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

Congressional research reportJan 13, 2023

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Earthquakes Induced by Underground Fluid

Injection and the Federal Role in Mitigation

January 13, 2023

Congressional Research Service

https://crsreports.congress.gov

R47386

SUMMARY

Earthquakes Induced by Underground Fluid

Injection and the Federal Role in Mitigation

Human activities, including underground fluid injection activities, may cause

earthquakes (known as induced earthquakes). Underground fluid injection activities,

such as hydraulic fracturing for oil and gas production, enhanced oil and gas recovery

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

of earthquakes of magnitude 3.0 or greater in the same region increased from 2009 to

2015, and these earthquakes are correlated in space and time with injection activities.

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.

R47386

January 13, 2023

Linda R. Rowan

Analyst in Natural

Resources and Earth

Sciences

Angela C. Jones

Analyst in Environmental

Policy

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

Contents

Introduction ..................................................................................................................................... 4

Understanding, Monitoring, and Assessing the Risk of Induced Seismicity ................................... 8

Seismic Monitoring of Induced Earthquakes ........................................................................... 11

Evaluating the Risk of Induced Earthquakes .......................................................................... 15

Overview of the Current Regulatory Structure Regarding Induced Seismicity ............................ 17

EPA Regulation of Underground Injection.............................................................................. 17

Consideration of Seismicity in EPA UIC Regulations ............................................................ 20

Recommendations to Mitigate Induced Seismicity Related to Class II Disposal

Wells .............................................................................................................................. 21

State Initiatives Regarding Induced Seismicity ...................................................................... 23

Options for Congress ..................................................................................................................... 24

Figures

Figure 1. Number of Magnitude 3.0 of Greater Earthquakes in the Central and Eastern

United States, 1973-2021 ............................................................................................................. 6

Figure 2. Illustration of the Possible Relationship Between Underground Injection

and Induced Seismicity ................................................................................................................ 9

Figure 3. Earthquakes of Magnitude 3.0 or Greater in Oklahoma, 2009-2021 ............................. 13

Figure 4. Chance of Damage from an Earthquake in the Central and Eastern United States

in 2018 ........................................................................................................................................ 16

Tables

Table 1. Damage from Induced Earthquakes in the United States Caused by Wastewater

Injection, 2011-2016.................................................................................................................... 11

Table 2. Underground Injection Control Program:

Classes of Injection Wells and Nationwide Numbers ................................................................ 19

Table A-1. Number of Oil and Gas and Disposal Wells By State.................................................. 27

Appendixes

Appendix. Onshore Oil and Gas Production and Disposal Wells By State ................................... 27

Contacts

Author Information........................................................................................................................ 29

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

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

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

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/earthquakehazards/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-uicdepartment/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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Earthquakes Induced by Underground Fluid Injection and the Federal Role in Mitigation

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, drilled through the flat-lying sedimentary rocks

into the underlying older crystalline rocks more than 12,000 feet deep, injected as much as 5.5 million 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 William L. Ellsworth, “Injection-Induced Earthquakes,” Science, vol. 341 (July 12, 2013), doi:

10.1126/science.1225942, at https://www.sciencemag.org/content/341/6142/1225942.full.

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

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

Notes: The figure is for illustrative 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

Location

Damage

2011

5.7

Prague, OK

Damaged homes, broke windows, cracked masonry, and collapsed 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/oilcompany-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%20DOEUSEA%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-earthquakesoverview#publications.

33 J. Ole Kaven et al., “Seismic Monitoring at the Decatur, IL, CO 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-anduic-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-2016oklahoma-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-texasearthquakes-fracking/ (hereinafter Douglas, “Earthquakes in Texas Doubled”).

39 Texas Railroad Commission (RRC), “Seismicity Response,” at https://www.rrc.texas.gov/oil-and-gas/applicationsand-permits/injection-storage-permits/oil-and-gas-waste-disposal/injection-disposal-permit-procedures/seismicityreview/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/nationalseismic-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-inducedearthquakes. 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. 22062220, 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/earthquakehazards/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

drinking water (USDW).

903, including 135

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

lowermost USDW.

Types of Class II wells include the following:a

>156,000



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 (CO 2) 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 wells 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

remediation project.

169

Class V

All injection wells not included in Classes I-IV, including experimental wells. Often inject nonhazardous fluids into or above USDW.

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.

>549,000

Class VI

Used for the geologic sequestration of CO2.

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 wells,

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).