Earthquakes Induced by Underground Fluid Injection and the Federal Role in Mitigation

January 13, 2023 R47386

Earthquakes Induced by Underground Fluid
January 13, 2023
Injection and the Federal Role in Mitigation
Linda R. Rowan
Human activities, including underground fluid injection activities, may cause
Analyst in Natural
earthquakes (known as induced earthquakes). Underground fluid injection activities,
Resources and Earth
such as hydraulic fracturing for oil and gas production, enhanced oil and gas recovery
Sciences
wells, and wastewater disposal wells, have increased in the central and eastern United

States since about 2008, in part due to advancements in horizontal drilling. The number
Angela C. Jones
of earthquakes of magnitude 3.0 or greater in the same region increased from 2009 to
Analyst in Environmental
2015, and these earthquakes are correlated in space and time with injection activities.
Policy
For example, over 1,000 earthquakes of magnitude 3.0 or greater occurred in the central

and eastern United States in 2015 (more than the annual historic rate of magnitude 3.0 or

greater earthquakes of less than 25). Disposal wells induced the largest earthquake
recorded in Oklahoma, a magnitude 5.8, in 2016, causing property damage and lawsuits.
The U.S. Geological Survey (USGS), state agencies, and universities have increased seismic monitoring and
research near underground fluid injection activities since 2008 to understand what causes induced earthquakes and
to mitigate the risks of these activities. In general, one or more fluid injections may change the geologic
conditions of a fault, causing the fault to slip in an induced earthquake. Current research topics include identifying
unstable faults and understanding how injection operations may cause a fault to slip. The USGS released one-year
seismic hazard forecasts for the central and eastern United States for 2016, 2017, and 2018, which included
naturally occurring and induced earthquakes.
Under the Safe Drinking Water Act (SDWA), the U.S. Environmental Protection Agency (EPA) regulates the
underground injection of fluids to protect underground drinking water sources. EPA has issued Underground
Injection Control (UIC) regulations for six classes of injection wells. Class II wells, primarily wastewater disposal
wells, have caused most of the induced earthquakes in the central and eastern United States. SDWA authorizes
states that meet program requirements to administer the federal UIC programs in lieu of EPA, and most oil and
gas producing states administer a UIC program for their state. Although SDWA does not address seismicity, EPA
rules for certain well classes require evaluation of seismic risk. Such requirements do not apply to Class II wells;
however, EPA developed a framework for evaluating seismic risk when reviewing Class II well permit
applications in states where EPA administers the UIC program.
Although a small fraction of underground fluid injection wells, primarily disposal wells, in the central and eastern
United States may induce earthquakes, potential seismic risk persists. Federal agencies, state agencies, and other
stakeholders continue to study, monitor, regulate, and mitigate this risk. Mitigation may include stopping, pausing,
or changing underground fluid injection operations. The study of induced seismicity caused by these fluid
injection activities may inform USGS and Department of Energy (DOE) efforts to develop an understanding of
how other underground fluid injection activities may induce earthquakes, such as enhanced geothermal energy
and geologic carbon sequestration systems.
Congress may consider the adequacy of federally funded research on induced seismicity. Congress also may
consider amending the statutory authorities of the UIC program to require consideration of induced seismicity. In
addition, Congress may consider whether the federal government should have a role in regulating underground
fluid injection activities for induced seismicity and whether current EPA or DOE requirements, reports, or
guidance regarding induced seismicity from underground fluid injection activities are sufficient. Some in
Congress have expressed interest in changing regulations for hydraulic fracturing for oil and gas production wells
through measures introduced in the 117th Congress. Although these measures did not mention induced seismicity,
any changes to the regulation of one underground fluid injection activity may affect the regulatory structure for
other types of wells and how federal agencies and state agencies deal with the risks of induced seismicity.
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Introduction
Human activities, such as dam building, mining, and injecting fluids via underground wells, may
cause earthquakes (also known as induced earthquakes or induced seismicity).1 Underground
fluid injection activities that may induce earthquakes include hydraulic fracturing oil and gas
production wells (HF), enhanced oil and gas recovery wells, wastewater disposal wells, some
enhanced geothermal energy production wells, and geologic sequestration wells for liquid carbon
dioxide storage.2 HF, recovery, and disposal well activity has increased in the central and eastern
United States since 2008 (CEUS, defined as the area on the inset map of Figure 1), in part due to
advances in horizontal drilling to recover oil and gas from unconventional resources.3 A small
fraction of tens of thousands of HF, recovery, and disposal wells induce tens to hundreds of
earthquakes in the CEUS.4 Wastewater disposal accounts for the majority of induced earthquakes

1 National Research Council (NRC), Induced Seismicity Potential in Energy Technologies (Washington, DC: National
Academies Press, 2013), doi:10.17226/13355 (hereinafter NRC, Induced Seismicity, 2013).
2 Hydraulic fracturing oil and gas production wells inject fluids via horizontal drilling into producing formations to
fracture the rock and release the oil and gas. Enhanced oil and gas recovery wells inject fluids into an existing
producing formation to flush out the remaining oil or gas. Wastewater disposal wells inject oil- and gas-produced
wastewaters and geologic sequestration wells inject carbon dioxide-captured liquids deep underground for permanent
disposal. Enhanced geothermal wells inject fluids via horizontal drilling into producing formations to fracture the rock
and release heated fluid. Geologic sequestration wells inject carbon dioxide-captured liquids into targeted underground
formations for permanent storage; geologic sequestration is a strategy to capture carbon dioxide emissions before they
can be released into the atmosphere to mitigate the impacts of climate change. EPA, “Protecting Underground Sources
of Drinking Water From Underground Injection (UIC),” at https://www.epa.gov/uic for short descriptions of injection
well types and USGS, “Energy Resources Program,” at https://www.usgs.gov/programs/energy-resources-program for
more on hydraulic fracturing, geothermal and geologic carbon sequestration. See also Ground Water Protection Council
(GWPC) and Interstate Oil and Gas Compact Commission (IOGC), Potential Induced Seismicity Guide: A Resource of
Technical and Regulatory Considerations Associated with Fluid Injection, March 2021, at https://www.gwpc.org/sites/
gwpc/uploads/documents/publications/.FINAL_Induced_Seismicity_2021_Guide_33021.pdf (hereinafter
GWPC/IOGC, Induced Seismicity Guide, 2021).
3 Most oil and gas activities produce wastewaters. In the central and eastern United States (CEUS), wastewater disposal
wells inject some of these produced wastewaters underground. An increase in oil and gas activities results in an
increase in wastewater disposal activities in some areas. GWPC/IOGC, Induced Seismicity Guide, 2021. The number of
hydraulic fracturing oil and gas production (HF) wells, particularly in the CEUS, has been increasing since 2007. For
example, the Energy Information Administration (EIA) estimates there were fewer than 10,000 HF wells in the United
States in 2000 and that the number of HF wells began to increase in 2007, reaching 159,000 HF wells in 2020. EIA,
The Distribution of U.S. Oil and Natural Gas Wells by Production Rate, January 2022, at https://www.eia.gov/
petroleum/wells/pdf/full_report.pdf (hereinafter EIA, Wells, 2022), Figure 2. More than 2 billion gallons of fluids are
injected into the subsurface in wastewater disposal and enhanced oil and gas recovery wells every day in the United
States, according to the EPA. There are about 156,000 Class II wells (most are wastewater disposal and enhanced oil
and gas recovery wells) in operation in the United States in 2022 (EPA, “Class II Oil and Gas Related Injection Wells,”
at https://www.epa.gov/uic/class-ii-oil-and-gas-related-injection-wells). See Table A-1 in the Appendix for the number
of oil and gas and disposal wells by state. See also CRS Report R46723, U.S. Energy in the 21st Century: A Primer,
coordinated by Melissa N. Diaz.
An unconventional resource (also called tight or continuous-type deposit) consists of an impermeable shale formation,
an organic-rich sedimentary rock that is the source and reservoir for oil and/or natural gas. An impermeable rock
formation is composed of fine-grained minerals tightly held together with little to no open pore space between grains.
CRS Report R43148, An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions, by
Michael Ratner and Mary Tiemann. Most onshore unconventional resources are located in the central and eastern U.S.
See USGS, “USGS Domestic Continuous (Unconventional) Oil & Gas Assessments, 2000-Present,” at
https://certmapper.cr.usgs.gov/data/apps/noga-summary/.
4 See Table A-1 in the Appendix for the number of wells by state. Summary reports and some specific studies that have
identified induced earthquakes associated with oil and gas plus wastewater disposal activities and in some cases the
pre-existing faults via space and time correlations with these fluid injection activities include GWPC/IOGC, Induced
Seismicity Guide, 2021; Ryan Schultz et al., “Hydraulic Fracturing-Induced Seismicity,” Reviews of Geophysics, vol.
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in the CEUS since 2009.5 Some of these induced earthquakes have caused damage and led to
lawsuits against well operators, motivating a variety of stakeholders to consider ways to mitigate
induced earthquakes.6
The number of induced earthquakes in the CEUS since 2009 correlates in space and time with
some underground fluid injection activities, such as oil and gas activities and wastewater
disposal, and in many cases research has identified a fault prone to slipping that may be the
source of these earthquakes near these injection activities (Figure 1).7 The number of magnitude
3.0 or larger (M 3.0+) earthquakes increased every year from 2009 to 2015 and reached a peak of
1,010 events in 2015 compared to an average number of M3.0+ earthquakes in the CEUS of 25 or
fewer events per year from 1973 to 2008.8 Since 2015, the annual number of M 3.0+ earthquakes
has declined from this peak, but remains above 25 earthquakes per year. In addition, there has
been a small increase in M 3.0+ earthquakes in 2020 and 2021 (Figure 1). As the annual number
of earthquakes in the CEUS has increased since 2009, so too has the magnitude of some of these
events, with more earthquakes greater than M 4.0. Some communities are feeling ground shaking
from these events and five earthquakes of M 4.8+ caused property damage in Colorado,
Oklahoma, and Texas between 2011 and 2016.

58 (June 2020), e2019RG000695, doi: 10.1029/2019RG000695 (hereinafter Schultz, HF-Induced Seismicity, 2020);
and Iason Grigoratos, Alexandros Savviadis, and Ellen Rathje, “Distinguishing the Causal Factors of Induced
Seismicity in the Delaware Basin: Hydraulic Fracturing or Wastewater Disposal?,” Seismological Research Letters,
(2022), pp. 1-19, doi: 10.1785/0220210320 (hereinafter, Grigoratos, Causal Factors of Induced Seismicity, 2022).
5 Estimates of the percentage of induced earthquakes caused by wastewater disposal versus enhanced oil and gas
recovery and HF wells in the CEUS since 2009 varies depending on the area considered, the range of earthquake
magnitudes considered (e.g., magnitude greater than 2.0 or magnitude greater than 3.0), and percentages of different
well operations occurring in the area of concern. USGS, “Myths and Misconceptions About Induced Earthquakes,” at
https://www.usgs.gov/programs/earthquake-hazards/myths-and-misconceptions-about-induced-earthquakes;
GWPC/IOGC, Induced Seismicity Guide, 2021, p. 11, 20, and 34; Schultz, HF-Induced Seismicity, 2020; and
Grigoratos, Causal Factors of Induced Seismicity, 2022.
6 Stakeholders include federal and state agencies, associations and organizations, earthquake science researchers, and
industry involved in underground fluid injection activities. Involvement may include research, monitoring, regulation,
guidance, or operation of underground fluid injection activities.
7 See footnote 4.
8 USGS, “Induced Earthquakes Overview,” at https://www.usgs.gov/programs/earthquake-hazards/science/induced-
earthquakes-overview. Magnitude refers to the size of an earthquake and the scale is logarithmic, meaning that a
magnitude 5.0 earthquake is 10 times the size (and about 32 times more energy) than a magnitude 4.0 earthquake.
USGS, “Earthquake Magnitude, Energy Released, and Shaking Intensity,” at https://www.usgs.gov/programs/
earthquake-hazards/earthquake-magnitude-energy-release-and-shaking-intensity.
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Figure 1. Number of Magnitude 3.0 of Greater Earthquakes in the Central and
Eastern United States, 1973-2021

Source: U.S. Geological Survey (USGS), “Induced Earthquakes,” at https://www.usgs.gov/programs/earthquake-
hazards/induced-earthquakes.
Notes: The inset map defines the area included as the central and eastern United States (CEUS) for the
purposes of this report. The USGS notes the rate of M 3.0+ earthquakes per year in this area was 25 or fewer
events from 1973 to 2008 (blue bars), and this may be considered the average geologic rate (i.e., the expected
average rate of earthquakes in the CEUS related to natural geologic processes based on recorded events). Since
2009, the annual rate of earthquakes in the CEUS has increased to at least 58 events per year from 2009 to 2012
and at least 100 events per year since 2013 (orange bars). The peak annual number in 2015 was 1,010 events.
The purple dots on the map (which correspond to blue bars on the graph) are earthquakes of magnitude 3.0 or
greater that occurred between 1973 and 2008. The red dots on the map (which correspond to the orange bars
on the graph) are earthquakes of M 3.0+ that occurred between 2009 and 2021.
Under the Safe Drinking Water Act (SDWA; 42 U.S.C. §§300f-300j), EPA is authorized to
regulate underground injection activities (except for most HF activities) to prevent endangerment
of underground sources of drinking water (USDW). EPA has issued Underground Injection
Control (UIC) regulations for six classes of wells, including wastewater disposal, enhanced oil
and gas recovery, some geothermal energy, and carbon sequestration.
SDWA does not require EPA to address seismicity directly; however, EPA UIC program
regulations include seismicity-related siting and testing requirements for hazardous waste and
carbon dioxide sequestration injection wells.9 Such requirements are not included in regulations

9 See EPA, “Underground Injection Control Regulations,” at https://www.epa.gov/uic/underground-injection-control-
regulations.
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governing oil and gas wastewater disposal wells, although regulators (either EPA or a state) have
discretionary authority to add conditions to individual permits. In 2015, EPA published technical
recommendations and best practices for minimizing and managing the impacts of induced
seismicity from oil and gas wastewater disposal wells.10
The USGS, universities, and state agencies have conducted seismic monitoring and research to
identify the causes and assess the risks of induced seismicity in the CEUS. These studies, in
addition to EPA guidance and state mitigation measures, may have contributed to decreasing the
annual number of earthquakes in the CEUS since the peak in 2015.11 Even so, the annual number
of induced earthquakes (M 3.0+) in the CEUS remains high (e.g., eight times higher in 2021 than
the historic annual rate before 2009) and more research and mitigation may help to reduce
earthquake risks.
Understanding induced earthquakes caused by underground fluid injection in the CEUS may help
the U.S. Geological Survey (USGS), the Department of Energy (DOE), and other stakeholders
understand fault mechanisms and the potential for induced earthquakes caused by similar
underground fluid injection processes used for geothermal energy production or geologic carbon
sequestration.12 Some in Congress are interested in increasing these activities for energy
production and for reducing the amount of carbon dioxide in the atmosphere.
In the 117th Congress, there was support for more research on induced seismicity to understand
the causes and reduce the risks. The House Committee on Appropriations, for example, in its
report accompanying the FY2023 Department of the Interior, Environment, and Related Agencies
appropriations bill, called for $3.1 million for the USGS Earthquake Hazards Program for
induced seismicity.13 Other measures introduced in the 117th Congress would have changed the
federal role in the regulation of some underground fluid injection activities. Congress may
consider whether the federal government should play any role in regulating induced seismicity
from underground fluid injection activities.

10 EPA, Minimizing and Managing Potential Impacts of Injection-Induced Seismicity from Class II Disposal Wells:
Practical Approaches, Underground Injection Control National Technical Workgroup, November 12, 2014 (released
February 6, 2015), at https://www.epa.gov/sites/default/files/2015-08/documents/induced-seismicity-201502.pdf
(hereinafter EPA, Minimizing and Managing).
11 Oklahoma Corporation Commission, Annual Report Fiscal Year 2018, 2018, pp. P. 48-49, https://oklahoma.gov/
content/dam/ok/en/occ/documents/ajls/about/Annual_Report-FY18.pdf, Oklahoma Corporation Commission,
“Response to Oklahoma Earthquakes,” at https://oklahoma.gov/occ/divisions/oil-gas/induced-seismicity-and-uic-
department/response-oklahoma-earthquakes.html, and GWPC/IOGC, Induced Seismicity Guide, 2021.
12 CRS Report R44902, Carbon Capture and Sequestration (CCS) in the United States, by Angela C. Jones and Ashley
J. Lawson.
13 U.S. Congress, House Committee on Appropriations, Department of the Interior, Environment, and Related Agencies
Appropriations Bill, 2023, report with minority views to accompany H.R. 8262, 117th Cong., 1st sess., H.Rept. 117-400,
July 1, 2022, p. 43, at https://www.congress.gov/117/crpt/hrpt400/CRPT-117hrpt400.pdf#page=47. Note the
committee-recommended amount of $3.1 million for induced seismicity research for the Earthquake Hazards Program
is the same as requested in the President’s FY2023 budget request. This amount does not include an additional $3.5
million requested in the President’s FY2022 budget request, for a joint investigation by USGS Energy Resources
Program and the Earthquake Hazards Program. The investigation would identify the potential for induced seismicity in
underground areas that may be used for carbon sequestration; USGS, Budget Justifications and Performance
Information Fiscal Year 2023, pp. 59, 72, at https://d9-wret.s3.us-west-2.amazonaws.com/assets/palladium/production/
s3fs-public/media/files/FY23-USGS-Greenbook.pdf.
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Understanding, Monitoring, and Assessing the Risk
of Induced Seismicity
Scientists and others have known, since the 1920s, that pumping fluids in and out of Earth’s
subsurface has the potential to cause earthquakes.14 Some wells pump fluids into a target rock
formation in the subsurface to permanently contain waste products deep underground, such as
wastewater disposal wells and carbon sequestration wells (see text box titled “A Historical
Example: The Rocky Mountain Arsenal”). Other wells pump fluids into a target rock formation in
the subsurface to extract oil and gas (e.g., enhanced oil and gas recovery wells or HF wells) or to
extract energy as heat (e.g., enhanced geothermal wells).15 The underground fluid injection may
change the amount of local stress in Earth’s crust, and the forces that prevent faults from slipping
may become unequal. Once those forces are out of equilibrium, the fault may become unstable
and may slip. The sudden movement on the fault leads to an earthquake, which releases energy
and sends seismic waves out from the fault; these waves may reach the surface with enough
energy to cause shaking at the surface and the shaking may cause damage.
A Historical Example: The Rocky Mountain Arsenal
A magnitude 4.8 (M 4.8) earthquake that struck northeast Denver, CO, on August 9, 1967, was the largest
recorded human-induced earthquake caused by fluid injection in the United States before 2011. The M 4.8
earthquake was part of a series of earthquakes that began within several months of the 1961 start of deep-well
injection of hazardous chemicals produced at the Rocky Mountain Arsenal defense plant. The earthquakes
continued after injection ceased in February 1966. A disposal well, dril ed through the flat-lying sedimentary rocks
into the underlying older crystalline rocks more than 12,000 feet deep, injected as much as 5.5 mil ion gallons per
month. Earthquake activity declined after 1967 but continued for the next two decades. Scientists concluded the
injection caused the earthquakes. Even after injection ceased, the migration of the underground pressure front
continued for years and initiated earthquakes along an ancient fault system many miles away from the injection
well.
The Rocky Mountain Arsenal earthquakes have similarities to the increased earthquake activity after 2008 related
to underground injection activities in the central and eastern United States. These similarities include, for example,
injection near or in underlying crystalline bedrock, activation of fault systems miles away from the well, and
migration of the pressure front away from the point of injection months or years after injection stopped.
Sources: J. H. Healy et al., “The Denver Earthquakes,” Science, vol. 161, no. 3848 (September 27, 1968), pp.
1301-1310; and Wil iam L. El sworth, “Injection-Induced Earthquakes,” Science, vol. 341 (July 12, 2013), doi:
10.1126/science.1225942, at https://www.sciencemag.org/content/341/6142/1225942.ful .
Horizontal (or directional) drilling techniques combined with HF helped spur an increase in oil
and gas activities in the CEUS since about 2008,16 where most of these economically viable
unconventional resources are concentrated.17 HF accounts for most of the onshore oil and gas
production in the United States in 2021.18 HF typically targets an impermeable shale formation

14 NRC, Induced Seismicity, 2013, p. vii.
15 An enhanced geothermal system consists of a well that pumps water into a formation, fracturing the rock and
creating a hot water-rock reservoir. Another well pumps the heated water back to the surface through a different well to
drive a steam turbine and generate electricity. NRC, Induced Seismicity, 2013.
16 EIA, Wells, 2022; and U.S. Energy Information Administration, Drilling Productivity Report Supplement, Gas-to-Oil
Ratios in the U.S. Primary Oil-Producing Regions, September 2021.
17 USGS, “USGS Domestic Continuous (Unconventional) Oil & Gas Assessments, 2000-Present,” at
https://certmapper.cr.usgs.gov/data/apps/noga-summary/ and Table A-1 of oil and gas wells by state in the Appendix.
18 CRS Report R46723, U.S. Energy in the 21st Century: A Primer, coordinated by Melissa N. Diaz; EIA, Wells, 2022;
and EIA, “Hydraulic Fracturing Accounts for About Half of Current U.S. Crude Oil Production,” at
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that contains oil or gas trapped in the rock (i.e., an unconventional resource); and works by
horizontal drilling into the formation (Figure 2).19 Fluids injected under high pressure into a shale
formation fracture the rock and enhance release of the oil and/or gas for extraction from a well.20
The fracturing of the rock during the HF process induces micro-earthquakes of M < 1.0 that do
not cause any human-felt shaking at the surface. In rare cases, where HF operations inject fluid
close to a preexisting fault (e.g., a fault in the deeper crystalline basement rocks below the shale
formation), the fluid may activate the fault and induce an earthquake of higher magnitude (e.g., M
3.0+) that may be felt at the surface, and if strong enough may actually cause damage.21
Figure 2. Illustration of the Possible Relationship Between Underground Injection
and Induced Seismicity

Source: North Carolina General Assembly, presentation by the Arkansas Oil and Gas Commission, Fayetteville
Shale Overview, for the North Carolina Delegation, slide 33, prepared by Southwestern Energy, November 21, 2013,
at http://www.ncleg.net/documentsites/committees/BCCI-6576/2013-2014/5%20-%20Feb.%204.%202014/
Presentations%20and%20Handouts/Arkansas%20Site%20Visit%20Attachments/Att.%205%20-
%20AOGC%20Presentation%2011-21-13%20%283%29.pdf.

https://www.eia.gov/todayinenergy/detail.php?id=25372.
19 See footnote 3.
20 Enhanced geothermal energy systems use the same process as HF oil and gas production. An enhanced geothermal
system works by horizontal drilling into a target formation and fracturing the rock to create permeable pathways to
circulate fluids (primarily water) at depth. Earth’s natural heat at depth increases the water temperature and a different
well pumps the heated water to the surface to drive a turbine and generate electricity. Other geothermal systems use
different techniques to generate energy and may induce earthquakes. NRC, Induced Seismicity, 2013.
21 Schultz, HF-Induced Seismicity, 2020 and GWPC/IOGC, Induced Seismicity Guide, 2021.
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Notes: The figure is for il ustrative purposes only and does not depict any specific location or geological
formation, which may be more complex than shown. The term triggered in the figure is synonymous with the
term induced as used in this report. Likewise, horizontal shale well is synonymous with hydraulic fracturing, an
unconventional oil and gas production technique, and water disposal is synonymous with wastewater disposal of
waste products from oil and gas activities. Shale, sand (or sandstone), and limestone are sedimentary rocks formed
from different sediments. Shale, formed from muds or clays on lakebeds or seabeds, may contain organic matter
and oil or gas. Igneous rocks, such as granite, formed from magma and are sometimes called crystalline rocks
because you can see crystals in the rock without a microscope.
HF and other oil and gas activities produce a large amount of wastewater (i.e., about 10 barrels of
wastewater for every barrel of product).22 Disposal wells inject wastewater into a sedimentary
formation (typically sandstone or limestone) below shallower underground water resources.
Disposal wells typically inject larger volumes of fluids for longer periods (months to years) than
HF wells, so disposal wells may be more likely than HF wells to induce seismicity.23
Fluid injection from a disposal well may induce an earthquake on a preexisting fault. After fluid
injection into a sedimentary layer (i.e., a target rock formation), the increase in pore pressure in
the sedimentary layer could propagate into preexisting fault(s), most commonly located in the
crystalline basement rocks underlying the sedimentary formation (Figure 2).24 Slip along a fault
creates an earthquake; the magnitude of the earthquake depends on the amount of slip on the fault
and other factors.
Not all induced earthquakes stem from faults in the crystalline basement rocks. Some studies
have identified induced earthquakes on shallower unstable faults at or above the fluid injection
depth. Also, induced earthquakes may occur months or years after fluid injection (similar to the
induced earthquakes that occurred years after injection at the Rocky Mountain Arsenal, see text
box titled “A Historical Example: The Rocky Mountain Arsenal”).25 Induced earthquakes which
occur near the Earth’s surface may transfer more of their energy into ground shaking at the
surface than earthquakes originating at greater depths.26 For this reason, an M 3.0 earthquake near

22 GWPC/IOGC, Induced Seismicity Guide, 2021, p. 81. The 10 barrels of wastewater for every barrel of product is an
estimate and GWPC calls it a national average. EPA has noted that the amount of wastewater produced varies from 1
barrel of wastewater for 1 barrel of product to 100 barrels of wastewater for 1 barrel of product, depending on the oil
and gas activities and depending on the product. Other sources, such as the Texas Alliance of Energy Producers,
provide estimates of produced wastewaters for the entire state in a given year (e.g., in 2017, oil and gas activities in
Texas produced more than 357 billion gallons of wastewater). EPA, Summary of Input on Oil and Gas Extraction
Wastewater Management Practices Under the Clean Water Act, EPA-821-S19-001, May 2020, pp. 5, 7, at
https://www.epa.gov/sites/default/files/2020-05/documents/oil-gas-final-report-2020.pdf. The definition of a barrel is
variable and may depend on what product or waste product is in the barrel. In this report, a barrel is about 42 U.S.
gallons by volume. The 42 US-gallon oil barrel is a unit of measurement of volume and no longer a physical container
for holding oil. The steel drum physical containers used to hold oil in the U.S. are 55 U.S. gallons by volume. The
American Petroleum Institute defines a standard barrel of oil as the amount of oil that would occupy a 42 U.S. gallon
volume at a specific pressure and temperature (i.e., a unit of measurement of specific volume). All other countries use
the metric system and different specific pressure and temperature for specific volume measurements. Given these
differences, financial institutions and regulators may establish a standard conversion factor for converting between
different units and may require a specific percentage of uncertainty in volume calculations (e.g., the measurement can
only be 0.25% uncertain).
23 GWPC/IOGC, Induced Seismicity Guide, 2021 and USGS, “Induced Earthquakes Overview,” at
https://www.usgs.gov/programs/earthquake-hazards/science/induced-earthquakes-overview.
24 Crystalline basement rocks refer to typically older igneous or metamorphic rocks, such as granite, that lie beneath
younger sedimentary rocks, such as sandstone, limestone, or shale.
25 Schultz, HF-Induced Seismicity, 2020; GWPC/IOGC, Induced Seismicity Guide, 2021; and Grigoratos, Causal
Factors of Induced Seismicity, 2022.
26 For example, in Oklahoma, induced earthquakes occur within 6 kilometers (3.7 miles) of the surface, whereas natural
earthquakes typically occur throughout the crust to about 30 kilometers (18.6 miles) below the surface and some occur
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the surface can produce more shaking and thus may cause more damage at the surface than a
deeper M 3.0 event.
Underground injection in wastewater disposal wells has induced five damaging earthquakes in the
United States (Table 1) between 2011 and 2016.27 Stakeholders in Oklahoma sued various well
operators to recover the costs of damages from an M 5.8 earthquake near Pawnee, OK, and an M
5.0 earthquake near Cushing, OK.28 (See text box titled “Magnitude 5.8 Earthquake near Pawnee,
OK, on September 3, 2016” for more details about the earthquake and subsequent mitigation
efforts).
Table 1. Damage from Induced Earthquakes in the United States Caused by
Wastewater Injection, 2011-2016
Year
M
Location
Damage
2011
5.7
Prague, OK
Damaged homes, broke windows, cracked masonry, and col apsed a turret
at St. Gregory’s University.
2011
5.3
Trinidad, CO
Caused structural damage to unreinforced masonry; cracked masonry;
caused fallen chimneys, broken windows, and fallen objects.
2012
4.8
Timpson, TX
Resulted in fallen chimneys and damaged masonry walls.
2016
5.8
Pawnee, OK
Damaged brickwork and cracked sheetrock at a number of structures.
2016
5.0
Cushing, OK
Caused cracks in buildings as well as fallen bricks and facades.
Source: Ground Water Protection Council and Interstate Oil and Gas Compact Commission, Potential Induced
Seismicity Guide: A Resource of Technical and Regulatory Considerations Associated with Fluid Injection, March 2021, p.
13, at https://www.gwpc.org/sites/gwpc/uploads/documents/publications/
FINAL_Induced_Seismicity_2021_Guide_33021.pdf.
Seismic Monitoring of Induced Earthquakes
Researchers say they lack sufficient data on well operations, geologic conditions underground and
in some cases sufficient monitoring of areas of concern for earthquakes with seismic instruments
to identify any critically stressed faults and analyze which underground fluid injection activities
may induce earthquakes on these faults.29
Seismic monitoring is a primary tool for estimating the state of stress and identifying faults
underground.30 The USGS Earthquake Hazards Program monitors and reports on earthquakes in
the United States and globally, assesses earthquake hazards, and conducts research on the causes
and effects of earthquakes under the authority of the National Earthquake Hazards Reduction

much deeper in the mantle. GWPC/IOGC, Induced Seismicity Guide, 2021, p. 2.
27 GWPC/IOGC, Induced Seismicity Guide, 2021.
28 Beth Wallis, “Oil Company Agrees to $850k Settlement for 2016 Oklahoma Earthquake Damages,” KOSU, Energy
and Environment, August 6, 2022, KOSU Fresh Air, at https://www.kosu.org/energy-environment/2022-08-06/oil-
company-agrees-to-850k-settlement-for-2016-oklahoma-earthquake-damages (hereinafter Wallis, “Oil Company
Agrees to Settlement”).
29 William Leith, Senior Science Advisor for Earthquakes and Geologic Hazards, U.S. Geological Survey (USGS),
“USGS Research into the Causes and Consequences of Injection-Induced Seismicity,” presentation at the U.S. Energy
Association, October 30, 2014, at https://usea.org/sites/default/files/event-/Leith%20induced%20for%20DOE-
USEA%20Oct14.pdf and GWPC/IOGC, Induced Seismicity Guide, 2021, p. 3.
30 Seismic monitoring is a primary research tool used to image the structure of the subsurface and understand geologic
processes such as earthquakes, volcanic activity, and plate tectonics.
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Program.31 The USGS has deployed seismic instruments to understand induced earthquakes
related to oil and gas activities in Kansas, Oklahoma, Ohio, and Texas.32 The USGS also deployed
seismic instruments near Decatur, IL to understand induced earthquakes related to an
experimental geologic carbon sequestration project.33
In addition to the USGS, state agencies and universities have enhanced or established short- and
long-term seismic monitoring to understand induced seismicity and to mitigate seismic risks in
the CEUS. For example, Arkansas, Kansas, Ohio, Oklahoma, and Texas have seismic networks
operated by state agencies and/or universities to study natural and induced seismicity.34
Researchers using these networks seek to understand which operations may cause induced
seismicity and to improve the capability of regulators and operators to mitigate induced
earthquakes.
One example of a state-run seismic monitoring network to understand earthquakes is the
Oklahoma Geological Survey’s (OGS’s) Seismic Monitoring Program.35 OGS has operated the
program since 1961 and increased the size of the network and its seismic monitoring capabilities
beginning in 2009 to understand the increasing number of earthquakes per year in the state.
Figure 3 shows the number of M 3.0+ earthquakes in Oklahoma from 2009 to 2021 from the
OGS earthquake catalogs. The figure shows a peak in the annual number of earthquakes in 2015
and a corresponding peak in higher-magnitude events (i.e., M 4.0+). The Oklahoma Corporation
Commission’s (OCC) Induced Seismicity Department correlated most of these earthquakes with
underground injection activities. The OCC regulates oil and gas activities and the Underground
Injection Control program (on behalf of the EPA) in Oklahoma (See text box titled “Magnitude
5.8 Earthquake near Pawnee, OK, on September 3, 2016”). According to a 2018 OCC report, the
annual number of induced earthquakes (M 3.0+) in Oklahoma has decreased since 2015,
primarily due to regulations and directives to mitigate induced seismicity.36

31 USGS, “Earthquake Hazards,” at https://www.usgs.gov/programs/earthquake-hazards and CRS Report R43141, The
National Earthquake Hazards Reduction Program (NEHRP): Issues in Brief, by Linda R. Rowan.
32 See USGS, “Observational Studies of Induced Earthquakes,” at https://www.usgs.gov/programs/earthquake-hazards/
science/observational-studies-induced-earthquakes, and a list of related publications at USGS, “Induced Earthquakes
Overview,” at https://www.usgs.gov/programs/earthquake-hazards/science/induced-earthquakes-
overview#publications.
33 J. Ole Kaven et al., “Seismic Monitoring at the Decatur, IL, CO2 Sequestration Demonstration Site,” Energy
Procedia, vol. 63 (2014), pp. 4264-4272, doi: 10.1016/j.egypro.2014.11.461.
34 Many states augmented or established state-managed seismic networks after the peak in induced seismicity in 2015
(see Figure 1). Arkansas Seismic Monitoring: Arkansas Geological Survey, “Earthquakes,” at
https://www.geology.arkansas.gov/geohazards/earthquakes-in-arkansas.html; Arkansas Geological Survey, “Arkansas
Seismicity Map from 1699 to 2019,” at https://www.geology.arkansas.gov/docs/pdf/maps-and-data/geohazard_maps/
arkansas-seismicity-map.pdf; and University of Memphis, Center for Earthquake Research and Information, “Recent
Earthquakes,” at https://folkworm.ceri.memphis.edu/REQ/html/recent.html. Kansas Seismic Monitoring: Kansas
Geological Survey, “Kansas Earthquakes,” at https://www.kgs.ku.edu/Geophysics/Earthquakes/index.html. Ohio
Seismic Monitoring: Ohio Division of Natural Resources, “The Ohio Seismic Network,” at https://ohiodnr.gov/
discover-and-learn/safety-conservation/about-ODNR/geologic-survey/division-of-geologic-survey/ohio-seis. Oklahoma
Seismic Monitoring: Oklahoma Geological Survey, “Earthquakes,” at https://www.ou.edu/ogs/research/earthquakes.
Texas Seismic Monitoring: University of Texas, Bureau of Economic Geology, “TexNet Seismic Monitoring
Program’” at https://www.beg.utexas.edu/texnet-cisr/texnet.
35 Oklahoma Geological Survey, “Seismic Monitoring Program,” at https://www.ou.edu/ogs/research/earthquakes/
seismicstations.
36 Oklahoma Corporation Commission, Annual Report Fiscal Year 2018, 2018, pp. P. 48-49, https://oklahoma.gov/
content/dam/ok/en/occ/documents/ajls/about/Annual_Report-FY18.pdf.
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Figure 3. Earthquakes of Magnitude 3.0 or Greater in Oklahoma, 2009-2021

Source: Oklahoma Geological Survey, “Earthquake Catalog Download Tool,” at https://www.ou.edu/ogs/
research/earthquakes/catalogs.
Notes: CRS downloaded the earthquake catalogs for the years 2009-2021. The plots show the number of
earthquakes of the indicated magnitude range for each year. There were no earthquakes of M 4.0 or greater in
2009 in the Oklahoma Geological Survey earthquake catalog.
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Magnitude 5.8 Earthquake near Pawnee, OK: September 3, 2016
On September 3, 2016, a magnitude (M) 5.8 earthquake occurred about 9 miles northwest of Pawnee, OK. It was
the largest recorded earthquake to occur in the state and caused damage to people and property. After the
earthquake, federal and state regulators required well operators to change or halt well operations in the area near
the event.
Underground wastewater injections into the Arbuckle Formation induced the earthquake. The U.S. Geological
Survey, working with the Oklahoma Geological Survey, identified a system of potentially unstable faults in the
crystalline bedrock below the Arbuckle Formation. The underground injections likely changed conditions on the
faults and at least one fault slipped, causing the earthquake.
Although it is difficult to assign a specific well’s activities to a specific fault and subsequent earthquake, the
Oklahoma Corporation Commission (OCC), which regulates oil and gas activities and underground fluid injection
in Oklahoma, took immediate action to shut down or curtail 37 wells within a 725 square mile area of the event.
Injections from those wells correlated in space and time to the September 3 earthquake.
The 725 square mile area of seismic concern included 211 square miles of Osage County, a portion of which is
part of the Osage Nation Mineral Reserve. The Environmental Protection Agency (EPA) implements the
Underground Injection Control program in Osage County, and the agency requested operators to shut in
(temporarily shut down) 17 wastewater disposal wells after the earthquake.
On September 12, 2016, the OCC expanded the area of seismic concern to 1,116 square miles, based on new
data. The OCC requested that 27 wells cease operations and 19 wells reduce disposal volumes. EPA requested
that 5 wells cease operations and 14 wells reduce disposal volumes in the Osage Nation Mineral Reserve.
Since the September 3, 2016 earthquake, organizations and individuals sued different well operators for
compensation for damage from the event. Part of one lawsuit was settled in August 2022.
Sources: Oklahoma Geological Survey, “Earthquakes,” at https://www.ou.edu/ogs/research/earthquakes; OCC,
“Media Advisory: Latest Action Regarding Pawnee Area,” press release, September 12, 2016, at
https://oklahoma.gov/content/dam/ok/en/occ/documents/ajls/news/2016/09-12-16pawnee-advisory.pdf; OCC,
“Advisory: Pawnee,” press release, November 3, 2016, at https://oklahoma.gov/content/dam/ok/en/occ/
documents/ajls/news/2016/11-03-16pawnee-posting.pdf; OCC, “Earthquake Response Summary,” at
https://oklahoma.gov/content/dam/ok/en/occ/documents/ajls/news/2018/05-30-18earthquakeactionsummary.pdf;
OCC, “Response to Oklahoma Earthquakes,” at https://oklahoma.gov/occ/divisions/oil-gas/induced-seismicity-and-
uic-department/response-oklahoma-earthquakes.html; and Beth Wallis, “Oil Company Agrees to $850k
Settlement for 2016 Oklahoma Earthquake Damages,” KOSU, Fresh Air, Energy & Environment, August 6, 2022, at
https://www.kosu.org/energy-environment/2022-08-06/oil-company-agrees-to-850k-settlement-for-2016-
oklahoma-earthquake-damages.
Seismic monitoring provides details about earthquakes that may help to identify and reduce
earthquake risks.37 For example, in Oklahoma seismic monitoring shows a slight increase in M
4.0+ events after some injection activities ceased or changed. This may signal that the fluid
injections may affect geologic conditions further from the injection location (see text box titled
“A Historical Example: Rocky Mountain Arsenal”). Similarly, the recently established Texas
Seismic Network (TexNet, started in 2017 by the Texas state legislature) identified an annual
increase in the number of M 3.0+ and M 4.0+ earthquakes from 2019 to 2021.38 Texas regulators
in consultation with seismologists at TexNet determined that wastewater disposal induced these
earthquakes and some of the earthquakes occurred at or above the fluid injection site on shallower
faults.39 The occurrence of induced earthquakes on shallower faults contrasts with the illustrative

37 GWPC/IOGC, Induced Seismicity Guide, 2021.
38 Erin Douglas, “Earthquakes in Texas Doubled in 2021. Scientists Cite Years of Oil Companies Injecting Sludgy
Water Underground,” Texas Tribune, February 8, 2022, at https://www.texastribune.org/2022/02/08/west-texas-
earthquakes-fracking/ (hereinafter Douglas, “Earthquakes in Texas Doubled”).
39 Texas Railroad Commission (RRC), “Seismicity Response,” at https://www.rrc.texas.gov/oil-and-gas/applications-
and-permits/injection-storage-permits/oil-and-gas-waste-disposal/injection-disposal-permit-procedures/seismicity-
review/seismicity-response (hereinafter, RRC Seismicity Response) and Grigoratos, Causal Factors of Induced
Seismicity, 2022.
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model in Figure 2 and with the identification of deeper faults in Oklahoma and Ohio,
highlighting the importance of understanding the different geologic conditions in different
locations.
Evaluating the Risk of Induced Earthquakes
The USGS Earthquake Hazards Program conducts research, monitors, reports, and assesses the
risks of induced seismicity from many underground injection activities as a small component of
its overall program.40 The increase in seismicity since 2009 in the CEUS (Figure 1) is caused by
underground fluid injection (primarily from wastewater disposal), according to USGS and other
studies.41 In addition to the increase in the number of earthquakes since 2009, the number of
induced earthquakes of M 4.0+ increased over the same period. Larger magnitude events (4.0+)
in the shallow crust increase the risk of damage from more intense ground shaking.
The USGS prepares and regularly updates U.S. Seismic Hazard Maps to assess earthquake
hazards and their associated risks across the country.42 These maps typically exclude the seismic
hazard posed by induced earthquakes, because researchers are unsure how to treat potentially
induced earthquakes in their seismic hazard analysis.43 The natural tectonic processes causing
earthquakes do not change much over geologic timescales of thousands to millions of years. For
example, the seismic hazard in portions of California, Alaska, and other states experiencing these
tectonic forces do not vary much from year to year.44 In contrast, induced seismicity can vary
over short timescales because underground fluid injection activities often change over short times
(i.e., weeks, months, or a few years). Those characteristics mean assessing risk from combining
natural seismic hazards with induced seismic hazards is difficult, in part because induced
earthquakes are a short-term hazard, compared with the perennial seismic hazard from natural
tectonic forces.45
Despite the difficulty, the USGS released one-year seismic hazard forecasts for the CEUS for
2016, 2017, and 2018 that included contributions from induced and natural earthquakes.46 The

40 USGS, “Induced Earthquakes,” at https://www.usgs.gov/programs/earthquake-hazards/science/induced-earthquakes.
41 USGS, “FAQ, Natural Hazards, Induced Earthquakes,” at https://www.usgs.gov/science/faqs/natural-hazards; USGS,
“Does fracking cause earthquakes?” https://www.usgs.gov/faqs/does-fracking-cause-earthquakes; Schultz, HF-Induced
Seismicity, 2020; and GWPC/IOGC, Induced Seismicity Guide, 2021. The USGS conducted studies often in
partnership with universities and/or state agencies.
42 USGS, “National Seismic Hazard Maps,” at https://www.usgs.gov/programs/earthquake-hazards/science/national-
seismic-hazard-maps.
43 A. McGarr et al., “Coping with Earthquakes Induced by Fluid Injection,” Science, vol. 347, no. 6224 (February 20,
2015), pp. 830-831 (hereinafter McGarr et al., “Coping with Earthquakes”).
44 See, for example, the National Seismic Hazard Maps published by the USGS at http://earthquake.usgs.gov/hazards/
products/conterminous/. For more information about earthquakes generally, see CRS Report RL33861, Earthquakes:
Risk, Detection, Warning, and Research, by Peter Folger.
45 The USGS designates a 50-year period for the National Seismic Hazard Maps partly because natural earthquakes are
time independent (i.e., the tectonic forces that lead to earthquakes are constant over a specified time, such as 50 years).
Induced seismicity caused by wastewater disposal, recovery, and HF wells can vary on a much shorter time scale (e.g.,
days, weeks or months).
46 Mark D. Petersen et al., 2016 One-Year Seismic Hazard Forecast for the Central and Eastern United States from
Induced and Natural Earthquakes, USGS, Open-File Report 2016-1035, June 17, 2016, at https://pubs.er.usgs.gov/
publication/ofr20161035 (hereinafter Petersen, 2016 One-Year Seismic Hazard Forecast) . USGS, “Hazard Estimation
for Induced Earthquakes,” at https://www.usgs.gov/programs/earthquake-hazards/science/hazard-estimation-induced-
earthquakes. Jason L. Rubinstein, Andrew J. Barbour, and Jack H. Norbeck, “Forecasting Induced Earthquake Hazard
Using a Hydromechanical Earthquake Nucleation Model,” Seismological Research Letters, vol. 92 (2021), pp. 2206-
2220, doi: 10.1785/0220200215 (hereinafter Rubinstein, Barbour, and Norbeck, “Forecasting,” 2021).
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2018 map in Figure 4 shows two main areas of earthquake hazard in the CEUS: the natural
seismic zone near New Madrid, MO, and the induced seismic zone extending around Oklahoma
City, OK.47
The risks from induced earthquakes is ultimately dependent on local geologic conditions and
local fluid injection activities.48 Oklahoma state agencies monitor induced earthquakes at the local
level and understand that fluid injections may cause earthquakes on preexisting faults in the
deeper crystalline basement below the injection site soon after injection or the earthquakes may
be delayed for reasons that are not fully understood. Oklahoma’s monitoring identifies different
fault risks for Oklahoma regulators to consider and they may adjust their response regarding fluid
injection activities that may induce earthquakes. Similarly Texas state agencies recognize that
induced earthquakes may occur on preexisting faults in the shallow layers above or at the same
level as the injection site as well as in the deeper crystalline basement based on TexNet
monitoring. Texas regulators have posted plans to respond to the seismicity in shallow and deep
areas to reduce risks.49
Figure 4. Chance of Damage from an Earthquake in the Central and Eastern United
States in 2018

Source: USGS, “Hazard Estimation for Induced Earthquakes,” at https://www.usgs.gov/programs/earthquake-
hazards/science/hazard-estimation-induced-earthquakes. Modified by CRS.
Notes: One-year forecast for 2018 of potential earthquake shaking in the central and eastern United States
based on past induced and natural earthquakes. The natural seismic zone near New Madrid, MO, and the
induced seismic zone near Oklahoma City, OK, had the highest potential for shaking in 2018.

47 The New Madrid Seismic Zone experienced high-magnitude earthquakes (M 7.0+) in 1811-1812 and continues to
experience smaller-magnitude earthquakes recorded on modern seismic instruments. See USGS, “The New Madrid
Seismic Zone,” at https://www.usgs.gov/programs/earthquake-hazards/new-madrid-seismic-zone. For more
information about earthquake risk in the United States generally, see CRS Report RL33861, Earthquakes: Risk,
Detection, Warning, and Research, by Peter Folger; and CRS Report R43141, The National Earthquake Hazards
Reduction Program (NEHRP): Issues in Brief, by Linda R. Rowan.
48 GWPC/IOGC, Induced Seismicity Guide, 2021.
49 RRC, Seismicity Response.
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Overview of the Current Regulatory Structure
Regarding Induced Seismicity
According to a National Research Council report, conventional oil and gas production and
hydraulic fracturing combined generate more than 800 billion gallons of fluid each year.
Underground injection control (UIC) Class II injection wells dispose of more than one-third of
this volume deep underground.50 Deep-well injection has long been the environmentally preferred
option for managing produced brine and other wastewater associated with oil and gas production.
However, the development and growth of HF production has contributed significantly to a
growing volume of wastewater requiring disposal and has created demand for disposal wells in
new locations. Recent incidents of seismicity near disposal wells have drawn renewed attention to
laws, regulations, and policies governing wastewater management and have generated various
responses at the federal and state levels. This section of the report reviews the current regulatory
framework for managing underground injection and identifies several federal and state initiatives
in response to concerns surrounding Class II disposal and induced seismicity.
EPA Regulation of Underground Injection
The principal law authorizing federal regulation of underground injection activities is the Safe
Drinking Water Act (SDWA), as amended.51 The law specifically directs EPA to promulgate
regulations for state UIC programs to prevent underground injection that endangers drinking
water sources.52 Historically, EPA has not regulated oil and gas production wells. Further, as
amended in 2005, SDWA explicitly excludes the regulation of underground injection of fluids or
propping agents (other than diesel fuels) associated with hydraulic fracturing operations related to
oil, gas, and geothermal production activities.53
SDWA authorizes states and Indian tribes to assume primary enforcement authority (primacy) for
the UIC program for any or all classes of injection wells.54 EPA must delegate this authority,
provided the state or tribal program meets certain statutory and EPA requirements.55 If EPA does
not approve a state’s UIC program plan or if a state chooses not to assume program responsibility,
then EPA implements the UIC program in that state.

50 NRC, Committee on Induced Seismicity Potential in Energy Technologies, Induced Seismicity Potential in Energy
Technologies (Washington, DC: National Academy Press, 2012), p. 110.
51 The Safe Drinking Water Act of 1974 (SDWA; P.L. 93-523) authorized the UIC program at EPA. UIC provisions are
contained in SDWA Part C, §§1421-1426; 42 U.S.C. §§300h-300h-5.
52 42 U.S.C. §300h(d). SDWA §1421.
53 The Energy Policy Act of 2005 (P.L. 109-58, §322) amended the definition of underground injection, SDWA
§1421(d), to expressly exempt hydraulically fractured oil, gas, or geothermal production wells from the UIC program
unless diesel fuels are used in the fracturing fluid. A propping agent is a material, such as sand, that is injected along
with hydraulic fracturing fluid to “prop” open the cracks in the formation.
54 For most SDWA programs, including the UIC provisions, state is defined to include the District of Columbia and
territories (SDWA §1401; 42 U.S.C. §§300f(14). Tribes are authorized to receive primacy under SDWA §1451; 42
U.S.C. §300j-11. Navajo Nation and the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation have
attained primacy for Class II wells.
55 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 or tribes must demonstrate that their programs are effective in preventing
endangerment of underground sources of drinking water.
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For oil and gas-related injection operations (e.g., produced water disposal through Class II wells),
the law allows states or tribes to administer the UIC program using state rules rather than meeting
EPA regulations, provided a state demonstrates it has an effective program that prevents
underground injection that endangers drinking water sources.56 Most oil and gas states and some
tribes have assumed primacy for Class II wells under this provision.
Under the UIC program, EPA, states, and tribes regulate more than 700,000 injection wells. To
implement the UIC program as mandated by SDWA, EPA has established six classes of
underground injection wells based on categories of materials injected by each class
In addition to the similarity of fluids injected, 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 USDW.57
Class II injection wells include wells (1) to inject fluids to enhance recovery of oil and gas from
conventional fields (Class IIR), (2) to dispose of brines (saltwater) and other fluids (wastewater)
associated with oil and gas production (Class IID), and (3) to store liquid hydrocarbons. There are
more than 156,000 Class II wells across the United States. Based on historical averages, roughly,
80% of the Class II wells are enhanced recovery wells and 20% are disposal wells.58 Class II
injection wells, specifically Class IID disposal wells, have caused the most induced earthquakes
in the CEUS since 2009 (see Table A-1 in the Appendix for the number of oil and gas wells and
Class II wells by state in operation in 2019 or 2020).

56 SDWA §1425 requires a state to demonstrate that its UIC program meets the requirements of §1421(b)(1)(A)
through (D) and represents an effective program (including adequate record keeping and reporting) to prevent
underground injection that endangers underground sources of drinking water. To receive approval under §1425’s
optional demonstration provisions, a state program must include permitting, inspection, monitoring, and record-keeping
and reporting requirements.
57 EPA regulations define an underground source of drinking water (USDW) to mean an aquifer or part of an aquifer
that (1) supplies a public water system, or contains a sufficient quantity of groundwater to supply a public water
system, and currently supplies drinking water for human consumption or contains fewer than 10,000 milligrams per
liter (mg/L or parts per million) total dissolved solids and (2) is not an “exempted aquifer.” 40 C.F.R. 144.3.
58 Enhanced recovery wells are separate from, but often surrounded by, production wells. Recovery wells inject
produced water (brine), fresh water, steam, polymers, or carbon dioxide (CO2) into oil-bearing formations to recover
additional oil (and sometimes gas) from former production wells. EPA, “Class II Oil and Gas Related Injection Wells,”
at https://www.epa.gov/uic/class-ii-oil-and-gas-related-injection-wells. See Table A-1 in the Appendix for the number
of disposal and recovery wells by state, as the percentages of each per state are more variable then the 80%/20%
average for the total number of wells in the United States.
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Table 2. Underground Injection Control Program: Classes of Injection Wells and Nationwide Numbers
Well
Class
Purpose and Uses
Number of Wells
Class I
Inject hazardous wastes, industrial nonhazardous liquids, or municipal wastewater beneath the lowermost underground source of
903, including 135
drinking water (USDW).
hazardous waste wells
Class II
Inject brines and other fluids associated with oil and gas production and liquid hydrocarbons for storage. Inject fluids beneath the
>156,000
lowermost USDW.
Types of Class II wells include the fol owing:a

Enhanced Recovery Wells: Separate from but often surrounded by production wells, enhanced recovery wells are used to
inject produced water (brine), fresh water, steam, polymers, or carbon dioxide (CO2) into oil-bearing formations to recover
additional oil (and sometimes gas) from production wells. These wells also may be used to maintain reservoir pressure. This
category includes hydraulic fracturing wel s when diesel fuels, however, most hydraulic fracturing wells do not use diesel fuels
and are excluded from the EPA UIC program. Approximately 80% of Class II wells are enhanced recovery (Class IIR) wells.

Disposal Wells: Produced water and other fluids associated with oil and gas production (including flowback from hydraulic
fracturing operations) are injected into disposal wells for permanent disposal. Approximately 20% of Class II wells are disposal
(Class IID) wells.

Hydrocarbon Storage Wells: More than 100 Class II wells are used to inject liquid hydrocarbons (e.g., petroleum) into
underground formations for storage.
Class III Inject fluids associated with solution mining of minerals (e.g., salt and uranium) beneath the lowermost USDW.
28,465
Class IV Inject hazardous or radioactive wastes into or above USDW. Banned unless authorized under a federal or state groundwater
169
remediation project.
Class V
Al injection wells not included in Classes I-IV, including experimental wells. Often inject nonhazardous fluids into or above USDW.
>549,000
Many are shallow, on-site disposal systems (e.g., cesspools and stormwater drainage wells). Some Class V wells (e.g., geothermal
energy) inject below USDW.
Class VI Used for the geologic sequestration of CO2.
4
Sources: U.S. Environmental Protection Agency (EPA), Underground Injection Control Program, Classes of Wells, and Class II Wells—Oil and Gas Related Injection Wells, at
http://www.epa.gov/uic/class-ii-oil-and-gas-related-injection-wells; and EPA, “FY2019 State UIC Injection Well Inventory,” accessed September 22, 2022.
Notes: Regulations for Class I (hazardous waste) and Class VI (CO2 sequestration) wells include evaluation of seismic risk among requirements to prevent movement of
fluids out of the injection zone to protect USDW. New York and New Jersey did not submit data for EPA’s UIC well inventory. This table does not include tribal wel s,
which include Class 1, Class II, and Class V wells (totaling 6,945 wells, according to EPA’s FY2019 Tribal UIC Injection Well Inventory). See Table A-1 in the Appendix
for the number of Class IID and Class IIR wells by state.
a. Additionally, a Class II permit would be required for an oil, gas, or geothermal production well if diesel fuels were used in the hydraulic fracturing fluid.
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Earthquakes Induced by Underground Fluid Injection and the Federal Role in Mitigation

Consideration of Seismicity in EPA UIC Regulations
SDWA does not mention seismicity; rather, the law’s UIC provisions authorize EPA to regulate
underground injection to prevent endangerment of USDW. Seismicity has the potential to affect
drinking water quality through various means (e.g., by damaging the integrity of a well or
creating new fractures and pathways for fluids to reach groundwater). EPA UIC regulations
include various requirements aimed at protecting USDW by ensuring injected fluids remain in a
permitted injection zone. Some of these measures also could reduce the likelihood of inducing
seismic events. For example, injection pressures for Class II (and other) wells may not exceed a
pressure that would initiate or propagate fractures in the confining zone adjacent to a USDW.59 As
a secondary benefit, limiting injection pressure could prevent fractures that may act as conduits
through which injected fluids could reach an existing fault.
EPA regulations for two categories of injection wells—Class I hazardous waste disposal wells and
Class VI wells for geologic sequestration of CO2—specifically address evaluation of seismicity
risks with siting and testing requirements. For Class I wells, EPA regulations include minimum
criteria for siting hazardous waste injection wells, requiring that wells be limited to geologically
suitable areas. The UIC director (i.e., EPA or the delegated state or tribe) is required to determine
geologic suitability based on an “analysis of the structural and stratigraphic geology, the
hydrogeology, and the seismicity of the region.”60 Testing and monitoring requirements for Class
I wells state that “the Director may require seismicity monitoring when he has reason to believe
that the injection activity may have the capacity to cause seismic disturbances.”61
For Class VI CO2 sequestration wells, EPA regulations similarly require evaluation of seismicity
risks through siting and testing requirements. In determining whether to grant a permit, the UIC
director must consider various factors, including potential for seismic activity:
Prior to the issuance of a permit for the construction of a new Class VI well or the
conversion of an existing Class I, Class II, or Class V well to a Class VI well, the owner or
operator shall submit ... and the Director shall consider ... information on the seismic
history including the presence and depth of seismic sources and a determination that the
seismicity would not interfere with containment.62
EPA regulations for oil and gas wastewater disposal wells (or other Class II wells) do not include
these provisions or otherwise address seismicity. However, the regulations give discretion to UIC
directors to include in individual permits additional conditions as needed to protect USDW
(including requirements for construction, corrective action, operation, monitoring, or reporting).63
Again, for the purpose of protecting drinking water sources, permits for all Class I, II, and III
wells must contain specified operating conditions, including “a maximum operating pressure
calculated to avoid initiating and/or propagating fractures that would allow fluid movement into a

59 40 C.F.R. §146.23(a)(1).
60 40 C.F.R. §146.62(b)(1).
61 40 C.F.R. §146.68(f).
62 40 C.F.R. §146.82(a)(3)(v).
63 Relevant provisions for Class II wells are published at 40 C.F.R. §144.12(b) and 40 C.F.R. §144.52(a)(9) or (b)(1).
See also 40 C.F.R. Part 147.
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USDW.”64 Regulations for Class I wells further specify that “injection pressure must be limited
such that no fracturing of the injection zone occurs during operation.”65
Outside of regulations, EPA has taken steps to address induced seismicity concerns associated
with Class II disposal wells. For example, EPA Region III, which directly implements the UIC
program in Pennsylvania and Virginia, evaluates induced seismicity risk factors when considering
permit applications for Class II wells.66 In responding to public comments on a Class II well
permit application in 2013, the regional office noted the following:
Although EPA must consider appropriate geological data on the injection and confining
zone when permitting Class II wells, the SDWA regulations for Class II wells do not
require specific consideration of seismicity, unlike the SDWA regulations for Class I wells
used for the injection of hazardous waste.... Nevertheless, EPA evaluated factors relevant
to seismic activity such as the existence of any known faults and/or fractures and any
history of, or potential for, seismic events in the areas of the Injection Well as discussed
below and addressed more fully in “Region 3 framework for evaluating seismic potential
associated with UIC Class II permits, updated September, 2013.”67
Recommendations to Mitigate Induced Seismicity Related to Class II Disposal
Wells
As discussed above, SDWA does not directly address seismicity; rather, the law authorizes EPA to
regulate subsurface injections to prevent endangerment of drinking water sources. In 2011, in
response to earthquake events in Arkansas and Texas, EPA asked the Underground Injection
Control National Technical Workgroup to “develop technical recommendations to inform and
enhance strategies for avoiding significant seismicity events related to Class II disposal wells.”
The workgroup was specifically asked to address concerns that induced seismicity associated
with Class II disposal wells could cause injected fluids to move outside the containment zone and
could endanger drinking water sources. EPA requested that the report contain the following
specific elements:
 Comparison of parameters identified as most applicable to induced seismicity
with the technical parameters collected under current regulations.
 Decisionmaking model/conceptual flow chart to
 provide strategies for preventing or addressing significant induced
seismicity,
 identify readily available applicable databases or other information,
 develop a site characterization checklist, and
 explore applicability of pressure transient testing and/or pressure
monitoring techniques.

64 EPA, Technical Program Overview: Underground Injection Control Regulations, EPA 816-R-02-005, revised July
2001, p. 65, at http://water.epa.gov/type/groundwater/uic/upload/
2004_5_3_uicv_techguide_uic_tech_overview_uic_regs.pdf.
65 Ibid., p. 66.
66 EPA also directly implements the UIC program for other oil and gas producing states, including Kentucky,
Michigan, and New York.
67 EPA Region III, Response to Comments for the Issuance of an Underground Injection Control (UIC) Permit for
Windfall Oil and Gas, Inc., 2013, pp. 3-9, at http://www.epa.gov/sites/default/files/2020-12/documents/windfall-
pas2d020bcle_response_to_comments_final_0.pdf.
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 Summary of lessons learned from case studies.
 Recommended measurement or monitoring techniques for high-risk areas.
 Applicability of conclusions to other well classes.
 Defined specific areas of research, as needed.68
In February 2015, EPA released the National Technical Workgroup’s final report, Minimizing and
Managing Potential Impacts of Injection-Induced Seismicity from Class II Disposal Wells:
Practical Approaches, which addressed the above tasks.69 The report does not constitute formal
agency guidance, nor has EPA initiated any rulemaking regarding this matter. Rather, the
document includes practical management tools and best practices to “provide the UIC Director
with considerations for addressing induced seismicity on a site-specific basis, using Director
discretionary authority.”70
Among other findings, the report identifies three key components that must be present for
injection-induced seismic activity to occur:
1. Sufficient pressure buildup from disposal activities.
2. A fault of concern.
3. A pathway allowing the increased pressure to communicate from the disposal
well to the fault.71
As discussed, current Class II regulations give discretion to UIC directors to include in individual
permits additional conditions and requirements as needed to protect USDW.72 The Practical
Approaches document notes that, although EPA is unaware of any USDW contamination resulting
from seismic events related to induced seismicity, potential USDW risks from seismic events
could include loss of disposal well mechanical integrity, impact to various types of existing wells,
changes in USDW water level or turbidity, or USDW contamination from a direct communication
with the fault inducing seismicity or contamination from earthquake-damaged surface sources.73
The report includes a decision model to inform regulators on site assessment strategies and
recommends monitoring, operational, and management approaches to manage and minimize
suspected injection-induced seismicity. Among the management recommendations, the report
suggests that, for wells suspected of causing induced seismicity, managers should take early
actions (e.g., requiring more frequent pressure monitoring and reducing injection rates) rather
than requiring definitive proof of causality.74
The technical workgroup also identified research needs to better understand the potential for
injection-related induced seismicity, including research regarding geologic siting criteria for
disposal zones in areas with limited or no data. As a general principal, the workgroup

68 EPA, Minimizing and Managing, p. 5.
69 EPA, Minimizing and Managing. The report includes case studies of induced seismicity events and responses in four
states: Arkansas, Ohio, Texas, and West Virginia. The UIC director is the state program director where the state has
program primacy or EPA in states where EPA implements the program directly.
70 EPA, Minimizing and Managing, ES-2.
71 EPA, Minimizing and Managing, ES-2.
72 Relevant provisions for Class II wells are published at 40 C.F.R. §144.12(b) and 40 C.F.R. §144.52(a)(9) or (b)(1).
See also 40 C.F.R. Part 147.
73 EPA, Minimizing and Managing, p. 4.
74 EPA, Minimizing and Managing, p. 35.
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recommended that future research be conducted using a holistic, multidisciplinary approach,
combining expertise in petroleum engineering, geology, geophysics, and seismicity.75
State Initiatives Regarding Induced Seismicity
Several organizations and states in the CEUS are monitoring, assessing, guiding, and regulating
Class II wells (i.e., waste and recovery) and HF operations that may induce seismicity.76 In 2014,
the Interstate Oil and Gas Compact Commission and the Ground Water Protection Council
formed an Induced Seismicity Work Group (ISWG) with state regulatory agencies and state
geological surveys to “proactively discuss the possible association between recent seismic events
occurring in multiple states and injection wells.”77 The ISWG issued its first primer about induced
seismicity in 2015, a second primer in 2017, and a guide in 2021. The 2015 and 2017 primers
focused on induced seismicity associated with Class II wells. The 2021 guide updated its
summary of the scientific understanding of induced seismicity and “expanded on the topic of
induced seismicity related to hydraulic fracturing.”78
States regulate oil and gas activities within their state boundaries, and in some cases the state oil
and gas activities program includes the state UIC program. In other cases, a different state agency
runs the UIC program.
States in the CEUS that have experienced increased induced seismicity related to oil and gas
activities have instituted mitigation strategies. Strategies may include requiring underground
injection operators to (1) assess seismic risks before beginning operations, (2) provide details
about their operations, and (3) monitor injection sites with seismic instruments for any
earthquakes. If induced seismicity is attributed to certain wells, regulators may ask or require the
operators to change their operations (e.g., reduce the volume or pressure of fluid injections or
change the depth of the injections), or to stop their operations.79 For example, Oklahoma has

75 EPA, Minimizing and Managing, pp. 31-32. In another federal initiative, the Department of Energy (DOE) is
conducting a research program to promote development of the nation’s geothermal resources, including development of
enhanced geothermal systems. The development of these systems can enable previously uneconomical hydrothermal
systems to produce geothermal energy on a large scale; the process of injecting fluids to enhance permeability of
hydrothermal systems may also induce earthquakes. In 2012, DOE released an Induced Seismicity Protocol to mitigate
risks associated with the development of these systems. Some of the approaches and mitigation measures included in
the DOE protocol may be applicable to issues posed by Class II disposal wells. See Emie Majer Tait et al., Protocol for
Addressing Induced Seismicity Associated with Enhanced Geothermal Systems, DOE, Office of Energy Efficiency and
Renewable Energy, DOE/EE-0662, January 2012, at https://www1.eere.energy.gov/geothermal/pdfs/
geothermal_seismicity_protocol_012012.pdf.
76 GWPC/IOGC, Induced Seismicity Guide, 2021.
77 The Interstate Oil and Gas Compact Commission is a multistate agency that states that it “works to champion the
conservation and efficient recovery of our nation’s oil and natural gas resources while protecting health, safety and the
environment.” The commission asserts it does so by “providing member states with a clear and unified voice and
serving as the authority on issues surrounding these vital resources,” and says it “assists states in balancing a multitude
of interests through sound regulatory practices.” According to the commission, its “unique structure offers a highly
effective forum for states, industry, Congress and the environmental community to share information and viewpoints to
advance our nation’s energy future” (Interstate Oil and Gas Compact Commission, “About Us,” at https://iogcc.ok.gov/
about-us.) The Ground Water Protection Council is “a nonprofit 501(c)6 organization whose members consist of state
ground water regulatory agencies which come together ... to mutually work toward the protection of the nation’s
ground water supplies” (Ground Water Protection Council, “About Us,” at https://www.gwpc.org/about-us/overview/).
States First Initiative, States Team Up to Assess Risk of Induced Seismicity, April 29, 2014, at
http://www.statesfirstinitiative.org or http://www.statesfirstinitiative.org/#!States-Team-Up-to-Assess-Risk-of-Induced-
Seismicity/c8t8/72D0196F-1DAB-4617-B446-B009A1D902FB.
78 GWPC/IOGC, Induced Seismicity Guide, 2021.
79 Ibid.
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regulations and directives to mitigate induced seismicity while allowing oil and gas activities in
the state.80 In addition, some states have banned the drilling of underground injection wells in
geologic zones of known seismic risk. The 2021 guide provides examples of state efforts to
regulate activities to reduce potential seismic risks and mitigate induced seismicity related to oil
and gas activities and concomitant wastewater disposal.
Options for Congress
Interest in policies or regulations to mitigate induced seismicity caused by underground fluid
injection in the CEUS may change in accordance with the number of induced earthquakes per
year, which peaked in 2015, then decreased from 2016 to 2019, and increased again in 2020 and
2021 (Figure 1). Other reasons for renewed interest include several M 5.0 or larger events in
Texas in 2020 and 2022 and an M 4.5 earthquake near Clyde, OK, in 2022; news reports and
public concern about induced seismicity damage and related litigation; increasing oil and gas
activities related to higher oil prices; and increasing interest in the development of enhanced
geothermal systems and geologic carbon sequestration.81 Underground fluid injection activities
associated with advancing geothermal energy systems, and injecting liquid carbon dioxide for
geologic sequestration may induce earthquakes and may require mitigation strategies similar to
those for oil and gas activities to reduce earthquake risks.
Congress may consider whether to support federal agency efforts in research, risk assessment,
response, and/or mitigation strategies to understand and reduce induced seismicity caused by
underground fluid injection activities. In the past, the USGS has studied induced seismicity
caused by underground fluid injections (e.g., oil and gas activities, wastewater disposal, and
geologic carbon sequestration) in the CEUS and issued one-year earthquake hazard forecasts for
the CEUS for 2016, 2017, and 2018 (see “Understanding, Monitoring, and Assessing the Risk of
Induced Seismicity”).82 The USGS has partnered with states in the CEUS to monitor earthquakes
with USGS and state-led seismic networks.83 The FY2022 and FY2023 President’s budget
requests called for increased funding for the USGS to study induced seismicity caused by
geothermal or geologic carbon sequestration activities, and for a one-year earthquake hazard
forecast for the CEUS similar to those produced in 2016-2018.84 The House Appropriations
Committee agreed with some of the Administration’s proposals to support induced seismicity

80 Oklahoma Corporation Commission, “Response to Oklahoma Earthquakes,” at https://oklahoma.gov/occ/divisions/
oil-gas/induced-seismicity-and-uic-department/response-oklahoma-earthquakes.html.
81 The M 5.0 or larger earthquakes in Texas include a M 5.0 event near Metone, TX on March 26, 2020, a M 5.4 event
near Coalson Draw, TX on November 16, 2022, and a M 5.3 event near Range Hill, TX on December 16, 2022 (see
USGS, “M 5.3 – Range Hill, Texas,” at https://earthquake.usgs.gov/earthquakes/eventpage/tx2022yplg/executive). Erin
Douglas, “Earthquakes in Texas Doubled”; Wallis, “Oil Company Agrees to Settlement”; and Anthony Faiola,
“Earthquakes for Ukraine: Dutch Gas Drilling Tests What Countries Will Accept,” Washington Post, September 1,
2022, at https://www.washingtonpost.com/world/2022/09/01/natural-gas-europe-ukraine-earthquakes/.
82 See USGS, “Observational Studies of Induced Earthquakes,” at https://www.usgs.gov/programs/earthquake-hazards/
science/observational-studies-induced-earthquakes, and a list of related publications at USGS, “Induced Earthquakes
Overview,” at https://www.usgs.gov/programs/earthquake-hazards/science/induced-earthquakes-
overview#publications. See also USGS, “Induced Seismicity Associated with Carbon Dioxide Geologic Storage,” at
https://www.usgs.gov/centers/geology-energy-and-minerals-science-center/science/induced-seismicity-associated-
carbon. Petersen, 2016 One-Year Seismic Hazard Forecast and USGS, “Hazard Estimation for Induced Earthquakes,”
at https://www.usgs.gov/programs/earthquake-hazards/science/hazard-estimation-induced-earthquakes.
83 See footnote 34.
84 USGS, Budget Justifications and Performance Information Fiscal Year 2023, 2022, at https://d9-wret.s3.us-west-
2.amazonaws.com/assets/palladium/production/s3fs-public/media/files/FY23-USGS-Greenbook.pdf.
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research at the USGS in FY2023 (H.Rept. 117-400).85 The Senate Appropriations Committee did
not express support for any specified induced seismicity work by the USGS in FY2023.86 The
FY2023 Consolidated Appropriations Act does not include any specific funding for induced
seismicity research or assessment by the USGS (P.L. 117-328). Congress may consider whether
to direct the USGS to specifically study or provide earthquake hazards assessment for induced
seismicity and whether to specify any funding for such work.
Congress may consider whether EPA or DOE requirements, reports, or guidance regarding
induced seismicity from underground fluid injection activities are sufficient to reduce the risks of
induced earthquakes. Especially given earthquake activity in the CEUS in the past few years and
ongoing research and seismic monitoring by federal, state, or local entities (e.g., USGS, state
geological surveys, state regulators, and universities). The EPA requires induced seismicity risk
assessment for Class I hazardous waste disposal wells and Class VI geologic carbon sequestration
wells, but not for Class II wells. EPA issued a report in 2015 on induced seismicity risk
assessment and management for Class II wastewater disposal wells (see “Consideration of
Seismicity in EPA UIC Regulations”), but the report has no regulatory authority and did not
discuss Class II enhanced oil and gas recovery wells. In addition, DOE supports research and
demonstration projects for enhanced geothermal systems and geologic carbon sequestration; these
underground fluid injection activities may induce earthquakes.87 DOE issued a report in 2012 on
induced seismicity protocols to mitigate earthquake risks associated with the development of
enhanced geothermal systems.88 Congress may provide oversight as to whether these past
requirements, reports, and guidance are sufficient to reduce the risks of induced earthquakes.
Congress may consider the federal role in regulating underground fluid injection activities to
mitigate induced seismicity. EPA has some regulatory authority regarding induced seismicity for
Class I and VI wells, while USGS and DOE have no regulatory authority regarding induced
seismicity for any underground injection activities (see “Overview of the Current Regulatory
Structure Regarding Induced Seismicity”). The EPA allows states and Indian tribes to operate the
UIC program in their state or tribal land if they meet the program criteria (see “EPA Regulation of
Underground Injection”). Most induced earthquakes in the CEUS are correlated with Class II
wastewater disposal and HF wells (excluded from the EPA UIC program, except when diesel fuel
is used) that are not regulated for induced seismicity by EPA. In the 117th Congress, some
Members introduced bills that would have regulated HF wells through EPA or the Bureau of Land
Management (BLM). Such measures could potentially include a federal role for regulating
induced earthquakes. For example, the Fracturing Responsibility and Awareness of Chemicals Act
of 2021 (H.R. 2202) proposed to repeal the exemption for HF activities in SDWA including the
underground injection of fluids for HF activities under SDWA Section 1421(d)(1). The Restoring
Community Input and Public Protections in Oil and Gas Leasing Act of 2021 (H.R. 1503)
proposed to give the BLM authority to regulate HF activities on federal lands. The Safe
Hydration is an American Right in Energy Development Act of 2021 (H.R. 2164) and the

85 The committee called for $3.1 million for the USGS Earthquake Hazards Program for induced seismicity and did not
specify whether the work should focus on any particular underground injection activities or hazard forecast.
86 United States Senate Committee on Appropriations, Explanatory Statement for the Department of the Interior,
Environment, and Related Agencies Appropriations Bill, 2023, p. 46-47, https://www.appropriations.senate.gov/imo/
media/doc/INTFY23RPT.PDF.
87 DOE Office of Energy Efficiency and Renewable Energy, “Geothermal Technologies Office,” at
https://www.energy.gov/eere/geothermal/geothermal-technologies-office and DOE Office of Fossil Energy and Carbon
Management, “Carbon Storage Research,” at https://www.energy.gov/fecm/science-innovation/carbon-capture-and-
storage-research.
88 See footnote 75.
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CLEAN Future Act (H.R. 1512) proposed to amend SDWA to require EPA to revise regulations
for state UIC programs to require testing of USDW that are within access of HF activities. None
of these measures would have required EPA to regulate Class II wells for induced seismicity.
Congress may consider allowing states to continue to regulate oil and gas and underground fluid
injection activities with support for research, monitoring, hazard assessment, and risk
management from federal agencies. Another bill introduced in the 117th Congress would have
specified state primacy in regulating HF wells. The Fracturing Regulations Are Effective in State
Hands Act (S. 2393) proposed to clarify that the state has sole authority to regulate HF activities
on federal land within state boundaries. Oklahoma provides an example of a state regulating oil
and gas activities and the UIC program in the state while working with federal agencies.89 The
Oklahoma Corporation Commission (OCC) regulates oil and gas activities and has primacy for
the UIC program in the state. As the number and magnitude of earthquakes on annual basis
increased in Oklahoma (Figure 3), the state began to address the issue. Oklahoma agencies
enhanced seismic monitoring, established regulations and protocols for induced seismicity, and
issued directives requiring well operators to change their operations or cease operations where
induced earthquakes posed a risk (see “Seismic Monitoring of Induced Earthquakes”, “State
Initiatives Regarding Induced Seismicity”, and the text box titled “Magnitude 5.8 Earthquake
near Pawnee, OK: September 3, 2016”). Oklahoma worked with the USGS on seismic monitoring
and earthquake science and with the EPA on managing the UIC program. In addition, Oklahoma
worked with EPA, which has primacy over the Osage Nation UIC program in Oklahoma to deal
with the aftermath of the M 5.8 earthquake near Pawnee, OK.90 The EPA issued directives similar
to the OCC directives, requesting well operators within the Osage Nation to change their
operations or cease operations near the M 5.8 event. The OCC attributed a decrease in the number
of induced earthquakes per year in Oklahoma after 2015 to their monitoring, research,
regulations, and directives.91

89 The Oklahoma Corporation Commission (OCC) has authority to regulate oil and gas activities under Oklahoma
Administrative Code (OAC) Title 52:3-139. Oklahoma Secretary of State, “Oklahoma Administrative Code,” at
https://rules.ok.gov/code. The OCC operates the Underground Injection Control (UIC) program in Oklahoma. Most
regulations for oil and gas activities, including wastewater disposal, are in OAC Title 165 Corporation Commission,
Chapter 10: Oil and Gas Conservation (OAC 165:10). These rules generally require operators to apply for permits for
underground injection operations in the state and to notify the OCC of the status of operations. OCC publishes
additional instructions regarding induced seismicity as directives or notices, OCC, “Response to Oklahoma
Earthquakes,” at https://oklahoma.gov/occ/divisions/oil-gas/induced-seismicity-and-uic-department/response-
oklahoma-earthquakes.html. The OCC has an Oil and Gas Conservation Division (OGCD) that includes an Induced
Seismicity Department and a UIC Department. Together, these state agencies deal with any potential induced
seismicity caused by underground fluid injection activities. The OCC has established areas of seismic concern, where
induced seismicity has occurred in the past related to underground fluid injection activities. Special directives govern
well operations in these areas. For example, OCC, “Clyde Earthquake Directive,” at https://oklahoma.gov/occ/news/
news-feed/2022/clyde-earthquake-directive.html. The OCC established induced seismicity protocols for Oklahoma’s
largest oil and gas production area, including for HF wells, OCC, “Well Completion Protocol Updated, 02-27-2018,” at
https://oklahoma.gov/content/dam/ok/en/occ/documents/og/02-27-18protocol.pdf.
90 EPA has primacy over some tribal UIC programs and the Osage Nation has by far the largest number of Class II
wells of any EPA-administered UIC tribal program (Osage Nation had 993 wastewater disposal wells and 1390
enhanced oil and gas recovery wells in 2019), EPA, “UIC Injection Well Inventory,” at https://www.epa.gov/uic/uic-
injection-well-inventory.
91 Monitoring and research helped to identify the critically stressed faults near underground injection activities.
Regulations and directives identified well operations causing induced earthquakes on these faults and directed the well
operators to cease or change their operations to mitigate additional induced earthquakes. Oklahoma Corporation
Commission, Annual Report Fiscal Year 2018, 2018, pp. P. 48-49, https://oklahoma.gov/content/dam/ok/en/occ/
documents/ajls/about/Annual_Report-FY18.pdf.
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Appendix. Onshore Oil and Gas Production and
Disposal Wells By State
The U.S. Energy Information Administration estimates the amount of oil and gas production and
the number of oil and gas wells accounting for this production for the country. Table A-1 shows
that most of the onshore oil and gas production per state by total number of oil and gas wells and
by HF wells is in the central and eastern United States. The Environmental Protection Agency
estimates the number of Class II disposal and recovery wells for the country. Table A-1 shows
that most of the Class II wells are in the central and eastern United States.
Table A-1. Number of Oil and Gas and Disposal Wells By State
2019 or 2020
State
Oil and Gas Wells
HF Wells
Disposal Wells
Recovery Wells
AK
2,326
19
51
1,499
AL
5,946
14
89
188
AR
11,047
5,417
800
226
AZ
17
0
0
0
CA
47,898
1,815
1,698
34,990
CO
47,861
8,813
417
569
CT
^
^
0
0
DC
^
^
0
0
DE
^
^
0
0
FL
66
0
17
49
HI
^
^
0
0
IA
^
^
4
0
ID
^
^
0
0
IL
*
*
1,106
6,914
IN
*
*
215
949
KS
68,137
4
4,954
11,160
KY
18,594
1,209
117
3,004
LA
32,998
4,892
2,631
461
MA
^
^
0
0
MD
1
0
0
0
ME
^
^
0
0
MI
8,063
264
770
658
MN
^
^
0
0
MO
30
0
9
425
MS
2,987
258
575
769
MT
9,609
1,685
272
989
NC
^
^
0
0
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State
Oil and Gas Wells
HF Wells
Disposal Wells
Recovery Wells
ND
17,643
16,075
674
772
NE
1,664
2
146
484
NH
^
^
0
0
NJ
^
^
*
*
NM
57,533
8,654
983
3,249
NV
67
0
12
5
NY
10,046
47
*
*
OH
38,439
2,719
2,208
128
OK
71,779
15,909
4,337
6,688
OR
10
0
4
5
PA
78,769
10,109
17
1,642
RI
^
^
0
0
SC
^
^
0
0
SD
195
122
18
90
TN
1,864
20
3
30
TX
293,316
73,792
13,731
37,193
UT
11,960
462
86
694
VA
8,118
119
13
0
VT
^
^
0
0
WA
^
^
1
0
WI
^
^
0
0
WV
55,528
3,692
55
650
WY
31,121
2,663
459
4,537
Total
931,306
158,756
36,421
117,518
Source: Numbers for columns two (Oil and Gas Wells) and three (HF Wells) are from U.S. Energy Information
Administration, “U.S. Oil and Natural Gas Wells by Production Rate, Release Data: January 13, 2022” Appendix
B: Selected summary tables, at https://www.eia.gov/petroleum/wells/. Numbers for columns four (Disposal
Wells) and five (Recovery Wells) are from United States Environmental Protection Agency, “UIC Injection Well
Inventory,” FY2019 State UIC Inventory table, at https://www.epa.gov/uic/uic-injection-well-inventory.
Notes: Oil and Gas Wells includes conventional vertical wells, unconventional horizontal wells, enhanced oil and
gas recovery wells and other wells as defined in the EIA supplementary tables. HF Wells means hydraulic
fracturing oil and gas production wells. The United States Energy Information Administration (EIA) refers to HF
Wells as Horizontal Wel s in supplementary tables. Disposal Wells means wastewater disposal wells. The
Environmental Protection Agency (EPA) refers to Disposal Wells as Class IID Wells. Recovery Wells means
enhanced oil and gas recovery wells. EPA refers to Recovery Wells as Class IIR Wells. ^ means no well counts
were col ected for these states because the states do not have any oil and gas well activity. * means no data was
submitted for these states, even though there is well activity in these states. IL and IN did not report their well
data for any year according to EIA. The EIA numbers are from 2020, except MD is from 2016, MO is from 2019,
and TN is from 2016. The EPA numbers are from 2019. NJ and NY did not submit any data to EPA. The well
numbers are estimates as states and other data sources may count wells in different ways (e.g., a well pad with
multiple individual wells may be counted as one well).

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Earthquakes Induced by Underground Fluid Injection and the Federal Role in Mitigation

Author Information

Linda R. Rowan
Angela C. Jones
Analyst in Natural Resources and Earth Sciences
Analyst in Environmental Policy

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Congressional Research Service
R47386 · VERSION 1 · NEW
29

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Jan. 13, 2023

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Topic areas

Energy Policy

Environmental Policy

Report Type: CRS Report

Source: CRSReports.Congress.gov

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