cases placed a strain on water resources and on wastewater treatment plants that were not

designed to remove salts and other contaminants from hydraulic fracturing flowback and

produced water, and these impacts can be mitigated by investing in additional control

technologies.

Water Quality Issues

Water quality issues have received much attention, and of these, the potential risks associated

with well stimulation by hydraulic fracturing have been at the forefront. Complaints of

contaminated well water have emerged in some areas where unconventional oil and gas

development has occurred, although regulators have not reported a direct connection between

hydraulic fracturing of shale formations at depth and groundwater contamination. In shale

formations, the vertical distance separating the target zone from usable aquifers generally is much

greater than the length of the fractures induced during hydraulic fracturing. Thousands of feet of

rock layers typically overlay the produced portion of shale, and these layers serve as barriers to

flow. In these circumstances, geologists and state regulators generally view as remote the

possibility of creating a fracture that could reach a potable aquifer. If the shallow portions of shale

formations were developed, then the thickness of the overlying rocks would be less and the

distance from the shale to potable aquifers would be shorter, posing more of a risk to

groundwater. In contrast to shale, coalbed methane (CBM) basins often qualify as underground

sources of drinking water. Injection of fracturing fluids directly into or adjacent to such

Adam Sieminski, Outlook for Shale Gas and Tight Oil Development in the U.S., U.S. Energy Information

Administration, presentation for the American Petroleum Institute, Washington, DC, April 4, 2013, p. 12.

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

formations may be more likely to present a risk of contamination, and this is where initial

regulatory attention and study was focused.11

State regulators have expressed more concern about the groundwater contamination risks

associated with developing a natural gas or oil well (drilling through an overlying aquifer and

casing, cementing, and completing the well), as opposed to hydraulic fracturing per se. The

challenges of sealing off the groundwater and isolating it from possible contamination are

common to the development of any oil or gas well and are not unique to hydraulic fracturing.

However, horizontally drilled, hydraulically fractured oil and gas wells pose more development

and production challenges and are subject to greater pressures than conventional vertical wells.

Identifying the source or cause of groundwater contamination can be difficult for various reasons,

including the complexity of hydrogeologic processes and investigations, a lack of baseline testing

of nearby water wells prior to drilling and fracturing, and the confidential business information

status traditionally provided for fracturing compounds. Investigations by regulators and

researchers have generally found that incidents involving residential water well contamination

(including methane gas migration) have been caused by failure of well-bore casing and cementing

or other well development and operating problems rather than the hydraulic fracturing process.12

The debate over groundwater contamination risks associated with hydraulic fracturing has been

fueled in part by the lack of scientific studies to assess more thoroughly current practices and

related complaints and uncertainties. To address this issue, Congress has asked the Environmental

Protection Agency (EPA) to conduct a study on the relationship between hydraulic fracturing and

drinking water.13 The “hydraulic fracturing” debate also has been complicated by terminology.

Many do not differentiate the well stimulation process of “fracing” or “fracking” from the full

range of activities associated with unconventional oil and gas exploration and production.14

Other water quality concerns—associated with both conventional and unconventional oil and

natural gas extraction—include the risks of contaminating ground and surface water from surface

spills, leaks from pits, and siltation of streams from drilling and pad construction activities.

Because of the large, but short-term, volumes of water needed for the hydraulic fracturing

operations used to extract shale gas and tight oil, water consumption issues have emerged as well.

U.S. Environmental Protection Agency (EPA), Evaluation of Impacts to Underground Sources of Drinking Water by

Hydraulic Fracturing of Coalbed Methane Reservoirs, Final Report, EPA-816-04-003, Washington, DC, June 2004, p.

4-1. EPA reviewed 11 major coalbed methane formations to determine whether coal seams lay within underground

sources of drinking water (USDWs). EPA determined that 10 of the 11 producing coal basins “definitely or likely lie

entirely or partially within USDWs.”

Avner Vengosh, Robert B. Jackson, and N. Warner et al., “A Critical Review of the Risks to Water Resources from

Unconventional Shale Gas Development and Hydraulic Fracturing in the United States,” Environmental Science and

Technology, vol. 10, no. 1021 (2014), p. 405118.

Department of the Interior, Environment, and Related Agencies Appropriations Act, 2010, P.L. 111-88, H.Rept. 111316. The EPA study (expected to be published in 2016) includes five case studies that involve drinking water

contamination incidents in areas where unconventional oil and gas development is occurring.

A 2012 Pacific Institute study found that many individuals interviewed for the study defined “hydraulic fracturing”

much more broadly than the industry meaning of the term (i.e., the pressurized injection of fluids into a production

well). These individuals used the term broadly to include well construction, completion, and other associated activities.

Noting the differences, the authors concluded that “additional work is needed to clarify terms and definitions associated

with hydraulic fracturing to support more fruitful and informed dialog and to develop appropriate energy, water, and

environmental policy.” See Hydraulic Fracturing and Water Resources: Separating the Frack from the Fiction, p. 29,

http://www.pacinst.org/reports/fracking/.

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Water use issues include the impacts that large water withdrawals might have on groundwater

resources, streams and aquatic life (particularly during low-flow periods), and other competing

uses (e.g., municipal or agricultural uses). Such impacts may be regional or localized and can

vary seasonally or with longer-term variations in precipitation.

The management of the large volumes of wastewater produced during natural gas production

(including flowback from hydraulic fracturing operations and water produced from source

formations) has emerged in many areas as a significant water quality issue as well as a cost issue

for producers. In some areas, such as portions of the Marcellus Shale region,15 capacity is limited

for wastewater disposal using underground injection wells (historically, the most common and

preferred produced-water disposal practice in oil and natural gas fields), and surface discharge of

wastewater is an increasingly restricted option.16 Such issues, as well as water-use concerns, are

driving increased water recycling and reuse in the industry.

Air Emissions

Air emissions associated with unconventional oil and natural gas production have also raised

public health concerns and have drawn regulatory scrutiny. Air pollutants can be released during

various stages of oil and natural gas production. Emission sources include pad, road, and pipeline

construction; well drilling and completion, and flowback activities and natural gas processing,

storage, and transmission equipment. Key pollutants include methane (the main component of

natural gas and a potent greenhouse gas), volatile organic compounds (VOCs), nitrogen oxides,

sulfur dioxide, particulate matter, and various hazardous air pollutants.17 According to EPA, the

oil and gas industry is a significant source of methane and VOC emissions, which react with

nitrogen oxides to form ozone (smog). EPA has identified hydraulically fractured gas wells during

flowback as an additional source of these emissions in the natural gas industry.18

Releases of methane and other pollutants can also occur where natural gas is produced in

association with oil and natural gas gathering pipelines and other infrastructure are lacking. In

such cases, the natural gas must generally be flared or vented. Flaring reduces VOC emissions

compared to venting, but like venting, it contributes to greenhouse gas emissions without

producing an economic value or displacing other fuel consumption.19 Natural gas flaring has

become an issue with the rapid and intense development of tight oil from the Eagle Ford

The Marcellus Shale formation is one of the largest unconventional natural gas resources in the United States,

underlying much of West Virginia and Pennsylvania, southern New York, eastern Ohio, western Maryland, and

western Virginia.

For a discussion of water management issues associated with shale energy development, see CRS Report R43635,

Shale Energy Technology Assessment: Current and Emerging Water Practices, by (name redacted), (name redacted), and

(name redacted). See also (name redacted), Garvin Heath, and Jordan Macknick, et al.,

Natural Gas and the

Transformation of the U.S. Energy Sector: Electricity, National Renewable Energy Laboratory, November 2012,

http://www.nrel.gov/docs/fy13osti/55538.pdf.

For a detailed discussion of air pollution issues associated with oil and gas exploration and development and recent

EPA regulations, see CRS Report R42833, Air Quality Issues in Natural Gas Systems, by (name redacted).

EPA, Overview of Final Amendments to Air Regulations for the Oil and Natural Gas Industry: Fact Sheet, October

2012, http://www.epa.gov/airquality/oilandgas/pdfs/20120417fs.pdf.

When vented, natural gas (largely methane) is released to the air without being burned. In contrast, when natural gas

is flared (burned), the main byproduct is carbon dioxide. Flaring is preferred to venting for safety reasons but also

because methane is several times more potent than carbon dioxide as a greenhouse gas (although more short-lived in

the atmosphere). Flaring also reduces emissions of ozone-forming pollutants compared to venting.

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Formation in Texas and the Bakken Formation in North Dakota, which have significant amounts

of associated gas.20 Other areas that have experienced large increases in tight oil production have

also had increases in the amount of natural gas being flared.

State Regulation of Oil and Gas Development

Oil and natural gas development is occurring in at least 32 states.21 Shale gas, tight oil, or other

unconventional resources (such as coalbed methane) are found in many of these states, primarily

on non-federal lands (see Figure 6). States are the principal regulators of oil and gas production

activities on state and private lands.22 The federal government, through the Department of the

Interior’s Bureau of Land Management (BLM), has responsibility for overseeing oil and gas

development on federally managed lands; however, some states require operators on federal

public lands within state boundaries to comply with the state’s oil and gas rules.23

Hydraulic fracturing, traditionally without horizontal drilling, has been used for decades to

stimulate increased production from existing oil or gas wells. This technique, along with other

well stimulation techniques, has been regulated to varying degrees through state oil and gas

codes. The detail and scope of applicable regulations vary across the states, and some states have

regulated “well stimulation” broadly without addressing hydraulic “fracturing” explicitly.24 State

regulators have noted that hydraulic fracturing operations have been regulated through provisions

that address various production activities, including requirements regarding well construction

(e.g., casing and cementing), well stimulation (e.g., hydraulic fracturing), well operation (e.g.,

pressure testing and blowout prevention), and wastewater management.25

Nonetheless, drilling and fracturing methods and technologies have changed significantly over

time as they have been applied to more challenging formations, greatly increasing the amount of

See CRS Report R42032, The Bakken Formation: Leading Unconventional Oil Development, by (name redacted) et

al. See also EIA, “North Dakota Aims to Reduce Natural Gas Flaring,” Today in Energy, October 20, 2014,

http://www.eia.gov/todayinenergy/detail.cfm?id=18451.

EIA, Rankings: Natural Gas Marketed Production, 2012, http://www.eia.gov/state/rankings/#/series/47. EIA reports

gas production in 32 states and oil production in 31 states. Five states (Texas, North Dakota, California, Alaska, and

Oklahoma) accounted for the bulk of oil and gas production in 2012. The biggest gains in oil production were in North

Dakota and Texas due in large part to increased horizontal drilling and hydraulic fracturing activity.

For a review of federal laws and regulations addressing leasing of federal lands for exploration and production of oil,

gas, and coal, see CRS Report R40806, Energy Projects on Federal Lands: Leasing and Authorization, by (name redacted).

Some states enter into memoranda of understanding with BLM to coordinate administration and enforcement of

various regulatory requirements on public lands within the state.

For state-specific information, see the Interstate Oil and Gas Compact Commission, Summary of State Statutes and

Regulations, http://www.iogcc.state.ok.us/state-statutes.

For example, before the state enacted hydraulic fracturing legislation (SB 4) in September 2013, California regulators

noted that requirements for protecting underground resources and well construction standards “provide a first line of

protection from potential damage caused by hydraulic fracturing.” However, the state noted, “There is a gap between

the requirements placed on oil and gas operators to safely construct and maintain their wells, and the information they

provide to the Division about hydraulic fracturing operations and steps taken to protect resources and the environment.

The Department’s pending regulatory process is intended to close that gap.” California Department of Conservation,

Hydraulic Fracturing in California, http://www.conservation.ca.gov/dog/general_information/Pages/

HydraulicFracturing.aspx. Among other provisions, the California law requires public disclosure of chemicals, baseline

and follow-up testing of nearby water wells, and groundwater monitoring plans, and it directs the state to conduct a

comprehensive environmental study of impacts associated with hydraulic fracturing. Also, SB 4 directs regulators to

make any needed revisions to rules governing construction of wells and well casings to ensure well integrity.

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water, fracturing fluids, and well pressures involved in tight oil and shale gas production

operations. State groundwater protection officials have reported that development of shale gas

and tight oil using high-volume hydraulic fracturing, in combination with directional drilling, has

posed new challenges for the management and protection of water resources.26 Consequently,

many of the major producing states have revised or are in the process of revising their oil and gas

laws and regulations to respond to these advances in oil and natural gas production technologies

and related changes in the industry.27

Figure 6.Unconventional Shale Plays in the Lower 48 States

(with federal lands shown)

Source: CRS, compiled from U.S. Energy Information Administration sources.

Notes: No information had been reported on active shale plays in Alaska at the time of this report. Hawaii’s

volcanic origin does not support the geologic process leading to the deposition of shale.

When revising laws and regulations, some states have added provisions to address hydraulic

fracturing specifically, such as requirements for disclosure of chemicals used in hydraulic

fracturing. Additionally, various states have adopted measures on water resources protection

(including casing, cementing and pressure testing, well spacing, setbacks, water withdrawal,

See, for example, Ground Water Protection Council, State Oil and Natural Gas Regulations Designed to Protect

Water Resources, 2014, http://www.gwpc.org/state-oil-gas-regulations-designed-protect-water-resources-2014-edition.

Alabama, Alaska, Arkansas, California, Colorado, Indiana, Michigan, Montana, North Dakota, New Mexico, Ohio,

Pennsylvania, Texas, Utah, West Virginia, and Wyoming are among the states that in recent years have revised oil and

gas laws and/or rules that address unconventional oil and gas development and hydraulic fracturing specifically.

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flowback, and wastewater storage and disposal requirements).28 According to the Ground Water

Protection Council (GWPC), the number of states with regulations governing hydraulic fracturing

operations specifically increased from 4 in 2009 to 13 in 2013, and the number of states requiring

reporting of hydraulic fracturing chemicals grew from 9 in 2009 to 21 in 2013.29 In February

2015, the GWPC reported that 27 states required chemical disclosure, and at least 18 of these

states allow or require companies to meet public disclosure requirements by using the FracFocus

website (see Figure 7).

Figure 7.States Requiring Disclosure of Hydraulic Fracturing Chemicals

Source: Ground Water Protection Council, http://fracfocus.org/welcome.

Notes: FracFocus was established in 2011 by the Ground Water Protection Council and the Interstate Oil and

Gas Compact Commission. FracFocus is a publicly available registry where oil and gas companies may voluntarily

identify chemicals used in hydraulic fracturing operations at specific wells. Many states allow or require operators

to meet state disclosure requirements by posting information on the FracFocus website. Similarly, new Bureau of

Land Management (BLM) hydraulic fracturing regulations require oil and gas operators on federal lands to

disclose chemicals through the FracFocus website.

For a comparison of state requirements for specific activities (e.g., wastewater disposal, chemical disclosure, and

cementing), see Resources for the Future, A Review of Shale Gas Regulations by State, July 2012, http://www.rff.org/

centers/energy_economics_and_policy/Pages/Shale_Maps.aspx.

Ground Water Protection Council, State Oil and Natural Gas Regulations Designed to Protect Water Resources,

2014, p. 8.

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In December 2014, the New York State environmental commissioner announced plans to prohibit

high-volume hydraulic fracturing based on the findings of a public health review.30 Maryland

environmental officials recommended in late 2014 that shale gas drilling be allowed using best

practices, following a three-year review of potential risks pursuant to an executive order. In 2013,

North Carolina lawmakers enacted legislation prohibiting the issuance of permits for oil and gas

development using hydraulic fracturing and horizontal drilling until new regulations were in place

and the legislature took affirmative action to allow permits to be issued; in 2014, the state enacted

legislation authorizing a regulatory permitting program for shale gas development.31

Debate over the Federal Role

While states continue to adopt and implement varying frameworks for oversight and regulation of

unconventional gas and oil development, some Members of Congress and various environmental

groups have pressed for greater environmental oversight of shale energy development at the

federal level. Some advocates of a larger federal role point to a wide range of differences in

substance, scope, and enforcement among state regulatory regimes and assert that a national

framework is needed to ensure a consistent baseline level of environmental and human health

protection and transparency.32 Such advocates further argue that greater regulatory uniformity

would reduce risks and uncertainties to both the industry and the public.33 Others, including many

oil and gas states, argue against greater federal involvement and point to established state oil and

gas programs and regulatory structures (which include a range of structures involving

commissions, boards, or divisions within natural resource agencies working to varying degrees

with, or within, state environmental agencies). In this view, experience lies with the states, and in

addition to the relative nimbleness of states to review and revise laws and rules, the states are

better able to consider regional differences in geology, topography, climate, and water resources.

In the 113th Congress, as in recent Congresses, the federal role in regulating oil and gas

production generally, and hydraulic fracturing specifically, was the subject of hearings, seminars,

and legislation.34 In the 114th Congress, bills have again been proposed to either limit or expand

federal involvement in regulating oil and gas development (see “Legislation” section). Such

proposals have been contentious, and Congress has not enacted such legislation since amending

the Safe Drinking Water Act (SDWA) in the Energy Policy Act (EPAct) of 2005 (P.L. 109-58) to

New York State Department of Environmental Conservation, “New York State Department of Health Completes

Review of High-Volume Hydraulic Fracturing,” press release, December 17, 2014, http://www.dec.ny.gov/press/

100055.html. High-volume hydraulic fracturing is used for shale gas and tight oil development. The state has not

prohibited other well stimulation and hydraulic fracturing operations.

General Assembly of North Carolina, Session Law 2013-365, Senate Bill 76. Also, Vermont banned hydraulic

fracturing. (EIA does not list Vermont as an oil- or gas-producing state.) The New Jersey legislature passed a ban on

shale gas drilling; however, the governor vetoed the bill and imposed a one-year ban, which has expired.

See, for example, Matthew McFeeley, State Hydraulic Fracturing Disclosure Rules and Enforcement: A

Comparison, Natural Resources Defense Council, July 2012.

For further discussion, see (name redacted), Garvin Heath, and Elizabeth Paranhos et al.,

Natural Gas and the

Transformation of the U.S. Energy Sector: Electricity, Joint Institute for Strategic Energy Analysis, January 2013,

http://www.nrel.gov/docs/fy13osti/55538.pdf.

The 113th Congress explored the role of states and the federal government in oil and gas production, specifically, and

in environmental protection broadly. In February 2013, the House Committee on Energy and Commerce,

Subcommittee on Environment and the Economy, held a hearing, The Role of the States in Protecting the Environment

Under Current Law. The Senate Committee on Energy and Natural Resources held a series of Natural Gas

Roundtables, including a May 2013 forum on Shale Development: Best Practices and Environmental Concerns.

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explicitly exclude from the SDWA definition of underground injection of fluids (other than diesel

fuels) related to hydraulic fracturing operations.35

Selected Federal Responses to Unconventional Resource Extraction

Provisions of several federal environmental laws and related regulations currently apply to certain

activities associated with oil and natural gas production.36 The Clean Water Act (CWA), for

example, prohibits the discharge of pollutants from point sources into surface waters without a

permit,37 and SDWA requires an Underground Injection Control (UIC) permit for wastewater

disposal through deep well injection.38 A SDWA UIC permit is required for the underground

injection of fluids or propping agents for hydraulic fracturing operations if the injected fracturing

fluids contain diesel fuels.39 In 2012, EPA issued regulations under the authority of the Clean Air

Act that require reductions in emissions related to oil and natural gas production, including

emissions of volatile organic compounds (VOCs) from hydraulically fractured natural gas wells.40

While congressional debate has continued on legislative proposals, the Administration has been

pursuing additional initiatives to regulate or otherwise manage activities related to

unconventional oil and gas production. EPA has been most active and is considering actions under

several pollution control statutes. Among these efforts, EPA is working to (1) establish

pretreatment standards to control discharges of wastewater from shale gas extraction to publicly

owned wastewater treatment plants; (2) revise water quality criteria to protect aquatic life from

discharges of brine produced during oil and gas extraction to surface waters; and (3) subject

hydraulic fracturing chemicals to toxic substance reporting requirements. In February 2014, EPA

finalized permitting guidance for the use of diesel in hydraulic fracturing operations.41 The

SDWA requires regulation of underground injection activities to protect underground sources of drinking water. EPA

has long regulated underground injections related to oil and gas field wastewater disposal and enhanced oil recovery.

Historically, EPA had not regulated injection of fluids for hydraulic fracturing of oil or gas production wells. In 1997,

the U.S. Court of Appeals for the 11th Circuit ruled that injections for fracturing for coalbed methane production in

Alabama constituted underground injection and must be regulated under SDWA. For more information, see CRS

Report R41760, Hydraulic Fracturing and Safe Drinking Water Act Regulatory Issues, by (name redacted) and (name

redacted).

See CRS Report R43152, Hydraulic Fracturing: Selected Legal Issues, by (name redacted), (name redacted), and

(name redacted).

CWA Section 301 prohibits the discharge of pollutants into the nation’s waters except in compliance with the

provisions of the law, which include obtaining a discharge permit. 33 U.S.C. §1311. For information on applicable

CWA requirements, see EPA, “Natural Gas Drilling in the Marcellus Shale, NPDES Program Frequently Asked

Questions,” March 16, 2011, http://www.epa.gov/npdes/pubs/hydrofracturing_faq.pdf.

The Safe Drinking Water Act of 1974 (P.L. 93-523) authorized the UIC program at EPA. UIC provisions, as

amended, are contained in SDWA Part C, §§1421-1426; 42 U.S.C. §§300h-300h-5.

EPAct 2005 (P.L. 109-58, §322) amended SDWA to exempt from the definition of underground injection the

injection of fluids or propping agents (other than diesel fuel) for hydraulic fracturing purposes.

The rules regulate VOC emissions from hydraulically fractured natural gas wells, compressors, pneumatic

controllers, storage vessels, and leaking components at onshore natural gas processing plants, as well as sulfur dioxide

emissions from onshore natural gas processing plants. The new standards require producers to capture about 90% of the

natural gas that escapes into the atmosphere as a result of production using hydraulic fracturing. For further discussion,

see CRS Report R42986, An Overview of Air Quality Issues in Natural Gas Systems, by (name redacted).

The EPA “UIC Program Guidance for Permitting Hydraulic Fracturing with Diesel Fuels” generally follows EPA

Class II underground injection well requirements (i.e., well construction standards; mechanical integrity testing;

operating, monitoring, and reporting requirements; and public notification and financial responsibility requirements).

The guidance provides recommendations for EPA permit writers for tailoring requirements for hydraulic fracturing

using diesel fuels. It applies in states where EPA implements the UIC program for Class II wells (including

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Appendix of this report provides a brief overview of selected federal environmental research and

regulatory activities related to the production of tight oil and gas resources. Several of these

initiatives are reviewed below.

EPA Study on Hydraulic Fracturing and Drinking Water

In 2009, the 111th Congress urged EPA to conduct a study on the relationship between hydraulic

fracturing and drinking water to gain a better understanding of potential contamination risks.42 In

2011, EPA published a final study plan that identified research projects that would address the full

life cycle of water in hydraulic fracturing, from water acquisition to chemical mixing and

injection through wastewater treatment and/or disposal. The study is intended to (1) examine

conditions that may be associated with potential contamination of drinking water sources, and (2)

identify factors that may lead to human exposure and risks.43 As part of the study, EPA has been

investigating five reported incidents of drinking water contamination in areas where hydraulic

fracturing has occurred. The purpose of the retrospective case studies is to determine the potential

relationship between reported impacts and hydraulic fracturing activities.44

In December 2012, EPA released a status report presenting the agency’s efforts on 18 research

projects being conducted for the study.45 Many of the individual research projects have been peer

reviewed and published, and these papers are available on the agency website.46 EPA has

designated the hydraulic fracturing study as a “highly influential scientific assessment,”47 which

will undergo peer review by EPA’s independent Science Advisory Board.48 EPA is synthesizing

(...continued)

Pennsylvania, New York, Michigan, Kentucky, Tennessee, and Virginia).

The Department of the Interior, Environment, and Related Agencies Appropriations Act, 2010 (P.L. 111-88, H.Rept.

111-316):

Hydraulic Fracturing Study.—The conferees urge the Agency to carry out a study on the

relationship between hydraulic fracturing and drinking water, using a credible approach that relies

on the best available science, as well as independent sources of information. The conferees expect

the study to be conducted through a transparent, peer-reviewed process that will ensure the validity

and accuracy of the data. The Agency shall consult with other Federal agencies as well as

appropriate State and interstate regulatory agencies in carrying out the study, which should be

prepared in accordance with the Agency’s quality assurance principles.

U.S. Environmental Protection Agency, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking

Water Sources, Office of Research and Development, EPA/600/R-11/122, November 2011, http://www2.epa.gov/

hfstudy.

EPA has conducted retrospective case studies at five sites to develop information about the potential impacts of

hydraulic fracturing on drinking water resources under different circumstances. The case studies include (1) the Bakken

Shale in Dunn County, ND; (2) the Barnett Shale in Wise County, TX; (3) the Marcellus Shale in Bradford County,

PA; (4) the Marcellus Shale in Washington County, PA; and (5) coalbed methane in the Raton Basin, CO.

EPA, Office of Research and Development, Study of the Potential Impacts of Hydraulic Fracturing on Drinking

Water Resources: Progress Report, EPA 601/R-12/011, December 2012.

U.S. Environmental Protection Agency, EPA’s Study of Hydraulic Fracturing and Its Potential Impact on Drinking

Water Resources, Published Scientific Papers, http://www2.epa.gov/hfstudy/published-scientific-papers.

Ibid., p. 4.

Because EPA has designated the hydraulic fracturing study as a “highly influential scientific assessment,” the agency

is to follow the peer review planning requirements described in the Office of Management and Budget’s Information

Quality Bulletin for Peer Review, 2004. The Bulletin states that important scientific information must be peer reviewed

by qualified specialists before being disseminated by the federal government. The EPA Science Advisory Board is an

external federal advisory committee that conducts peer reviews of significant EPA research products and activities.

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the results of the research projects into a draft report and plans to submit it for peer review and

public comment in 2015. A final report is not expected to be completed before 2016.

Multiagency Collaboration on Unconventional Oil and Gas Research

In March 2011, the White House issued a broad Blueprint for a Secure Energy Future, which

identified a need to “expand safe and responsible domestic oil and gas development and

production.” Additionally, the President directed the Secretary of Energy to identify steps that

could be taken to improve the safety and environmental performance of shale gas production and

to develop consensus recommendations on practices to ensure the protection of public health and

the environment.49

In response, the Secretary of Energy’s Advisory Board (SEAB) convened the Shale Gas

Production Subcommittee to identify and evaluate issues and make recommendations to mitigate

possible impacts of shale gas development. The SEAB final report included recommendations for

the states, federal government, and industry. The subcommittee recommended, among other

actions, that companies and regulators—to the extent that such actions had not been undertaken—

adopt further measures to protect water quality and to manage water use and wastewater disposal,

publicly report the composition of water and flow throughout the fracturing and cleanup process,

disclose fracturing fluid composition, and adopt best practices for well development and

construction (especially casing, cementing, and pressure management).50 The committee also

recommended actions to protect air quality through reduction of emissions of air toxics, ozone

precursors, methane, and other pollutants.

In 2012, the President issued Executive Order (E.O.) 13605, “Supporting Safe and Responsible

Development of Unconventional Domestic Natural Gas Resources,” to coordinate the efforts of

federal agencies overseeing the development of unconventional domestic natural gas resources

and associated infrastructure. The order states, “Because efforts to promote safe, responsible, and

efficient development of unconventional domestic natural gas resources are underway at a

number of executive departments and agencies, close interagency coordination is important for

effective implementation of these programs and activities.”51

E.O. 13605 established an interagency working group to coordinate agency activities and to

engage in long-term planning to ensure coordination on research, resource assessment, and

infrastructure development. In April 2012, the lead agencies—the Department of Energy (DOE),

EPA, and the Department of the Interior (DOI/U.S. Geological Survey)—signed a Memorandum

of Agreement to develop a multiagency research plan “to address the highest priority research

questions associated with safely and prudently developing unconventional shale gas and tight oil

The White House, “Blueprint for a Secure Energy Future,” March 30, 2011, p. 13, http://www.whitehouse.gov/sites/

default/files/blueprint_secure_energy_future.pdf.

U.S. Department of Energy, the Secretary of Energy Advisory Board (SEAB), Shale Gas Production Subcommittee,

Second Ninety Day Report, November 18, 2011, http://www.shalegas.energy.gov/. In November 2013, Energy

Secretary Ernest Moniz requested the SEAB to form a task force to review how FracFocus “houses the information

Federal and State regulatory agencies require as part of their regulatory functions with regard to disclosure of the

composition and quantities of fracturing fluids injected into unconventional oil and gas wells.” This review is available

at http://energy.gov/seab/secretary-energy-advisory-board-seab-task-force-fracfocus-20.

Executive Order 13605, “Supporting Safe and Responsible Development of Unconventional Domestic Natural Gas

Resources,” April 13, 2012, http://www.gpo.gov/fdsys/pkg/DCPD-201200269/pdf/DCPD-201200269.pdf.

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reserves.” In July 2014, the three agencies released a research and development strategy for

unconventional oil and gas resources.52

BLM Regulation of Hydraulic Fracturing

While states have the predominant role in regulating oil and gas development on state and private

lands, the federal government is responsible for managing oil and gas resources on federal lands.

Additionally, some states require oil and gas operators on federal lands within their state to

comply with various state rules; consequently, the debate over the federal role in regulating

unconventional oil and gas production—and related concerns over possible overlapping,

inconsistent, or duplicative rules—has extended to activities on federal lands.

The Bureau of Land Management is the federal agency responsible for overseeing oil, natural gas,

and coal leasing and production on federal and Indian lands, including split estates, where the

federal government owns the subsurface mineral estate and another entity owns the surface.53

BLM is tasked with leasing subsurface mineral rights not only on BLM-administered land but

also for lands managed by other federal agencies, including the U.S. Forest Service.54 BLM

oversees roughly 700 million subsurface acres of federal mineral estate and 56 million subsurface

acres of Indian mineral estate nationwide. As of June 30, 2014, there were roughly 47,000 active

oil and gas leases and 95,000 wells on public lands. BLM estimates that 2,800 new wells were

drilled on federal and Indian lands in 2013 and that hydraulic fracturing was used to stimulate

roughly 90% of these wells.55

Final Hydraulic Fracturing Rule

On March 26, 2015, BLM promulgated a hydraulic fracturing rule applicable to oil and gas

operations on federal and Indian lands.56 The rule revises BLM’s oil and gas rules related to

hydraulic fracturing, which were promulgated in 1982 and last revised in 1988, before the

widespread use of hydraulic fracturing and horizontal drilling.57 The rule is scheduled to enter

into effect on June 24, 2015.

When first proposing the rule in 2012, BLM noted that the “rule is necessary to provide useful

information to the public and to assure that hydraulic fracturing is conducted in a way that

adequately protects the environment.”58 BLM estimates that the rule will affect roughly 2,800

hydraulic fracturing operations each year; however, based on previous levels of activity on

The Memorandum of Agreement and research strategy are available at the Administration website, “Multi-Agency

Collaboration on Unconventional Oil and Gas Research,” http://unconventional.energy.gov/.

Mineral Leasing Act of 1920 (30 U.S.C. §181 et seq.), the Indian Mineral Leasing Act (25 U.S.C. §2107), the

Federal Land Policy and Management Act (43 U.S.C. §1701 et seq.), and other statutes.

For a discussion of federal lands leasing authorities and activities, see CRS Report R40806, Energy Projects on

Federal Lands: Leasing and Authorization, by (name redacted).

Department of the Interior, Bureau of Land Management, “Oil and Gas; Hydraulic Fracturing on Federal and Indian

Lands: Final Rule,” 80 Federal Register 16131, March 26, 2015.

80 Federal Register 16130.

The final rule revises existing BLM well completion regulations at 43 C.F.R. §316.3-2 and adds a new §3162.3-3.

The rule is available at http://www.blm.gov/wo/st/en/info/newsroom/2015/march/nr_03_20_2015.html.

BLM, “Oil and Gas; Well Stimulation, Including Hydraulic Fracturing, on Federal and Indian Lands: Proposed

Rule,” 77 Federal Register 27691, May 11, 2012.

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federal lands, the rule could affect as many as 3,800 operations annually, and total compliance

costs could reach $45 million annually.59

BLM received more than 177,000 comments on the proposed rule, and in May 2013, BLM

published a Supplemental Notice of Proposed Rulemaking (SNPR) and Request for Comment.60

BLM reviewed more than 1.4 million comments on the SNPR before issuing the final rule.61

In developing the rule, BLM reached out to states, industry, and other stakeholders. Some

elements of the rule are patterned after state requirements, and the final rule shares overarching

features with the 2012 proposal and the 2013 SNPR. Broadly, the rule revises BLM oil and gas

regulations to:

•

add reporting and management requirements for fluids used and produced in

hydraulic fracturing operations, including stricter storage requirements for fluids

that flow back to the surface,

•

require public disclosure of chemicals and proppants used in hydraulic fracturing,

and

•

add requirements to ensure that wells are constructed and operated in a manner

that ensures wellbore integrity and protects water resources.

Following are selected requirements of the final BLM hydraulic fracturing rule:

•

Before hydraulic fracturing operations begin, a detailed “request for approval of

hydraulic fracturing” must be submitted to BLM and approved. Operators may

submit a request for approval for a single well or may submit a master hydraulic

fracturing plan for a group of wells where geologic characteristics are similar.62

•

The rule specifies information that operators must provide in the request for

approval, including:

•

information regarding wellbore geology (including information on the

formation into which fracturing fluids are to be injected, estimated depths of

confining zones and occurrences of usable water, and a map regarding known

or suspected faults or fractures);

•

a map showing the planned wellbore trajectory and the estimated length,

direction, and depth of fractures expected to be propagated;

•

information concerning the source, location, transport, and volume of water

to be used in hydraulic fracturing; and

80 Federal Register 16195. BLM estimates that compliance could cost $11,400 per hydraulic fracturing operation

(roughly 0.13 to 0.21% of the cost of drilling a well).

BLM, “Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands: Supplemental Notice of Proposed

Rulemaking,” 78 Federal Register 31636, May 24, 2013.

The 2012 proposed rule applied to “well stimulation” activities broadly. The SNPR would have applied to hydraulic

fracturing and refracturing but excluded acidizing and enhanced secondary and tertiary recovery so that the rule would

apply only to hydraulic fracturing and not to other “well stimulation” activities. The final rule does not include the term

refracturing.

Operators may submit requests for approval either through an application to drill (APD) or notice of intent (NOI).

Under existing law and regulations, BLM field offices must post APDs for at least 30 days before issuing a permit (see

43 C.F.R. §316.3-1(g)). The BLM rule does not preempt notification requirements of states or tribes.

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•

estimated volume of fluid to be recovered from the fracturing operations and

proposed methods of handling and disposing of the recovered fluids.

•

Prior to hydraulic fracturing operations, an operator must document that the

cement is adequate to isolate all usable water formations. If there are indications

of inadequate cement, operators must take remedial actions and meet additional

reporting requirements.

•

Mechanical integrity testing (pressure testing) of wellbores is required prior to

fracturing operations.

•

The rule sets stricter requirements for the interim storage of recovered fluids.

Recovered fluids must be stored in above-ground tanks. In very limited

conditions, BLM may approve the use of a pit instead of a tank.

•

Companies must disclose information on each additive used in the hydraulic

fracturing fluids (chemicals and proppants) with exceptions and requirements for

trade secrets. Operators must provide this information to BLM by posting it on

the FracFocus website within 30 days of completing fracturing operations.63

•

On a case-by-case basis, an operator may request a variance from requirements

of the rule if the operator can demonstrate that the objectives of the rule would be

met using an alternate approach.64

•

States or tribes may work with BLM to craft variances from specific regulatory

provisions that would allow compliance with state or tribal requirements to be

accepted as compliance with the BLM rule (if the state or tribal provision is at

least as protective as the pertinent BLM provision). BLM does not provide for

statewide exemptions from the hydraulic fracturing rule.65

BLM further plans to revise its oil and gas rules to set standards to limit venting and flaring of

natural gas at oil and gas production facilities on federal and Indian lands.66

Coast Guard Regulation of Barge Shipments of Shale Gas Wastewater

The disposal of the large volumes of wastewater produced during shale gas extraction has posed

challenges for companies, state regulators, and communities—particularly in the Marcellus Shale

region. On-site disposal options are limited, and trucking wastewater to distant injection wells is

costly. In 2012, the Coast Guard received two requests for approval for the bulk shipment of

FracFocus was established in 2011 by the Ground Water Protection Council, an organization of state water quality

regulatory agencies, and the Interstate Oil and Gas Compact Commission, a multi-state government agency. FracFocus

is a publicly available registry where oil and gas companies may voluntarily identify chemicals used in hydraulic

fracturing operations at specific wells. Many states allow or require operators to meet state disclosure requirements by

posting information on the FracFocus website (http://www.fracfocus.org). FracFocus is supported, in part, by the

Department of Energy.

§3162.3-3(k)(1).

§3162.3-3(k)(2). In 2012, BLM proposed to implement on public lands “whichever rules, state or Federal, are most

protective of Federal lands and resources and the environment, consistent with longstanding practice and relevant

statutory authorities.” 77 Federal Register 72694.

Office of Management and Budget, Unified Agenda, RIN: 1004-AE14: Department of the Interior, “Venting and

Flaring: Waste Prevention and Use of Produced Oil and Gas for Beneficial Purposes,” Notice of Proposed Rulemaking

expected 2015, http://reginfo.gov/public/do/eAgendaViewRule?pubId=201410&RIN=1004-AE14.

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wastewater resulting from shale gas extraction in the Marcellus Shale to storage or treatment

centers and final disposal sites in Ohio, Texas, and Louisiana.

The Coast Guard regulates the shipment of hazardous materials on the nation’s rivers and

classifies cargoes for bulk shipment.67 For a cargo that has not been classified in the regulations

or under prior policy, the ship owner must request Coast Guard approval prior to shipping the

cargo.68 The Coast Guard has identified concerns with shipment of shale gas wastewater in

barges. A key Coast Guard concern with the wastewater is “its potential for contamination with

radioactive isotopes such as radium-226 and -228. Radium is of particular concern because it is

chemically similar to calcium and so will easily form surface residues and may lead to radioactive

surface contamination of the barges.”69 Consequently, the Coast Guard currently does not allow

barge shipment of shale gas extraction wastewater (SGEWW), and is developing a policy to

allow SGEWW to be transported for disposal.

In March 2013, the Coast Guard submitted for review to the Office of Management and Budget a

draft document, “Carriage of Conditionally Permitted Shale Gas Extraction Waste Water in

Bulk.” In October 2013, the Coast Guard published a notice of availability of a proposed “policy

letter” concerning barge shipments of SGEWW and requested public comment. The Coast Guard

received more than 70,000 comments and has been reviewing them. After addressing public

comments, the Coast Guard plans to issue a final policy letter that specifies conditions and

information requirements that barge owners would be required to meet to receive approval to

transport shale gas wastewater in bulk on inland waterways.70

Legislation

The 113th Congress

Contrasting bills were offered in the 113th Congress addressing unconventional oil and gas

development and hydraulic fracturing specifically. Several bills proposed to limit federal

regulation of hydraulic fracturing activities, while others would have expanded federal

involvement.

In November 2013, the House passed H.R. 2728 to amend the Mineral Leasing Act to prohibit the

Department of the Interior (DOI) from enforcing any federal regulation, guidance, or permit

requirement regarding hydraulic fracturing relating to oil, gas, or geothermal production activities

on or under any land in any state that has regulations, guidance, or permit requirements for

hydraulic fracturing. Although the language broadly applied to any federal regulation, guidance,

and permit requirements “regarding hydraulic fracturing,” the prohibition on enforcement applied

only to DOI and therefore presumably would have impacted only hydraulic fracturing operations

This action is based on authority in 46 U.S.C. Chapter 37—“Carriage of Liquid Bulk Dangerous Cargoes.”

Implementing regulations are published in 46 C.F.R. Subchapter O—“Certain Bulk Dangerous Cargoes.”

See 46 C.F.R. 153.900(c)-(d) or 46 C.F.R. 151.01-15.

U.S. Coast Guard, Marine Safety Engineering, Shale Gas Extraction Waste Water, Commercial Regulations and

Standards Directorate, Fall 2012, p. 5, http://www.uscg.mil/hq/cg5/cg52/docs/2012fall.pdf.

U.S. Coast Guard, “Carriage of Conditionally Permitted Shale Gas Extraction Waste Water in Bulk: Notice of

Availability and Request for Comments,” 78 Federal Register 64905, October 30, 2013. http://www.uscg.mil/hq/cg5/

cg521/.

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

on lands managed by that agency. The bill would have also required DOI to defer to state

regulations, permitting, and guidance for all activities related to hydraulic fracturing relating to

oil, gas, or geothermal production activities on federal land, regardless of whether those rules

were duplicative, more or less restrictive, or did not meet federal guidelines.

As passed, H.R. 2728 further would have (1) prohibited the department from enforcing hydraulic

fracturing regulations on Trust lands, except with express tribal consent, and (2) required the

Government Accountability Office to study the economic benefits of domestic shale oil and gas

production resulting from hydraulic fracturing. H.R. 2728 also incorporated the text of H.R. 2850

(H.Rept. 113-252), the EPA Hydraulic Fracturing Study Improvement Act. These provisions

proposed to require EPA to (1) follow certain procedures governing peer review and data

presentation in conducting its study on the relationship between hydraulic fracturing and drinking

water, and (2) issue the final report by September 30, 2016. On November 20, 2013, S. 1743, a

companion bill to H.R. 2728 as introduced, was offered in the Senate. H.R. 2728 was placed on

the Senate Legislative Calendar in December 2013. In September 2014, the House passed broad

energy legislation (H.R. 2), which included the text of H.R. 2728 in Subdivision D. The Senate

did not act on either bill.

Similarly, the Fracturing Regulations are Effective in State Hands Act, H.R. 2513 and S. 1234,

proposed to give states sole authority to regulate hydraulic fracturing operations on lands within

state boundaries. The legislation further specified that hydraulic fracturing on federal public lands

would be subject to the law of the state in which the land is located. S. 1482, the Empower States

Act of 2013, would have generally prohibited the Secretary of the Interior from issuing

regulations or guidelines regarding oil and gas production on federal land in a state if the state

had otherwise met the requirements under applicable federal law. Among other provisions, the

bill also proposed to (1) amend the Safe Drinking Water Act to require federal agencies, before

issuing any oil and gas regulation or guideline, to seek comment and consult with each affected

state agency and Indian tribe, and (2) require any future rule requiring disclosure of hydraulic

fracturing chemicals to refer to the FracFocus database. H.R. 1548 (H.Rept. 113-263) would have

prohibited the BLM hydraulic fracturing rule from having any effect on land held in trust or

restricted status for Indians, except with the express consent of its Indian beneficiaries. H.R. 2,

Section 25009, included this language.

In contrast to the above bills, several others proposed to expand federal regulation of hydraulic

fracturing. The Fracturing Responsibility and Awareness of Chemicals Act (FRAC) of 2013 (H.R.

1921 and S. 1135) would have amended the SDWA to (1) require disclosure of the chemicals used

in the fracturing process, and (2) repeal the hydraulic fracturing exemption established in EPAct

2005 and amend the term “underground injection” to include the injection of fluids used in

hydraulic fracturing operations, thus authorizing EPA to regulate this process under the SDWA.

The Climate Protection Act of 2013, S. 332, Section 301, contained similar chemical disclosure

provisions. Additionally, S. 332 proposed to repeal SDWA Section 1425, which provides states

with an alternative to meeting the specific requirements contained in EPA UIC regulations by

allowing states to demonstrate to EPA that their existing programs for oil and gas injection wells

are effective in preventing endangerment of underground sources of drinking water.71 S. 332,

Section 302, would have required EPA to report to Congress on fugitive methane emissions

resulting from natural gas infrastructure.

42 U.S.C. §300h-4.

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Legislation was also introduced to require baseline and follow-up testing of potable groundwater

supplies in the vicinity of hydraulic fracturing operations. H.R. 2983, the Safe Hydration is an

American Right in Energy Development Act of 2013, would have amended the SDWA to prohibit

hydraulic fracturing unless the person proposing to conduct the fracturing operations agreed to

testing and reporting requirements regarding underground sources of drinking water. The

legislation would have required testing (for substances specified by EPA) before, during, and after

hydraulic fracturing operations. EPA would have been required to post all test results on its

website.

Broader oil and gas regulatory bills included H.R. 1154, the Bringing Reductions to Energy’s

Airborne Toxic Health Effects Act, which proposed to amend the Clean Air Act to authorize EPA

to aggregate emissions from oil and gas wells, pipelines, and related units for purposes of

regulating toxic air pollutants. H.R. 2825, the Closing Loopholes and Ending Arbitrary and

Needless Evasion of Regulations Act of 2013, would have amended the Resource Conservation

and Recovery Act to require EPA to determine whether wastes associated with oil and gas

production meet the criteria for hazardous waste and to regulate any such wastes as hazardous.

The 114th Congress

Legislation in this Congress addressing unconventional oil and gas production repeats themes

from 113th Congress. Again bills have been introduced both to expand and limit federal regulation

of hydraulic fracturing operations. Several relevant bills are outlined below.

•

H.R. 1482, Fracturing Responsibility and Awareness of Chemical Act of 2015,

would amend the SDWA to (1) amend the term “underground injection” to

include the injection of fluids used in hydraulic fracturing operations, thus

authorizing EPA to regulate this process under the SDWA; and (2) require public

disclosure of chemicals used in the fracturing process.

•

H.R. 1515, Safe Hydration is an American Right in Energy Development Act of

2015, would require baseline and follow-up testing of potable groundwater

supplies in the vicinity of hydraulic fracturing operations. It would amend the

SDWA to prohibit hydraulic fracturing unless the person proposing to conduct

the fracturing operations agreed to testing and reporting requirements regarding

underground sources of drinking water. The bill would require testing (for

substances specified by EPA) before, during, and after hydraulic fracturing

operations. EPA would be required to post test results on its website.

•

S. 15, Protecting States’ Rights to Promote American Energy Security Act, would

amend the Mineral Leasing Act to prohibit DOI from enforcing any federal

regulation, guidance, or permit requirement regarding hydraulic fracturing

relating to oil, gas, or geothermal production activities on or under any land in

any state that has regulations, guidance, or permit requirements for hydraulic

fracturing. The bill would also require DOI to defer to state regulations,

permitting, and guidance for all activities related to hydraulic fracturing relating

to oil, gas, or geothermal production activities on federal land. A similar bill,

H.R. 1647, would further direct the Comptroller General to examine the

economic benefits of domestic shale oil and gas production resulting from the use

of hydraulic fracturing.

Congressional Research Service

An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

•

S. 785, FRAC Act, would amend the SDWA to (1) amend the term “underground

injection” to include the injection of fluids used in hydraulic fracturing

operations, thus authorizing EPA to regulate this process under the SDWA, and

(2) require public disclosure of chemicals and proppants used in the fracturing

process. Additionally, the Senate bill would authorize states to seek primary

enforcement responsibility for hydraulically fractured wells separately from other

underground injection wells.

•

S. 828 would clarify that a state has the sole authority to regulate hydraulic

fracturing on federal land within the boundaries of the state.

Conclusion: Above- and Below-Ground Issues

a Concern

The prospect that by the end of the decade the United States could become a significant exporter

of natural gas and the world’s leading oil producer is a phenomenal change of circumstances from

just a few years ago. The technological advances that drove the changes in the United States have

also reversed the global perspective of dwindling oil and natural gas resources and increased the

concern about greenhouse gas emissions. Other countries seek to emulate the U.S. production

success but have yet to do so. The U.S. oil and gas situation continues to be extremely dynamic,

and many questions remain about how the United States will develop its resources.

Many observers, including U.S. government officials, have only recently recognized the

tremendous resource size and the benefits that will accrue from developing the resources. Even

though shale gas development is still considered very new and tight oil production is even newer,

the industry has continued to improve its efficiency in extracting the resources, particularly of

natural gas. As more industry resources are shifted to tight oil plays, the natural gas sector has had

to produce more with less. Some in industry point out that at the beginning of shale gas

development about 5% of the resource was able to be extracted; now it is closer to 20% but will

likely increase over time. By comparison, the extraction rate for conventional gas is between 30%

and 60% of the resource.

Development of these resources has generated concern and debate over potential environmental

and human health risks. Concerns include potential impacts to groundwater and surface water

resources from well development and stimulation operations and wastewater management, as

well as air quality impacts from emissions of air pollutants, including methane. These concerns

have drawn scrutiny of regulatory regimes governing this industry and have led to calls for

greater federal oversight of oil and gas development. A growing concern is that the deep-well

disposal of oil and gas production wastewater may be responsible for increasing rates of seismic

activity in certain areas.72 Although primary regulatory authority over oil and natural gas

exploration and production on state and private lands generally rests with the states, provisions of

several federal environmental laws currently apply to certain activities associated with oil and

natural gas exploration and production. Moreover, EPA has been reviewing other statutory

authorities and pursuing new regulatory initiatives, and BLM is planning further revisions to its

For information on this topic, see CRS Report R43836, Human-Induced Earthquakes from Deep-Well Injection: A

Brief Overview, by (name redacted) and (name redacted).

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

oil and gas rules to address venting and flaring of natural gas on federal and Indian lands. A

broader concern among some is that the low price of natural gas is having negative consequences

for the development and growth in energy efficiency, renewable energy sources, and nuclear

power, potentially resulting in another generation of greenhouse-gas-producing energy sources.

The importance of tight oil and shale gas resources to U.S. energy policy and regional economies

is likely to keep issues surrounding their development on the agenda in the 114th Congress. Bills

have been introduced to expand and also to constrain federal involvement in oil and gas

development involving hydraulic fracturing. Meanwhile, the Administration continues to pursue

actions to broaden federal oversight of this industry sector through administrative means.73

See the Appendix for a review of federal research and regulatory initiatives related to unconventional oil and gas

production, with emphasis on hydraulic fracturing.

Congressional Research Service

An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Appendix. Selected Federal Initiatives Related to

Unconventional Oil and Gas Production

Table A-1. Selected Federal Actions

Related to Unconventional Oil and Gas Production

(with emphasis on hydraulic fracturing)

Agency: Statute,

as Amended

EPA: Clean Air

Act (CAA)

Regulatory/Guidance

Research

Status

Air emissions. In 2012, EPA issued regulations that

revised existing rules and promulgated new ones to

regulate emissions of volatile organic compounds

(VOCs), sulfur dioxide, and hazardous air pollutants

(HAPs) from many production and processing activities

in the oil and gas sector that had not been subject

previously to federal regulation.

Rules were

promulgated in

August 2012 (77

Federal Register

49489);

requirements phase

in through 2015.

Particularly pertinent to shale gas production are the

New Source Performance Standards (NSPS), which

require reductions in emissions of VOCs from

hydraulically fractured natural gas wells. The rules

require operators to use reduced emissions

completions (green completions) for all hydraulically

fractured natural gas wells beginning no later than

January 2015.

EPA agreed to

revisit elements of

the NSPS and, on

April 12, 2013,

proposed revisions

to the NSPS for

storage tanks (78

Federal Register

22125).

Applying broadly across the sector, the NSPS require

reductions of VOCs from compressors, pneumatic

controllers, storage vessels, and other emission

sources and also revise existing standards for sulfur

dioxide emissions from onshore natural gas processing

plants and HAPs from dehydrators and storage tanks.

In September 2013, EPA updated its 2012 performance

standards for oil and natural gas to address VOC

emissions from storage tanks used by the crude oil and

natural gas production industry. The updates are

intended to ensure that tanks likely to have the highest

emissions are controlled first, while providing tank

owners and operators time to purchase and install

VOC controls. The amendments reflect recent

information showing that more storage tanks will be

coming on line than the agency originally estimated.

(Thus, presumably, producers need more time to

purchase and install emission controls.)a

On September 23,

2013, EPA finalized

revisions to the

NSPS for storage

tanks (78 Federal

In July 2014, EPA proposed updates and clarifications

to NSPS requirements for well completions, storage

tanks, and natural gas processing plants. The proposal

would not change the required emission reductions in

the rules, including standards applicable to hydraulically

fractured natural gas wells.

On July 17, 2014,

EPA proposed

changes to the NSPS

rules (79 Federal

Congressional Research Service

An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Agency: Statute,

as Amended

EPA: Clean

Water Act

(CWA)

Regulatory/Guidance

Wastewater discharge. In 2011, EPA announced

plans to begin two separate rulemakings to revise the

Effluent Limitations Guidelines and Standards (ELGs)

for the Oil and Gas Extraction Point Source Category

to control discharges of wastewater from (1) coalbed

methane (CBM) and (2) shale gas extraction. Under

CWA Section 304(m), EPA sets national pretreatment

standards for discharges of industrial wastewater based

on best available technologies that are economically

achievable (BAT). States incorporate these limits into

discharge permits. Oil and gas wastewaters often

contain elevated levels of TDS (i.e., salts), and shale gas

wastewater may contain chemicals, metals, and

naturally occurring radioactive materials (NORM).

Discharges to treatment plants: Existing ELGs lack

pretreatment standards for “indirect” discharges of

unconventional oil and gas wastewaters to publicly

owned wastewater treatment works (POTWs), which

typically are not designed to treat this wastewater.c In

April 2015, EPA proposed to establish a “zero

discharge” pretreatment standard to ban discharges to

POTWs of wastewater resulting from unconventional

oil and gas (excluding CBM) production. EPA notes

that, while states are not approving requests for such

discharges to POTWs, the proposed zero discharge

standard would “provide regulatory certainty and

would eliminate the burden on POTWs to analyze

such requests” (80 Federal Register 18561).

Discharges to surface water: Current ELGs prohibiting

direct discharges of oil and gas extraction wastewater

into surface waters do not apply to CBM-produced

water. Rather, CBM wastewater discharge permits are

based on the best professional judgment of state or

EPA permit writers. EPA was considering developing

national discharge standards for CMB operations but

has determined not to do so.

EPA: CWA

Wastewater discharge. Produced water from oil

and gas production (including flowback from hydraulic

fracturing) can have high levels of total dissolved solids

(TDS), largely chlorides, which can harm aquatic life

and affect receiving water uses (e.g., fishing or

irrigation). EPA is updating its chloride water quality

criteria for protection of aquatic life.

Research

Status

Notice of the final

Effluent Guidelines

Program Plan was

published in

October 2011 (76

Federal Register

66286).

On April 7, 2015,

EPA issued a

proposed rule that

would set a “zero

discharge”

pretreatment

standard for

discharges of

wastewater from

unconventional oil

and gas extraction to

POTWs (80 Federal

On August 7, 2013,

EPA proposed to

delist CBM from the

ELG rulemaking plan

based on the

“declining prevalence

and economic

viability” of the

industry. EPA

determined that no

economically

achievable

technology is

available currently

(78 Federal Register

48159).

Draft criteria

document expected

in early 2016.

CWA Section 304(a)(1) requires EPA to develop

criteria for water quality that reflect the latest scientific

understanding of the effects of pollutants on aquatic life

and human health. States may use EPA-recommended

criteria to establish or update state water quality

standards, which in turn are used to develop

enforceable discharge permits. If reflected in state

water quality standards, the revised chloride water

quality criteria could affect discharges of produced

water from extraction of conventional and

unconventional oil and gas (e.g., CMB).b

Congressional Research Service

An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Agency: Statute,

as Amended

EPA: Safe

Drinking Water

Act (SDWA)

Regulatory/Guidance

Final guidance issued

in February 2014.

Study. EPA is

studying the

relationship

between

hydraulic

fracturing and

drinking water.

Congress

requested the

study in EPA’s

FY2010

appropriations

act. EPA

designated the

pending “report

of results” as a

“highly

influential

scientific

assessment,”

which requires

peer review by

qualified

specialists.

Chemical reporting. In response to a citizen petition

(TSCA Section 21), EPA published an Advance Notice

of Proposed Rulemaking (ANPR) to get input on the

design and scope of possible reporting requirements

for hydraulic fracturing chemicals. EPA is considering

requiring information reporting under TSCA Section

8(a) and health and safety data reporting under Section

8(d). EPA has sought public comment on the types of

chemical information that could be reported and

disclosed and approaches to obtaining this information

for chemicals used in hydraulic fracturing.

Congressional Research Service

Status

Draft guidance

issued in May 2012.

Diesel fuels. EPA has issued UIC Program Guidance for

Permitting Hydraulic Fracturing with Diesel Fuels in

response to the revised SDWA definition of

“underground injection” in the Energy Policy Act

(EPAct) of 2005 to explicitly exclude the underground

injection of fluids (other than diesel fuels) used in

hydraulic fracturing. The guidance provides

recommendations for EPA permit writers to use in

writing permits for hydraulic fracturing operations

using diesel fuels. The guidance applies in states where

EPA implements the UIC program for oil and natural

gas related (Class II) injection wells. States are not

required to adopt the guidance but may do so.d

EPA: SDWA

EPA: Toxic

Substances

Control Act

(TSCA)

Research

Draft report is

expected to be

submitted for peer

review in 2015.

A final report is

expected in 2016

(extended from

2014).

Initiated in January

2012.

ANPR under TSCA

Section 8 published

May 9, 2014 (79

Federal Register

28664).

Public comment

period closed

September 18, 2014.

An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Agency: Statute,

as Amended

EPA: Resource

Conservation and

Recovery Act

(RCRA)

Regulatory/Guidance

Storage/disposal pits and ponds. EPA has been

considering developing guidance to address the design,

operation, maintenance, and closure of pits used to

store hydraulic fracturing fluids for reuse or pending

final disposal. These wastes are exempt from regulation

as a hazardous waste under RCRA.

In April 2014, EPA issued a document that compiles

voluntary management practices for oil and gas

exploration and production wastes. This nonregulatory, non-guidance document is intended to

provide information only and does not establish agency

policy.

Research

Status

In April 2014, EPA

issued a Compilation

of Publicly Available

Sources of Voluntary

Management Practices

for Oil and Gas

Exploration and

Production (E&P)

Wastes as They

Address Pits, Tanks,

and Land Application.

Department of

the Interior,

Bureau of Land

Management

(BLM): Mineral

Leasing Act,

Indian Mineral

Leasing Act

Hydraulic fracturing on public lands. BLM has

promulgated revisions to rules governing oil and

natural gas production on federal and Indian lands. BLM

proposes to (1) require public disclosure of chemicals

used in hydraulic fracturing, (2) tighten regulations

related to wellbore integrity, and (3) add new

reporting and management/storage requirements for

water used and produced in hydraulic fracturing. BLM

first proposed a rule in May 2012. After extensive

public comment, BLM issued a Supplemental Notice of

Proposed Rulemaking on May 24, 2013 (78 Federal

Final rule published

March 26, 2015 (80

Federal Register

16130).

Department of

Homeland

Security, Coast

Guard: 46 U.S.C.

Ch. 37

Wastewater shipment. The Coast Guard regulates

the shipment of hazardous materials on the nation’s

rivers. Because of the potential for shale gas

wastewater in the Marcellus Shale region to contain

radioactive materials (especially radium, which can

form surface residues and may lead to radioactive

surface contamination of the barges), the Coast Guard

currently does not allow barge shipment of shale gas

extraction wastewater. In 2013, the Coast Guard’s

Hazardous Materials Division issued a proposed policy

letter establishing requirements for bulk shipment of

shale gas extraction wastewater by barge for disposal.

The Coast Guard received more than 70,000

comments and has been reviewing them.

On October 30,

2013, the Coast

Guard published a

notice for a onemonth comment

period on a

proposed policy

letter setting

conditions for bulk

shipment of shale gas

wastewater (78

Federal Register

64905).

Congressional Research Service

An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Agency: Statute,

as Amended

Regulatory/Guidance

DOE/EPA/DOIUSGS: E.O. 13605

Research

Status

Federal

research

coordination.

In 2012, the

three agencies

agreed, through

an MOU, to

develop a

multiagency

research plan

“to address the

highest priority

research

questions

associated with

safely and

prudently

developing

unconventional

shale gas and

tight oil

resources.”

Multiagency

Research Strategy

was issued on July

18, 2013.e

Source: Prepared by the Congressional Research Service.

Notes: This table presents selected Administration activities related to unconventional oil and natural gas

extraction. It excludes, for example, regional or site-specific research studies conducted by federal agencies.

More information on EPA initiatives to regulate oil and gas production and hydraulic fracturing is available at

EPA’s website, Natural Gas Extraction—Hydraulic Fracturing, http://www2.epa.gov/hydraulicfracturing.

These CAA rules, issued under court order, establish new air emissions standards for the “Crude Oil and

Natural Gas Production” and “Natural Gas Transmission and Storage” source categories. For details, see

CRS Report R42986, An Overview of Air Quality Issues in Natural Gas Systems, by (name redacted).

For more information, see the EPA Water Quality Criteria web page, http://water.epa.gov/scitech/

swguidance/standards/criteria/.

EPA explains that “[f]or direct dischargers of unconventional oil and gas wastewaters from onshore oil and

gas facilities—with the exception of coalbed methane—technology-based limitations are based on the

Effluent Limitations Guidelines (ELGs) for the Oil and Gas Extraction Category (40 CFR Part 435). Permits

for onshore oil and gas facilities must include the requirements in Part 435, including a ban on the discharge

of pollutants, except for wastewater that is of good enough quality for use in agricultural and wildlife

propagation for those onshore facilities located in the continental United States and west of the 98th

meridian.... Part 435 does not currently include categorical pretreatment standards for indirect discharges

to publicly owned treatment works (POTWs) for wells located onshore.” U.S. Environmental Protection

Agency, Unconventional Extraction in the Oil and Gas Industry, http://water.epa.gov/scitech/wastetech/guide/

oilandgas/unconv.cfm.

EPA regulates the underground injection of fluids through SDWA §§1421-1426; 42 U.S.C. §§300h-300h-5. In

February 2014, EPA issued UIC Program Guidance for Permitting Hydraulic Fracturing with Diesel Fuels, which

generally follows EPA Class II underground injection well requirements (i.e., well construction standards;

mechanical integrity testing; operating, monitoring, and reporting requirements; and public notification and

financial responsibility requirements). The guidance provides recommendations for EPA permit writers for

tailoring requirements for hydraulic fracturing using diesel fuels. The guidance applies in states where EPA

implements the UIC program for Class II wells (including Pennsylvania, New York, Michigan, Kentucky,

Tennessee, and Virginia).

Federal Multiagency Collaboration on Unconventional Oil and Gas Research—A Strategy for Research and

Development, http://unconventional.energy.gov/.

Congressional Research Service

An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Author Contact Information

(name redacted)

Specialist in Energy Policy

#redacted#@crs.loc.gov, 7-....

Congressional Research Service

(name redacted)

Specialist in Environmental Policy

#redacted#@crs.loc.gov, 7-....

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