Hydraulic Fracturing and
Safe Drinking Water Act Issues
Mary Tiemann
Specialist in Environmental Policy
Adam Vann
Legislative Attorney
July 12, 2012
Congressional Research Service
7-5700
www.crs.gov
R41760
CRS Report for Congress
Pr
epared for Members and Committees of Congress
Hydraulic Fracturing and Safe Drinking Water Act Issues
Summary
Hydraulic fracturing is a technique developed initially to stimulate oil production from wells in
declining oil reservoirs. With technological advances, hydraulic fracturing is now widely used to
initiate oil and gas production in unconventional (low-permeability) oil and gas formations that
were previously inaccessible. This process now is used in more than 90% of new oil and gas
wells. Hydraulic fracturing is done after a well is drilled and involves injecting large volumes of
water, sand (or other propping agent), and specialized chemicals under enough pressure to
fracture the formations holding the oil or gas. The sand or other proppant holds the fractures open
to allow the oil or gas to flow freely out of the formation and into a production well.
Its application, along with horizontal drilling, for production of natural gas (methane) from tight
gas sands, unconventional shale formations, and coal beds, has resulted in the marked expansion
of estimated U.S. natural gas reserves in recent years. Similarly, hydraulic fracturing is enabling
the development of tight oil resources, such as the Bakken and Eagle Ford formations. However,
the rapidly increasing and geographically expanding use of fracturing has raised concerns over its
potential impacts on groundwater and drinking water supplies, and has led to calls for greater
state and/or federal oversight of this activity.
Historically, the Environmental Protection Agency (EPA) had not regulated the underground
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 fracturing for coalbed methane (CBM) production in
Alabama constituted underground injection and must be regulated under the Safe Drinking Water
Act (SDWA). This ruling led EPA to study the risk that hydraulic fracturing for CBM production
might pose to drinking water sources. In 2004, EPA reported that the risk was small, except where
diesel was used, and that national regulation was not needed. However, to address regulatory
uncertainty the ruling created, the Energy Policy Act of 2005 (EPAct 2005) revised the SDWA
term “underground injection” to explicitly exclude the injection of fluids and propping agents
(except diesel fuel) used for hydraulic fracturing purposes. Consequently, EPA currently lacks
authority under the SDWA to regulate hydraulic fracturing, except where diesel fuel is used. (In
May, EPA issued draft permitting guidance for use of diesel during fracturing.) As the use of this
process has grown, some in Congress would like to revisit this statutory exclusion.
Several relevant bills are pending. H.R. 1084 and S. 587 would repeal the exemption for
hydraulic fracturing operations established in EPAct 2005, and amend the term “underground
injection” to include explicitly the injection of fluids used in hydraulic fracturing operations, thus
authorizing EPA to regulate this process under the SDWA. The bills also would require disclosure
of the chemicals used in the fracturing process. S. 2248 and H.R. 4322 would specify that a state
has sole authority to regulate hydraulic fracturing on federal lands within state boundaries. EPA’s
FY2010 appropriations act urged the agency to study the relationship between hydraulic
fracturing and drinking water quality. Interim and final reports are expected in 2012 and 2014,
respectively. Meanwhile, numerous states are reviewing or have revised their oil and gas rules to
address the increased use of high-volume hydraulic fracturing.
This report reviews past and proposed treatment of hydraulic fracturing under the SDWA, the
principal federal statute for regulating the underground injection of fluids to protect groundwater
sources of drinking water. It reviews current SDWA provisions for regulating underground
injection activities, and discusses some possible implications of, and issues associated with,
enactment of legislation authorizing EPA to regulate hydraulic fracturing under this statute.
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Hydraulic Fracturing and Safe Drinking Water Act Issues
Contents
Introduction...................................................................................................................................... 1
Background—Hydraulic Fracturing in Oil and Gas Production ............................................... 1
Hydraulic Fracturing and Drinking Water Issues ...................................................................... 4
The Safe Drinking Water Act and the Federal Role in Regulation of Underground
Injection........................................................................................................................................ 7
Review of Relevant SDWA UIC Provisions.............................................................................. 7
The “Endangerment” Standard.................................................................................................. 9
Defining “Underground Source of Drinking Water” ............................................................... 10
Underground Injection Control Regulatory Program Overview ............................................. 10
Class II Wells........................................................................................................................... 12
State Primacy for UIC Program Administration...................................................................... 13
The Debate over Regulation of Hydraulic Fracturing Under the SDWA ...................................... 15
The LEAF Challenge to the Alabama UIC Program and EPA’s Interpretation of the
SDWA................................................................................................................................... 15
Alabama’s Regulation of Hydraulic Fracturing in CBM Production ...................................... 16
EPA’s 2004 Review of Hydraulic Fracturing for CBM Production......................................... 18
EPAct 2005: A Legislative Exemption for Hydraulic Fracturing .................................................. 20
EPA Guidance on SDWA Regulation of Hydraulic Fracturing Using Diesel Fuels ................ 20
Proposed Legislation in the 112th Congress............................................................................. 21
FRAC Act.......................................................................................................................... 22
FRESH Act........................................................................................................................ 23
Potential Implications of Hydraulic Fracturing Regulation Under the SDWA ....................... 24
State Regulation of Hydraulic Fracturing...................................................................................... 29
GWPC Review of State Regulations ....................................................................................... 30
UIC Program Resources .......................................................................................................... 32
Federal Studies and Research ........................................................................................................ 34
Concluding Observations............................................................................................................... 36
Figures
Figure 1. Geologic Nature of Major Sources of Natural Gas in the United States .......................... 3
Figure 2. Primacy Status for EPA’s UIC Program ......................................................................... 13
Figure 3. Hydraulic Fracturing Chemical Disclosure by State ...................................................... 25
Tables
Table 1. Minimum Federal Technical Requirements for Class I, II, and III Wells ........................ 11
Table 2. Minimum EPA Regulatory Requirements for Class II Wells........................................... 12
Table 3. States Regulating Oil and Gas (Class II) UIC Wells Under SDWA Section 1425........... 14
Table 4. States Where EPA Implements the UIC Class II Program ............................................... 14
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Contacts
Author Contact Information........................................................................................................... 38
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Hydraulic Fracturing and Safe Drinking Water Act Issues
Introduction
Background—Hydraulic Fracturing in Oil and Gas Production
The process of hydraulic fracturing was developed initially in the 1940s to stimulate production
from oil reservoirs with declining productivity.1 More recent technological advances have
allowed this practice to be used to initiate oil and gas production in unconventional (low-
permeability) oil and gas formations.2 Its application—combined with horizontal drilling—in the
production of natural gas from coal beds, tight gas sands,3 and unconventional shale formations
has resulted in the marked expansion of estimated U.S. natural gas reserves in recent years.
Similarly, hydraulic fracturing is enabling the development of unconventional domestic oil
resources, such as the Bakken Formation in North Dakota and Montana and the Eagle Ford
Formation in Texas. However, the rapidly increasing and geographically expanding use of
fracturing, along with a number of complaints of well water contamination and other water
quality problems attributed to this practice, have led to calls for greater state and/or federal
oversight of this activity.
Hydraulic fracturing involves injecting into production wells large volumes of water, sand or
other proppant,4 and specialized chemicals under enough pressure to fracture low-permeability
geologic formations containing oil and/or natural gas.5 The sand or other proppant holds the new
fractures open to allow the oil or gas to flow freely out of the formation and into a production
well. Fracturing fluid and water remaining in the fracture zone can inhibit oil and gas production,
and must be pumped back to the surface. The fracturing fluid—“flowback”—along with any
naturally occurring formation water pumped to the surface, together called produced water,
typically has been disposed through deep well injection or treated before disposal into surface
waters.6 According to industry estimates for various geographic areas, the volume of flowback
water can range from less than 30% to more than 70% of the original fracture fluid volume.7
1 Hydraulic fracturing is also used for other purposes, such as developing water supply wells and geothermal
production wells. This report focuses only on its use for oil and gas development.
2 For a brief history of technological developments that have enabled unconventional gas and oil production, see U.S.
Department of Energy, Shale Gas: Applying technology to Solve America's Energy Challenges, National Energy
Technology Laboratory, March 2011, http://www.netl.doe.gov/technologies/oil-
gas/publications/brochures/Shale_Gas_March_2011.pdf.
3 Tight gas sands are sandstone formations with very low permeability that must fractured to release the gas.
4 According to the Schlumberger Oilfield Glossary, propping agents, or proppants, are “sized particles mixed with
fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand
grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like
sintered bauxite, may also be used.” The glossary is available at http://www.glossary.oilfield.slb.com/default.cfm.
5 This process is distinct from enhanced oil and gas recovery and other secondary and tertiary hydrocarbon recovery
techniques which involve separate wells. Injections for hydraulic fracturing are done through the production wells.
6 The Schlumberger glossary notes that “produced fluid is a generic term used in a number of contexts but most
commonly to describe any fluid produced from a wellbore that is not a treatment fluid. The characteristics and phase
composition of a produced fluid vary and use of the term often implies an inexact or unknown composition.”
“Flowback” refers to “the process of allowing fluids to flow from the well following a treatment, either in preparation
for a subsequent phase of treatment or in preparation for cleanup and returning the well to production.”
7 U.S. Department of Energy, Office of Fossil Energy and National Technology Laboratory, Modern Shale Gas
Development in the United States: A Primer, DE-FG26-04NT15455, April 2009, p. 66, http://fossil.energy.gov/
programs/oilgas/publications/naturalgas_general/Shale_Gas_Primer_2009.pdf.
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Reliance on the use of hydraulic fracturing continues to increase, as more easily accessible oil and
gas reservoirs have declined and companies move to develop unconventional oil and gas
formations. Hydraulic fracturing is used for oil and/or gas production in all 33 U.S. states where
oil and natural gas production takes place. According to industry estimates, hydraulic fracturing
has been applied to more than 1 million wells nationwide, and often multiple times per well.8
The frequency of its use expanded markedly in the 1980s and 1990s with its application to
coalbed methane (CBM) development. CBM production through wells began in the 1970s,
largely as a safety measure in coal mines to reduce the explosion hazard posed by methane. In
1984, fewer than 100 coalbed wells existed in the United States.9 In the 1980s, demand for natural
gas, new fracturing technologies, and federal tax credits for nonconventional fuels production led
to dramatic growth in the CBM development industry. By 1990, nearly 8,000 coalbed wells had
been drilled nationwide. In 2008, the Environmental Protection Agency (EPA) identified 56,000
CBM wells managed by operators in 692 different projects.10
Other unconventional gas resource formations relying on hydraulic fracturing include tight sands
gas and shale gas. The Department of Energy’s (DOE’s) Energy Information Administration
(EIA) reports that natural gas from tight sand formations is the largest source of unconventional
production, while production from shale formations is the fastest-growing source.11 Figure 1
illustrates different types of natural gas reservoirs.
The number of onshore gas wells in the United States increased from roughly 260,000 wells in
1989 to 487,627 wells in 2010.12 According to the Independent Petroleum Association of America
(IPAA), more than 90% of new natural gas wells rely on hydraulic fracturing. Similarly,
fracturing is increasingly applied to U.S. oil production. In June 2012, the U.S. Energy
Information Agency (EIA) reported that U.S. natural gas production had reached an all-time high
and oil production had reached its highest level since 1998.13
Shale gas and other “tight” oil and gas production involves drilling a well vertically and then
drilling horizontally out from the wellbore. Because of the low permeability of these formations,
more wells must be drilled into a reservoir than more permeable, conventional reservoirs to
retrieve the same amount of oil or gas. A benefit of horizontal drilling through a producing shale
layer is that one well pad that utilizes horizontal well drilling can replace numerous individual
well pads and reduce the surface density of wells in an area. Six to eight horizontal wells, and
potentially more, can be drilled from a single well pad and access the same reservoir. According
to a report prepared for DOE:
8 American Petroleum Institute, Hydraulic Fracturing, http://www.api.org/policy/exploration/hydraulicfracturing.
9 U.S. Environmental Protection Agency, Study Design for Evaluation of Impacts to Underground Sources of Drinking
Water by Hydraulic Fracturing of Coalbed Methane Reservoirs, http://www.epa.gov/safewater/uic/
wells_coalbedmethanestudy_finalstudydesign.html.
10 U.S. Environmental Protection Agency, Effluent Guidelines: Coalbed Methane Extraction Detailed Study,
http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm.
11 The U.S. Geological Survey’s National Assessment of Oil and Gas Resources Update (August 2011) is available at:
http://energy.usgs.gov/OilGas/AssessmentsData/NationalOilGasAssessment/AssessmentUpdates.aspx.
12 U.S. Energy Information Administration, Natural Gas Navigator: Number of Producing Gas Wells, December 2011,
http://www.eia.gov/dnav/ng/ng_prod_wells_s1_a.htm.
13 U.S. Energy Information Administration, Today in Energy: U.S. Crude Oil Production in First Quarter of 2012
Highest in 14 Years, June 8, 2012, http://www.eia.gov/todayinenergy/detail.cfm?id=6610.
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the spacing interval for vertical wells in the gas shale plays averages 40 acres per well for
initial development. The spacing interval for horizontal wells is likely to be approximately
160 acres per well. Therefore, a 640-acre section of land could be developed with a total of
16 vertical wells, each on its own individual well pad, or by as few as 4 horizontal wells all
drilled from a single multi-well drilling pad.14
Figure 1. Geologic Nature of Major Sources of Natural Gas in the United States
Source: U.S. Energy Information Administration, Independent Statistics and Analysis, October 2008. Available at
http://www.eia.gov/oil_gas/natural_gas/special/ngresources/ngresources.html.
Notes: The diagram shows schematically the geologic nature of most major U.S. sources of natural gas:
•
Gas-rich shale is the source rock for many natural gas resources, but, until [recently], has not been a
focus for production. Horizontal drilling and hydraulic fracturing have made shale gas an economically viable
alternative to conventional gas resources.
•
Conventional gas accumulations occur when gas migrates from gas rich shale into an overlying
sandstone formation, and then becomes trapped by an overlying impermeable formation, cal ed the seal.
Associated gas accumulates in conjunction with oil, while non-associated gas does not accumulate with oil.
•
Tight sand gas accumulations occur in a variety of geologic settings where gas migrates from a source
rock into a sandstone formation, but is limited in its ability to migrate upward due to reduced permeability
in the sandstone.
•
Coalbed methane does not migrate from shale, but is generated during the transformation of organic
material to coal.
14U.S. Department of Energy, Office of Fossil Energy and National Technology Laboratory, Modern Shale Gas
Development in the United States: A Primer, April 2009, pp. 47-48, http://www.netl.doe.gov/technologies/oil-gas/
publications/EPreports/Shale_Gas_Primer_2009.pdf.
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A single production well may be fractured multiple times, using from 500,000 gallons to more
than 6 million gallons of water, with compounds and proppants of various amounts added to the
water.15 Slickwater fracturing, which involves adding chemicals to increase fluid flow, is a more
recent development used for unconventional shale gas development.16
Hydraulic Fracturing and Drinking Water Issues
While the use of hydraulic fracturing, along with directional drilling to develop unconventional
oil and natural gas resources has enabled the oil and gas industry to markedly increase domestic
production, questions have emerged regarding the potential impacts that this process may have on
groundwater quality and on private wells and water supplies, specifically. During hydraulic
fracturing, new fractures are induced into a shale or other tight formation and existing fractures
may be lengthened. As production activities have increased and expanded into more populated
areas, so has concern that the fracturing process might introduce chemicals, methane, and other
contaminants into aquifers.
A particularly contentious issue concerns whether the fracturing process could create or extend
fractures linking the producing zone to an overlying aquifer and, thus, provide a pathway for gas
or fracturing fluids to migrate. 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 overly the produced portion of the
shale, and these layers serve as barriers to flow. Consequently, regulators and geologists generally
view as remote the possibility of creating a fracture that reaches a potable aquifer. However, 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 basins often lie within aquifers that
are underground sources of drinking water. Injection of fracturing fluids directly into or adjacent
to such formations would be much more likely to present a risk of contamination.17
Public complaints of impacts to well water have increased with unconventional gas development
and the use of hydraulic fracturing. Published studies and agency investigations have not reported
a direct connection between hydraulic fracturing of shale formations and groundwater
contamination.18 In 2009, the Ground Water Protection Council (GWPC)19 reported that several
15 Multiple fractures are typical in deep shale formations. Scott Stevens and Vello Kuuskraa of Advanced Resources
International report that “[t]oday, deep shale drillers all employ essentially the same Barnett-style well drilling and
completion design: ±4,000-ft. long lateral stimulated by multimillion-lb slick-water fracs in a dozen stages.” Source:
Seven Plays Dominate North America Activity, Oil and Gas Journal, September 28, 2009, v. 107, n. 36 p. 41.
16 Using slickwater fracturing increases the rate at which fluid can be pumped down the wellbore to fracture the shale.
The process may involve the use of friction reducers, biocides, surfactants, and scale inhibitors. Biocides prevent
bacteria from clogging wells; surfactants help keep the sand or other proppant suspended. Slickwater fracturing was
first used in the Barnett shale in Texas.
17 EPA reviewed 11 major coalbed methane formations to determine whether coal seams lay within USDWs. EPA
determined that 10 of the 11 producing coal basins “definitely or likely lie entirely or partially within USDWs.” (U.S.
Environmental Protection Agency, Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic
Fracturing of Coalbed Methane Reservoirs, Final Report, EPA-816-04-003, Washington, D.C., June 2004, p. 4-1.)
18 Charles G. Groat, Principal Investigator, and Thomas W. Grimshaw, Co-Principal Investigator, et al, Fact-Based
Regulation for Environmental Protection in Shale Gas Development, University of Texas, Energy Institute, February
2012, http://energy.utexas.edu/images/ei_shale_gas_regulation120215.pdf.
19 The GWPC is a national association representing state groundwater and underground injection control (UIC)
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complaints of well water contamination attributed to hydraulic fracturing appeared to be related
to hydraulic fracturing of CBM zones that were in relatively close proximity to underground
sources of drinking water.20
The larger risk for groundwater contamination concerns the process of developing a natural gas or
oil well (drilling through an overlying aquifer, and casing, cementing and completing the well).
Incidents of well water contamination attributed to hydraulic fracturing typically have been found
to be caused by problems with the well casing or cementing.21 In Pennsylvania, for example,
regulators confirmed that methane had migrated to water wells from drilling sites in two counties,
and determined that the gas migration was caused by improperly cased and cemented wells, as
well as excessive pressures in some cases.22 Notably, the challenge of sealing off the groundwater
and isolating it from possible contamination is common to the development of any oil or gas well,
not only those that rely on hydraulic fracturing. Nonetheless, given the higher pressures and large
volumes of water used in hydraulic fracturing, a number of states have revised well casing,
cementing, pressure testing, and other requirements to protect water resources.
Another concern involves the potential contamination of ground water from surface activities. For
example, leaky surface impoundments, accidental spills, or careless surface disposal of drilling
fluids at the production site could increase the risk of contaminating water supply wells. Other
potential water quality issues involve the management (storage, treatment, and disposal) of water
produced in the fracturing process.23
In some cases, the source or cause of well-water contamination remains undetermined.
Identifying the cause of contamination can be difficult for various reasons, including the
complexity of hydrogeologic processes and investigations and a lack of baseline testing of nearby
water wells prior to drilling and fracturing, as well as the confidential business information status
(...continued)
agencies whose mission is to promote protection and conservation of groundwater resources for beneficial uses. The
stated purpose of the GWPC is “to promote and ensure the use of best management practices and fair but effective laws
regarding comprehensive ground water protection.” http://www.gwpc.org
20 Ground Water Protection Council, U.S. Department of Energy, Office of Fossil Energy, National Energy Technology
Laboratory, State Oil and Natural Gas Regulations Designed to Protect Water Resources, May 2009, p. 24. Coal beds
are often a source of good quality groundwater, thus presenting challenges to developers and potential conflicts with
well owners.
21 For a discussion of environmental concerns and recommendations, see, for example, Environmental Working Group,
Drilling Around the Law, January 2010, http://static.ewg.org/files/EWG-2009drillingaroundthelaw.pdf.
22 New York State Department of Environmental Conservation, Fact Sheet: What We Learned from Pennsylvania,
NYS DEC NEWS, http://www.dec.ny.gov/energy/75410.html.
23 The scope of this report is limited to potential issues related to hydraulic fracturing and contamination of
underground sources of drinking water related to the fracturing process. Another environmental concern related to
hydraulic fracturing is the disposal or treatment of “flowback” from the fracturing/drilling process, which may present
environmental and regulatory issues and also water treatment infrastructure issues. Disposal of flowback by means
other than disposal through injection wells is regulated pursuant to the Clean Water Act. For a discussion of the
hydraulic fracturing process and potential sources of ground and surface water contamination, see CRS Report R42333,
Marcellus Shale Gas: Development Potential and Water Management Issues and Laws, by Mary Tiemann et al. This
report also addresses the management of water withdrawals from streams, lakes and aquifers. For a discussion of the
“discharge” requirements under the Clean Water Act, 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. EPA
has initiated a rulemaking to control the discharge of wastewater produced by CBM and shale gas extraction. See EPA
website, Effluent Guidelines (Clean Water Act section 304(m)): 2010 Effluent Guidelines Program Plan,
http://water.epa.gov/lawsregs/lawsguidance/cwa/304m/.
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traditionally given to fracturing compounds across the states. In most cases that have been
investigated, regulators typically have attributed groundwater contamination incidents to poor
well construction or surface activities, rather than the specific hydraulic fracturing process.
Responding to a 2009 survey, major oil and gas producing states reported that the hydraulic
fracturing process had not been linked directly to groundwater contamination. Nonetheless,
contamination incidents attributed to poor well construction have raised concerns regarding the
adequacy and/or enforcement of state well construction regulations (covering, for example,
cementing, casing, and blowout prevention) for purposes of managing oil and gas development
that is increasingly dependent on fracturing. Moreover, many who express concern about the
potential water problems associated with hydraulic fracturing do not differentiate between the
fracturing process and associated stages of unconventional oil and gas development and
production.24
A key barrier to better understanding groundwater contamination risks that may be associated
with hydraulic fracturing has been the lack of scientific studies to assess the practice and related
complaints. In 2009, Congress urged EPA to conduct a study on the relationship between
hydraulic fracturing and drinking water.25 The agency expects to report on the interim research
results in 2012, and issue a follow-up report in 2014. Other studies also are being conducted. A
2012 shale gas study by the Energy Institute at the University of Texas26 concluded that,
[T]here is at present little or no evidence of groundwater contamination from hydraulic
fracturing of shales at normal depths.27 No evidence of chemicals from hydraulic fracturing
fluid has been found in aquifers as a result of fracturing operations.
Regarding claims of water well impacts from shale gas development (mainly involving methane,
turbidity, odor, and chemical contaminants), the report notes that such constituents in many cases
were present before shale gas development, “but often there is insufficient baseline (pre-drilling)
sampling or monitoring to establish the impacts of drilling fracturing, and other operations.”28
The authors identified changes in well-water quality that may be caused by shale gas
development in the absence of any construction or operation problems with a gas well:
24 A recent study found that many individuals interviewed for the study defined ‘hydraulic fracturing’ much more
broadly than the industry meaning of the term (i.e., 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/.
25 The Department of the Interior, Environment, and Related Agencies Appropriations Act, 2010. P.L. 111-88, H.Rept.
111-316.
26 Charles G. Groat, and Thomas W. Grimshaw, et al, Fact-Based Regulation for Environmental Protection in Shale
Gas Development, p. 19. The researchers also found that: (1) many reports of groundwater contamination occur in
conventional oil and gas operation (e.g., failure of well-bore casing and cementing) and are not unique to hydraulic
fracturing; (2) surface spills of hydraulic fracturing fluids appear to pose greater risks to groundwater resources; (3)
methane found in water wells in some shale gas areas can most likely be traced to natural sources and likely was
present before shale gas operations began; and (4) blowouts—uncontrolled fluid releases during well construction or
operation—are rare, but subsurface blowouts appear to be under-reported. See summary document, Separating Fact
from Fiction in Shale Gas Development, Energy Institute, February 2012, http://www.energy.utexas.edu.
27 The report also noted that, “apparently in some cases, such as the Pavilion area, Wyoming, fracturing has been
performed at depths shallower than normal for shale gas wells, which are typically more than 2,000 or 3,000 feet deep.”
28 Id. p. 18.
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It appears that many of the water quality changes observed in water wells in a similar time
frame as shale gas operations may be due to mobilization of constituents that were already
present in the wells by energy (vibrations and pressure pulses) put into the ground during
drilling and other operations rather than by hydraulic fracturing fluids or leakage from the
well casing. As the vibrations and pressure changes disturb the wells, accumulated particles
of iron and manganese oxides, as well as other materials on the casing wall and well bottom,
may become agitated into suspension causing changes in color (red, orange or gold),
increasing turbidity, and release of odors.29
In addition to scientific and information gaps, regulatory issues contribute to uncertainty over a
possible legislative or regulatory framework that might be developed for hydraulic fracturing
activities under SDWA. A basic issue is whether the current EPA program fits. EPA developed the
underground injection control (UIC) program primarily to regulate wells that received fluids
injected for the long term or for enhanced recovery operations, but excluded oil and gas
production wells. This distinction could raise regulatory challenges and the possibility that the
agency may need to develop an essentially new framework to address hydraulic fracturing of
production wells. In May 2012, EPA issued draft guidance for fracturing operations that involve
diesel fuels.30 This guidance may indicate how the agency might approach the broader regulation
of hydraulic fracturing. (See discussion under “EPA Guidance on SDWA Regulation of Hydraulic
Fracturing Using Diesel Fuels.”)
This report reviews past and proposed treatment of hydraulic fracturing under the SDWA, the
principal federal statute for regulating the underground injection of fluids to protect groundwater
sources of drinking water. It reviews current SDWA provisions for regulating underground
injection activities and discusses some possible implications of, and issues associated with,
enactment of legislation authorizing EPA to regulate hydraulic fracturing under this statute. This
report also discusses recent developments among the states to address the growing reliance on
high-volume hydraulic fracturing, which may add insight to the possible implications of proposed
federal legislation and any subsequent regulations.
The Safe Drinking Water Act and the Federal Role
in Regulation of Underground Injection
Review of Relevant SDWA UIC Provisions
To evaluate studies and any new federal or state action, it is helpful to understand the existing
statutory and regulatory framework. Most public water systems and nearly all rural residents rely
on groundwater as a source of drinking water. Because of the nationwide importance of
underground sources of drinking water, Congress included groundwater protection provisions in
the 1974 Safe Drinking Water Act. The SDWA, among other things, directs the EPA to regulate
the underground injection of fluids (including solids, liquids, and gases) to protect underground
sources of drinking water.31
29 Id.
30 Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels—Draft: Underground
Injection Control Program Guidance #84, 77 Fed. Reg. 27,451 (May 10, 2012).
31 The Safe Drinking Water Act of 1974 (P.L. 93-523) authorized the UIC program at EPA. UIC provisions are
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Part C of the SDWA establishes the national regulatory program for the protection of underground
sources of drinking water, including the oversight and limitation of underground injections that
could affect aquifers through the establishment of underground injection control regulations. Key
UIC requirements and exceptions contained in SDWA, Part C, include:
• Section 1421 of the SDWA directs the EPA Administrator to promulgate
regulations for state UIC programs, and mandates that the EPA regulations
“contain minimum requirements for programs to prevent underground injection
that endangers drinking water sources.” Section 1421(b)(2) specifies that EPA:
may not prescribe requirements for state UIC programs which interfere with or impede—(A)
the underground injection of brine or other fluids which are brought to the surface in
connection with oil or natural gas production or natural gas storage operations, or (B) any
underground injection for the secondary or tertiary recovery of oil or natural gas, unless such
requirements are essential to assure that underground sources of drinking water will not be
endangered by such injection.32 [emphasis added]
• Section 1421(d), as amended by Energy Policy Act of 2005 (EPAct 2005),33
specifies that the term “underground injection” as it is used in the SDWA means
the subsurface emplacement of fluids by well injection, and specifically excludes
the underground injection of fluids or propping agents associated with hydraulic
fracturing operations related to oil, gas, or geothermal production activities.34 The
use of diesel fuels in hydraulic fracturing, however, forfeits eligibility for this
exclusion from the definition of “underground injection.”35
• Section 1422 authorizes EPA to delegate primary enforcement authority
(primacy) for UIC programs to the states, provided that the state program meets
EPA requirements promulgated under Section 1421 and prohibits any
underground injection that is not authorized by a state permit or rule.36 If a state’s
UIC program plan is not approved, or the state has chosen not to assume program
responsibility, then EPA must implement the UIC program in that state.
• Section 1425 authorizes EPA to approve the portion of a state’s UIC program that
relates to “any underground injection for the secondary or tertiary recovery of oil
or natural gas” if the state program meets certain requirements of Section 1421
and represents an effective program to prevent underground injection which
endangers drinking water sources.37 Under this provision, states may demonstrate
(...continued)
contained in SDWA Part C, §§1421-1426; 42 U.S.C. §§300h-300h-5.
32 42 U.S.C. §300h(b)(2).
33 P.L. 109-58, §322.
34 42 U.S.C. §300h(d).
35 Id.
36 42 U.S.C. §300h-1. The minimum requirements for a state UIC program can be found at 40 C.F.R. Part 145.
37 42 U.S.C. §300h-4. SDWA Section 1425 was added by the Safe Drinking Water Act Amendments of 1980, P.L. 96-
502. The House committee report accompanying the legislation that added Section 1425 noted that:
Most of the 32 states that regulate underground injection related to the recovery or production of oil
or natural gas (or both) believe they have programs already in place that meet the minimum
requirements of the Act including the prevention of underground injection which endangers
drinking water sources. This is especially true of the major producing states where underground
injection control programs have been underway for years. It is the Committee’s intent that states
(continued...)
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to EPA that their existing programs for oil and gas injection wells are effective in
preventing endangerment of underground sources of drinking water. This
provides states with an alternative to meeting the specific requirements contained
in EPA regulations promulgated under Section 1421.38 (See discussion on p. 11.)
• Section 1423 authorizes EPA enforcement actions for UIC regulatory violations.
• Section 1431 applies broadly to the SDWA and grants the EPA Administrator
emergency powers to issue orders and commence civil actions to protect public
water systems or underground sources of drinking water.39
• Section 1449, another broadly applicable SDWA provision, authorizes citizen
civil actions against persons allegedly in violation of the act’s enforceable
requirements, or against EPA for allegedly failing to perform a duty. State-
administered oil and gas programs may not have such provisions, so this could
represent an expansion in the ability of citizens to challenge administration of
statutes and regulations related to hydraulic fracturing and drinking water, were
the hydraulic fracturing exemption provision to be repealed.
The “Endangerment” Standard
As noted, the SDWA states that UIC regulations must “contain minimum requirements for
effective programs to prevent underground injection which endangers drinking water sources.”40
Known as the “endangerment standard,” this statutory standard is a major driving force in EPA
regulation of underground injection.
The endangerment language focuses on protecting groundwater that is used or may be used to
supply public water systems. This focus parallels the general scope of the statute, which addresses
the quality of water provided by public water systems and does not address private, residential
wells. The endangerment language has raised questions as to whether EPA regulations can reach
underground injection activities to protect groundwater that is not used by public water systems.
(...continued)
should be able to continue these programs unencumbered with additional Federal requirements if
they demonstrate that they meet the requirements of the Act. (U.S. House of Representatives,
Committee on Interstate and Foreign Commerce, Safe Drinking Water Act Amendments, H. Rept.
96-1348 to accompany H.R. 8117, 96th Congress, 2d Session, September 19, 1980, p. 5.)
38 SDWA Section 1425 requires a state to demonstrate that its UIC program meets the requirements of Section
1421(b)(1)(A) through (D) and represents an effective program (including adequate record keeping and reporting) to
prevent underground injection which endangers underground sources of drinking water. To receive approval under
Section 1425’s optional demonstration provisions, a state program must include permitting, inspection, monitoring, and
record-keeping and reporting requirements.
39 42 U.S.C. §300i. The Administrator may take action when information is received that (1) a contaminant is present in
or is likely to enter a public drinking water supply system or underground source of drinking water “which may present
an imminent and substantial endangerment to the health of persons,” and (2) the appropriate state or local officials have
not taken adequate action to protect such persons.
40 42 U.S.C. §300h(b)(1).
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Defining “Underground Source of Drinking Water”
The SDWA directs EPA to protect against endangerment of an “underground source of drinking
water” (USDW). The statute defines a USDW to mean an aquifer or part of an aquifer that either
• supplies a public water system, or
• contains a sufficient quantity of groundwater to supply a public water system;41
and
• currently supplies drinking water for human consumption; or
• contains fewer than 10,000 milligrams per liter (mg/L) total dissolved solids;
and
• is not an “exempted aquifer.”42
In a 2004 report on hydraulic fracturing of coalbed methane reservoirs, the agency further noted
that the “EPA also assumes that all aquifers contain sufficient quantity of groundwater to supply a
public water system, unless proven otherwise through empirical data.”43 However, because these
expanded agency characterizations of what constitutes a USDW are not included in SDWA or
related regulation, and, therefore, are not binding on the agency, it is uncertain how they might be
applied in future situations. Notably, the SDWA does not prohibit states from establishing
requirements that are stricter than federal requirements, and many states have their own
definitions and classifications for groundwater resources.
Underground Injection Control Regulatory Program Overview
To implement the UIC program as mandated by the provisions of the SDWA described above,
EPA has established six classes of underground injection wells based on categories of materials
that are injected into the ground by each class. In addition to the similarity of fluids injected in
each class of wells, each class shares similar construction, injection depth, design, and operating
techniques. The wells within a class are required to meet a set of appropriate performance criteria
for protecting underground sources of drinking water (USDW). The six well categories are briefly
described below, including the estimated number of wells nationwide.44
41 EPA further explained this requirement in a 1993 memorandum which provided that “[t]o better quantify the
definition of USDW, EPA determined that any aquifer yielding more than 1 gallon per minute can be expected to
provide sufficient quantity of water to serve a public water system and therefore falls under the definition of a USDW.”
EPA Memorandum: Assistance on Compliance of 40 CFR Part 191 with Ground Water Protection Standards. From
James R. Elder, Director, Office of Ground Water and Drinking Water, to Margo T. Oge, Director, Office of Radiation
and Indoor Air, June 4, 1993.
42 §40 C.F.R. 144.3. According to EPA regulations, an exempted aquifer is an aquifer, or a portion of an aquifer, that
meets the criteria for a USDW, for which protection has been waived under the UIC program. Under 40 C.F.R. Part
146.4, an aquifer may be exempted if it is not currently being used—and will not be used in the future—as a drinking
water source, or it is not reasonably expected to supply a public water system due to a high total dissolved solids
content. The SDWA does not mention aquifer exemption, but EPA explains that without aquifer exemptions, certain
types of energy production, mining, or waste disposal into USDWs would be prohibited. EPA, typically at the Region
level, makes the final determination on granting all exemptions.
43 U.S. Environmental Protection Agency, Evaluation of Impacts to Underground Sources of Drinking Water by
Hydraulic Fracturing of Coalbed Methane Reservoirs, EPA 816-R-04-003, June 2004, pp. 1-5.
44 Regulatory requirements for state UIC programs are established in 40 C.F.R. §§144-147.
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• Class I wells inject hazardous wastes, industrial non-hazardous liquids, or
municipal wastewater beneath the lowermost USDW. (There are 650 such wells
regulated as Class I wells in the United States.) The most stringent UIC
regulations apply to these wells.
• Class II wells inject brines and other fluids associated with oil and gas
production, and hydrocarbons for storage. The wells inject fluids beneath the
lowermost USDW (151,000 wells). Section 1425, which allows states to apply
their own regulations in lieu of EPA regulations, applies to Class II wells.
• Class III wells inject fluids associated with solution mining of minerals (e.g., salt
and uranium) beneath the lowermost USDW (21,400 wells).
• Class IV wells inject hazardous or radioactive wastes into or above USDWs.
These wells are banned unless authorized under a federal or state groundwater
remediation project (24 wells).
• Class V includes all injection wells not included in Classes I-IV, including
experimental wells. Class V wells frequently inject non-hazardous fluids into or
above USDWs and are typically shallow, on-site disposal systems. However,
some deep Class V wells inject below USDWs (500,000-650,000).45
• Class VI wells: In 2010, EPA issued a rule establishing Class VI wells, to be used
for the geologic sequestration of carbon dioxide (0).
The UIC regulatory program includes the following broad elements: site characterization, area of
review, well construction, well operation, site monitoring, well plugging and post-injection site
care, public participation, and financial responsibility. While the six classes broadly share similar
regulatory requirements, those for Class I wells are the most comprehensive and stringent. Table
1 outlines the shared minimum technical requirements for Class I, II, and III wells.
Table 1. Minimum Federal Technical Requirements for Class I, II, and III Wells
Permitting Requirements Common to Class I, II, and III Wells
Demonstration that casing and cementing are adequate to prevent movement of fluid into or between USDWs.
Cement bond logs are often needed to evaluate/verify the adequacy of the cementing records.
Financial assurances (bond, letter of credit, or other adequate assurance) that the owner or operator will maintain
financial responsibility to properly plug and abandon the wells.
A maximum operating pressure calculated to avoid initiating and/or propagating fractures that would allow fluid
movement into a USDW.
Monitoring and reporting requirements.
Requirement that all permitted (and rule authorized) wells which fail mechanical integrity be shut in immediately. A
well may not resume injection until mechanical integrity has been demonstrated.
Schedule for demonstrating mechanical integrity (at least every five years for Class I nonhazardous, Class II, and Class
III salt recovery wells).a
Al permitted injection wel s, which have had the tubing disturbed, must have a pressure test to demonstrate
mechanical integrity.
45 U.S. Environmental Protection Agency, Underground Injection Control Program, Classes of Wells,
http://water.epa.gov/type/groundwater/uic/wells.cfm. The inventory of Class V wells is incomplete.
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Permitting Requirements Common to Class I, II, and III Wells
Plans for plugging and abandonment. All Class I, II, and III wells must be plugged with cement.
Source: U.S. EPA Technical Program Overview: Underground Injection Control Regulations, EPA 816-R-02-025,
December 2002, p. 65.
a. Class I hazardous wells must demonstrate mechanical integrity once a year.
Class II Wells
Because this discussion of hydraulic fracturing is related to oil and gas production, this report
focuses primarily on regulatory requirements for Class II wells rather than other categories of
wells in EPA’s UIC program. If authorized or mandated to regulate hydraulic fracturing broadly
under SDWA, EPA might regulate hydraulic fracturing as a Class II activity, which would parallel
its approach for regulating the injection of diesel for fracturing purposes. However, it is possible
that EPA could classify oil and gas production wells that are hydraulically fractured under a
different class, or develop an entirely new regulatory structure or subclass of wells.46
A Class II well may be used to dispose of brines (salt water) and other fluids associated with oil
and gas production or storage, to store natural gas, or to inject fluids for enhanced oil and gas
recovery. EPA estimates that some 80% of Class II wells are enhanced recovery (ER) wells.
These wells inject brine, water, stream polymers, or carbon dioxide primarily into oil-bearing
formations (also called secondary or tertiary recovery). Enhanced recovery wells are separate
from, and typically surrounded by, production wells.47 Table 2 outlines basic requirements for
Class II wells.
Table 2. Minimum EPA Regulatory Requirements for Class II Wells
Requirement Explanation
Permit Required
Yes, except for existing Enhanced Oil Recovery (EOR) wel s authorized by
rule
Life of Permit
Specific period, may be for life of well
Area of Review
New wel s—¼ mile fixed radius or radius of endangerment
Mechanical Integrity Test (MIT)
Internal MIT: prior to operation, and pressure test or alternative at least
Required
once every five years for internal well integrity. External MIT: cement
records may be used in lieu of logs.
Other Tests
Annual fluid chemistry and other tests as needed/required by permit
Monitoring
Injection pressure, flow rate and cumulative volume, observed weekly for
disposal and monthly for enhanced recovery
Reporting Annual
Source: U.S. Environmental Protection Agency, Technical Program Overview: Underground Injection Control
Regulations, EPA 816-R-02-025, July 2001, p. 11, 67, and Appendix E.
46 Regulations for wells related to oil and gas production (Class II wells) are located at 40 C.F.R. Parts 144 and 146.
47 EPA historically has differentiated Class II wells from production wells. The agency’s UIC website states that
“[p]roduction wells bring oil and gas to the surface; the UIC Program did not regulate production wells.” U.S.
Environmental Protection Agency, Class II Wells—Oil and Gas Related Injection Wells (Class II), “What are the types
of Class II wells?,” http://water.epa.gov/type/groundwater/uic/class2/index.cfm.
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State Primacy for UIC Program Administration
SDWA Section 1422 authorizes EPA to delegate primary enforcement authority for the UIC
program to the states for any or all classes of wells, provided that the state program meets EPA
requirements promulgated under Section 1421 and prohibits underground injection that is not
authorized by permit of rule; otherwise, EPA must implement the UIC program in that state.
Thirty-three states have assumed primacy for the UIC program, EPA has lead implementation
authority in 10 states, and authority is shared in the remaining states. EPA directly implements the
entire UIC program in several oil and gas producing states, including Kentucky, Michigan, New
York, Pennsylvania, and Virginia.48 Figure 2 identifies state primacy status for the UIC program.
Figure 2. Primacy Status for EPA’s UIC Program
Source: U.S. Environmental Protection Agency, available at http://www.epa.gov/safewater/uic/primacy.html.
As noted, for oil and gas related injection operations, under Section 1425, a state may be
delegated primary enforcement authority without meeting EPA regulatory requirements for state
UIC programs promulgated under Section 1421, provided the state demonstrates that it has an
effective program that prevents underground injection that endangers drinking water sources. EPA
has issued guidance for approval of state programs under Section 1425.49 If directed by Congress
48 To receive primacy, a state, territory, or Indian tribe must demonstrate to EPA that its UIC program is at least as
stringent as the federal standards; the state, territory, or tribal UIC requirements may be more stringent than the federal
requirements. For Class II wells, states must demonstrate that their programs are effective in preventing endangerment
of underground sources of drinking water (USDWs). Requirements for state UIC programs are established in 40 C.F.R.
§§144-147.
49 U.S. Environmental Protection Agency, Guidance for State Submissions under Section 1425 of the Safe Drinking
(continued...)
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to regulate hydraulic fracturing as underground injection, this regulatory approach could give
states significant flexibility and thus might reduce potential regulatory costs, redundancy, and
other possible impacts to the industry and the states.50 EPA’s draft guidance on the use of diesel
fuels in fracturing fluids does not require revision or review of state UIC programs.
Most oil and gas producing states exercise primary enforcement authority for injection wells
associated with oil and gas production (Class II wells) under SDWA Section 1425. Among these
states, Alaska, California, Colorado, Indiana, Montana, and South Dakota have received primacy
only for Class II wells, while EPA administers the remainder of the UIC program (Class I, III, IV,
and V wells) for these states. Table 3 lists states that regulate Class II wells under Section 1425.
Table 3. States Regulating Oil and Gas (Class II) UIC Wells
Under SDWA Section 1425
Alabama Louisiana
Oklahoma
Alaska Mississippi Oregon
Arkansas Missouri
South
Dakota
California Montana
Texas
Colorado Nebraska
Utah
Illinois
New Mexico
West Virginia
Indiana North
Dakota
Wyoming
Kansas Ohio
Source: Adapted from information provided by U.S. Environmental Protection Agency.
Note: With primacy granted under Section 1425, states regulate Class II wel s using their own program
requirements rather than following EPA regulations, providing significant regulatory flexibility to the states. EPA
notes that state requirements “can be, and often are, more stringent than minimum federal standards.”
Underground Injection Control 101, Permitting Guidance for Hydraulic Fracturing Using Diesel Fuels, Technical
Webinars, May 9-16, 2011.
Table 4. States Where EPA Implements the UIC Class II Program
Shale Gas Producing States
Others
Pennsylvania Arizona
New York
District of Columbia
Michigan Florida
Kentucky Hawai
(...continued)
Water Act, Ground Water Program Guidance #19, p. 20, http://www.epa.gov/safewater/uic/pdfs/guidance/
guide_uic_guidance-19_primacy_app.pdf.
50 The House report for the 1980 Safe Drinking Water Act Amendments, H.R. 8117, which established Section 1425,
states that “So long as the statutory requirements are met, the states are not obligated to show that their programs mirror
either procedurally or substantively the Administrator’s regulations.” H. Report to accompany H.R. 8117, No. 96-1348,
September 19, 1980, p. 5.
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Tennessee Iowa
Virginia Minnesota
Multiple tribes, few territories
Source: U.S. Environmental Protection Agency, May 22, 2012
Notes: Numerous states (e.g., Arizona, Maryland, New Jersey, and North Carolina) have no Class II wells.
The Debate over Regulation of Hydraulic Fracturing
Under the SDWA
From the date of the enactment of the SDWA in 1974 until the late 1990s, hydraulic fracturing
was not regulated under the act by EPA or the states tasked with administration of the SDWA.
However, in the last 15 years a number of developments have called into question the extent to
which hydraulic fracturing should be considered an “underground injection” to be regulated under
the SDWA. One trigger for this debate was a challenge to the Alabama UIC program brought by
the Legal Environmental Assistance Foundation (LEAF).
The LEAF Challenge to the Alabama UIC Program and
EPA’s Interpretation of the SDWA
In 1994, LEAF petitioned EPA to initiate proceedings to have the agency withdraw its approval of
the Alabama UIC program because the program did not regulate hydraulic fracturing operations
in the state associated with production of methane gas from coalbed formations.51 The state of
Alabama had previously been authorized by EPA to administer a UIC program pursuant to the
terms of the SDWA.52 EPA denied the LEAF petition in 1995 based on a finding that hydraulic
fracturing did not fall within the definition of “underground injection” as the term was used in the
SDWA and the EPA regulations promulgated under that act.53 According to EPA, that term
applied only to wells whose “principal function” was the placement of fluids underground.54
LEAF challenged EPA’s denial of its petition in the U.S. Court of Appeals for the Eleventh
Circuit, arguing that EPA’s interpretation of the terms in question was inconsistent with the
language of the SDWA.55
The court rejected EPA’s claim that the language of the SDWA allowed it to regulate only those
wells whose “principal function” was the injection of fluids into the ground. EPA based this claim
on what it perceived as “ambiguity” in the SDWA regarding the definition of “underground
injection” as well as a perceived congressional intent to exclude wells with primarily non-
51 Legal Environmental Assistance Foundation, Inc. v. U.S. Environmental Protection Agency, 118F.3d 1467, 1471
(11th Cir. 1997) (“LEAF I”).
52 Id. at 1470.
53 Id. at 1471.
54 Id.
55 Id. at 1472,
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injection functions.56 The court held that there was no ambiguity in the SDWA’s definition of
“underground injection” as “the subsurface emplacement of fluids by well injection,” noting that
the words have a clear meaning and that:
The process of hydraulic fracturing obviously falls within this definition, as it involves the
subsurface emplacement of fluids by forcing them into cracks in the ground through a well.
Nothing in the statutory definition suggests that EPA has the authority to exclude from the
reach of the regulations an activity (i.e. hydraulic fracturing) which unquestionably falls
within the plain meaning of the definition, on the basis that the well that is used to achieve
that activity is also used—even primarily used—for another activity (i.e. methane gas
production) that does not constitute underground injection.57
The court therefore remanded the decision to EPA for reconsideration of LEAF’s petition for
withdrawal of Alabama’s UIC program approval.58
Alabama’s Regulation of Hydraulic Fracturing in CBM Production
Consideration of Alabama’s UIC program after the LEAF I decision was issued in 1997 is a
helpful case study. It is useful in assessing exactly how EPA authorized a state to regulate
hydraulic fracturing under the SDWA “Class” well system, understanding the regulatory options
available to EPA and the states authorized to enforce SDWA programs, and evaluating the
industry impact resulting from the requirement that hydraulic fracturing be regulated under a UIC
program.
Following the LEAF I decision and EPA’s initiation of proceedings to withdraw its approval of
Alabama’s Class II UIC program, in 1999 Alabama submitted a revised UIC program to EPA.59
The revised UIC program sought approval under Section 1425 of the SDWA rather than Section
1422(b). As discussed above, Section 1425 differs from Section 1422(b) in that approval under
Section 1425 is based on a showing by the state that the program meets the generic requirements
found in Section 1421(b)(1)(A)-(D) of the SDWA and that the program “represents an effective
program (including adequate recordkeeping and reporting) to prevent underground injection
which endangers drinking water sources.”60 In contrast, approval of a state program under Section
1422(b) requires a showing that the state’s program satisfies the requirements of the UIC
regulations promulgated by EPA.61 In its decision on the challenge to EPA’s approval of
Alabama’s revised UIC program, the U.S. Court of Appeals for the Eleventh Circuit observed that
“the practical difference between the two statutory methods for approval is that the requirements
for those programs covered under § 1425 are more flexible than the requirements for those
programs covered under § 1422(b).”62
56 Id. at 1473-74.
57 Id. at 1474-75.
58 Id. at 1478.
59 See 64 Fed. Reg. 56986 (October 22, 1999).
60 42 U.S.C. §300h-4(a).
61 Id. at §300h-1(b)(1)(A).
62 Legal Environmental Assistance Foundation, Inc. v. U.S. Environmental Protection Agency, 276 F.3d 1253, 1257
(11th Cir. 2001) (LEAF II).
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EPA approved Alabama’s revised UIC program under Section 1425 in 2000.63 LEAF appealed
EPA’s decision to the U.S. Court of Appeals for the Eleventh Circuit. LEAF made three
arguments. First, LEAF claimed that EPA should not have approved state regulation of hydraulic
fracturing under Section 1425 because it does not “relate to ... underground injection for the
secondary or tertiary recovery of oil or natural gas,” one of the requirements for approval under
Section 1425.64 The court rejected this argument, finding that the phrase “relates to” was broad
and ambiguous enough to include regulation of hydraulic fracturing as being related to secondary
or tertiary recovery of oil or natural gas.65
Second, LEAF challenged the Alabama program’s regulation of hydraulic fracturing as “Class II-
like” wells not subject to the same regulatory requirements as Class II wells.66 The court agreed
with LEAF on this point, noting that in its decision in LEAF I, it had held that methane gas
production wells used for hydraulic fracturing are “wells” within the meaning of the statute.67 As
a result, the court found that wells used for hydraulic fracturing must fall under one of the five
classes set forth in the EPA regulations at 40 C.F.R. Section 144.6.68 Specifically, the court found
that the injection of hydraulic fracturing fluids for recovery of coalbed methane “fit squarely
within the definition of Class II wells,” and as a result the court remanded the matter to EPA for a
determination of whether Alabama’s updated UIC program complied with the requirements for
Class II wells.69
Finally, LEAF alleged that even if Alabama’s revised UIC program was eligible for approval
under Section 1425 of the SDWA, EPA’s decision to approve it was “arbitrary and capricious”
and therefore a violation of the Administrative Procedure Act.70 The court rejected this
argument.71
Among other provisions added in response to the Eleventh Circuit’s decisions, the Alabama
regulations prohibited fracturing “in a manner that would allow the movement of fluid containing
any contaminant into a USDW, if the presence of the contaminant may (a) cause a violation of
any applicable primary drinking water standard; or (b) otherwise adversely affect the health of
persons.”72 The state regulations further required state approvals (but not permits) prior to
individual fracturing jobs. Specifically, well operators were required to certify in writing, with
supporting evidence, that a proposed hydraulic fracturing operation would not occur in a USDW,
or that the mixture of fracturing fluids would meet EPA drinking water standards. Regulations
also prohibited fracturing at depths shallower than 399 feet (most drinking water wells rely on
shallow aquifers) and prohibited the use of diesel oil or fuel in any fracturing fluid mixture. The
requirements regarding minimum depths and the diesel ban remain in place, but the rules no
longer require that injection fluids meet drinking water standards. Instead, “each coal bed shall be
63 65 Fed. Reg. 2889 (October 2000).
64 Id. at 1256.
65 Id. at 1259-61.
66 Id. at 1256.
67 Id. at 1262.
68 Id. at 1263.
69 Id. at 1263-64.
70 Id. at 1256 (referring to 5 U.S.C. §706(2)(A).
71 Id. at 1265.
72 Ala. Admin. Code, r. 400-3-8-.03(4), (2002). Responding to EPAct 2005 (see below), the state made some revisions
to its regulations for hydraulic fracturing of coal beds in 2007. Ala. Admin. Code r. 400-3-8-.03(1).
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hydraulically fractured so as not to cause irreparable damage to the coalbed methane (CBM) well,
or to adversely impact any fresh water supply well or any fresh water resources.”73
With hydraulic fracturing regulations in place, CBM development in Alabama continued. In 2009,
a member of the State Oil and Gas Board of Alabama noted, “since Alabama adopted its
hydraulic fracturing regulations, coalbed operators have submitted thousands of hydraulic
fracturing proposals and engaged in thousands of hydraulic fracturing operations.”74
The number of CBM well permits increased in the years following the adoption of revised
regulations.75 However, it is not clear whether, or by how much, the number of wells, the
production costs, or the time required by operators may have been different without the
revisions.76 One of the requirements of the Alabama regulations in response to LEAF I was that
fracturing fluids had to meet tap water standards where fracturing would occur within an
underground source of drinking water. To ensure compliance, operators purchased water from
municipal water supplies that were in compliance with federal drinking water standards to use for
fracturing wells. Industry representatives have noted that if this approach were adopted for
hydraulic fracturing nationwide, it would not only raise costs, but potentially put companies in
competition with communities for drinking water supplies.
Some concern has been expressed that if Congress passed legislation requiring federal regulation
of hydraulic fracturing broadly,77 a separate permit might be required each time a well is
hydraulically fractured, thus repeatedly disrupting oil and gas production activities. In Alabama,
in response to LEAF I, the state did not require a permit for each fracturing operation, but rather
had operators give notice and receive approval before fracturing. To further facilitate approvals
for hydraulic fracturing, service companies identified to the state chemicals contained in various
fracturing fluid mixtures that met the regulatory requirement that the mixtures not exceed federal
drinking water standards. A well operator then could select from a list of pre-approved hydraulic
fracturing fluids and provide the product name to the state, rather than have to submit separate
analyses. Alabama regulations apply this approach where fracturing would occur within an
underground source of drinking water.
EPA’s 2004 Review of Hydraulic Fracturing for CBM Production
In response to the LEAF I decision, citizen reports of water well contamination attributed to
hydraulic fracturing of coal beds, and the rapid growth in CBM development, EPA undertook a
study to evaluate the environmental risks to underground sources of drinking water from
hydraulic fracturing practices associated with CBM production. EPA issued a draft report in
August 2002.78 The draft report identified water quality and quantity problems that individuals
73 Ala. Admin. Code r. 400-3-8-.03(1).
74 S. Marvin Rogers, State Oil and Gas Board of Alabama and Chairman, IOGCC Legal and Regulatory Affairs
Committee, History of Litigation Concerning Hydraulic Fracturing to Produce Coalbed Methane, January 2009, p. 5.
75 Ala. Admin. Code r. 400-3-8-.03(6)(a), 2002. To mitigate its increased administrative costs associated with
implementation of the added regulations, operators pay a fee of $175 for each coalbed group fractured.
76 A representative of the Alabama Coalbed Methane Association noted that the costs of hydraulic fracturing are very
site specific and vary with operators as well as geology.
77 Currently, EPA has authority to regulate only the use of diesel fuel in fracturing operations.
78 U.S. Environmental Protection Agency. Draft Evaluation of Impacts to Underground Sources of Drinking Water by
Hydraulic Fracturing of Coalbed Methane Reservoirs. EOA 816-D-02-006, August 2002.
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had attributed to hydraulic fracturing of coal beds in Alabama, New Mexico, Colorado, Wyoming,
Montana, Virginia, and West Virginia.79 Based on the preliminary results of the study, EPA
tentatively concluded that the potential threats to public health posed by hydraulic fracturing of
coalbed methane wells appeared to be small and did not justify additional study or regulation.
EPA also reviewed whether direct injection of fracturing fluids into underground sources of
drinking water posed any threat. EPA reviewed 11 major coalbed methane formations to
determine whether coal seams lay within USDWs. EPA determined that 10 of the 11 producing
coal basins “definitely or likely lie entirely or partially within USDWs.”
In January 2003, the EPA’s National Drinking Water Advisory Council submitted to the EPA
Administrator a report on hydraulic fracturing, underground injection control, and coalbed
methane production and its impacts on water quality and water resources. The Council noted
concerns regarding (1) the lack of resources to implement the UIC program, (2) the use of diesel
fuel and potentially toxic additives in the hydraulic fracturing process, (3) the potential impact of
coalbed methane development on local underground water resources and the quality of surface
waters, and (4) the maintenance of EPA regulatory authority within the UIC program.80
In 2004, EPA issued a final version of the 2002 draft report, based primarily on an assessment of
the available literature and extensive interviews, and concluded that the injection of hydraulic
fracturing fluids into CBM wells posed little threat to underground sources of drinking water and
required no further study. However, EPA found that very little documented research had been
done on the environmental impacts of injecting fracturing fluids.81 Additionally, EPA had
discussed the use of diesel fuel in fracturing fluids in the 2002 draft report, and concluded in the
final report that “The use of diesel fuel in fracturing fluids poses the greatest potential threat to
USDWs because the BTEX constituents in diesel fuel exceed the MCL [maximum contaminant
level] at the point-of-injection.”82
EPA also noted that estimating the concentration of diesel fuel components and other fracturing
fluids beyond the point of injection was beyond the scope of its study.83 Moreover, the EPA study
focused specifically on CBM wells and did not review the use of hydraulic fracturing in other
geologic formations, such as the Marcellus Shale or other tight oil and gas formations.
To address concerns about the use of diesel fuel in hydraulic fracturing fluids, EPA entered into
an agreement with three companies that provided roughly 95% of hydraulic fracturing services
(BJ Services, Halliburton Energy Services, and Schlumberger Technology Corporation). Under
79 Id., p. 6-20-6-21.
80 National Drinking Water Advisory Council. Report on Hydraulic Fracturing and Underground Injection Control and
Coalbed Methane by the National Drinking Water Advisory Council Resulting from a Conference Call Meeting Held
December 12, 2002. Washington DC.
81 U.S. Environmental Protection Agency, Evaluation of Impacts to Underground Sources of Drinking Water by
Hydraulic Fracturing of Coalbed Methane Reservoirs, Final Report, EPA-816-04-003, Washington, D.C., June 2004,
p. 4-1.
82 Evaluation of Impacts to USDWs by Hydraulic Fracturing of Coalbed Methane Reservoirs, Final Report, p. 4-19.
83 Id. p. 4-12. BTEX is the term for benzene, toluene, ethylbenzene and xylene, which are compounds typically found
in petroleum product, such as gasoline and diesel fuel. These compounds are common indicators of gasoline, diesel, or
other petroleum product contamination.
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this agreement, the firms agreed to remove diesel fuel from CBM fluids injected directly into
drinking water sources if cost-effective alternatives were available.84
EPAct 2005: A Legislative Exemption for
Hydraulic Fracturing
The decision by the U.S. Court of Appeals for the Eleventh Circuit in LEAF I highlighted a
debate over whether the SDWA, as it read at the time, required EPA to regulate hydraulic
fracturing. Although the Eleventh Circuit’s decision applied only to hydraulic fracturing for
coalbed methane production in Alabama, the court’s reasoning—in particular, its finding that
hydraulic fracturing “unquestionably falls within the plain meaning of the definition [of
underground injection]”85—raised the issue of whether EPA could be required to regulate
hydraulic fracturing under the SDWA.
Before this question was resolved through agency action or litigation, Congress passed an
amendment to the SDWA as a part of EPAct 2005 (P.L. 109-58) that addressed this issue. Section
322 of EPAct 2005 amended the definition of “underground injection” in the SDWA as follows:
The term “underground injection”—(A) means the subsurface emplacement of fluids by
well injection; and (B) excludes—(i) the underground injection of natural gas for purposes of
storage; and (ii) the underground injection of fluids or propping agents (other than diesel
fuels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal
production activities.
This amendment clarified that the UIC requirements found in the SDWA do not apply to
hydraulic fracturing, although the exclusion does not extend to the use of diesel fuel in hydraulic
fracturing operations. This amended language is the definition of “underground injection” found
in the SDWA as of the date of this report.
EPA Guidance on SDWA Regulation of Hydraulic Fracturing Using
Diesel Fuels
As noted above, the 2005 amendment to the definition of “underground injection” in the SDWA
excluded injections as part of hydraulic fracturing operations, but such injections involving the
use of diesel fuels were not made part of the exclusion, meaning that injections for purposes of
hydraulic fracturing involving the use of diesel fuel might still be made subject to regulation
under the SDWA. It was not clear to states or the regulated community how EPA would address
the EPAct 2005 amendment, and for several years EPA took no official position regarding the
regulation of hydraulic fracturing using diesel fuel under the SDWA.86 In May of 2012, EPA
84 Memorandum of Agreement Between the United States Environmental Protection Agency and BJ Services Company,
Halliburton Energy Services, Inc., and Schlumberger Technology Corporation, December 12, 2003.
85 LEAF I, 118 F.3d at 1475.
86 In January 2011, an investigation led by Representatives Waxman, Markey and DeGette of the House Committee on
Energy and Commerce found that, “oil and gas service companies have injected over 32 million gallons of diesel fuel
or hydraulic fracturing fluids containing diesel fuel in wells in 19 states between 2005 and 2009.”
http://democrats.energycommerce.house.gov/index.php?q=news/waxman-markey-and-degette-investigation-finds-
(continued...)
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issued draft UIC program permitting guidance for hydraulic fracturing injection activities where
diesel fuels are used in fluids or propping agents.87 The proposed guidance is intended for EPA
permit writers and is relevant where EPA directly implements the UIC Class II program.
In the proposed guidance, EPA states its interpretation that “oil and gas hydraulic fracturing
operations using diesel fuels as a fracturing fluid, or as a component of a fracturing fluid .... are
subject to UIC Class II permitting requirements.”88 As described earlier in this report, injections
subject to UIC Class II requirements must comply with a number of regulatory requirements.
These include permitting requirements, and testing and monitoring obligations with respect to the
well. If this proposed guidance is adopted as “final,” EPA UIC program administrators would be
expected to apply it going forward in their permitting of Class II wells. EPA noted in the proposed
guidance that “[t]o the extent that states may choose to follow some aspects of EPA guidance in
implementing their own programs, it may also be relevant in areas where EPA is not the
permitting authority.”89
A key issue regards how EPA may define “diesel fuels” in the final guidance. The draft guidance
recommends using six Chemical Abstracts Service Registry Numbers (CASRNs) for determining
whether diesel fuels are used in hydraulic fracturing operations.90 These six CASRNs collectively
include various types of diesel fuels, home heating oils, kerosene, crude oil, and a range of other
petroleum compounds.91 The draft also includes alternative descriptions of diesel that are broader
in scope. Also at issue is whether the final guidance will specify a de minimus amount of diesel
fuel content for hydraulic fracturing fluids; the draft guidance does not do so. EPA plans to
develop a final guidance document in 2013.
Proposed Legislation in the 112th Congress
In March 2011, the Fracturing Responsibility and Awareness of Chemicals Act of 2011 (FRAC
Act), H.R. 1084 and S. 587, was introduced in the Senate and the House of Representatives.92 The
bills have some minor language differences, but are substantially similar. (They also are similar to
bills introduced in the previous Congress.) Each contains two amendments to the SDWA—one
that would amend the definition of underground injection to include hydraulic fracturing, and
(...continued)
continued-use-of-diesel-in-hydraulic-fracturing-f/
87 Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels—Draft: Underground
Injection Control Program Guidance #84, 77 Fed. Reg. 27,451 (May 10, 2012). The draft describes how UIC Class II
requirements may be tailored to address the risks of diesel fuel injections. Comment period deadline: August 23, 2012.
88 Id.
89 Id at 27,542.
90 EPA explains that “diesel fuels may be used in hydraulic fracturing operations as a primary base (or carrier) fluid, or
added to hydraulic fracturing fluids as a component of a chemical additive to adjust fluid properties (e.g., viscosity and
lubricity) or act as a solvent to aid in the delivery of gelling agents. Some chemicals of concern often occur in diesel
fuels as impurities or additives. Benzene, toluene, ethylbenzene, and xylene compounds (BTEX) are highly mobile in
ground water and are regulated under national primary drinking water regulations because of the risks they pose to
human health.” Source: FACT SHEET: Underground Injection Control (UIC) Program Permitting Guidance for Oil
and Gas Hydraulic Fracturing Activities Using Diesel Fuels, UIC Program Guidance #84 – Draft, EPA 816-K-12-001.
91 Id at 27,453.EPA explains that these CASRNs were selected “because either their primary name, or their common
synonyms contained the term “diesel fuel” and they meet the chemical and physical properties “diesel fuel” as provided
in the Toxic Substances Control Act (TSCA) Inventory.
92 H.R. 1084, S. 587.
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another that would create a new disclosure requirement for the chemicals used in hydraulic
fracturing.
FRAC Act
H.R. 1084 provides that the definition of “underground injection” that was amended in 2005 to
exclude most hydraulic fracturing would be amended once again to include “the underground
injection of fluids or propping agents pursuant to hydraulic fracturing operations related to oil,
gas or geothermal production activities,” excluding injection of natural gas for subsurface
storage.93 This would not only repeal the amended definition of “underground injection” that was
enacted as part of EPAct 2005 which excluded hydraulic fracturing, but would essentially codify
the court’s decision in LEAF I and clear up any ambiguity regarding regulation of hydraulic
fracturing under the SDWA.
The second amendment to the SDWA in the FRAC Act would create a new hydraulic fracturing
disclosure requirement.94 H.R. 1084 would create a new statutory obligation requiring anyone
conducting hydraulic fracturing to:
disclose to the State (or the [EPA] if the [EPA] has primary enforcement responsibility in the
State)—(I) prior to the commencement of any hydraulic fracturing operations at any lease
area of portion thereof, a list of chemicals intended for use in any underground injection
during such operations, including identification of the chemical constituents of mixtures,
Chemical Abstracts Service numbers for each chemical and constituent, material safety data
sheets when available, and the anticipated volume of each chemical; and (II) not later than 30
days after the end of any hydraulic fracturing operations the list of chemicals used in each
underground injection during such operations, including identification of the chemical
constituents of mixtures, Chemical Abstracts Service numbers for each chemical and
constituent, material safety data sheets when available, and the volume of each chemical
used.95
The bill would also require that the state or EPA “make the disclosure of chemical constituents ...
available to the public, including by posting the information on an appropriate Internet Web site,”
and the bill clarifies that the disclosure requirements “do not authorize the State (or the [EPA]) to
require the public disclosure of proprietary information.”96 In other words, the disclosure
requirements address only the chemicals used, not the manner of their use or the amounts or
ratios in which they are used. This language attempts to protect proprietary business information,
that is, “secret” formulas or practices that drilling companies may feel they should not be required
to disclose to their competitors. Some state oil and gas production statutes and regulations extend
similar protections for proprietary business information, while still requiring disclosure to
regulators of the chemical constituents being used in hydraulic fracturing.97
93 H.R. 1084, at §2(a). S. 587 is similar but does not include geothermal production activities.
94 For a detailed review of state and federal chemical disclosure developments, see CRS Report R42461, Hydraulic
Fracturing: Chemical Disclosure Requirements, by Brandon J. Murrill and Adam Vann.
95 Id. at §2(b).
96 Id.
97 In 2008, for example, the Colorado Oil and Gas Conservation Commission promulgated regulations requiring
operators to maintain inventories of chemicals stored onsite for use downhole, and to provide a list of the chemicals of
“trade secret chemical products” to commission officials upon request. Operators are also required to disclose chemical
information to treating medical professionals. (2 Colo. Code Regs. §404-1:205).
(continued...)
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Furthermore, the FRAC Act would require operators to disclose proprietary chemical information
to treating medical professionals in cases of medical emergencies.98 Although most state oil and
gas rules do not require disclosure of proprietary chemical information to medical professionals,
such disclosure broadly parallels federal requirements under the Occupational Safety and Health
Act (OSHAct).99 Nonetheless, the OSHAct requirements were not designed for environmental
investigations and have been criticized as deficient for this purpose. Calls for disclosure of
hydraulic fracturing chemicals have increased as homeowners and others express concern about
the potential presence of unknown chemicals in tainted well water near oil and gas operations.
FRESH Act
Introduced in March 2012, the Fracturing Regulations are Effective in State Hands Act (FRESH
Act), S. 2248 and H.R. 4322, would specify that a state has sole authority to regulate hydraulic
fracturing on federal lands within the boundaries of the state. This legislation comes after the
President announced in his 2012 State of the Union address that he would require “all companies
that drill for gas on public lands to disclose the chemicals they use.” In May 2012, the Bureau of
(...continued)
Wyoming is another state that did not wait for the federal government to adopt disclosure requirements for persons
engaged in hydraulic fracturing. On September 15, 2010, the Wyoming Oil and Gas Conservation Commission
(WOGCC) promulgated its own set of hydraulic fracturing disclosure requirements. In accordance with these
regulations, drilling operators are required to:
• identify all water supply wells within one-quarter mile of the drilling activity as well as the depth from which
water is being appropriated (Wyo. Rules and Regs. Oil Gen §3-8);
• provide stimulation fluid information to the WOGCC on its Application for Permit to Drill, as part of a
comprehensive drilling/completion/recompletion plan, or on a separate notice (Wyo. Rules and Regs. Oil Gen §3-
45(a));
• provide geological names, geological description and depth of the formation into which well stimulation fluids
are to be injected (Wyo. Rules and Regs. Oil Gen §3-45(c));
• provide to an WOGCC Supervisor, for each stage of the well stimulation program, the chemical additives,
compounds and concentrations or rates proposed to be mixed and injected, including (i) stimulation fluid
identified by additive type; (ii) the chemical compound name and Chemical Abstracts Service (CAS) number of
any constituents; and (iii) the proposed rate or concentration for each additive. The WOGCC Supervisor is also
authorized to request additional information as deemed appropriate (Wyo. Rules and Regs. Oil Gen §3-45(d)).
• provide a detailed description of the proposed well stimulation design, which shall include (i) the anticipated
surface treating pressure range; (ii) the maximum injection treating pressure; and (iii) the estimated or calculated
fracture length and fracture height.
The regulations prohibit the underground injection of “volatile organic compounds, such as benzene, toluene,
ethylbenzene and xylene, also known as BTEX compounds or any petroleum distillates, into groundwater.” (Wyo.
Rules and Regs. Oil Gen. §3-45(g)). The regulations do state that confidentiality protection will be provided for “trade
secrets, privileged information and confidential commercial, financial, geological or geophysical data furnished by or
obtained from any person.” (Wyo. Rules and Regs. Oil Gen. §3-45(f)). There also are logging requirements applicable
to post-well stimulation (Wyo. Rules and Regs. Oil Gen. §3-45(h)).
98 H.R. 1084, §2(b).
99 The Occupational Safety and Health Administration has promulgated a set of regulations under Occupational Safety
and Health Act (OSHAct), referred to as the Hazard Communication Standard (29 C.F.R. §1910.1200). Additionally,
OSHAct regulations require operators to maintain Material Safety Data Sheets (MSDS) for hazardous chemicals at the
job site. The federal Emergency Planning and Community Right to Know Act (EPCRA) requires that facility owners
submit an MSDS for each hazardous chemical present that exceeds an EPA-determined threshold level, or a list of such
chemicals, to the local emergency planning committee (LEPC), the state emergency response commission, and the
local fire department. For non-proprietary information, EPCRA generally requires a LEPC to provide an MSDS to a
member of the public on request.
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Land Management (BLM) proposed a rule to require public disclosure of chemicals used in
hydraulic fracturing on BLM managed lands.100 The proposed rule also would tighten regulations
related to well-bore integrity, and add new reporting and management requirements for water
used in hydraulic fracturing. The proposal would require operators to submit to BLM detailed
information on their proposed well stimulation plans (such as expected volume of fluid to be
used, injection pressures, estimated fracture length, and plans for treating flowback), and
following hydraulic fracturing operations, operators would be required to submit updated
information and disclose the chemicals used.101
Potential Implications of Hydraulic Fracturing Regulation Under
the SDWA
The full regulation of hydraulic fracturing under the SDWA (i.e., beyond injections involving
diesel) potentially could have significant, but currently unknowable, environmental benefits as
well as impacts on oil and natural gas producers and state and federal regulators. Resulting
groundwater protection and public health benefits would likely be experienced most significantly
in any states that may have relatively weak groundwater protection requirements (such as
substandard cementing and casing requirements, or allowing injection of hydraulic fracturing
fluids directly into or adjacent to USDWs). Alternatively, the possible benefits of federal
regulation would likely be reduced to the degree that states currently have effective groundwater
protection requirements, or respond to increased development of unconventional gas and oil
resources with their own revised requirements.
The regulation of the underground injection of fluids for hydraulic fracturing purposes would not
address surface management of chemicals or drilling wastes, or the treatment and disposal of
produced water. If such surface activities were determined to be the sources of most water
contamination incidents associated with unconventional oil and gas development, then federal
regulation of hydraulic fracturing under the SDWA may have limited environmental and public
health benefits.
Regulations requiring chemical disclosure could also be beneficial. The lack of information
regarding chemicals used in hydraulic fracturing has made investigations of contamination
difficult in some cases, because well owners and state regulators typically do not know which
chemicals to test for to determine whether a fracturing fluid has migrated into a water source.102
The Ground Water Protection Council and Interstate Oil and Gas Compact Commission (IOGCC)
have established a public registry where companies may voluntarily identify chemicals used in
hydraulic fracturing in individual wells (http://www.fracfocus.org). Figure 3 identifies states that
have adopted chemical disclosure requirements.
100 Department of the Interior, Bureau of Land Management, "Oil and Gas; Well Stimulation, Including Hydraulic
Fracturing, on Federal and Indian Lands," 77 Federal Register 27691, May 11, 2012. (On federal lands, the Bureau of
Land Management, within the Department of the Interior, administers leasing and coordinates planning and permitting
with other federal agencies, as appropriate.)
101 Mike Soraghan, Hydraulic Fracturing: BLM Proposes More Disclosure than Most States, Greenwire, February 6,
2012. For further discussion, see CRS Report R42461, Hydraulic Fracturing: Chemical Disclosure Requirements, by
Brandon J. Murrill and Adam Vann.
102 As noted, the BLM has proposed amending its oil and gas regulations to require chemical disclosure after fracturing
operations.
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Figure 3. Hydraulic Fracturing Chemical Disclosure by State
Source: Ground Water Protection Council, June 2012
Notes: GWPC reports that legislation is pending in California, Massachusetts, New York, and North Carolina.
If the SDWA were amended to authorize (but not mandate) EPA to regulate hydraulic fracturing,
EPA might undertake further study to assess the potential risks of hydraulic fracturing to
underground sources of drinking water. (The agency currently is conducting such studies, as
discussed below.) Subsequently, EPA might determine the need for, and potential scope of, any
new regulations, and decide whether to adapt the existing regulatory framework or to develop a
new approach under the UIC program. The rulemaking process typically takes several years. A
2009 presentation by EPA’s Region 8 UIC program explained that, if legislative change occurs
additional study may take place, regulations may be written by EPA, some combination of
these may happen, [and] there may be a phased-in approach. If regulations are developed,
they typically include: establishing a regulation development workgroup which can include
the public; a proposed regulation, including opportunity for public comment (and one or
more hearings if needed); a final regulation, including opportunity for judicial appeals; and
an effective date for the regulation.103
One implication of regulating hydraulic fracturing under SDWA relates to the SDWA’s citizen suit
provisions. As noted, Section 1449 provides for citizen civil actions against any person or agency
allegedly in violation of provisions of SDWA, or against the EPA Administrator for alleged failure
103 U.S. Environmental Protection Agency, Region 8, Hydraulic Fracturing, Presentation, Underground Injection
Control Program Meeting, Glenwood Springs, Colorado, August 8, 2009.
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to perform any action or duty that is not discretionary.104 This provision could represent an
expansion in the ability of citizens to challenge state administration of oil and gas programs
related to hydraulic fracturing and drinking water, were the hydraulic fracturing exemption
provision to be repealed.
As discussed, the SDWA currently includes two options for approving state UIC programs related
to oil and gas recovery.105 Under the less restrictive requirements of Section 1425, EPA may be
able to implement new requirements primarily through guidance and review and approval of state
programs revised to address hydraulic fracturing. EPA used this approach when ordered to require
Alabama to regulate hydraulic fracturing of coal beds, and a federal district court approved this
approach. For regulating the use of diesel fuel in hydraulic fracturing, EPA has drafted guidance
for EPA permit writers, but has not proposed any new requirements nor has the agency proposed
to review state programs.
If EPA decided to allow states to regulate hydraulic fracturing under Section 1425, the agency
also might write new hydraulic fracturing regulations under Section 1421 for states, such as North
Carolina, that exercise primacy under Section 1422. Regardless of regulatory approach, new
requirements would likely require substantially more resources for UIC program administration
and enforcement by the states and EPA.
The possible impacts of enacting legislation directing EPA to regulate hydraulic fracturing could
vary for different oil and gas production operations. The SDWA directs EPA, when developing
UIC regulations, to take into consideration “varying geologic, hydrological, or historical
conditions in different States and in different areas within a State.”106 Consequently, if EPA were
to regulate hydraulic fracturing broadly under the SDWA, the agency conceivably could establish
different requirements to address such differences among states or regions. If practical and
applicable, EPA might find this statutory flexibility helpful, as the USDW contamination risks of
hydraulic fracturing could vary widely among different formations and settings. For example,
fracturing a coal bed that may qualify as a USDW poses very different groundwater
contamination risks than fracturing a shale formation that is widely separated from any USDW.107
Thus, the possible application and impact of federal regulations might vary significantly in
different formations, and the impacts and potential environmental benefits would likely be
greatest in such coal beds or other formations occurring in or near USDWs.108 However, the
agency has not used the flexibility in the past and might broadly apply new requirements, such as
those related to well construction and cementing, and mechanical integrity testing, to protect
USDWs through which wells may pass, among other purposes.
104 §1449; 42 U.S.C. 300j-8.
105 In the case concerning Alabama, the Eleventh Circuit Court of Appeals ruled that “EPA’s decision to subject
hydraulic fracturing to approval under § 1425 rests upon a permissible construction of the Safe Drinking Water Act.”
Legal Environmental Assistance Fund v. Environmental Protection Agency, State Oil and Gas Board of Alabama, 276
F.3d 1253 (11th Cir. 2001).
106 §1421(b)(3)(A); 42 U.S.C. 300h(b)(3)(A).
107 Because coal beds frequently are sources of drinking water, the Alabama State Oil and Gas Board requires well
operators to certify that a proposed hydraulic fracturing operation would not occur in a USDW, or that the mixture of
fracturing fluids would meet EPA drinking water standards. State rules also prohibit fracturing at depths shallower than
399 feet, as most drinking water wells rely on shallow aquifers.
108 U.S. Department of Energy Office of Fossil Energy and National Technology Laboratory, Modern Shale Gas
Development in the United States: A Primer, DE-FG26-04NT15455, April 2009, http://fossil.energy.gov/programs/
oilgas/publications/naturalgas_general/Shale_Gas_Primer_2009.pdf.
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For the oil and gas industry, regulation of hydraulic fracturing under the UIC program could have
a range of impacts. In some states, oil and gas operations are subject to regulation by a state oil
and gas agency or commission as well as an environmental or public health agency. Industry
representatives have expressed concern over the potential for some duplication of requirements
from state oil and gas regulators and environmental regulators. Delays in issuing permits and
commensurate delays in well stimulation and gas marketing are among the concerns. The citizen
suit provision of the SDWA also may be an issue. One analysis attempting to measure the
economic and energy effects of potential regulation noted that
Experience suggests that there will be a reduction in the number of wells completed each
year due to increased regulation and its impact on the additional time needed to file permits,
push-back of drilling schedules due to higher costs, increased chance of litigation, injunction
or other delay tactics used by opposing groups and availability of fracturing monitoring
services.109
Several studies have attempted to estimate the potential economic and energy supply impact of
regulating hydraulic fracturing under the federal UIC program. A 2009 study prepared by a
consultant for DOE estimated the costs associated with “a stringent set of potential federal
requirements” including (1) obtaining a permit; (2) conducting an area of review assessment; (3)
performing in-situ stress analysis; (4) conducting three-dimension fracture simulation; (5)
monitoring; (6) mapping fractures, or conducting other post-fracture analysis; (7) for some wells
(perhaps 10%), performing state-of-the-art down-hole fracture imaging; and (8) additional cement
to ensure isolation of the target zone before fracturing.110 Based on these assumed elements of a
regulatory program, the study estimated that the compliance costs for regulating hydraulic
fracturing for oil and gas development would be $100,505 for new wells receiving hydraulic
fracturing treatment.111
A stringent regulatory program under Section 1422 arguably could include many of the above
requirements. However, it is unknown what EPA might require and unclear what costs would be
attributed to federal regulation. Some activities already are used in the industry or required by
states (e.g., well cementing across all groundwater zones).112 EPA UIC staff note that some of the
requirements assumed in the study have never been a part of the federal UIC regulations. Other
effects that are not easily quantified include the costs associated with waiting periods between
fracturing jobs for approvals and other potential disruptions to operations. Notably, most states
implement the oil and gas UIC program using their own rules, as authorized under Section 1425.
109 IHS Global Insight, Measuring the Economic and Energy Impacts of Proposals to Regulate Hydraulic Fracturing,
Task 1 Report, Prepared for the American Petroleum Institute, Lexington, MA, 2009, p. 7.
110 Advanced Resources International, Inc., Potential Economic and Energy Supply Impacts of Proposals to Modify
Federal Environmental Laws Applicable to the U.S. Oil and Gas Exploration and Production Industry, U.S.
Department of Energy, Office of Fossil Energy, January 2009. The authors note that cost estimates are based on a 1999
memorandum prepared for DOE, from Robin Petrusak, ICF Consulting to Nancy Johnson, U.S. Department of Energy,
“Documentation of Estimated Potential Cost of Compliance for Toxic Release Inventory (TRI) Reporting and
Hydraulic Fracturing,” August 19, 1999.
111 Id. p. 25-26.
112 In discussing lessons learned from developing the Barnett shale industry consultants recently reported that an
“important factor, requiring 3D seismic [imaging], is the avoidance of geo-hazards, such as water-bearing karsts and
faults.” Scott Stevens and Vello Kuuskraa, Advanced Resources International, Inc., “Gas Shale-1: Seven Plays
Dominate North America Activity,” Oil & Gas Journal, vol. 107, no. 36 (September 28, 2009), p. 41.
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The Ground Water Protection Council,113 representing state agencies, has opposed reclassification
of hydraulic fracturing as a permitted activity under the UIC programs, stating that (1) a risk has
not been identified, and thus, there is no evidence that [UIC] regulation is necessary; and (2) UIC
regulation would divert resources from higher risk activities.114 The legislatures of major oil and
gas producing states, including the states of Alabama, Alaska, Montana, North Dakota, Wyoming,
and Texas, passed and sent to Congress resolutions asking Congress not to extend SDWA
jurisdiction over hydraulic fracturing activities.
As discussed, the GWPC has recommended the adoption of various best management practices to
strengthen protection of water resources when developing oil and gas resources. The American
Petroleum Institute (API) has developed best practices for hydraulic fracturing and well
construction, and some states reference these standards in regulation.115 In other states, some
companies apply API best practices independent of regulation; however, voluntary industry
practices can not be enforced, and there is no assurance that they would be widely adopted.
If authorized, EPA regulation of hydraulic fracturing under the SDWA UIC program would not
address many significant public concerns often associated with the development of
unconventional oil and gas resources. These concerns involve land surface disturbances
associated with the development of roads, well pads, and natural gas gathering pipelines;
potential impacts of water withdrawal and consumption; treatment and disposal of flowback
water to surface waters; air quality impacts; noise; etc. Some of these activities are subject to
other federal laws, such as Clean Water Act requirements covering the treatment and discharge of
produced water into surface waters. The state and federal regulatory requirements for treatment
and discharge of produced water may have a more significant impact on the industry than
possible UIC-related requirements.116 Other impacts related to development of unconventional oil
and gas resources are highly visible and may raise more concern than the specific process of deep
underground fracturing of oil and gas formations. Some of these issues (particularly land-use and
facility siting issues) are beyond the reach of federal regulation, and thus, are left to state and
local governments to address. New York State’s Revised Draft Supplemental Generic
Environmental Impact Statement is one example of a state taking a comprehensive approach to
addressing a broad range of possible environmental impacts that could be associated with
Marcellus Shale development.117
113 The GWPC is a national association representing state groundwater and UIC agencies whose mission is to promote
protection and conservation of groundwater resources for beneficial uses. The stated purpose of the GWPC is “to
promote and ensure the use of best management practices and fair but effective laws regarding comprehensive ground
water protection.” http://www.gwpc.org/about_us/about_us.htm.
114 Statement of Scott Kell, for the Ground Water Protection Council, House Committee on Natural Resources,
Subcommittee on Energy and Mineral Resources, Oversight Hearing on “Unconventional Fuels, Part I: Shale Gas
Potential,” June 4, 2009.
115 American Petroleum Institute, Hydraulic Fracturing, http://www.api.org/policy/exploration/hydraulicfracturing.
116 U.S. Department of Energy, Office of Fossil Energy and National Technology Laboratory, Modern Shale Gas
Development in the United States: A Primer p. 29-42.
117 New York imposed a temporary moratorium on unconventional gas drilling until the state can update oil and gas
regulations to govern development of the Marcellus Shale and other tight shale formations in the state using hydraulic
fracturing combined with directional drilling. See New York State Department of Environmental Conservation and
Division of Mineral Resources, Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas
and Solution Mining Regulatory Program: Well Permit Issuance for Horizontal Drilling and High-Volume Hydraulic
Fracturing to Develop the Marcellus Shale and Other Low-Permeability Gas Reservoirs, September 2011,
http://www.dec.ny.gov/energy/75370.html.
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State Regulation of Hydraulic Fracturing
While the federal government currently exempts most hydraulic fracturing activity from
regulation under the SDWA, the states are free to regulate the practice as they see fit. Although
state oil and gas regulatory programs initially focused on managing petroleum reservoirs,
efficient production, and addressing mineral rights issues, these programs have become more
environmentally focused through the decades. The GWPC and the Interstate Oil and Gas
Compact Commission (IOGCC)118 each report that the major oil and gas producing states now
have laws and regulatory requirements in place to protect water resources during oil and natural
gas exploration and production activities.
Both the GWPC and the IOGCC oppose federal regulation of hydraulic fracturing, noting that
this process is regulated by the states, sometimes specifically, but most often through general oil
and gas production regulations, policies, and practices.119 The IOGCC notes that member states
have adopted comprehensive laws and regulations to provide for safe operations and to protect
the nation’s drinking water sources, and that these states have trained personnel with expertise to
effectively regulate oil and gas exploration and production, thus making the states the best-suited
regulators of hydraulic fracturing. The IOGCC further makes the case for keeping responsibility
with the states:
Hydraulic fracturing is currently, and has been for decades, a common operation used in
exploration and production by the oil and gas industry in all gas producing states. Because of
the unique position of the states and their collective expertise on matters concerning the oil
and gas industry, regulation of hydraulic fracturing should remain the responsibility of the
States. The States have as much of a vested interest in the protection of groundwater as the
federal government and as such, will continue to regulate the process effectively and
efficiently, taking into account the particulars of the geology and hydrology within their
boundaries. There is not a “one-size fits all” approach to effective regulation.120
However, hydraulic fracturing methods and technologies have changed significantly over time as
they have been applied to more challenging formations, increasing markedly the amount of water
and fracturing fluids used, and well pressures involved in production operations. The question
that has arisen is whether state oil and gas programs effectively address increasing groundwater
protection concerns arising with the heightened concentration and broadened geographic extent of
oil and gas resource development that relies on hydraulic fracturing in combination with deep
horizontal drilling.121 As noted, various states recently have revised, or are considering revisions
118 The Interstate Oil and Gas Compact Commission represents the state oil and gas agencies. The commission was
established in the 1930s, initially to reduce the waste of oil during exploration and production by developing model
statutes and practices to improve the conservation of oil resources.
119 The GWPC passed a resolution in 2003 encouraging Congress to clarify the definition of underground injection in
Part C of SDWA to exclude the practice of hydraulic fracturing. http://www.gwpc.org/advocacy/documents/
resolutions/RES-03-5.htm.
120 Further policy positions and information can be found at the IOGCC website: http://www.iogcc.org/hydraulic-
fracturing.
121 Hydraulic fracturing is used commonly used for gas production in conventional formations as well as
unconventional formations. Wyoming, for example, reported that in 2008, 100% (1,316) of new conventional gas wells
were fracture stimulated, many wells with multi-zone stimulations in each well bore, some staged, and some individual
fracture stimulations. Source: Wyoming Oil and Gas Conservation Commission. The Commission rules require
operators to receive approval prior to hydraulic fracturing treatments. Operators are required to provide detailed
information regarding the fracturing process, including the source of water and/or trade name fluids, type of proppants,
(continued...)
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to their oil and gas exploration and production laws and regulations in response to new types and
levels of natural gas production, and specifically to increase protection of water resources.
A related issue concerns the extent to which state oil and gas agencies coordinate adequately with
their water pollution control counterparts. Most states have different agencies administering oil
and gas programs and environmental programs. State UIC programs often are administered by the
environmental agency, while oil and gas exploration and production activities are overseen by
separate oil and gas entities. Moreover, with the exception of Alabama, which acted in response
to a court ruling, no state has chosen to regulate hydraulic fracturing as part of its EPA-authorized
underground injection control program.122
GWPC Review of State Regulations
Although states have extensive regimes in place to manage oil and gas development activities, the
GWPC also noted that related state groundwater protection regulations, policies, and practices
can be uneven. In 2009, the GWPC published a review of state oil and gas regulations designed to
protect water resources for the 27 major oil and gas producing states.123 Based on this review, the
GWPC concluded that, in general, state oil and gas regulations are adequately designed to protect
water resources. Among the states, requirements to protect water resources covered permitting,
well drilling, and construction (e.g., casing, cementing, and test pressure requirements), well
closure and abandonment, and waste fluid management.
While few states explicitly mentioned hydraulic fracturing in their regulations, many had well
drilling, construction, completion, and reporting requirements intended to protect ground and
surface water resources. For example, 10 major producing states required reporting of chemicals
used in well treatments, 25 states required operators to submit well treatment (including
fracturing) reports, and 22 states require operators to cement across groundwater zones. State
requirements vary greatly, from the specific requirements that were adopted in Alabama to more
general mandates not to harm water resources (e.g., Arizona oil and gas rules require operators to
“conduct operations in a manner that prevents oil, gas, salt water, fracturing fluid or any other
substance from polluting any surface or subsurface waters”).124
While finding that most states had an extensive array of permitting and operating requirements
for oil and gas wells, the GWPC also noted that some states lacked important provisions in their
programs. For example, most, but not all, states had well construction requirements that include
provisions for cementing above oil or gas producing zones and across groundwater zones. The
GWPC made a series of recommendations to strengthen state programs to protect water
(...continued)
and estimated pump pressures. After a treatment is complete, the operator must provide fracturing data and production
results.
122 In October 2007, in response to the 2005 Energy Policy Act, Alabama revised its Class II UIC program to once
again exclude hydraulic fracturing. The state retains most hydraulic fracturing requirements which it administers under
its oil and gas regulatory regime.
123 Ground Water Protection Council, U.S. Department of Energy, Office of Fossil Energy, National Energy
Technology Laboratory, State Oil and Natural Gas Regulations Designed to Protect Water Resources, May 2009, p.
124 More details of state rules are included in the more detailed Regulations Reference Document accompanying the
GWPC report, State Oil and Natural Gas Regulations Designed to Protect Water Resources, http://www.gwpc.org/e-
library/e_library_list.htm. Various states (e.g., CO, MT, ND, OH, PA, TX, WY) have since revised their rules.
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resources. States vary widely in requirements for well integrity testing, cement specifications,
baseline testing of nearby water wells, and other groundwater protection practices. A sample of
findings and recommendations from the GWPC review follows:
• State oil and gas regulations are adequately designed to directly protect water
resources through the application of specific program elements such as
permitting, well construction, well plugging, and temporary abandonment
requirements.
• Some exploration and production (E&P) activities have caused contamination of
both surface and groundwater. Past practices related to pit construction, well
cementing and operation, and well plugging were not always adequate to prevent
migration of contaminants to surface and groundwater.
• Hydraulic fracturing in oil or gas bearing zones that occur in non-exempt
USDWs should be either stopped, or restricted to the use of materials that do not
pose a risk of endangering groundwater and do not have the potential to cause
human health effects (e.g., fresh water, sand, etc.).
• Hydraulic fracturing of deep zones poses little to no risk of groundwater
contamination.
• States should review current regulations in several program areas to determine
whether they meet an appropriate level of specificity (e.g., use of standard
cements, plugging materials, pit liners, siting criteria, and tank construction
standards, etc.).
• Comprehensive studies should be undertaken to determine the relative risk to
groundwater resources from the practice of shallow hydraulic fracturing. These
studies should be used, with current knowledge, to develop a generic set of best
management practices (BMPs) for hydraulic fracturing which state agencies
could use either to develop state specific BMPs or develop additional state
regulations.
• Many states split jurisdiction between oil and gas and water quality or pollution
control agencies over some aspects of oil and gas regulation including tanks, pits,
waste handling, and spills. Where split jurisdiction of oil and gas operations
exists, formal memoranda of agreement and regulatory implementation plans
should be negotiated.125
• States should consider requiring companies to submit a list of additives used in
formation fracturing and their concentration within the fracture fluid matrix.
Further, states that do not currently regulate handling and disposal of fracture
fluid additives and constituents recovered during recycling operations should
consider the need to develop such regulations.
125 Four states reported to GWPC that agencies other than the oil and gas authority are involved in the permit review
process, either by requirement or upon request of the oil and gas agency. In 2008, Colorado revised its oil and gas
regulations to allow for greater public participation in permitting and environmental assessment of oil and gas field
sites. This expanded participation includes review by other state water protection agencies. GWPC (2009).
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• A state program review process, conducted by the national nonprofit group, State
Review of Oil and Natural Gas Environmental Regulations (STRONGER),126
should be recognized as an effective tool for assessing the capability of state
programs to manage E&P waste and measure program improvement over time.
• Best Management Practices that can be adapted to each state should be developed
to manage hydraulic fracturing. STRONGER should evaluate whether to update
its mission to include environmental elements of state oil and gas programs
beyond the traditional area of E&P waste [to include hydraulic fracturing].
(STRONGER issued hydraulic fracturing guidelines in February 2010, and
review teams are using the guidelines to the evaluate oil and gas regulatory
programs of states that have volunteered to be reviewed.)127
Various states have determined that the growing development of unconventional oil and gas
resources, along with the increased use of hydraulic fracturing and directional drilling, requires
more state oversight. Some states are responding by increasing staff resource levels. And in some
states, including Colorado, North Dakota, New York, Ohio, Pennsylvania, Texas, West Virginia,
and Wyoming, this expansion has prompted a reassessment and revision of oil and gas production
regulations and policies. Common changes include new requirements for cementing, casing,
pressure testing, and chemical disclosure. Colorado’s rules, for example, include a well casing
program to protect groundwater, require well treatment and fracturing reporting, and require
operators to notify landowners at least one week before conducting various operations, including
fracturing. A number of states, including Colorado and North Dakota, require baseline testing of
nearby wells before drilling begins.
UIC Program Resources
The funding and staffing resource implications of including hydraulic fracturing under the UIC
program could be significant for regulatory agencies. Based solely on the number of wells added
to the program, the workload under Class II UIC programs could more than double. Currently,
there are approximately 146,800 Class II wells nationwide.128 In contrast, the DOE Energy
Information Administration reports that the number of gas producing wells in the United States
increased from 302,421 in 1999 to 487,100 wells in 2009, and most new wells are fractured.129
EPA’s annual appropriation includes funds for state grants to support state administration of
various EPA programs. For the past 30 years, the annual appropriations to support state UIC
programs have remained essentially flat (not accounting for inflation) at roughly $10.5 million to
126 STRONGER, Inc., State Review of Oil and Natural Gas Environmental Regulations, Inc.,
http://www.strongerinc.org. The STRONGER state review process involves teams representing industry, states,
environmental and public interest groups reviewing state oil and gas waste management programs.
127 Ground Water Protection Council, State Oil and Natural Gas Regulations Designed to Protect Water Resources, pp.
7, 39-40. STRONGER has been reviewing state programs to assess whether any revisions may be needed to address
issues surrounding the use of hydraulic fracturing in oil and gas development. Hydraulic fracturing reviews have been
conducted for Arkansas, Pennsylvania, Ohio, Louisiana, and North Carolina, Ohio, and Oklahoma.
128 U.S. Environmental Protection Agency, FY2008 Drinking Water Factoids, EPA 816-K-08-004, November, 2008,
http://www.epa.gov/safewater/databases/pdfs/data_factoids_2008.pdf.
129 EIA, Natural Gas Navigator: Number of Producing Gas Wells, August 2009, http://tonto.eia.doe.gov/dnav/ng/
ng_prod_wells_s1_a.htm.
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$11 million.130 Ten EPA regional offices and 42 states share this amount annually to administer
the full UIC program, which covers 1.7 million wells (Classes I through V) nationwide.131 In
2007, the GWPC has estimated that annual UIC program funding would need to increase to $56
million to fully meet the needs of the existing UIC program.132 The GWPC further estimated that
EPA would need to provide funding at a level of $100 million annually to meet the needs for the
full UIC program, including the regulation of geologic sequestration of carbon dioxide. Given the
large number of wells that are fractured, UIC program oversight and enforcement costs for state
agencies could be considerably higher if this process is subjected to federal UIC regulations, in
addition to state oil and gas rules. EPA and states would need to develop new regulatory
requirements for these wells and increase staff to review applications and make permitting
decisions. States and industry representatives have expressed concern that failure to provide
sufficient resources would likely create permitting backlogs. For example, under UIC regulations,
EPA or the primacy state must provide for a public hearing for each permit issuance, and have
inspectors on site.133 Some states impose permit fees or use other revenue-generating
mechanisms, while such approaches have not been embraced in other states.
Because of the sheer number of potentially newly regulated wells, EPA (given its current resource
levels) would necessarily need to rely heavily upon the states to implement this program. In 2007,
the GWPC noted that states are already struggling to fully implement their UIC programs, and
new requirements for hydraulic fracturing would be problematic. The GWPC cautioned that
without substantial increases in funding for the UIC program:
• More states would decide to return primacy to EPA (which also would require
additional funds to implement the program).
• The overall effectiveness of UIC programs would suffer as more wells and well
types are added without a concurrent addition of resources to manage them.
• Decisions regarding which parts of the program to fund with limited dollars
could result in actual damage to USDWs if higher risk/higher cost portions of the
program are put “on the back burner.”
• Negative impacts on the economy could occur as permitting times lengthen due
to increased program workloads.134
EPA resources are also at issue. The agency would require additional technically trained staff to
oversee and enforce state programs and implement the program in non-primacy states (such as
Michigan, New York, and Pennsylvania). Should some states decide not to assume primacy for
130 Congress provided $11.84 million for FY2011 and $10.85 million for FY2012.
131 Mike Nickolaus, Ground Water Protection Council, UIC Funding Presentation, Ground Water Protection Council
2007 Meeting January 23, 2007, http://www.gwpc.org/meetings/uic/2007/proceedings/Nickolaus_UIC07.pdf.
132 Ground Water Protection Council, Ground Water Report to the Nation: A Call to Action, Underground Injection
Control, Ch. 9, Oklahoma City, OK, 2007, http://www.gwpc.org. This estimate preceded EPA’s promulgation of new
UIC regulations establishing Class VI wells for geologic sequestration of carbon dioxide and EPA’s determination that
production wells that use diesel must receive a Class II permit.
133 See requirements at, for example, 40 C.F.R. 144.51(m), Requirements prior to commencing injection. Also, 40
C.F.R. Section 124.11 provides for public comments and requests for public hearings for UIC permits. The UIC
program director is required to hold a public hearing whenever he or she finds a significant degree of public interest in
a draft permit (40 C.F.R. §124.12(a)). Section 124.13 states that a comment period may need to be longer than 30 days
to allow commenters time to prepare and submit comments.
134 Mike Nickolaus, Ground Water Protection Council, UIC Funding Presentation, January 23, 2007.
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the new program, EPA’s resource challenges would increase. As with states, EPA resources are
stretched. For example, the agency is continuing its review and approval of various state Class V
UIC programs that are being revised to implement a 1999 rulemaking. Additionally, EPA
published a rule in 2010 establishing UIC requirements for the geologic sequestration of carbon
dioxide.
Federal Studies and Research
Technical and practical questions regarding the development of the shale gas and other “tight” oil
and gas resources remain unanswered. In 2009, U.S. Geological Survey (USGS) researchers
noted that while drilling and hydraulic fracturing technologies have improved over the past
several decades, “the knowledge of how this extraction might affect water resources has not kept
pace.”135 Consequently, environmental regulators, oil and gas developers, and communities have
faced new challenges and some uncertainties as these resources are developed. State regulations,
industry practices, and technologies are evolving.
The federal government has undertaken or sponsored several studies and research projects related
to hydraulic fracturing and potential water quality impacts have been initiated. In August 2009,
DOE announced that it was funding nine new research projects intended to improve methods for
treating, reusing, and managing water associated with natural gas development—including gas
from coal beds and shale. Several of these projects address hydraulic fracturing, including
projects to develop processes and technologies for pretreatment of produced brine and hydraulic
fracturing flowback waters. Another project is intended to develop a new hydraulic fracturing
module to assist regulators and operators in enhancing protective measures for source water and
streamlining the well-permitting process.136 Such research studies could help reduce water
contamination risks associated with fracturing and reduce regulatory impacts.
In EPA’s FY2010 appropriations act (P.L. 111-88), Congress directed EPA 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.137 EPA expects
to report on the interim research results in 2012, and issue a follow-up report in 2014. EPA’s Draft
Hydraulic Fracturing Study Plan states that the overall purpose of the study is to understand the
relationship between hydraulic fracturing and drinking water resources. Specifically, the study is
designed to examine conditions that may be associated with potential contamination of drinking
135 U.S. Geological Survey, Water Resources and Natural Gas Production from the Marcellus Shale, U.S. Department
of the Interior, Fact Sheet 2009-3032, May 2009, http://pubs.usgs.gov/fs/2009/3032/pdf/FS2009-3032.pdf.
136 U.S. Department of Energy, DOE Projects to Advance Environmental Science and Technology: Nine
Unconventional Natural Gas Projects Address Water Resource and Management Issues, August 19, 2009. List of
projects is available at
http://www.fossil.energy.gov/news/techlines/2009/09058-DOE_Selects_Natural_Gas_Projects.html.
137 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.
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water sources, and to identify factors that may lead to human exposure and risks. EPA has
proposed research studies that address the full lifecycle of water in hydraulic fracturing, from
water acquisition and chemical mixing, through actual fracturing and to post-fracturing stages,
including the management of flowback and produced water and its treatment and/or disposal.138
As part of the study, EPA is investigating reported incidents of drinking water contamination
where hydraulic fracturing has occurred. These retrospective case studies will be used to
determine the potential relationship between reported impacts and hydraulic fracturing activities.
Prospective case studies include sampling and water resource characterization before fracturing
occurs, and then evaluating any water quality or chemistry changes afterward. The EPA studies
may add insight regarding the risks of hydraulic fracturing as well as possible regulatory gaps in
studied locations.
The study’s breadth and associated costs have drawn attention. The draft House Appropriations
Committee report for the 2013 Department of the Interior, Environment, and Related Agencies
Appropriation Bill does not provide the requested $4.25 million increase for additional hydraulic
fracturing research. Furthermore, the draft report directs EPA to narrow the scope of study:
Hydraulic Fracturing.—In 2010, the Committee urged EPA to research whether there is a
relationship between hydraulic fracturing and drinking water. The Committee understands
EPA has incorporated a review of environmental justice impacts into this study, which the
Committee finds to be outside the scope of the 2010 language and an inappropriate use of
funds. No funds have been provided in the bill to research environmental justice impacts
related to hydraulic fracturing, and EPA shall discontinue the use of any resources that may
have been diverted to this subactivity. The Committee directs the Agency to release the
study’s findings with respect to whether there is a relationship between hydraulic fracturing
and drinking water following appropriate public comment as directed in H.Rept. 112-151
and peer review.139 (p. 48)
In March 2011, President Obama announced a broad “Blueprint for a Secure Energy Future.” In
it, the President asked the Secretary of Energy to identify steps that can 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,
including water quality.140 In November, the Secretary of Energy Advisory Board (SEAB) Shale
Gas Subcommittee issued a final report, with recommendations for state and federal governments
and industry. Water quality recommendations, aimed mainly at the states, include
138 EPA has designated the 2014 final report as a “highly influential scientific assessment” (HISA) and, thus, will
follow the peer review planning requirements described in the Office of Management and Budget’s Information
Quality Bulletin for Peer Review, December 2004,
http://www.whitehouse.gov/sites/default/files/omb/memoranda/fy2005/m05-03.pdf. The Bulletin states that important
scientific information must be peer reviewed by qualified specialists before it is disseminated by the federal
government. Also, the Bulletin applies stricter minimum requirements for the peer review of highly influential
scientific assessments (a subset of influential scientific information). Information on EPA’s hydraulic fracturing study
is available at http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/index.cfm.
139 H.Rept. 112-151 – Department of the Interior, Environment, and Related Agencies Appropriation Bill, 2012, to
accompany H.R. 2584, included the following provision: Hydraulic Fracturing.--The Committee directs the Agency to
submit the Final Draft of the Interim Study Results and any additional final study results of the Plan to Study the
Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, for Interagency Review and public comment,
consistent with the processes described in Sections 2.2 and 2.5 of the Draft Hydraulic Fracturing Study Plan released
February 7, 2011.
140 See http://www.whitehouse.gov/sites/default/files/blueprint_secure_energy_future.pdf.
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• adopting best practices for well construction (casing, cementing, and pressure
management),
• adopting requirements for background water quality measurements,
• manifesting all water transfers across various locations, and
• measuring and publicly reporting the composition of water stocks and flow
throughout the fracturing and cleanup process.
The SEAB further suggested that states review and modernize oil and gas rules and
enforcement practices.141
Concluding Observations
Hydraulic fracturing bills introduced in the 112th Congress and previously have generated
considerable debate. Many state agencies have argued against regulation of hydraulic fracturing
under the SDWA groundwater protection provisions, and note a long history of the successful use
of this practice in developing oil and gas resources. Industry representatives argue that additional
federal regulation is unnecessary and would likely slow domestic gas development and increase
energy prices. At the same time, the amount of natural gas and oil produced from formations that
rely on hydraulic fracturing continues to grow. Drilling and fracturing methods and technologies
have changed significantly over time as they have been applied to more challenging formations,
greatly increasing the amount of water, fracturing fluids, and well pressures involved in oil and
gas production operations. The increasing density of wells and geographic expansion of the use of
hydraulic fracturing, along with a growing number of citizen complaints of groundwater
contamination and other environmental problems attributed to this practice has led to calls for
greater state and/or federal environmental oversight of this activity.
Central issues in the debate concern the need for, and potential benefits of, regulation of hydraulic
fracturing under the Safe Drinking Water Act. Pollution prevention generally, and groundwater
protection in particular, is much less costly than cleanup, and where groundwater supplies are not
readily replaceable, protection becomes a high priority. Environmental regulations generally
involve internalizing costs associated with processes. And federal regulations generally are used
to address activities found to have widespread public health and environmental risks, particularly
where significant regulatory gaps and unevenness exist among the states. To the extent that a
regulation is needed and is well designed and implemented, public benefits (i.e., protecting
underground sources of drinking water) would be expected to accrue. If Congress directed EPA to
regulate fracturing under the SDWA, the environmental benefits could be significant if the risks
of contamination were significant and states were not effectively addressing those risks.
Alternatively, the benefits may be small if most pollution incidents are found to be related to
other oil and gas production activities, such as improper disposal of produced water or
mishandling of materials on the surface. Some of these issues are not subject to SDWA authority
and would not be addressed through regulation under this act. Issues related to well construction
and operation could be addressed through the UIC program.
141 U.S. Department of Energy, The Secretary of Energy Advisory Board, Shale Gas Production Subcommittee, Second
Ninety Day Report—November 18, 2011, http://www.shalegas.energy.gov/.
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Thus far, the data suggest that hydraulic fracturing—particularly in deep shales—is unlikely to
contaminate underground sources of drinking water, and most reports of contamination have been
associated with surface activities or well construction problems, not hydraulic fracturing per se.
However, while state regulators and industry practitioners define hydraulic fracturing as a specific
well stimulation operation, concerned individuals, the media, and others often use the term to
refer broadly to full the range of activities associated with unconventional oil and gas
development. The answer to the question, “is hydraulic fracturing contaminating drinking water
supplies?” may depend on how broadly one defines hydraulic fracturing.
State oil and gas and groundwater protection agencies widely support keeping responsibility for
regulating hydraulic fracturing with the states. In September 2009, the GWPC—representing state
groundwater protection agencies—approved a resolution supporting continued state regulation of
hydraulic fracturing and encouraging Congress, EPA, DOE, and others to work with the states
and the GWPC to evaluate the risks posed by hydraulic fracturing. The GWPC and others have
expressed concern that regulation of hydraulic fracturing under the SDWA would divert
compliance and enforcement resources from higher priority issues. Additionally, the IOGCC—
representing state oil and gas agencies—has adopted a resolution urging Congress not to remove
the fracturing exemption from provisions of the SDWA, noting that the process is a temporary
injection-and-recovery technique and does not fit the UIC program which EPA generally
developed to address the permanent disposal of wastes.
Nonetheless, given the critical importance of good quality water supplies to homeowners,
ranchers, and communities, and uneven regulation across the states,142 many have called for a
federal solution. It could be expected that the potential impact of federal regulations on states and
industry would be lessened (and provide fewer added benefits) to the degree that states currently
have effective requirements or respond to increased development of unconventional gas and oil
resources with their own revised requirements. In the past few years, a number of major oil and
gas producing states have revised their regulations in response to changes in the industry, while
other states currently are developing or considering new laws and regulations.
Whether state or federal, regulations require adequate resources to be administered effectively.
The sheer number of wells that rely on fracturing suggests that significant new staffing and other
resources might be needed by state and federal regulators to implement and enforce any new EPA
requirements on top of existing state requirements. States that have compatible requirements in
place to address hydraulic fracturing might not experience significant impacts.
Currently, there is little agreement as to the risks that hydraulic fracturing operations pose to
underground sources of drinking water, and Congress has directed EPA to study this matter. The
results of this and other studies could provide a better assessment of potential risks, and may help
inform the need for additional regulation—whether at the state or federal level.
In May 2012, EPA issued draft UIC program permitting guidance for hydraulic fracturing
injection activities where diesel fuels are used in fluids or propping agents diesel. The guidance is
intended for use by EPA permit writers in states where EPA directly implements the Class II UIC
program. The final diesel guidance may provide the clearest insight into how EPA might regulate
this process broadly, if Congress authorized EPA to do so.
142 See, for example, a new report by RFF Center for Energy Economics and Policy, A Review of Shale Gas
Regulations by State, http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale_Maps.aspx.
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Author Contact Information
Mary Tiemann
Adam Vann
Specialist in Environmental Policy
Legislative Attorney
mtiemann@crs.loc.gov, 7-5937
avann@crs.loc.gov, 7-6978
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