Injection and Geologic Sequestration of Carbon Dioxide: Federal Role and Issues for Congress

January 24, 2020 – September 22, 2022 R46192

Injection and Geologic Sequestration of
September 22, 2022
Carbon Dioxide: Federal Role and Issues for
Angela C. Jones
Congress
Analyst in Environmental
Policy
For several decades, the federal government has funded efforts to explore the feasibility of

mitigating the release of greenhouse gases (GHGs) while burning fossil fuels as a source of
energy. Carbon capture and storage (CCS)—the process of capturing manmade carbon dioxide

(CO2) at its source and storing it before its release into the atmosphere—has been proposed as a
technological solution for mitigating emissions into the atmosphere while continuing to use fossil energy. Permanent
underground carbon storage, known as geologic sequestration, is the long-term containment of a fluid (including gas or liquid
CO2) in subsurface geologic formations. CO2 may be injected, and a portion incidentally stored, as part of enhanced oil
recovery (EOR) operations that increase production from aging oil reservoirs.
The U.S. Department of Energy (DOE) leads the federal government’s carbon storage research and development (R&D) as
part of the agency’s fossil energy programs. The agency conducts CCS research and carries out public-private partnerships
for testing and development of CO2 injection and storage projects. Congress has recently directed DOE to expand its R&D
activities to support deployment and commercialization of CCS projects.
The Safe Drinking Water Act (SDWA), administered by the U.S. Environmental Protection Agency (EPA), provides
authorities for regulating underground injection of fluids and serves as the framework for regulation of injection of CO2 for
geologic sequestration and EOR. The major purpose of the act’s Underground Injection Control (UIC) provisions is to
prevent endangerment of underground sources of drinking water from injection activities. EPA has promulgated regulations
and established minimum federal requirements for six classes of injection wells. In 2010, EPA promulgated regulations for
the underground injection of CO2 for long-term storage and established UIC Class VI, a new class of wells solely for
geologic sequestration of CO2. The well performance standards and other requirements established in the Class VI Rule are
based on the distinctive features of CO2 injection compared to other types of injection. Two Class VI wells, both in Illinois,
are currently permitted by EPA. EOR, including CO2-EOR, is conducted using Class II wells classified for disposal of fluids
associated with oil and gas production. SDWA authorizes states to administer the federal UIC programs in lieu of EPA,
known as primacy. For Class VI CO2 geologic sequestration wells, North Dakota and Wyoming have primacy under SDWA.
For Class II wells, SDWA authorizes states to regulate these wells under their own state programs, and most oil- and gas-
producing states have primacy for Class II wells. Currently in the United States, one geologic sequestration facility, the ADM
facility in Illinois, has EPA Class VI permits and is actively injecting CO2 from an ethanol plant for geologic sequestration.
North Dakota has issued two state Class VI permits for geologic sequestration.
Congress has supported carbon storage via underground injection through recent legislation that directs DOE to expand
research, development, and deployment activity and expands the federal tax credit for carbon sequestration. A policy
challenge that Congress may face with underground carbon storage is balancing protection of underground sources of
drinking water with supporting and encouraging the development of cost-effective CCS technology. Other policy issues of
congressional interest may include unresolved liability and property rights issues, overall CCS project cost, public acceptance
of these projects and participation in their planning, and the relationship of the growth of underground carbon injection and
storage with continuing to burn fossil fuels for generating electricity. In addition, Congress may consider potential health and
environmental risks (beyond any related risks to underground sources of drinking water) not addressed by SDWA.
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Injection and Geologic Sequestration of Carbon Dioxide

Introduction
For several decades, the federal government has funded efforts to explore the feasibility of
mitigating greenhouse gases (GHGs) emitted to the atmosphere from the burning of fossil fuels at
power plants and other large industrial facilities. Carbon capture and storage (CCS) is the process
of capturing manmade carbon dioxide (CO2), a GHG, at its source, such as a coal-fired power
plant, and injecting and storing it underground instead of releasing into the atmosphere.1 CCS has
been proposed as a technological solution for mitigating emissions while continuing to use fossil
energy. In a 2021 report to Congress on CCS, the Council on Environmental Quality (CEQ) noted
that in order to meet the Biden Administration’s goal of net-zero emissions by 2050, “significant
quantities” of CO2 will likely need to be permanently sequestered.2 Federal policies on CCS have
received support in recent Congresses, including support for research and development and
expansion of tax credits for carbon utilization or sequestration.3 This report focuses on federal
policy regarding the underground carbon injection and storage stage of CCS.
Under specific conditions, underground carbon storage can be achieved through geologic
sequestration and as a secondary result of enhanced oil recovery (EOR) processes that use CO2.
Both use wells to inject CO2 into deep subsurface geologic formations. Geologic sequestration
involves storing CO2 by placing it in an underground formation for ultimate permanent storage. A
small number of geologic sequestration projects are currently operating with goals of storing over
1 million tons of storage in several countries, typically developed with significant government
investment in research and development.4 EOR involves injecting water or certain chemicals—in
some cases CO2—to produce additional oil from underground reservoirs.
Injection of CO2 for both geologic sequestration and EOR are regulated under the Safe Drinking
Water Act (SDWA) for the purpose of protecting underground sources of drinking water
(USDWs).5 The U.S. Environmental Protection Agency (EPA) and delegated states administer
sections of SDWA relevant to underground injection and carbon storage. The U.S. Department of
Energy (DOE) also engages in underground carbon storage activities through supporting research,
development, and deployment (RD&D) activities.
In recent years, Congress has passed legislation related to carbon storage via underground
injection that directs DOE to expand RD&D activity and for the IRS to expand the federal tax
credit for carbon sequestration and utilization. As Congress considers further policies on
underground carbon storage, including geologic sequestration and EOR, Members may consider

1 CCS is one of several acronyms used to describe similar processes of capturing and storing or sequestering CO2
underground. Other commonly used terms include carbon capture, utilization, and sequestration and carbon capture,
utilization, and storage, both referred to as CCUS. This report uses “CCS” as a broad reference to all of these types of
systems.
2 Council on Environmental Quality, Report to Congress on Carbon Capture, Utilization, and Sequestration, June 30,
2021. The USE IT Act (Division S, P.L. 116-260, Consolidated Appropriations Act, 2021) directed CEQ, in
consultation with other agencies, to submit a report to Congress on permitting requirements and regulatory frameworks
for CCS infrastructure and projects.
3 Congress has amended Section 45Q through the American Recovery and Reinvestment Act (P.L. 111-5), the
Bipartisan Budget Act of 2018 (BBA; P.L. 115-123), the Consolidated Appropriations Act, 2021 (P.L. 116-260), and
the budgetary measure commonly known as the Inflation Reduction Act of 2022 (IRA; P.L. 117-169).
4 Consideration of “large-scale” carbon injection and sequestration has evolved in recent years in legislation and federal
law. 42 U.S.C. §16293 defines “large-scale” to mean a scale that has a goal of sequestering “not less than 50 million
metric tons of carbon dioxide.” This does not include earlier DOE-sponsored research pilot projects of significantly
smaller volumes.
5 Safe Drinking Water Act, §§1421-1425; 42 U.S.C. §§300h - 300h-5.
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the current regulatory framework and status of federal and federally sponsored activities in this
area.
This report provides background on underground injection and geologic sequestration processes,
related federal RD&D, and CO2 injection and storage projects. It then analyzes the federal
framework for regulating land-based underground injection of CO2 both for geologic
sequestration and EOR. Finally, it includes a discussion of several policy issues for Congress and
recent relevant federal legislation. Not covered in this report are research and management of
CCS elements not directly related to underground injection, including carbon capture and the
pipeline and transportation infrastructure for captured CO2. Regulation of geologic sequestration
on federal land and offshore geologic sequestration of CO2 are also beyond the scope of this
report. For additional information on the technical aspects of CCS, see CRS Report R44902,
Carbon Capture and Sequestration (CCS) in the United States.
Underground Carbon Storage Process
Underground Injection
Underground injection has been used for decades
Key Terms6
to dispose of a variety of fluids, including oil field
A fluid is “any material or substance which flows or
brines (salty water) and industrial, manufacturing,
moves whether in a semisolid, liquid, sludge, gas or
mining, pharmaceutical, and municipal wastes.
any other form or state.”
Injection wells are also used to enhance oil and
Carbon capture and storage (CCS) is the process of
gas recovery production; for solution mining; and,
capturing CO2 from an emission source,
compressing and transporting it to an injection
more recently, to inject CO2 for geologic
site, and injecting it into deep subsurface rock
sequestration. As of 2019 (the latest data
formations for long-term storage.
available), EPA estimated that there were more
Enhanced oil recovery/enhanced gas recovery
than 735,000 permitted injection wells across the
(EOR/EGR) is the process of injecting a fluid into an
states and more than 6,900 additional wells on
oil- or gas-bearing formation to recover residual
tribal lands.
oil or natural gas. This report wil use the term
7
EOR to refer to both EOR and EGR.
CO2 injection wells are a type of deep injection
well, used for injection into deep, isolated rock formations and can reach thousands of feet deep.8
More details on specific well types are provided later in this report.
Geologic Sequestration
Geologic sequestration is the long-term containment of a fluid (including a gas, liquid, or
supercritical CO2 stream) in subsurface geologic formations. The goal of geologic sequestration
of CO2 is to trap or transform CO2 emitted from stationary anthropogenic sources permanently
underground and ultimately reduce emissions of GHGs from these sources into the atmosphere.
CO2 for sequestration is first captured from a large stationary source, such as a coal-fired power

6 40 C.F.R §144.3 and U.S. Environmental Protection Agency, “Federal Requirements Under the Underground
Injection Program for Carbon Dioxide (CO2) Geological Sequestration (GS) Wells; Proposed Rule,” 73 Federal
Register 43492-43541, July 5, 2008, p. 43493.
7 EPA, FY 2019 State UIC Injection Well Inventory and FY2019 Tribal UIC Injection Well Inventory, accessed
September 22, 2022, at https://www.epa.gov/uic/uic-injection-well-inventory.
8 Most underground injection wells are relatively shallow wells, including wells for disposing of motor vehicle waste,
large-capacity cesspools and septic wells, and stormwater drainage wells.
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plant or chemical production facility.9 Although CO2 is initially captured as a gas, it is
compressed into a supercritical fluid—a relatively dense fluid with both gas-like and liquid-like
properties—before injection and remains in that state due to high pressures in the underground
formation. The CO2 is injected through specially designed wells into geologic formations,
typically a half a mile or more below the Earth’s surface. These formations include, for example,
large deep saline reservoirs (underground basins containing salty fluids) and oil and gas reservoirs
no longer in production.10 Research shows that CO2 could also be sequestered in deep ocean
waters or mineralized.11 Impermeable rocks above the target reservoir, combined with high CO2
pressures, keep the CO2 in a supercritical fluid state and prevent migration into shallower
groundwater or into other formations.
The National Energy Technology Laboratory
(NETL) estimates that the total onshore storage
Physical and Chemical Process of
capacity in the United States ranges between
Geologic Sequestration
about 2.6 trillion and 22 trillion metric tons
(hereinafter tons in this report) of CO
CO2 can be sequestered in underground formations
2.13 (For
in several different ways. CO2 can be physically
more details, see Appendix A.) By comparison,
trapped in the pore space, trapped through a
U.S. energy-related CO2 emissions in 2020
chemical reaction of the CO2 with rock and water,
totaled 4,575 million tons.14 Theoretically, the
dissolved into the existing fluid within the formation,
United States contains storage capacity to store
adsorbed onto organic material, or go through other
chemical transformations. Researchers expect that
all CO2 emissions from large stationary sources
geologic sequestration wil take place over hundreds
(such as power plants), at the current rate of
of years after injection, which may ultimately result in
emissions, for centuries. For additional
permanent storage of the CO2. According to one
information on the technical aspects of CCS, see
analysis from the Intergovernmental Panel on
CRS Report R44902, Carbon Capture and
Climate Change (IPCC), “For well-selected, designed
and managed geological storage sites, the vast
Sequestration (CCS) in the United States.
majority of the CO2 wil gradually be immobilized by
various trapping mechanisms and, in that case, could
be retained for up to mil ions of years.”12

9 An emerging technology that captures CO2 directly from the atmosphere—called direct air capture—could also
provide a source of CO2 for geologic sequestration or EOR. For more information on carbon capture, see CRS In Focus
IF11501, Carbon Capture Versus Direct Air Capture, by Ashley J. Lawson.
10 Researchers and industry are also considering unmineable coal seams as potential target formations.
11 In addition to geologic sequestration in underground reservoirs, research and development is under way on
technologies for ocean sequestration, where CO2 is injected directly into deep waters or below the seabed, and mineral
carbonation, a process where CO2 is converted into solid inorganic carbonates through chemical reactions.
12 IPCC 2005, p. 14.
13 U.S. Department of Energy, National Energy Technology Laboratory, Carbon Utilization and Storage Atlas, 5th ed.,
2015, pp. 18-20 (hereinafter U.S. Department of Energy 2015).
14 U.S. Energy Information Agency, “U.S. Energy-Related Carbon Dioxide Emissions, 2020,” accessed May 24, 2022,
at https://www.eia.gov/environment/emissions/carbon/. Energy-related emissions are generally those associated with
fossil fuel combustion. Other sources of emissions include agriculture, forestry, and waste (e.g., landfills).
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Figure 1. Examples of Carbon Capture, Injection, Storage, and Utilization

Source: U.S. Department of Energy, Office of Fossil Energy, “Carbon Utilization and Storage Atlas,” 4th ed.,
2012, p. 4.
Notes: EOR is enhanced oil recovery; ECMB is enhanced coal bed methane recovery.
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Enhanced Oil Recovery (EOR)
Injecting substances to increase production from oil-bearing formations is a process known as
enhanced oil recovery, or EOR.15 The EOR process involves use of recovery wells (separate from
production wells) to inject brine, water, steam, polymers, or CO2 into oil-bearing formations.
EOR, which is also known as tertiary recovery, can significantly increase the amount of oil or gas
produced from a reservoir.16
CO2 is the most common gas injection agent used in EOR projects.17 The use of wells to inject
CO2 builds on known industrial processes used by the oil and gas industry since the 1970s. CO2
injected for EOR is most commonly extracted from naturally occurring underground CO2
reservoirs, but may also be captured from anthropogenic sources, such as natural gas production,
ammonia production, and coal gasification facilities.18 In many cases, the CO2 is transferred from
the source to the injection site by pipeline. The CO2 is typically injected into depleted oil or gas
reservoirs using the existing well infrastructure from the original production process. The injected
CO2 travels through the pore spaces of the formation, where it combines with residual oil. The
mixture is then pumped to the surface, where the CO2 is separated from other fluids,
recompressed, and reinjected. Through repeated EOR cycles, some CO2 can be gradually stored
in the reservoir. NETL reports that generally, 30%-40% of the CO2 is stored in each injection
cycle, depending on the reservoir characteristics, through what it terms “incidental storage.”19
This portion of the CO2 “will be contained indefinitely within the reservoir,” according to
NETL.20
In 2017 (the latest data available), commercial CO2-EOR projects were operating in 80 oil fields
in the United States, primarily located in the Permian Basin of western Texas.21 For 2020, EOR
facilities reported receiving a total of 35.2 million tons of CO2 for EOR.22

15 As of 2014. See Vello Kuuskraa and Matt Wallace, “CO2-EOR Set for Growth as New CO2 Supplies Emerge,” Oil
and Gas Journal, vol. 112, no. 4 (April 7, 2014), p. 66. Oil recovery consists of three stages. In primary recovery, the
natural difference in pressure causes oil to rise through a well and to the surface of the reservoir, or artificial lift
methods are used to move the oil. In secondary recovery, water or gas is injected through injection wells to move the
oil toward the production wells and to the surface. Tertiary recovery involves the use of thermal methods, gas
injection, or chemical flooding to recover additional oil. EOR is sometimes referred to as tertiary recovery. Enhanced
recovery is also used occasionally in natural gas production
16 NETL, “Enhanced Oil Recovery,” accessed November 20, 2019, at https://netl.doe.gov/oil-gas/oil-recovery.
17 NETL, “Enhanced Oil Recovery.”
18 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Program for
Carbon Dioxide (CO2) Geological Sequestration Wells,” 75 Federal Register 77230-77303, December 10, 2010, p.
77234.
19 NETL, CO2 Leakage During EOR Operations—Analog Studies to Geological Storage of CO2, January 2019, p. 17, at
https://www.netl.doe.gov/projects/files/
CO2LeakageDuringEOROperationsAnalogStudiestoGeologicStorageofCO2_013019.pdf.
20 NETL, CO2 Leakage During EOR Operations, 2019, p. 17.
21 IEA, “Commentary: Whatever Happened to Enhanced Oil Recovery,” November 28, 2018 (embedded dataset). In
2020, 70 facilities reported receiving CO2 for EO under EPA’s Greenhouse Gas Reporting Program, discussed later in
this report.
22 U.S. Environmental Protection Agency, “Supply, Underground Injection, and Geologic Sequestration of Carbon
Dioxide,” accessed on May 24, 2022 at https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-
sequestration-carbon-dioxide.
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Some analysts project that the federal tax credit for carbon utilization and sequestration and the
potential increased supply of CO2 from carbon capture could lead to expansion in both the
number and locations of CO2 injection for EOR operations.23
Federal Research and Development for
Underground Carbon Storage
Over the last decade, the focus of federal carbon storage RD&D efforts, including geologic
sequestration and EOR, has shifted from small demonstration projects to exploration of the
technical and commercial viability for injecting and storing large volumes of captured CO2.
DOE leads the federal government’s underground carbon storage RD&D as part of the agency’s
fossil energy programs implemented in the Office of Fossil Energy and Carbon Management.
DOE’s work includes conducting laboratory research on wells, storage design, geologic settings,
and monitoring and assessment of the injected CO2. In 2003, DOE created the Regional Carbon
Sequestration Partnerships (RCSP) program—a set of public-private partnerships across the
United States to characterize, validate, and develop large-scale field testing of CO2 injection and
storage methods. Projects supported through the RCSP include potential carbon storage through
geologic sequestration and EOR, conducted through partnerships with the petroleum and
chemical industries and public and private research institutions. These projects were scheduled to
end by July 2022.24
In September 2019, DOE announced four new projects awarded funding through the
department’s Regional Initiative to Accelerate CCUS Deployment.25 The regionally based
projects are intended to support commercial-scale deployment through activities such as
identifying challenges with CCUS technology and CO2 transportation, evaluating regional CO2
infrastructure, developing CCUS readiness indicators, and identifying geologic storage sites.26
DOE’s Carbon Storage Assurance Facility Enterprise (CarbonSAFE) initiative, launched in 2016,
promotes the development of geologic sequestration sites capable of storing over 50 million tons
of CO2 from industrial sources.27 Through the initiative, DOE has funded 13 pre-feasibility (Phase
I) projects, 6 feasibility (Phase II) projects, and 5 site characterization and permitting (Phase III)
projects.28 The Phase II projects focus on storage complex feasibility, and Phase III projects
include activities such as site characterization, obtaining EPA permits to construct CO2 injection
wells for geologic sequestration, CO2 capture assessments, and activities related to obtaining a
National Environmental Policy Act determination.29 Future Phase IV projects would include

23 NETL, CO2 Leakage During EOR Operations, 2019, p. 10.
24 Based on CRS discussions with DOE, September 26, 2019.
25 U.S. Department of Energy, “FOA 2000: Regional Initiative to Accelerate CCUS Deployment,” accessed September
22, 2020, at https://www.energy.gov/fe/foa-2000-regional-initiative-accelerate-ccus-deployment.
26 U.S. Department of Energy, “FOA 2000: Regional Initiative to Accelerate CCUS Deployment,” accessed September
22, 2020, at https://www.energy.gov/fe/foa-2000-regional-initiative-accelerate-ccus-deployment.
27 NETL, “CARBONSAFE,” accessed September 22, 2020, at https://www.netl.doe.gov/coal/carbon-storage/storage-
infrastructure/carbonsafe.
28 U.S. Department of Energy, “Carbon Management Webinar,” December 1, 2021, at https://www.energy.gov/fecm/
articles/1201-carbon-management-webinar-presentation.
29 NETL, “CarbonSafe Initiative,” accessed July 19, 2022, at https://netl.doe.gov/carbon-management/carbon-storage/
carbonsafe.
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obtaining an EPA permit for CO2 injection for geologic sequestration and construction of a CO2
storage complex.30 The projects are managed by NETL.
CO2 Injection and Storage Projects
In the United States, most CO2 injection and storage projects have been developed and operated
through collaborations among DOE, industry, and local research institutions.31 These projects
include the smaller research and development projects administered by DOE and designed to test
various methodologies and technology and demonstrate technical feasibility, as well as the first
larger-scale injection and storage projects, which some designate as a “commercial” project.32 As
explained later in this report in the “History of Congressional Action on Injection and Storage of
CO2,” Congress has recently directed DOE to expand its RD&D activities to support
commercialization of CCS projects.
To date in the United States, nine research and development projects funded, or partially funded,
by DOE have injected large volumes of CO2 into underground formations for intended geologic
sequestration or EOR-related storage RD&D projects (see Appendix B). Three of these projects
have involved injection into saline formations for geologic sequestration (for demonstration
purposes), five have involved injection for EOR purposes, and one has involved both
sequestration and EOR.
One of these projects, the ADM project, in Decatur, IL, is actively injecting CO2 for geologic
sequestration.33 ADM is injecting CO2 from its ethanol production plant into an onsite sandstone
formation and has injected 2 million metric tons of CO2 between 2016 and 2020 (the most recent
injection data available).34
At least two other DOE-funded CCS projects are currently capturing and injecting CO2 as part of
EOR operations. The Air Products Carbon Capture Project in Port Arthur, TX, has been injecting
CO2 captured from steam methane reformers since 2013 as part of EOR operations. The Michigan
Basin Project in Otsego County, MI, is injecting CO2 from a natural gas facility for EOR. The
Petra Nova facility in Texas was the first operating coal-fired electricity generating plant with a
CCS system in the United States. Now idled, this facility injected CO2 for EOR from 2017
through May 2020.35 The ADM, Air Products, and Petra Nova projects received funds from the
American Recovery and Reinvestment Act of 2009 (P.L. 111-5). DOE provided partial funding
for Michigan Basin project through the RCSP program.

30 U.S. Department of Energy, Overview of the COE CCUS R&D Program, August 2020.
31 An additional project, the FutureGen Alliance project in Jacksonville, IL, planned to retrofit a power plant to capture
emissions and inject CO2 for geologic sequestration. The project was originally conceived by the George W. Bush
Administration and revived under the Obama Administration as FutureGen 2.0 with $1 billion in ARRA funding. The
project was cancelled in 2016 due to a variety of technical and financial challenges.
32 For example, the Global CCS Institute (GCCSI) has defined a commercial facility as “a facility capturing CO2 for
permanent storage as part of an ongoing commercial operation that generally has an economic life similar to the host
facility whose CO2 it captures, and that supports a commercial return while operating and/or meets a regulatory
requirement.”
33 This project is also referred to as the Illinois Industrial Carbon Capture and Storage Project.
34 EPA FLIGHT database, accessed February 16, 2022.
35 The owner and operator, NRG, idled Petra Nova’s carbon capture equipment in May 2020 in response to lower oil
prices caused, in part, by the COVID-19 pandemic (NRG Energy, “Petra Nova Status Update,” accessed September 14,
2020, at https://www.nrg.com/about/newsroom/2020/petra-nova-status-update.html).
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From 2009 to 2021, five other projects were implemented through the RCSP program as large-
scale field tests of larger volumes of CO2 storage.36 The projects included injection into various
underground formations for geologic storage and injection associated with EOR, with volumes of
CO2 injected and stored ranging from a few hundred tons to nearly 5 million tons (at the time,
DOE considered over 1 million tons to be commercial-scale).37 In total, according to DOE, RCSP
projects resulted in the injection and storage of more than 11 million tons of CO 38
2. Five of these
projects have completed injection and are now in the post-injection monitoring phase.39 See
Appendix B for project details.
While no uniform definition of “commercial” CCS project exists, some CCS stakeholders track
projects and report data on projects with certain commercial characteristics and projects under
various stages of planning and development. According to one set of data collected by the Global
CCS Institute (GCCSI) as of December 2021, 12 commercial CCS projects were operating in the
United States that both capture CO2 and inject it into underground formations, including the ADM
and Air Products projects. 40

In addition to these projects, in early 2022, Red Trail Energy in Richardton, ND, began injecting
CO2 from an ethanol production plant into a nearby saline formation. The project, regulated by
North Dakota, is expected to inject a total of 3.7 million tons of CO2 over the lifetime of the
project.41 In 2022, North Dakota also granted a Class VI permit to Minnkota Power (also known
as Project Tundra) for injection of CO2 captured from a coal-fired power plant.
Worldwide, several CO2 geologic sequestration projects are operating in diverse regions,
primarily developed through public-private partnerships. In Norway, facilities at the Sleipner Gas
Field in the North Sea and Snohvit in the Barents Sea conduct offshore sequestration under the
Norwegian continental shelf.42 The Quest CCS facility in Canada has stored over 5 million tons
of CO2 since 2015.43 Chevron’s Gorgon Injection Project, a natural gas production facility in
Australia, began operating in 2019 and is expected to store a total of 100 million tons of CO2.44 In
Qatar, a project injecting CO2 for geologic sequestration from a natural gas processing facility has
been operating since 2019.45
For more information on CCS projects, see CRS Report R44902, Carbon Capture and
Sequestration (CCS) in the United States.

36 U.S. Department of Energy 2015, p. 4.
37 Based on CRS discussions with DOE, September 21, 2020. A seventh project never reached the injection stage due
to technical challenges.
38 Based on CRS discussions with DOE, 2020.
39 Based on CRS discussions with DOE, 2020.
40 Global CCS Institute, Global Status Report 2021, December 1, 2021. GCCSI does not include a definition of
“commercial” in its 2021 report. Two additional CCS facilities injecting CO2 for EOR suspended operations in 2020.
41 North Dakota Industrial Commission, NDIC Case No. 28848 -Draft Permit Fact Sheet and Storage Facility Permit
Application,” accessed on February 16, 2022, at www.dmr.nd.gov/oilgas/GeoStorageofCO2.asp. This injection well is
permitted by North Dakota.
42 IPCC 2005, p. 201.
43 Shell, “Quest CCS Facility Captures and Stores Five Million Tonnes of CO2 Ahead of Fifth Anniversary,” accessed
September 25, 2020, at https://www.shell.ca/en_ca/media/news-and-media-releases/news-releases-2020/quest-ccs-
facility-captures-and-stores-five-million-tonnes.html.
44 Chevron, “Gorgon,” accessed September 23, 2020, at https://www.chevron.com/projects/gorgon.
45 Global CCS Institute, Global Status Report 2021, December 1, 2021.
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Federal Framework for Regulating Injection of CO2
This section provides an overview of the federal framework for regulating underground injection
of CO2 for both geologic sequestration and EOR. It describes the primary federal statute for
underground injection control (UIC), the general federal and state roles in developing and
implementing UIC regulations, and the UIC well classes. The section analyzes the differences
between wells used solely for geologic sequestration and wells used for EOR. It also outlines the
regulatory requirements for transitioning from EOR wells to geologic sequestration wells.
Safe Drinking Water Act (SDWA)
SDWA is the primary federal statute governing underground injection activities in the United
States, including those associated with geologic sequestration of CO2. SDWA Section 1421
directs EPA to promulgate regulations for state UIC programs to protect underground sources of
drinking water and prohibits any underground injection activity except when authorized by a
permit or rule.46 The statute defines underground injection as “the subsurface emplacement of
fluids by well injection.”47
Preventing Endangerment of USDWs From Underground Injection
SDWA states that UIC regulations must “contain minimum requirements for effective programs to prevent
underground injection which endangers drinking water sources.” The statute defines endangerment as the
fol owing: “Underground injection endangers drinking water sources if such injection may result in the presence in
underground water which supplies or can reasonably be expected to supply any public water system of any
contaminant, and if the presence of such contaminant may result in such system’s not complying with any national
primary drinking water regulations or may otherwise adversely affect the health of persons.” Endangerment
applies to both current and potential USDWs.48
Federal and State Roles
EPA issues regulations for underground injection, issues guidance to support state program
implementation, and in some cases, directly administers UIC programs in states.49 The agency has
established minimum requirements for state UIC programs and permitting for injection wells.
These requirements include performance standards for well construction, operation and
maintenance, monitoring and testing, reporting and recordkeeping, site closure, financial
responsibility, and for some types of wells, post-injection site care. Most states implement the
day-to-day program elements for most categories of wells, which are grouped into “classes”
based on the type of fluid injected. Owners or operators of underground injection wells must

46 SDWA §1421; 42 U.S.C. §300h. EPA defines underground source of drinking water as an “aquifer or its portion
which supplies any public water system or which contains a sufficient quantity of ground water to supply a public
water system; and currently supplies drinking water for human consumption; or contains fewer than 10,000 mg/l total
dissolved solids; and which is not an exempted aquifer” (40 C.F.R. §146.3). In addition to the provisions described
above, Sections 1421 and 1447 establish that injections by federal agencies or injections on property owned or leased
by the federal government are subject to the state UIC requirements. Section 1423 sets forth enforcement standards and
procedures for the UIC program, including civil and criminal penalties.
47 SDWA §1421(d)(1); 42 U.S.C. §300h.
48 SDWA §1421; 42 U.S.C. §300h.
49 40 C.F.R. §§144-147.
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follow the permitting requirements and standards established by the UIC program authority in
their state.
SDWA authorizes EPA to delegate primary enforcement authority for UIC programs, known as
primacy, to individual states (see Figure 2). Section 1422 mandates that states seeking primacy
adopt and implement UIC programs that meet all minimum federal requirements under Section
1421.50 For wells other than certain oil- and gas-related injection wells, states must adopt laws
and regulations at least as stringent as EPA regulations and meet other statutory requirements to
be granted primacy. EPA grants a state primacy through a federal rulemaking process for one or
more classes of wells. If granted primacy for a class of wells, a state administers that UIC
program, develops its own requirements, and allows well injection by state rule or by issuing
permits. If a state’s UIC plan has not been approved, or the state has chosen not to assume
program responsibility, SDWA requires that EPA directly implement the program in that state.51
UIC Well Classes
Under SDWA authority, EPA has established six classes of underground injection wells based on
similarity in the fluids injected.52 Construction, injection depth, design requirements, and
operating techniques vary among well classes. Some wells are used to inject fluids into
formations below USDWs, while others involve injection into or above USDWs. EPA regulations
set out specific permitting and performance standards for each class of wells. In 2010, EPA issued
the first federal rule specific to underground injection of CO2, Federal Requirements Under the
Underground Control (UIC) Program for Carbon Dioxide (CO2) Geological Sequestration (Class
VI Rule).53 In the rule, the agency promulgated regulations for underground injection of CO2 for
long-term storage and established UIC Class VI, a new class of wells for geologic sequestration
of CO2. Prior to the Class VI Rule’s effective date in January 2011, injection of CO2 was
permitted under Class II if used for EOR, or Class V if the well was experimental (e.g., DOE-
supported research wells). Table 1 lists the classes of UIC wells.
Table 1. UIC Well Classes and Estimated Wells
Estimated
Percentage
Number of EPA
of Total
Class
Permitted Wells
Wells
Type of Fluid Injected
Class I
903
0.12%
Injection of hazardous and non-hazardous wastes into
deep, isolated rock formations
Class II
156,547
21.29%
Injection of fluids associated with oil and natural gas
production (including injection of CO2 for enhanced
recovery and produced water disposal)
Class III
28,465
3.87%
Injection of fluids for solution mining (e.g., extracting
uranium or salt)

50 SDWA §1422(b). For Class II wells (used for oil- and gas-related injections), a state may exercise primacy under
either SDWA Section 1422 or Section 1425. To receive primacy under 1425, a state must demonstrate that it has an
effective program that prevents endangerment of underground sources of drinking water from underground injection.
51 SDWA §1422.
52 Injection well means a well into which “fluids” are being injected (40 C.F.R. §144.6). EPA UIC regulations are
codified at 40 C.F.R. §§144-148.
53 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal Register 77230-77303,
December 10, 2010.
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Estimated
Percentage
Number of EPA
of Total
Class
Permitted Wells
Wells
Type of Fluid Injected
Class IV
169
0.02%
Injection of hazardous or radioactive wastes through
shallow wells into or above formations that contain a
USDW (these wells are banned unless authorized under a
federal or state groundwater remediation project)
Class V
549,322
74.70%
Any well used to inject non-hazardous fluids underground
that does not fall under the other five classes, including
storm water drainage wells, septic system leach fields,
aquifer storage and recovery wells, and experimental wells;
most Class V wells are used for injection of wastes into or
above USDWs
Class VI
2
Less than .01%
Injection of CO2 into geologic formations for long-term
storage or geologic sequestration
TOTAL
735,408

Sources: 40 C.F.R. §144.6; EPA, FY 2019 State UIC Injection Well Inventory, accessed September 22, 2022.
Notes: Estimates based on 2019 EPA data (latest available). New York and New Jersey did not submit data for
these estimates. 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 FY 2019 Tribal UIC Injection Well Inventory). The two Class VI wells are
both located at one site. Class VI estimate does not include two wells permitted by North Dakota in 2022.
EPA has delegated UIC program primacy for well Classes I-V to 32 states (see Figure 2). EPA
has delegated primacy for all six well classes to two states, North Dakota and Wyoming.54 Seven
states and two tribes have primacy for Class II wells only. Including those states, a total of 40
states have primacy for Class II.55
EPA shares UIC implementation responsibility with seven states and two Indian tribes, and
implements the UIC program for all well classes in eight states.
For Class VI, EPA has delegated primacy to two states and has direct implementation authority in
48 states and all territories.56 EPA requires that state primacy for Class VI wells would be
implemented under SDWA Section 1422. Additional states are pursuing Class VI primacy; for
example, Louisiana is in a completeness determination phase and West Virginia and Arizona are
in a pre-application phase for all six well classes.57 As with regulations for other well classes, the
Class VI Rule allows states to apply for primacy for Class VI wells without applying for primacy
for other well classes.

54 EPA granted Class VI primacy to North Dakota in 2018 and to Wyoming in 2020.
55 States may request primacy for Class II oil- and gas-related injection operations programs under SDWA Section
1422 or Section 1425 (see “Class II Oil and Gas Related Wells” in this report).
56 EPA retains direct implementation authority for Class II wells in Florida and Idaho, with those states having primacy
over Classes I, III, IV, and V.
57 U.S. Environmental Protection Agency, “Primacy Enforcement Authority for the Underground Injection Control
Program,” accessed on September 22, 2022, at https://www.epa.gov/uic/primary-enforcement-authority-underground-
injection-control-program-0.
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Figure 2. State UIC Primacy Map

Source: CRS, from EPA, “Primary Enforcement Authority for the Underground Injection Control Program,”
accessed on September 22, 2022, at https://www.epa.gov/uic/primary-enforcement-authority-underground-
injection-control-program-0, accessed on September 22, 2022.
Note: North Dakota and Wyoming have primacy for all well classes, including Class VI. EPA implements the
Class VI program for all other states, territories, and tribes.
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Class VI Geologic Sequestration Wells
Underground injection for the purpose of
long-term geologic sequestration of CO
Figure 3. Conceptual Class VI Well
2 is
subject to SDWA UIC regulations for Class
Diagram
VI wells. Class VI requirements may also
apply to CO2 injection for EOR using Class II
wells when EPA or the delegated state
determines that there is an increased risk to
USDWs.58
Two Class VI wells, both in Illinois, are
currently permitted by EPA in the United
States. EPA issued these final permits in 2017
for two wells injecting CO2 into a saline
aquifer at the ADM ethanol plant in Illinois.
As of February 2022, EPA is reviewing 26
Class VI permit applications for wells in the
pre-construction phase.59
In 2015, EPA issued a final Class VI permit
for the FutureGen project, but the permit
expired after the project was cancelled
without any CO2 injection taking place.60
North Dakota has issued two Class VI
permits, for injection of CO2 captured from an
ethanol production facility and from a coal-
fired power plant.61
Unique Class VI Requirements
When developing minimum federal
requirements for Class VI wells, EPA
generally built upon Class I hazardous waste
requirements. The agency added new
requirements to address the unique properties
of CO

2 and geologic sequestration in the
Class VI Rule. In the preamble to the Class
Source: EPA, https://www.epa.gov/uic/class-vi-wells-
used-geologic-sequestration-co2.

58 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal Register 77230-77303,
December 10, 2010, p. 77245.
59 U.S. Environmental Protection Agency, “Class VI Wells Permitted by EPA,” accessed on September 14, 2022, at
https://www.epa.gov/uic/class-vi-wells-permitted-epa.
60 The FutureGen Alliance project in Jacksonville, IL, planned to retrofit a power plant to capture emissions and inject
CO2 for geologic sequestration. The project was originally conceived by the George W. Bush Administration and
revived under the Obama Administration as FutureGen 2.0 with $1 billion in ARRA funding. The project was
cancelled in 2016 due to a variety of technical and financial challenges.
61 North Dakota Oil and Gas Division, “Class VI Wells,” accessed on February 14, 2022, at https://www.dmr.nd.gov/
oilgas/GeoStorageofCO2.asp; and Project Tundra, “Minnkota Received CO2 Storage Permit from NDIC,” accessed on
February 14, 2022, at www.projecttundrand.com/post/minnkota-receives-co2-storage-permit-from-ndic.
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VI Rule, EPA noted that “the Agency has determined that tailored requirements, modeled on the
existing UIC regulatory framework, are necessary to manage the unique nature of CO2 injection
for geologic sequestration.”62 EPA bases the regulation of CO2 injection as a separate class of
wells on several unique risk factors to USDWs:
 the large volumes of CO2 expected to be injected through wells;
 the relative buoyancy of CO2 in underground geologic formations;
 the mobility of CO2 within subsurface formations;
 the corrosive properties of CO2 in the presence of water that can effect well
materials; and
 the potential presence of impurities in the injected CO2 stream.63
Due to all of these properties, Class VI requirements establish a larger injection site “area of
review” compared to
requirements for other classes.
Human Health and Environmental Considerations
The area of review for Class VI
of CO2 and Use of Wells for
wells “includes the subsurface
Geologic Sequestration
three-dimensional extent of the
CO2 itself is not federally regulated as a toxic or hazardous substance.
carbon dioxide plume, associated
The “CO2 stream,” the ful stream of fluid injected for geologic
area of elevated pressure, and
sequestration, however, is not likely to be pure CO2. Depending on its
source, CO2 streams may contain substances that could be harmful to
displaced fluids, as well as the
humans or the environment and subject to applicable regulations.
surface area above that delineated
EPA and other analysts have identified several potential risks
region.”65 The requirements also
associated with injection and geologic sequestration of CO2:
obligate well owners or operators

contamination of shallower groundwater formations, including
to track, model, and predict CO2
drinking water sources, through vertical migration of CO2 in the
plume movement. The monitoring
subsurface;
and post-injection site care

movement of salty water (brine) into drinking water sources
requirements in the regulations
caused by injection pressure;
are based on estimates that

gradual leaks into the air from the injection well components or
commercial-scale CO
monitoring wel s;
2 injection
projects are expected to operate

sudden large accidental releases that could raise CO2
between 30 and 60 years.
concentration above safe levels for humans;
Appendix C compares the major

elevated CO2 concentrations in soils that could affect plant and
permitting requirements and
animals;
technical standards for Class II

elevated CO2 concentrations in the subsurface that could affect
wells related to oil and gas
microbial populations;
production, which are used for

effects on the minerals in the geologic formation; and

earthquakes induced by injection pressure.64

62 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal Register 77230-77303,
December 10, 2010, p. 77233.
63 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal Register 77230-77303,
December 10, 2010, p. 77234.
64 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Proposed Rule,” 73 Federal Register 43492-43541,
July 25, 2008, p. 43497; IPCC 2005, pp. 245-250; and Interagency Task Force on Carbon Capture and Storage, Report
of the Interagency Task Force on Carbon Capture and Storage, 2010, pp. 246-250.
65 40 C.F.R. §146.81.
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EOR, and Class VI wells for geologic sequestration of CO2.
To assist states and owner operators with the permitting process, EPA has also issued 11 technical
guidance documents on Class VI wells. These documents are not legally enforceable, but provide
additional information on site characterization, area of review, construction, reporting and
recordkeeping, site closure, financial responsibility, and other permit elements.
Class II Oil and Gas Related Wells
Class II wells are used to inject fluids associated with oil and gas production, including
wastewater disposal wells (disposal wells) and wells injecting water, brine, steam, CO2, or other
chemicals for EOR (recovery wells). EOR wells are the most common type of Class II wells. As
of 2019, there were approximately 156,500 permitted Class II wells, approximately 119,500
(76%) of which were recovery wells.66 Most of these wells are located in California, Texas,
Kansas, Illinois, and Oklahoma. The remaining approximately 20% of Class II wells are disposal
wells and hydrocarbon storage wells.
States may request primacy for Class II oil- and gas-related injection operations programs under
SDWA Section 1422 or Section 1425. Section 1422 mandates that state programs meet EPA
requirements promulgated under Section 1421 and prohibits underground injection that is not
authorized by permit or rule.67 EPA regulations under Section 1421 specify requirements for
siting, construction, operation, monitoring and testing, closure, corrective action, financial
responsibility, and reporting and recordkeeping.68 Sixteen states and three territories have Class II
primacy under Section 1422.
Section 1425 allows states to administer their own Class II UIC programs using state rules in lieu
of EPA regulations, provided a state demonstrates that it has an effective program preventing any
underground injection that endangers drinking water sources.69 To receive approval under Section
1425’s optional demonstration provisions, a state program must include permitting, inspection,
monitoring, and record-keeping and reporting requirements. Twenty-four states and two tribes
have Class II primacy under Section 1425. Most oil- and gas-producing states have primacy for
Class II under this section. Overall, nearly 99% of EOR wells are located in states with primacy
under Section 1425.70 In the 10 states without Class II primacy, the District of Columbia, and for
most tribes, EPA directly implements the Class II program, and federal regulations apply.71
While both Class II CO2-EOR wells and Class VI wells involve injection of CO2 into
underground reservoirs, the purposes and regulations of these two classes are different. Class II
EOR wells inject primarily into oil or gas fields for the purposes of enhancing production from an
underground oil and gas reservoir. In Class II wells, only some of the CO2 stays in the reservoir
during each recovery cycle, gradually increasing the total volume of CO2 stored. In Class VI
wells, all of the injected CO2 is intended to remain in the reservoir for sequestration. CO2
injection through Class VI wells generally involves higher injection pressures, larger expected

66 EPA, FY19 State UIC Injection Well Inventory.
67 SDWA §1422.
68 SDWA §1421.
69 Section 1425 requires a state to demonstrate that its UIC program meets the requirements of Section 1421(b) for
inspection, monitoring, recordkeeping, and reporting, and represents an effective program to prevent underground
injection that endangers underground sources of drinking water (SDWA §1425 (a)).
70 EPA, FY19 State UIC Injection Well Inventory.
71 40 C.F.R. §142.
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fluid volumes, and different physical and chemical properties of the injection stream compared to
Class II CO2-EOR wells.
Given these differences between the two well classes, EPA Class II regulations specify different
requirements than Class VI regulations. Generally, EPA Class II requirements impose less
comprehensive performance requirements and provide longer time periods between mandatory
testing and reporting, compared to EPA Class VI requirements. Unlike EPA Class VI
requirements, EPA Class II requirements do not include providing seismicity information,
continuous monitoring of the injection pressure and CO2 stream, monitoring of the CO2 plume
and pressure front, or monitoring of groundwater quality throughout the lifetime of the project.72
EPA Class II requirements also do not impose post-injection site care or emergency and remedial
response requirements, which are included in EPA Class VI requirements.73 Class II wells can be
granted a permit or authorized by rule by either a primacy state or EPA, while Class VI wells
cannot be authorized by rule.74 See Appendix C for more information on EPA Class II well
requirements.
Transition of Wells from Class II to Class VI Wells
Class II CO2-EOR wells have a different primary purpose than Class VI wells and must transition
to a Class VI permit under certain conditions. EPA has determined that, “owners or operators of
Class II wells that are injecting carbon dioxide for the primary purpose of long-term storage into
an oil or gas reservoir must apply for and obtain a Class VI permit where there is an increased
risk to USDWs compared to traditional Class II operations.”75 EPA recognizes that there may be
some CO2 trapped in the subsurface at EOR operations. However, if the Class VI UIC Program
Director (either EPA or the primacy state) has determined that there is no increased risk to
USDWs, then these operations would continue to be permitted under the Class II requirements.76
To date, no Class II wells have been transitioned to Class VI.
Other Federal Authorities
Regulations promulgated under most other federal environmental statutes have generally not
applied to underground injection or geologic sequestration of CO2. If the well owner or operator
constructs, operates, and closes the injection well in accordance with a UIC Class II or Class VI
permit, the injection and storage would typically not be subject to other federal air quality, waste
management, or environmental response authorities and related liability. For example, a release of
a hazardous substance in compliance with a UIC permit would be exempt as a “federally
permitted release” from liability and reporting requirements of the Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA).77 Such federally permitted releases

72 40 C.F.R. §§144 and 146.
73 40 C.F.R. §§144 and 146.
74 SDWA §1422.
75 40 C.F.R. §144.19(a). This section specifies nine criteria that the UIC Program Director must consider in the
determination of risk to USDWs.
76 EPA, Geologic Sequestration of Carbon Dioxide; Draft Underground Injection (UIC) Program Guidance on
Transitioning Class II Wells to Class VI Wells, p. 1.
77 Section 107(j) of CERCLA (42 U.S.C. §9607(j)) exempts federally permitted releases of hazardous substances from
liability under the statute. Section 103(a) of CERCLA (42 U.S.C. §9603(a)) also exempts such releases from reporting
to the National Response Center. Section 101(10)(G) of CERCLA (42 U.S.C. §9601(10)(G)) defines a “federally
permitted release” to include underground injection of fluids authorized under the Safe Drinking Water Act, including
permits issued by states with authorities delegated under that statute. For a discussion of liability and response
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would also be exempt from emergency notification requirements of the Emergency Planning and
Community Right-to-Know Act (EPCRA).78
During the development of the UIC Class VI final rule, some stakeholders in the CCS industry
asked EPA for clarification on how hazardous waste requirements, established under the Resource
Conservation and Recovery Act (RCRA), may apply to CO2 streams that are geologically
sequestered. In response, EPA promulgated a rule excluding CO2 from RCRA’s hazardous waste
management requirements when injected into UIC Class VI wells.79 As a result, when injected in
compliance with a UIC Class VI well permit, CO2 streams are not separately subject to RCRA
requirements applicable to the management of hazardous waste.
Certain federal regulations may apply to CCS processes or facilities that support CO2 injection
and sequestration, such as carbon capture and CO2 transportation and compression. The
regulatory frameworks of these activities are beyond the scope of this report.
Clean Air Act Greenhouse Gas Reporting Program
In the Consolidated Appropriations Act, 2008 (P.L. 110-161), Congress provided $3.5 million for
EPA to promulgate a greenhouse gas reporting rule that would “require mandatory reporting of
greenhouse gas emissions above appropriate thresholds in all sectors of the economy of the
United States.”80 Under its Clean Air Act (CAA) authorities, EPA requires certain sources of
GHGs to report emissions data.81 In 2010, EPA promulgated a rule to include injection of CO2 for
EOR and geologic sequestration in the GHGRP. In this rule, the agency explained that facilities
that inject CO2 for long-term sequestration and all other facilities that inject CO2 underground fall
within the GHGRP covered source categories.82 Therefore, reporting requirements apply to both
Class VI wells and Class II wells that inject CO2. EPA’s purpose for collecting this information is
two-fold—to track CO2 emissions and to quantify the amount of CO2 being sequestered.
Under the GHGRP Rule Subpart RR, facilities that inject a CO2 stream for long-term containment
(i.e., geologic sequestration) must develop and implement a monitoring, reporting, and
verification (MRV) plan.83 The purpose of the MRV plan is to verify the amount of CO2
sequestered and collect data on any CO2 surface emissions from geologic sequestration
facilities.84 Any facility holding an EPA Class VI permit would be subject to Subpart RR and be

authorities of CERCLA, see CRS Report R41039, Comprehensive Environmental Response, Compensation, and
Liability Act: A Summary of Superfund Cleanup Authorities and Related Provisions of the Act, by David M. Bearden.
78 Section 304(a) of EPCRA (42 U.S.C. §11004(a)) exempts CERCLA federally permitted releases from emergency
notification requirements for reporting to state and local emergency response officials. For a discussion of EPCRA
emergency notification requirements, see CRS Report R44952, EPA’s Role in Emergency Planning and Notification at
Chemical Facilities, by Richard K. Lattanzio and David M. Bearden.
79 U.S. Environmental Protection Agency, “Hazardous Waste Management System: Conditional Exclusion for Carbon
Dioxide (CO2) Streams in Geologic Sequestration Activities,” 79 Federal Register 350-364, January 3, 2014.
80 The Consolidated Appropriations Act, 2008, P.L. 110-161, provided funding for EPA to develop and finalize a rule
to “require mandatory reporting of GHG emissions above appropriate thresholds in all sectors of the economy of the
United States.” Congress directed EPA to issue a final rule no later than 18 months after the date of enactment. EPA
promulgated the GHGRP under the authority in Clean Air Act Sections 114 and 208.
81 Clean Air Act §114 (for stationary sources) and §208 (for mobile sources).
82 U.S. Environmental Protection Agency, “Mandatory Reporting of Greenhouse Gases: Injection and Geologic
Sequestration of Carbon Dioxide; Final Rule,” 75 Federal Register 75060-75089, December 1, 2010.
83 40 C.F.R. §98, Subpart RR.
84 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal Register 77230-77303,
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required to report the mass of CO2 that is received, injected into the subsurface, produced, emitted
by surface leakage, emitted by leaks in equipment, and emitted by venting.85 Facilities also must
report the mass of CO2 sequestered in subsurface geologic formations.86
Subpart UU of the rule applies to Class II wells used to inject CO2 for EOR and for small and
experimental sequestration projects exempted under Subpart RR. Subpart UU does not require an
MRV plan and sets forth different and fewer requirements for monitoring and reporting.87
For GHGRP reporting year 2020, 70 facilities reported receiving CO2 for EOR and 6 facilities
reported injecting CO2 for geologic sequestration.88 For addition information, see CRS Report
R46757, Reporting Carbon Dioxide Injection and Storage: Federal Authorities and Programs, by
Angela C. Jones.
History of Congressional Action on Injection and
Storage of CO2
For over a decade, Congress has supported DOE’s carbon storage-related RD&D activities and
EPA’s UIC Class VI program through passage of legislation, oversight, and agency
appropriations.
The Energy Policy Act of 2005 (EPAct05; P.L. 109-58) Section 963 originally directed DOE to
carry out a 10-year carbon capture RD&D program to develop technologies for use in new and
existing coal combustion facilities and has since been amended. Among the specified objectives
of this program, Congress directed DOE, “in accordance with the carbon dioxide capture
program, to promote a robust carbon sequestration program” and to continue RD&D work
through carbon sequestration partnerships.89 Section 354 of the act directed the agency to
establish a demonstration program to inject CO2 for the purposes of EOR while increasing the
sequestration of CO2.
The Energy Independence and Security Act of 2007 (EISA; P.L. 110-140) amended EPAct
Section 963 and expanded DOE’s work in carbon storage RD&D. EISA Title VII, Subtitle A,
directed DOE to conduct fundamental science and engineering research in carbon capture and
sequestration, and to conduct geologic sequestration training and research. Subtitle A of the act
also specifically directed DOE to carry out at least seven large-scale projects testing carbon
sequestration systems in a diversity of formations, which could include RCSP projects. Subtitle B
directed DOE to conduct a national assessment for onshore capacity of CO2 sequestration.
In 2008, the Energy Improvement and Extension Act (P.L. 110-343) authorized federal tax credits
for carbon sequestration. This act added Section 45Q to the Internal Revenue Code (I.R.C.),
which established tax credits for CO2 disposed of in “secure geologic storage” or through EOR

December 10, 2010, p. 77236.
85 40 C.F.R. §98, Subpart RR. EPA defines surface leakage as “the movement of the injected CO2 stream from the
injection zone into the surface, and into the atmosphere, indoor air, oceans, or surface water” (40 C.F.R. §98.449).
86 40 C.F.R. §98, Subpart RR.
87 40 C.F.R. §98, Subpart UU.
88 U.S. Environmental Protection Agency, “Supply, Underground Injection and Sequestration of Carbon Dioxide,”
accessed on February 28, 2022, at https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-
sequestration-carbon-dioxide. Of the six sequestration reporters, one facility has a Class VI permit and the others
voluntary report under Subpart RR.
89 EPAct05 §963.
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with “secure geologic storage.”90 Over time, Congress has amended Section 45Q through the
American Recovery and Reinvestment Act (P.L. 111-5), the Bipartisan Budget Act of 2018 (BBA;
P.L. 115-123), the Consolidated Appropriations Act, 2021 (P.L. 116-260), and the budgetary
measure commonly known as the Inflation Reduction Act of 2022 (IRA; P.L. 117-169). See
“Carbon Sequestration Tax Credits” below for more information on the Section 45Q tax credit
and associated issues for Congress. See also the CRS In Focus IF11455, The Tax Credit for
Carbon Sequestration (Section 45Q), by Angela C. Jones and Molly F. Sherlock.
Recently Enacted Legislation
Energy Act of 2020
In recent years, Congress has provided additional funding for DOE and directed the department to
continue and expand RD&D activities for CO2 storage and sequestration. In the Energy Act of
2020 (Division Z of the Consolidated Appropriations Act, 2021, P.L. 116-260), enacted in
December 2020, Congress reauthorized the general DOE CCS research program through
amendments to EPAct05.91 The act characterizes relevant DOE activities as “Carbon Storage
Validation and Testing” rather than “research, development and deployment” referred to in EISA.
The Energy Act of 2020 specifically directs DOE to establish a large-scale carbon storage
program that would develop geologic sequestration mapping and monitoring tools, assess
sequestration safety, and other activities at a variety of geologic settings. In Section 4003, the act
defines large-scale carbon sequestration as a project scale that demonstrates geologic
sequestration of CO2 and has a goal of sequestering at least 50 million metric tons of CO2 over a
10-year period.92 The act directs DOE to establish a large-scale demonstration program intended
to provide information on the cost and feasibility of these projects. The act also supports efforts
toward commercialization of carbon storage projects through DOE activities to transition large-
scale storage demonstration projects to “integrated commercial storage complexes,” including site
identification and assessment of technical and commercial viability of the sites.93
USE IT Act
In the Utilizing Significant Emissions with Innovative Technologies Act (USE IT Act, Division S,
§102) enacted as part of the Consolidated Appropriations Act, 2021 (P.L. 116-260), Congress
directed EPA and CEQ to undertake several activities related to geologic sequestration and related
CCS infrastructure, among other provisions related to carbon utilization, project permitting, and
CCS infrastructure. The act directed EPA, in consultation with DOE and other relevant federal
agencies, to submit a report to Congress on “deep saline formations” that addresses potential risk
and benefits to project developers, recommendations for managing these risks, and
recommendations for potential legislation and federal policy in these areas.94 The USE IT Act
also directed CEQ, in consultation with EPA, DOE, and other agencies, to submit a report to
Congress regarding the permitting and review of CCS projects and CO2 pipelines.95 Among other
CCS topics, the report was to include information on federal permitting and authorities for
sequestration projects and “gaps in the current federal regulatory framework” for sequestration

90 26 U.S.C §45Q. P.L. 115-123 expanded the tax credit to carbon oxides, which includes CO2.
91 P.L. 116-260, Division D §4003.
92 The definition was altered in 2021 by P.L. 117-58 to remove the 10-year time frame (42 U.S.C. §16293).
93 P.L. 116-260, Division Z §4003.
94 P.L. 116-260, Division.S §102(b).
95 P.L. 116-260, Division.S §102(b).
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projects, capture and utilization projects, and CO2 pipelines. The act also directed CEQ to issue a
guidance to federal agencies based on this report that facilitates reviews and supports the
development of CCS projects and CO2 pipelines. See “CEQ 2021 CCS Report to Congress and
2022 CCS Guidance” later in this report for a discussion of CEQ’s report and guidance in
response to these directives.
Other Relevant Provisions in P.L. 116-260
In Division G of the Consolidated Appropriations Act, 2021, Congress directed EPA to submit a
report and provide a briefing to Congress on recommendations to “improve Class VI permitting
procedures.”96 In the act, Congress also extended the start of construction deadline for projects
seeking the federal tax credit for carbon sequestration, also known as the “Section 45Q” tax credit
by two years, to 2026.97
Infrastructure Investment and Jobs Act
The Infrastructure Investment and Jobs Act (IIJA; P.L. 117-58), enacted in November 2021,
expanded some of the DOE large-scale carbon storage activities authorized in the Energy Act of
2020 and adds “commercialization” of projects as a focus of the agency’s carbon storage
program. Specifically, IIJA Division D, Title III, directed DOE to establish a new “large-scale
carbon storage commercialization program” for geologic sequestration projects. IIJA also changes
the definition of “large-scale carbon sequestration,” removing the 10-year time frame for
sequestering 50 million tons enacted in the Energy Act of 2020.98 In Division J of IIJA, Congress
also provided $2.5 billion in total supplemental appropriations to DOE for carbon storage,
validation, and testing activities for FY2022-FY2026.
For EPA, IIJA directed the agency to establish a grant program for states that have been granted
Class VI program primacy by EPA. Division J of the act provides $50 million in supplemental
appropriations to EPA for grants to states that have or are working toward Class VI primacy, and
an additional $25 million to the agency for Class VI permitting administration, both for FY2022.
The Inflation Reduction Act of 2022
In the budgetary measure commonly known as the Inflation Reduction Act of 2022 (IRA; P.L.
117-169), Congress amended Section 45Q in numerous ways. The IRA changed existing
provisions and added new provisions that revised the tax credit amounts, lowered the amounts of
CO2 facilities are required to capture each year to qualify for the credit, and extended the deadline
for when a facility must start construction, among other changes.99 For more information on the
Section 45Q tax credit, see “Carbon Sequestration Tax Credits” later in this report.
Issues for Congress
If Congress were to address carbon storage through underground injection, there are a variety of
policy issues Members may consider. Several policy issues relate to the current SDWA UIC
regulatory framework and what elements of CO2 injection are covered under the statute’s purpose

96 P.L. 116-260, Division G, Title II, Environmental Protection Agency.
97 P.L. 116-260, Division EE, the Taxpayer Certainty and Disaster Relief Act of 2020, Title I, §121.
98 P.L. 117-58, Division D §40305 (42 U.S.C. §16293).
99 P.L. 117-169, §13104. Application of tax credit amounts, construction deadlines, and other Section45Q provisions
depend on when capture equipment is placed in service.
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and approach. Congress may also wish to consider other issues that may have implications for
CO2 injection and storage policy, including current pathways of federal support for CCS and
underground carbon storage, project cost, and stakeholder perspectives on CCS and fossil fuels.
In addition, in 2021, as directed by Congress, CEQ provided a report on CCS that contains
additional issues for consideration.
Scope of the SDWA UIC Regulatory Framework
SDWA currently serves as the major federal authority for regulating injection of CO2 for geologic
sequestration, and carbon storage in general. However, the major purpose of the act’s UIC
provisions is to prevent endangerment of public water supplies and sources from injection
activities. In the preamble to the proposed Class VI Rule, EPA states, “While the SDWA provides
EPA with the authority to develop regulations to protect USDWs from endangerment, it does not
provide authority to develop regulations for all areas related to GS [geologic sequestration].”100
The agency identified specific policy areas related to geologic sequestration that are beyond the
agency’s authority, including, but not limited to, capture and transport of CO2, managing human
health and environmental risks other than drinking water endangerment, determining property
rights, and transfer of liability from one entity to another.101
The agency acknowledges the challenge of balancing SDWA goals with broader efforts to support
geologic sequestration. In the preamble to the Class VI Rule, EPA noted that “[t]his rule ensures
protection of USDWs while also providing regulatory certainty to industry and permitting
authorities and an increased understanding of GS through public participation and outreach.”102
Potential Environmental Risks of Injection and Geologic Sequestration of CO2
Federal agencies, external analysts, and other stakeholders have expressed a variety of viewpoints
on the potential risks associated with injection and geologic sequestration of CO2. EPA, the
Interagency Task Force on Carbon Capture and Storage (Task Force), and others have recognized
that CO2 injection and sequestration activities may convey risks to the environment and human
health.103 Some of these risks involve potential endangerment of USDWs that would be covered

100 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Proposed Rule,” 73 Federal Register 43492-43541,
July 25, 2008, p. 43495.
101 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Proposed Rule,” 73 Federal Register 43492-43541,
July 25, 2008, p. 43495.
102 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal Register 77230-77303,
December 10, 2010, p. 77279.
103 In its 2010 report, the U.S. Interagency Task Force on Carbon Capture and Storage stated, “Because [the] SDWA is
focused on the protection of drinking water sources, it may require clarification to support actions to address or remedy
ecological or non-drinking water human health impacts arising from the injection and sequestration of CO2”
(Interagency Task Force on Carbon Capture and Storage, Report of the Interagency Task Force on Carbon Capture and
Storage, 2010). In another report, a coalition of academic experts, the CCSReg Project, stated, “Because of the
constraints of its statutory mandate, the UIC program cannot comprehensively manage all potential issues that arise in
connection with geologic sequestration operations, and, because it places protection of drinking water aquifers
(independent of quantity or depth) above all other objectives, it cannot address tradeoffs between risk to groundwater
and risks from climate change” (CCSReg Project, Carbon Capture and Sequestration: Framing the Issues for
Regulation, 2009).
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by SDWA. Other potential impacts, however, are not covered by SDWA or the UIC implementing
regulations.
For groundwater-related risks, EPA has noted that expansion of CO2-EOR and associated CO2
storage could increase the risk of endangerment to USDWs due to increased injection zone
pressures and the large number of wells in oil and gas fields that could serve as leakage
pathways.104 Injected CO2 could also force brine from the target formation into USDWs, which
could affect drinking water.105 To address potential releases or leakage that could endanger
USDWs, in the Class VI Rule, EPA included monitoring, reporting, and record-keeping
requirements specific to CO2 injection.106 Class VI construction and testing requirements, which
are generally more stringent than Class II requirements for EOR, are also intended to prevent
USDW endangerment.107
Regarding other types of risk from improperly managed projects, EPA identified risks to air
quality, human health, and ecosystems as potential concerns not addressed by SDWA
authorities.108 In its 2010 report, the Task Force concluded that SDWA’s limited application to
only those groundwater formations that meet the specific statutory definition of USDWs may
“require clarification to support actions to address or remedy ecological or non-drinking water
human health impacts arising from the injection and sequestration of CO2.”109 The Task Force
also stated that an accidental large release could result in risks to surface water, local ecology, and
human health.110 (See text box Human Health and Environmental Considerations of CO2 and
Geologic Sequestration.)
An additional concern with injection and sequestration of CO2 is the increased potential for
earthquakes associated with deep-well injection. Earthquakes induced by CO2 injection could
fracture the rocks in the reservoir, or more importantly, the caprock above the reservoir.111 Class
VI well regulations require that information on earthquake-related history be included in the
permit application and that owners or operators not exceed injection pressure that would induce
seismicity or initiate fractures.112

104 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal Register 77230-77303,
December 10, 2010, p. 77244. Most CO2-EOR is regulated by states under SDWA Section 1425 rather than regulated
directly by EPA.
105 IPCC 2005, p. 248.
106 40 C.F.R. §146.90 and §146.91.
107 40 C.F.R. §146.86-§146.90.
108 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Proposed Rule,” 73 Federal Register 43492-43541,
July 25, 2008, p. 43497.
109 Interagency Task Force on Carbon Capture and Storage, Report of the Interagency Task Force on Carbon Capture
and Storage, 2010, p. 106.
110 Interagency Task Force on Carbon Capture and Storage, 2010 p. 42. Such as a release due to well damage or
failure, or certain circumstances where the injected CO2 could migrate in an unexpected way (IPCC 2005, p. 247).
111 Mark D. Zoback and Steven M. Gorelick, “Earthquake Triggering and Large-Scale Geologic Storage of Carbon
Dioxide,” PNAS, vol. 109, no. 26 (June 26, 2012), pp. 10164-10168.
112 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Proposed Rule,” 73 Federal Register 43492-43541,
July 25, 2008, p. 43498.
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In a 2005 CCS report, the IPCC notes that data on physical leakage from geological storage sites
are “very limited,” and “physical leakage rates are estimated to be very small for geological
formations chosen with care.”113
NETL and other stakeholders offer other perspectives on potential health and environmental risks.
Regarding the risks of CO2 leakage, NETL outlines several case studies on leakage related to
underground carbon storage in a 2019 report.114 The report states that use of EOR in the United
States “has demonstrated that large volumes of gas can be stored safely underground and over
long timeframes when the appropriate best-practices are implemented.”115 According to the
report, “Despite over 40 years of operating CO2 EOR projects, leakage events have rarely been
reported”; although the report also notes that “there has been no official mechanism for reporting
leaks of CO2 until recently.”116 Other stakeholders have also commented that even given potential
health and environmental risks, the benefits of CO2 sequestration in reducing GHG emissions as
part of climate change mitigation efforts outweigh such risks.117
Liability and Property Rights Issues
In the Class VI Rule, EPA acknowledged stakeholder interest in liability and long-term
stewardship, but noted that that the agency does not have the authority to determine property
rights or transfer liability from one owner or operator to another.118 In its report, the Task Force
also identified that “the existing [f]ederal framework largely does not provide for a release or
transfer of liability from the owner/operator to other persons” and noted that some stakeholders
view these issues as a barrier to future CCS project deployment.119 Specific policy questions
regarding property rights include who owns and controls the subsurface formations (known as the
pore space) targeted for CO2 storage, if and how such property can be transferred or aggregated,
and how underground reservoirs that cross state and tribal boundaries should be regulated. State
laws and contractual property arrangements, similar to those established for oil and gas
development, may address some of these questions, but some analysts identify the need for more
clarity.120
Issues of financial liability and long-term stewardship of injection sites and storage reservoirs
also remain largely unresolved. Analysts have raised questions such as (1) who is responsible for
the site and reservoir after the 50-year mandated post-injection site care period; (2) what is the
role of the federal or state government in assisting site developers and operators with managing
the risks associated with sequestration activities; and (3) whether the federal government should
be involved in taking on some or all financial responsibility during the life-cycle of sequestration
projects.121 Large-scale commercial geologic sequestration projects would likely require unique

113 IPCC 2005, pp. 371.
114 NETL, CO2 Leakage During EOR Operations, 2019, pp. 104-109.
115 NETL, CO2 Leakage During EOR Operations, 2019, p. 2.
116 NETL, CO2 Leakage During EOR Operations, 2019, pp. 104 and 110.
117 CCReg Project 2009, p. 83.
118 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Proposed Rule,” 73 Federal Register 43492-43541,
July 25, 2008, p. 43495, and U.S. Environmental Protection Agency, “Federal Requirements Under the Underground
Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal
Register 77230-77303, December 10, 2010, p. 77272.
119 Interagency Task Force 2010, p. 109.
120 CCReg project 2009, p. 95, and Interagency Task Force 2010, p. 71.
121 Interagency Task Force 2010, p. 68, and CCReg Project 2009, p. 58.
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liability and stewardship structures that address issues such as the particular characteristics of
CO2, the entire life-cycle of sequestration projects—from site selection to periods beyond site
closure—and the geologic time frame (hundreds or thousands of years) over which sequestration
occurs. For more information on legal issues, see CRS Report RL34307, Legal Issues Associated
with the Development of Carbon Dioxide Sequestration Technology, by Adam Vann and Paul W.
Parfomak.
Other Policy Considerations
Research, Development, and Deployment
EPA has stated that, “a supporting regulatory framework for the future development and
deployment of [carbon storage] technology can provide the regulatory certainty needed to foster
industry adoption of CCS, which is crucial to supporting the goal of any climate change
legislation.”122 Even with the completion of several large-scale demonstration field projects,
analysts recognize uncertainties regarding wide-spread commercial CCS operation in the United
States. These include uncertainties in operations, such as how much CO2 would be injected, CO2
sources, availability of appropriate locations, and the exact constituents of CO2 injection
streams.123 A lack of existing infrastructure for CCS systems—from capture technology to
pipelines to transport CO2—may also act as barriers to future CCS deployment.124
As noted earlier in this report, recent legislative directives from Congress to DOE and CEQ, as
well as appropriations to DOE for carbon storage RD&D, demonstrate increased attention to
supporting research and development activities that further technical knowledge and facilitate
deployment of CCS projects.125 The Energy Act of 2020, the USE IT Act, and IIJA expanded
DOE’s CCS activities in research and demonstration of geologic sequestration technologies and
assessments of sequestration sites. Congress provided $2.5 billion in IIJA to DOE for carbon
storage, validation, and testing activities. Congress has also directed DOE to prepare reports on
CCS RD&D.126 Overall, in recent years congressional attention has moved toward supporting
larger-scale projects and the technology and programs needed to move these projects from
demonstrations toward deployment and commercial operation.
Project Cost
The cost of constructing and operating a new CCS system or retrofitting an existing facility, such
as a coal-fired or natural gas power plant, with CCS, is likely to play a major role in the future
deployment of commercially viable sequestration projects. Costs for large-scale geologic
sequestration or EOR include expenses directly related to injection and storage, as well as costs of
investing in sufficient carbon capture and transportation infrastructure and maintaining ongoing
facility operations. Regarding regulatory costs associated with geologic sequestration, in the

122 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Proposed Rule,” 73 Federal Register 43492-43541,
July 25, 2008, p. 43496.
123 Interagency Task Force 2010, pp. C-5-C-9.
124 Interagency Task Force 2010, p. 48.
125 See Divisions S and Z of P.L. 116-260 and Divisions D and J of P.L. 117-58.
126 Division Z of P.L. 116-260, §4003 (42 U.S.C §16293).
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preamble to the Class VI Rule, EPA specified the agency’s intention that the rule would not
impede geologic sequestration:
Should this rule somehow impede GS from happening, then the opportunity costs of not
capturing with the benefits associated with GS could be attributed to this regulation;
however the Agency has tried to develop a rule that balances risk with practicability, site
specific flexibility and economic considerations and believes the probability of such
impedance is low.127
Analysts expect that the costs of CCS, whether new system or retrofitting of an existing facility,
are likely to total more than a billion dollars per project, which could act as a barrier to future
CCS deployment without the continuation of federal subsidies for development.128 According to
Enchant Energy, a company planning to retrofit power generation facilities in New Mexico and
North Dakota, the projects are expected to cost $1.3 billion and $1 billion, respectively.129
Minnkota Power estimates that a CCS project in North Dakota, Project Tundra, will require $1
billion in capital investment.130 The project is in the early development stages and would install
carbon capture at a coal-fired power plant and inject CO2 into a nearby formation for geologic
sequestration.
Examples of completed commercial-scale CCS operations and associated costs are limited,
causing some uncertainty regarding future investments and the scale of project deployment in the
coming decades. In a 2019 report, NETL indicated that “the potential costs of commercial-scale
CCS are still not fully understood, particularly from a fully integrated (capture, transportation,
and storage) perspective.”131 Costs could vary greatly due to a variety of site-specific factors. The
type of capture technology is the largest component of costs, possibly accounting for as much as
80% of the total.132 The variations in the geology of storage formations also make predicting
future geologic sequestration costs particularly difficult. In one set of estimates reported by the
National Petroleum Council, storage costs in the United States range from $7 to $11 per ton of
CO2, depending on the storage location.133
Projects that inject some or all the CO2 for EOR (with incidental carbon storage) involve different
cost implications and economic factors from projects injecting solely for permanent CO2
sequestration. These factors could influence future deployment of these types of projects, as
facility owners and operators may consider cost implications when deciding whether to invest in
EOR or when deciding between investing projects for EOR or permanent geologic sequestration.
EOR operations typically use the existing injection infrastructure in place from earlier oil and gas
production activities; thus, the well exploration and construction costs are “sunk costs.” Unlike
geologic sequestration projects, these expenses may not be included in total project cost

127 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal Register 77230-77303,
December 10, 2010, p. 77279. EPA’s cost estimates apply to injection activities only and do not include capture and
transport of CO2.
128 See IPCC 2005, p. 347, and Jeffrey Rissman and Robbie Orvis, “Carbon Capture and Storage: An Expensive Option
for Reducing U.S. CO2 Emissions,” Forbes, May 3, 2017.
129 Carlos Anchondo and Edward Klump, “Petra Nova is Closed: What It Means for Carbon Capture,” Energywire,
September 22, 2020.
130 Project Tundra, “Project Tundra,” accessed on February 28, 2022, at https://www.projecttundrand.com.
131 NETL, Class I Injection Wells-Analog Studies to Geologic Storage of CO2, January 2019, p. 75, at
https://www.netl.doe.gov/projects/files/UICClassIInjectionWellsAnalogStudiestoGeologicStorageofCO2_013019.pdf.
132 Steve Furnival, “Burying Climate Change for Good,” Physics World, September 1, 2006.
133 National Petroleum Council, Meeting the Dual Challenge, updated June 5, 2020, p. 2-24.
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calculations, resulting in comparatively lower costs for injecting and storing the CO2. In addition,
for EOR projects, overall project costs could be influenced by revenue for the owner or operator
from additional oil and gas production. EOR project costs may also be subject to variability and
uncertainty, however. NETL notes that the price of oil and the cost and availability of CO2 are key
drivers in the economics of CO2 EOR.134
Federal tax credits for carbon sequestration, available since 2009 for both EOR and geologic
sequestration, may also play a role in underground injection and storage of CO2 project costs and
investment decisions. These credits are discussed later in this report.
Public Acceptance and Participation
In the preamble to the proposed Class VI Rule, EPA noted that “GS of CO2 is a new technology
that is unfamiliar to most people, and maximizing the public’s understanding of the technology
can result in more meaningful public input and constructive participation as new GS projects are
proposed and developed.”135 EPA also stated that “the agency expects that there will be higher
levels of public interest in GS projects than for other injection activities.”136 In the Class VI Rule,
EPA adopted the existing UIC public participation requirements, which require permitting
authorities to provide public notice of pending actions, hold public hearings if requested, solicit
and respond to public comments, and involve a broad range of stakeholders.137
At least two cases involving Class VI permits have come before EPA’s Environmental Appeals
Board.138 The first case involved the permit for the FutureGen facility, which was never
constructed. The second case involved ADM’s Illinois facility, currently operating and permitted
in Illinois. Public concerns centered on safety and environmental protection issues, including air
quality, groundwater quality, and protection of endangered species. Local landowners claimed
that the permits did not adequately address how the facility will ensure these protections in the
event of leakage or well failure. They also raised concerns about property rights (including
mineral rights), potential decreases in property value, and increased traffic associated with the
facilities.139
Continued Use of Fossil Fuels
In EPAct05 and EISA, Congress recognized connections between injection of CO2 and the
continued use of fossil fuel as a major energy source for electric power in the United States.

134 NETL, Carbon Dioxide Enhanced Oil Recovery, pp. 14-20, https://www.netl.doe.gov/sites/default/files/netl-file/
CO2_EOR_Primer.pdf.
135 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Proposed Rule,” 73 Federal Register 43492-43541,
July 25, 2008, p. 43523.
136 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal Register 77230-77303,
December 10, 2010, p. 77273.
137 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Final Rule,” 75 Federal Register 77230-77303,
December 10, 2010, p. 77273.
138 UIC Appeal No. 114-68; 14-69; 14-70; 14-71 (Consolidated), (Environmental Appeals Board United States
Environmental Protection Agency 2014) and UIC Appeal No. 17-05 (Environmental Appeals Board United States
Environmental Protection Agency 2017).
139 “EAB Dismisses Challenge to Second SDWA Permit Issued for CCS Project,” EnergyWashingtonWeek, December
17, 2014.
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Consistent with Congress’s directives, DOE’s CCS research identifies that the purpose of its CCS
research, technology development, and testing is “to benefit the existing and future fleet of fossil
fuel power generating facilities by creating tools to increase our understanding of geologic
reservoirs appropriate for CO2 storage and the behavior of CO2 in the subsurface.”140 In the
preamble to the proposed Class VI rule, EPA stated that, “the capture and storage of CO2 would
enable the continued use of coal in a manner that greatly reduces the associated CO2 emissions
while other safe and affordable energy sources are developed in the coming decades.”141
Some stakeholders have argued for further research, development and deployment of CCS (when
coupled with negative carbon technology, such as direct air capture) as a method for achieving the
negative emissions trajectories modeled by the IPCC.142 Some of these stakeholders state that
CCS is an appropriate transitional technology to reduce CO2 emissions from electricity generation
and other industrial sources while expanding the capacity of low or zero-carbon power sources,
such as renewable energy.143 Research on the net emissions reductions of CO2 associated with
EOR is ongoing, although large variations exist in the current literature regarding EOR emissions
life cycle analysis methodologies and parameters.144
In contrast, other stakeholders have argued that CO2 storage could create a disincentive to reduce
fossil-fuel-based power plant emissions or shift to renewable energy sources.145 For example, in
its 2021 draft recommendations to the Biden Administration, the White House Environmental
Justice Advisory Council included CCS projects in its list of “examples of the types of projects
that will not benefit a community.”146 In particular, some stakeholders note that injecting CO2 for
EOR may actually increase net GHG emissions, as it produces additional oil and gas to be burned
as fuel.147 CCS systems also require energy to compress, transport, and inject the CO2, which, if
derived from fossil fuel combustion, could detract from the net GHG reduction benefits of carbon
storage.
Carbon Sequestration Tax Credits
Federal tax credits for carbon sequestration were first authorized in 2008 with the enactment of
the Energy Improvement and Extension Act (P.L. 110-343). This act added Section 45Q to the
Internal Revenue Code (I.R.C.), which established tax credits for CO2 disposed of in “secure

140 U.S. Department of Energy 2015, p. 9.
141 U.S. Environmental Protection Agency, “Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration Wells; Proposed Rule,” 73 Federal Register 43492-43541,
July 25, 2008, p. 43498.
142 Net negative carbon is a type of negative emission technology, which the IPCC defines as the “removal of
greenhouse gases from the atmosphere by deliberate human activities” (IPCC, Global Warming of 1.5ºC, A Special
Report on the Impacts of Global Warming of 1.5ºC Above Pre-industrial Levels, 2018, Glossary).
143 Natural Resources Defense Council, “Capturing Carbon Pollution While Moving Beyond Fossil Fuels,” accessed on
November 27, 2019, at https://www.nrdc.org/experts/david-doniger/capturing-carbon-pollution-while-moving-beyond-
fossil-fuels.
144 For example, an International Energy analysis concluded that under certain conditions and within certain
parameters, injecting CO2 for EOR results in negative net CO2 emissions per barrel of oil produced (International
Energy Agency, Storing CO2 Through Enhanced Oil Recovery, 2015, p. 30).
145 Carlos Anchondo, “Industry Warns Lawmakers of CCS Threats,” Energywire, November 25, 2019; and Richard
Conniff, “Why Green Groups Are Split on Subsidizing Carbon Capture Technology,” YaleEnvironment360, April 9,
2018, YaleEnvironment360, April 9, 2018.
146 White House Environmental Justice Advisory Council, Draft Recommendations on: Justice 40 Climate and
Economic Justice Screening Tool & E.O. 12898, May 13, 2021.
147 Conniff, 2018.
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geologic storage” or through EOR with “secure geologic storage.”148 For EOR, only the initial
CO2 injected as a tertiary injectant qualifies for the tax credit; CO2 recaptured, recycled, or
reinjected does not qualify.149
Provisions in Section 45Q establish the amount of the tax credit per ton of carbon oxide captured
and disposed of, annual CO2 capture minimums, deadlines for beginning facility construction,
and credit claim periods; and direct the U.S. Department of the Treasury (Treasury) to issue 45Q
regulations, among other provisions. Credit rates, capture minimums, and other provisions differ
depending on when the facility or capture equipment was placed in service in relation to the
Bipartisan Budget Act of 2018 (BBA) and IRA enactment. As noted previously in this report,
Congress has amended Section 45Q through several legislative measures, such as the BBA, IIJA,
and the IRA. The BBA expanded the tax credit to “carbon oxides” captured and to carbon oxides
utilized in a qualified manner (in addition to EOR), as defined in the act.150
In 2022, the IRA amended 45Q to revise the credit amounts and extend the start of construction
deadline, among other changes. For facilities or equipment placed in service after December 31,
2022, and that meet prevailing wage and registered apprenticeship requirements, the tax credit
amount is $85 per ton of CO2 disposed of in “secure geologic storage” and $60 per ton of CO2
used for EOR and disposed of in “secure geologic storage,” or utilized in a qualified matter.151
Different credit rates apply to equipment placed in service between the enactment of the BBA on
February 9, 2018, and December 31, 2022, and to equipment placed in service prior to BBA
enactment.152
In the IRA, Congress established a separate set of credit amounts for CO2 captured using direct air
capture (DAC), an emerging technology designed to remove CO2 directly from the atmosphere
rather than from a point source of CO2 emissions. For DAC facilities or equipment placed in
service after December 31, 2022, and that meet prevailing wage and registered apprenticeship
requirements, the credit is $180 per ton for CO2 captured using DAC and disposed of in “secure
geologic storage,” and $130 per ton for CO2 captured using DAC that is used for EOR and
disposed of in “secure geologic storage,” or utilized in a qualified manner.153
To qualify for these tax credits, a point source facility or DAC facility must begin construction by
December 31, 2032.154
The IRA also established a lower amount of CO2 that certain facilities must capture each year to
qualify for the credit, compared to what had previously been required. For facilities that begin

148 26 U.S.C §45Q. P.L. 115-123 expanded the tax credit to carbon oxides, which includes CO2.
149 26 U.S.C §45Q (c)(2). Tertiary injectant refers to the injection of CO2 for enhanced oil recovery (also known as
tertiary recovery). For the purposes of §45Q, tertiary injectant has the same meaning as used in 26 U.S.C §193.
150 26 U.S.C §45Q (a). For more information on Section 45Q, please see CRS In Focus IF 11455, The Tax Credit for
Carbon Sequestration (Section 45Q), by Angela C. Jones and Molly F. Sherlock. Carbon oxide refers to any of the
three oxides of carbon: carbon dioxide, carbon monoxide, and carbon suboxide.
151 P.L. 117-169, §13104(b). For facilities that do not meet prevailing wage and apprenticeship requirements, the base
credit amount is $17 per ton for secure geologic storage and $12 per ton for EOR or other qualified use. Credit amounts
are adjusted for inflation after 2026.
152 26 U.S.C §45Q (a).
153 P.L. 117-169, §13104(c). Prior to the IRA amendments, eligible taxpayers disposing of CO2 captured through DAC
would receive the credit amount for the type of disposal used, either geologic sequestration or EOR/utilization. For
facilities or equipment placed in service after December 31, 2022, the base credit amount is $36 per ton for CO2
captured using DAC and geologically sequestered and $26 per ton for CO2 captured using DAC that is used for EOR or
utilized in a qualified manner.
154 P.L. 117-169, §13104(a).
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Injection and Geologic Sequestration of Carbon Dioxide

construction after August 16, 2022, DAC facilities must capture at least 1,000 tons of CO2 per
year.155 Electricity generating facilities must capture at least 18,750 tons of CO2 per year and have
a capture design capacity at least 75% of the unit’s baseline carbon oxide production; and other
facilities must capture at least 12,500 tons of CO2 per year.156
In January 2021, the IRS issued final Section 45Q regulations that include requirements for
demonstrating the “secure geological storage” of carbon oxides in underground formations
needed to qualify for 45Q tax credits.157 The rule adds new I.R.C. Section 1-45Q-3, which
establishes that compliance with relevant provisions of the EPA’s Mandatory Reporting of
Greenhouse Gases Rule satisfies the 45Q secure storage demonstration requirements.158 In
addition, the regulations require that carbon oxides must also be injected into a well that complies
with applicable EPA UIC regulations to be considered secure geological storage.159 For more
information, see CRS In Focus IF11639, Carbon Storage Requirements in the 45Q Tax Credit, by
Angela C. Jones.
Treasury estimates that for FY2023, the credit will reduce federal income tax revenue by $720
million.160 Over the FY2022-FY2031 budget window, Treasury estimates that the tax credit will
reduce federal income tax revenue by a total of $20.1 billion.161 As of June 2020 (the latest data
available), the amount of stored carbon oxide claimed for 45Q credits (for projects in service
before February 9, 2018) since 2011 totaled 72,087,903 tons.162 In a November 2021 notice,
Treasury did not provide an updated total of claimed credits, but noted that it is not certifying that
the total has reached 75 million tons.163
CEQ 2021 CCS Report to Congress and 2022 CCS Guidance
In response to the USE IT Act, CEQ in 2021 provided Congress with a report on carbon capture,
utilization, and sequestration.164 One of several reports required by Congress in the Consolidated

155 P.L. 117-169, §13104(a).
156 P.L. 117-169, §13104(a). For equipment placed in service after the enactment of the BBA on February 9, 2018 and
before January 1, 2023, the annual capture requirements are: (1) in the case of a facility that emits no more than
500,000 metric tons of carbon oxide, capture at least 25,000 metric tons of carbon oxide that is either fixated through
the growing of algae or bacteria, chemically converted into a material or chemical compound in which the carbon oxide
is stored, or used for another commercial purpose (other than a tertiary injectant); (2) in the case of an electricity
generating facility not described in (1), capture at least 500,000 metric tons of carbon oxide per year; or (3) in the case
of a direct air capture facility not described in (1) or (2), capture at least 100,000 metric tons of carbon oxide. For
equipment placed in service before February 9, 2018, the capture requirement is 500,000 tons per year.
157 Internal Revenue Service, “Credit For Carbon Oxide Sequestration,” 86 Federal Register 4728-4773, January 15,
2021.
158 29 C.F.R. Part 1 §1-45Q-3.
159 29 C.F.R. Part 1 §1-45Q-3.
160 U.S. Department of the Treasury, “FY 2023 Tax Expenditures,” accessed February 17, 2022, at
https://home.treasury.gov/policy-issues/tax-policy/tax-expenditures.
161 U.S. Department of the Treasury, “FY2023 Tax Expenditures,” accessed February 17, 2022, at
https://home.treasury.gov/policy-issues/tax-policy/tax-expenditures.
162 Internal Revenue Service Notice 2020-40, “Credit for Carbon Dioxide Sequestration 2020 45Q Inflation Adjustment
Factor,” June 15, 2020. This applies to tax credits for geologic sequestration and EOR.
163 Internal Revenue Service Notice 2021-35, “Credit for Carbon Dioxide Sequestration 2021 45Q Inflation Adjustment
Factor,” November 15, 2021.
164 CEQ, Council on Environmental Quality Report to Congress on Carbon Capture, Utilization, and Sequestration,
https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf. The report to Congress
is required by P.L. 116-260, Division S, §102.
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Appropriations Act, 2021 (P.L. 116-260), this report provides information on federal permitting
and regulations for CCS projects and examines technical, financial, and policy-related issues for
project deployment. In its key findings, CEQ states that “the Federal Government has an existing
regulatory framework that is rigorous and capable of managing permitting and review actions
while protecting the environment, public health, and safety as CCUS projects move forward.”165
CEQ also finds that with the complex nature of CCS projects, there are opportunities for
improvement in the federal regulatory framework to “ensure that CCUS is responsibly scaled in a
timely manner that is aligned with climate goals.”166 CEQ identifies two specific areas of
improvement related to CO2 injection and sequestration—EPA UIC Class VI program capacity
and resolving questions of underground pore space ownership and liability. For the EPA Class VI
program, CEQ recommends increasing staff capacity and training to process and administer the
potential increase in Class VI permit applications and the number of states seeking Class VI
program primacy.167 Regarding pore space, CEQ recommends that EPA, the Department of the
Interior, the Department of Agriculture, and possibly other federal agencies, develop regulations
to clarify property rights and pore space ownership on federal lands.168 CEQ also recommends
that the agencies should also specify the process for leasing pore space for geologic sequestration
on federal lands.169
CEQ released an interim guidance, “Carbon Capture, Utilization, and Sequestration Guidance,” in
February 2022, also as directed by Congress in the USE IT Act.170 The interim guidance includes
recommendations for federal agencies that would support “the efficient, orderly, and responsible
development and permitting of CCUS projects at an increased scale in line with the
Administration’s climate, economic, and public health goals.”171 Related to CO2 injection and
geologic sequestration, CEQ provides guidance on the processes for permitting and review of
CCUS projects and CO2 pipelines, public engagement, and assessing environmental impacts of
CCUS projects.

165 CEQ CCS Report, p. 8.
166 CEQ CCS Report, p. 8.
167 CEQ CCS Report, p. 39.
168 CEQ CCS Report, p. 42.
169 CEQ CCS Report, p. 42.
170 Council on Environmental Quality, “Carbon Capture, Utilization, and Sequestration Guidance,” 87 Federal Register
8808-8811, February 16, 2022. The CEQ guidance is required by P.L. 116-260, Division S, §102.
171 Council on Environmental Quality, “Carbon Capture, Utilization, and Sequestration Guidance,” 87 Federal Register
8808-8811, February 16, 2022, p. 8809.
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Appendix A. Estimates of U.S. Storage Capacity for
CO2
Table A-1. Estimates of U.S. Storage CO2 Capacity
(in billions of metric tons)
Formations
Low
Medium
High
Oil and Natural Gas Reservoirs
186
205
232
Unmineable Coal Seams
54
80
113
Saline Formations
2,379
8,328
21,978
Total
2,618
8,613
22,323
Source: U.S. Department of Energy, National Energy Technology Laboratory, Carbon Utilization and Storage Atlas,
5th ed., August 20, 2015, at https://www.netl.doe.gov/sites/default/files/2018-10/ATLAS-V-2015.pdf (data current
as of November 2014).
Notes: The low, medium, and high estimates correspond to a calculated probability of exceedance of 90%, 50%
and 10% respectively, meaning that there is a 90% probability that the estimated storage volume wil exceed the
low estimate and a 10% probability that the estimated storage volume wil exceed the high estimate. Numbers in
the table may not add precisely due to rounding.
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Appendix B. Department of Energy Funded Large Scale Injection and
Geologic Sequestration of CO2 Projects in the United States
Table B-1. Large Scale CO2 Injection Projects in the United States (RCSP and Recovery Act Funded) as of 2021
Volume Injected for
Storage
Funding Source and
Project
CO2 Source
Type
Injection Status
(in tons)
Amount
Illinois Industrial Carbon
Ethanol fermentation
Saline storage
Active injection and
1.8 mil ion
ARRA
Capture and Storage
plant
sequestration
(as of July 2020)
$141,405,945 (funding
Project (Archer Daniels
includes Il inois Basin
Midland Facility)
Project)a
Decatur, IL
Air Products Project
Steam methane
EOR
Active injection
6.8 mil ion
ARRA
Port Arthur, TX
reformers
(as of July 2020)
$284,000,000b
Michigan Basin Project
Natural gas processing
EOR
Active injection
1,638,692c
RCSP
Otsego County, MI
plant
$1,019.414d
Petra Nova Plant
Coal-fired power plant
EOR
Idlede
1.4 mil ion per year
ARRA
Thompsons, TX
(through 2019)
$167,000,000 and
FY2016 Consolidated
Appropriations Act
$23,000,000
($190,000,000 total)f
Citronelle Project
Coal-fired power plant
Saline storage
Completed Sept. 2014;
114,104
RCSP
Citronelle, AL
post-injection monitoring
$76,981.260g
Illinois Basin Decatur
Ethanol fermentation
Saline storage
Completed Nov. 2014;
999,215
RCSP
Project (Archer Daniels
plant
post-injection monitoring
$141,405,945 (funding
Midland Facility)
includes Il inois Industrial
Decatur, IL
Project)h
Cranfield Project
Natural
EOR with saline storage
Completed Jan. 2015;
4,743,898
RCSP
Natchez, MS
post-injection monitoring
$76,981.260i
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Volume Injected for
Storage
Funding Source and
Project
CO2 Source
Type
Injection Status
(in tons)
Amount
Bell Creek Field Project
Natural gas processing
EOR
Completed; post-
2,982,000
RCSP
Crook County, WY
plant
injection monitoring
$95,453,751j
Farnsworth Unit
Ethanol and fertilizer
EOR
Completed; post-
791,593
RCSP
Ochitree County, TX
production plant
injection monitoring
$65,618,315k
Kevin Dome Project
None
Saline storage
Project suspended
0
RCSP
Toole County, MT
$67,000,000l
Sources: For Project, CO2 Source, Type, Injection Status and Volume Injected: DOE, Carbon Utilization and Storage Atlas 2015; based on CRS discussions with DOE,
September 26, 2019, and September 21, 2020; NETL, “Petra Nova Parish Holdings,” accessed October 25, 2019, at htpps://www.netl.doe.gov/sites/default/files/netl-
file/Petra_Nova.pdf; NETL, “Recovery Act: CO2 Capture from Biofuels Projection and Sequestration into the Mt. Simon Sandstone Reservoir,” accessed October 25,
2019, at https://www.netl.doe.gov/project-information?p=FE0001547.
Notes: ARRA is the American Recovery and Reinvestment Act (P.L. 111-5); RSCP is the Regional Carbon Sequestration Partnership.
a. NETL, “Recovery Act: CO2 Capture from Biofuels Projection and Sequestration into the Mt. Simon Sandstone Reservoir,” accessed October 25, 2019, at
https://www.netl.doe.gov/project-information?p=FE0001547.
b. NETL, “Demonstration of Carbon Capture and Sequestration of Steam Methane Reforming Process Gas Used for Large-Scale Hydrogen Production,” accessed
October 25, 2019, at https://www.netl.doe.gov/sites/default/files/netl-file/2012-10-18-PCC-Presentation-APCI—Zinn-Rev1.pdf.
c. Total as of December 2019. Although injection continues, DOE is no longer col ecting stored CO2 data on this facility.
d. NETL, “Northern Michigan Basin CarbonSAFE Integrated Pre-Feasibility Project,” accessed October 25, 2019, at https://www.netl.doe.gov/project-information?p=
FE0029276.
e. NRG idled Petra Nova’s carbon capture equipment in May 2020, in response to lower oil prices (NRG Energy, “Petra Nova Status Update, accessed September 14,
2020, at www.nrg.com/about/newsroom/2020/petra-nova- status-update.html).
f.
NETL, “Petra Nova—W.A. Parish Project,” accessed October 25, 2019, at https://www.energy.gov/fe/petra-nova-wa-parish-project.
g. SECARB, “Phase III Anthropogenic CO2 Injection Field Test,” accessed October 25, 2019, at http://www.secarbon.org/files/anthropogenic-test.pdf.
h. NETL, “Recovery Act: CO2 Capture from Biofuels Projection and Sequestration into the Mt. Simon Sandstone Reservoir,” accessed October 25, 2019, at
https://www.netl.doe.gov/project-information?p=FE0001547.
i.
SECARB, “Phase III Early CO2 Injection Field Test at Cranfield,” accessed October 25, 2019, at http://www.secarbon.org/files/early-test.pdf.
j.
DOE, “Federal Investments in Coal as Part of A Clean Energy Innovation Portfolio,” accessed October 25, 2019, at https://www.energy.gov/sites/prod/files/2016/06/
f32/Federal%20Investments%20in%20Coal%20as%20Part%20of%20a%20Clean%20Energy%20Portfolio.pdf.
k. DOE, “Federal Investments in Coal as Part of A Clean Energy Innovation Portfolio,” accessed October 25, 2019, at https://www.energy.gov/sites/prod/files/2016/06/
f32/Federal%20Investments%20in%20Coal%20as%20Part%20of%20a%20Clean%20Energy%20Portfolio.pdf.
CRS-33

l.
Big Sky Sequestration Partnership, “Kevin Dome Storage Project Fact Sheet,” accessed October 25, 2019, at https://www.bigskyco2.org/sites/default/files/outreach/
KevinProjectMediaKit_071511.pdf.
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link to page 41
Appendix C. Comparison of Class II and Class VI Wells
Table C-1. Minimum EPA Requirements for Class II and Class VI Wells
Class II Requirements Apply to 10 States Where EPA Administers the Class II Program and 16 States with Class II Primacy Under Section 1422
Requirements
Class IIa
Class VI
General Permit
The permit applicant must provide basic facility
Class II requirements plus detailed information on the CO2 stream, baseline
Information
information, a listing of permits under other federal
geochemical data on subsurface formations, including all USDWs in the area of review
programs, a topographic map of the property including and more detailed information on the geologic structure and hydrogeologic properties
injection well sites and water bodies within a ¼ mile
of the storage site and overlaying formation.
of the facility boundary, land records, and a plugging
and abandonment plan.
Siting Criteria
New wells must be sited so that they inject into a
The permit applicant must demonstrate that within the geologic system: the injection
formation separated from any USDW by a confining
site is in a suitable geologic formation for geologic sequestration; the injection zone can
zone that is free of known open faults or factures
receive the total anticipated volume of the CO2 stream; and the confining zone is free
within area of review.
of faults or fractures and of sufficient extent and integrity to contain the injected CO2
stream and displace formation fluids at the proposed maximum pressures and volumes
without initiating or propagating fractures.
Permit Required
Yes, except for existing EOR wells authorized by rule.
Yes; cannot be authorized by rule.
Seismicity Information
None.
Provide information on seismic history of the site; demonstration that the formation’s
confining zone (which limits fluid movement) is free of faults or fractures and can
contain the injected CO2 and other formation fluids (e.g., brine) without initiating or
propagating fractures in the formation.
Area of Review
For new wells, a ¼ mile fixed radius or radius of
Designates a larger AOR that accounts for the physical and chemical properties of
(AOR) and Corrective endangerment.
CO2, including how CO2 injection plumes flow through underground formations.
Action
For new wells, must identify the location of all known
Owner/operator must review the AOR every five years.
wells within the injection well’s AOR which penetrate
Corrective action on all wells in the area of review that are determined to need
the injection zone, or in the case of Class II wells
corrective action, using methods designed to prevent the movement of fluid into or
operating over the fracture pressure of the injection
between USDWs, including use of materials compatible with the CO2 stream, where
formation, all known wells within the AOR penetrating appropriate.
formations affected by the increase in pressure. For
improperly sealed, completed, or abandoned wells,
must submit a corrective action plan.
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link to page 41 link to page 41 link to page 41
Requirements
Class IIa
Class VI
Financial
Financial assurances (bond, letter of credit, or other
Financial responsibility instruments to cover corrective action, injection, well plugging,
Responsibility
adequate assurance) that the owner or operator wil
post-injection site care, and any emergency and remedial response that meets the
maintain financial responsibility to properly plug and
regulatory requirements of those actions.
abandon the wells.

Well Construction
Casing and cementing are adequate to prevent
Class II requirements plus must also use materials and performance standards suitable
movement of fluids into or between USDWs.
for long-term contact with CO2 for the life of the project.
Logging, Sampling, and
New wells must be tested for mechanical integrity
Class II requirements plus more specific requirements to determine or verify the
Testing Prior to
prior to operation.
characteristics of formation fluids in all relevant geologic formations.
Operation
Specific tests required to demonstrate mechanical integrity.
Specific requirements for testing and recording of the physical and chemical
characteristics of the injection zone.
Operating
Injection pressure shall not exceed a calculated
Class II requirements plus more specific limits on injection pressure and continuous
Requirements
maximum or cause the movement of injection or
monitoring of injection pressure and CO2 stream.
formation fluids into a USDW.
In no case may injection pressure initiate fractures in the confining zone(s) or cause the
movement of injection or formation fluids that endangers a USDW.
Mechanical Integrity
Internal—pressure test at least once every five years.
Specific standards for when a Class VI well demonstrates mechanical integrity, including
External—adequate cement records may be used in
the requirement for annual testing to determine the absence of significant fluid
lieu of logs.
movement.
Testing and
Annual fluid chemistry and other tests as
The testing and monitoring plan must verify that the project is operating as permitted
Monitoring
needed/required by permit.
and is not endangering USDWs.
Injection pressure, flow rate, and cumulative volume
Analysis of CO2 stream at sufficient frequency.
observed weekly for disposal and monthly for
Continuous monitoring of the CO2 injection pressure, rate, and volume.
enhanced recovery.
Testing and monitoring of the underground CO2 plume and pressure front both during
injection and for a period fol owing injection.b
Quarterly corrosion monitoring of well materials.
Periodic monitoring of groundwater quality throughout the lifetime of the project.
The UIC director may require air and/or soil gas monitoring.
Well Plugging and Site
Well must be plugged with cement in a manner that
Class II requirements plus more specific well plugging and site closure requirements for
Closurec
wil not allow the movement of fluids into or between
testing, notification, and reporting.
USDWs.
Technical and management requirements to prevent CO2 leakage from the entire site
after operation ceases.
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link to page 41 link to page 41 link to page 41
Requirements
Class IIa
Class VI
Reporting and
Required annually.
Required semiannually.
Recordkeeping
Retain records of all monitoring information.
Class II requirements plus reporting of more specific information on injection fluid
Reporting of noncompliance which may endanger
stream and pressure data.
health or the environment.
Owners/operators must report within 24 hours “evidence that the injected carbon
dioxide stream or associated pressure front may cause an endangerment to a
USDW.”d
Records must be retained for all data col ected under Class VI permit applications for
the life of the project and 10 years fol owing side closure; monitoring data must be
retained for 10 years after col ected.
Post-injection Site
None.
Continue monitoring of the CO2 plume and pressure front to prevent endangerment
Care
of USDWs after injection.
50-year period of monitoring after final injection.e
Emergency and
None.
Submit an emergency and remedial response plan to prevent endangerment of a
Remedial Response
USDW.
Notification and plan implementation in the event of a CO2 release.
Permitting Period
Specific period, may be for the life of well. Existing
Sets a longer permitting period, including the lifetime of the facility plus a 50 year post-
Class II recovery or hydrocarbon storage injection
injection period.
wells are authorized by rule for the life of the project.
UIC program directors must review each permit at least once every five years.
UIC program directors must review each permit at
least once every five years.
Area Permits
Generally allowed.
Not allowed.
Source: EPA, “Technical Program Overview: Underground Injection Control Regulations,” EPA 816-R-02-025, December 2002, pp. 11 and 67; 40 C.F.R. §144.36; 40
C.F.R. §144; 40 C.F.R. §146.81.
a. Most oil and gas production occurs in states with primacy (program oversight and enforcement authority) for Class II wells under SDWA Section 1425. These states
regulate Class II wells under their own state programs, rather than the EPA regulations discussed here.
b. Pressure front means the zone of elevated pressure that is created by the injection of CO2 into the subsurface; can refer to the pressure sufficient to cause the
movement of injected fluids or formation fluids into a USDW (40 C.F.R. §146.81(d)).
c. Closure means the point in time when the facility owner or operator is released from post-injection site care responsibilities, as determined by the UIC program
director (40 C.F.R. §146.81(d)).
d. 40 C.F.R. §146.91(c)(1).
e. Other well classes have post-closure monitoring periods as determined by the UIC Director.
CRS-37

Injection and Geologic Sequestration of Carbon Dioxide

Author Information

Angela C. Jones

Analyst in Environmental Policy

Acknowledgments
CRS Research Librarians Kezee Procita, Rachel Eck, and L.J. Cunningham made significant contributions
to this report.

Disclaimer
This document was prepared by the Congressional Research Service (CRS). CRS serves as nonpartisan
shared staff to congressional committees and Members of Congress. It operates solely at the behest of and
under the direction of Congress. Information in a CRS Report should not be relied upon for purposes other
than public understanding of information that has been provided by CRS to Members of Congress in
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