June 16, 2020
CO2 Underground Injection Regulations: Selected Differences
for Enhanced Oil Recovery and Geologic Sequestration
Underground injection and storage of carbon dioxide (CO2)
To prevent endangerment of underground sources of
has been proposed as a solution for mitigating CO2
drinking water (USDWs), EPA regulations for GS require
emissions into the atmosphere from stationary sources
that these formations meet certain criteria for receiving and
burning fossil fuels. In this process, CO2 is compressed into
retaining expected high volumes and pressures of injected
a fluid (supercritical) state and injected underground for
CO2 without leaking.
enhanced oil recovery (EOR) or for geologic sequestration
(GS). Both operations use wells to place CO2 into deep
Two EPA-permitted wells are currently operating for GS in
subsurface geologic formations, but they are regulated
the United States, both located at a facility in Illinois.
differently both by the U.S. Environmental Protection
Agency (EPA) and states. Recent discussions in Congress
EPA and State Program Regulations
regarding underground carbon storage, including debate
The Safe Drinking Water Act (SDWA) directs EPA to
about tax credits for geologic sequestration and EOR CO2
regulate underground injection activities to prevent
injection, have raised interest in the similarities and
endangerment of USDWs (42 U.S.C. §300h). EPA has
differences between these operations and associated
issued regulations for six classes of underground injection
regulations.
wells based on type and depth of fluids injected and
potential for endangerment of USDWs. Class II wells are
Enhanced Oil Recovery (EOR)
used to inject fluids related to oil and gas production,
EOR is a process used in the oil industry since the 1970s
including injection of CO2 for EOR. Class VI wells are
whereby certain fluids are injected underground to increase
used to inject CO2 for GS.
production from partially depleted oil reservoirs. CO2 has
become the most common injection fluid used in EOR
SDWA Section 1421 requires that EPA regulations for state
projects. The CO2 can be pumped out for reuse after
Underground Injection Control (UIC) programs include
injection, although some of the CO2 remains trapped
requirements for inspection, monitoring, recordkeeping, and
underground. There are more than 134,000 EOR wells
reporting. Accordingly, EPA’s UIC regulations specify
injecting CO2 in the United States, predominantly in
minimum requirements for siting, construction, operation,
California, Texas, Kansas, Illinois, and Oklahoma.
monitoring and testing, closure, corrective action, financial
responsibility, and reporting and recordkeeping (40 C.F.R.
Most CO2 injected for EOR comes from naturally occurring
§§144-148).
underground CO2 reservoirs, but roughly 20% comes from
industrial sources. The CO
State Primacy
2 is typically injected into an
aging oil reservoir using the existing well infrastructure
SDWA directs EPA to delegate primary responsibility for
from the original oil production process. According to a
program administration and enforcement (primacy) for UIC
2019 National Energy Technology Laboratory report,
programs to states, territories, and tribes that meet statutory
between 30% and 40% of the CO2 is generally considered
requirements. For Class II wells only, states can assume
to be stored after each injection cycle, depending on the
primacy under either SDWA Section 1422 or Section 1425.
reservoir characteristics.
States delegated primacy under Section 1422 must meet
EPA regulatory requirements promulgated under Section
Geologic Sequestration of CO2
1421. Sixteen states have Section 1422 primacy. Two of
GS of CO2 is envisioned as the long-term containment of
these states have EOR wells, which are therefore subject to
supercritical CO2 in subsurface geologic formations. The
EPA’s regulations. In addition, EPA directly administers
intent is to permanently trap the injected CO2 underground,
Class II UIC programs in 10 states, five of which have EOR
either in its injected form or through geochemical
wells.
transformation. GS projects, including research projects and
large-scale demonstration projects, may use CO2 captured
Section 1425 allows states to administer their own Class II
from large stationary sources, such as coal-fired power
UIC program without meeting EPA’s regulatory
plants or industrial facilities. The CO2 is compressed and
requirements provided the state demonstrates that its
injected through wells into geologic formations, typically
program meets certain requirements under SDWA Section
saline reservoirs a half a mile or more below the earth’s
1421 and represents an effective program to prevent
surface. CO2 injection for GS generally involves higher
endangerment of USDWs (42 U.S.C. §300h-4). Twenty-
injection pressures, larger expected fluid volumes, and
four states and three tribes have Class II primacy under
different physical and chemical properties of the injection
Section 1425. Nearly 99% of Class II wells for EOR are
stream compared to EOR injection.
located in these states and tribal lands.
https://crsreports.congress.gov
CO2 Underground Injection Regulations: Selected Differences for Enhanced Oil Recovery and Geologic Sequestration
Primacy for Class VI wells is available under Section 1422
Information on potential seismicity (earthquakes) in the
only. EPA has delegated Class VI primacy to one state,
area of the proposed injection site;
North Dakota. On April 14, 2020, EPA proposed to grant
Demonstration that the formation’s confining zone
Class VI primacy to Wyoming as well (85 Federal Register
(which limits fluid movement) is free of faults or
20621).
fractures and can contain the injected CO2 and other
Table 1. EOR and Permanent GS Injection Wells
formation fluids (e.g., brine) without initiating or
propagating fractures in the formation; and
Enhanced Oil
Geologic
Well plugging, closure, site care, and emergency and
Recovery
Sequestration
remedial response plans.
EPA Well Class
Class II
Class VI
Select EPA construction and operating requirements for
GS wells only:
Purpose
Injecting CO2
Injecting CO2 into
into aging oil
geologic formations
Use of materials and performance standards suitable for
fields for EOR
for permanent CO2
CO2 contact for the life of the project,
storage
Specific mechanical integrity testing to demonstrate that
Number of
134,650
2
there is no significant leakage or fluid movement into a
Wells
USDW,
CO2 Volume
68 mil ion
1.3 mil ion total
Continuous monitoring of CO2 injection pressure,
Injected
tons/year (as of
(one project in IL
2014)
[2019 data])
Analysis of CO2 stream characteristics,
SDWA Primacy
40
1
Testing and monitoring of the underground CO2 plume
States
and pressure front,
(16 under §1422
24 under §1425)
Periodic monitoring of ground water quality above the
Notes: Number of permitted EOR wells is approximate and based
confining zone(s), and
on 2018 EPA data. CO2 volume based on most recent data available.
More frequent (semi-annual) reporting of testing and
SDWA = Safe Drinking Water Act.
monitoring data and reporting of more specific
Selected Differences in EPA Regulation
information on the CO2 stream and pressure.
For Class II EOR wells, under UIC regulations (40 C.F.R.
Select EPA post-injection requirements for GS wells only:
§§144-147), all new wells require a permit and are subject
Continuous monitoring of the underground CO2 plume
to permitting standards for construction, operation, financial
and pressure front, and
responsibility, mechanical integrity, and corrective action.
Pre-existing EOR wells, in contrast, are generally
Post-injection site care for 50 years after injection.
authorized by rule for the lifetime of the project and must
Transition from Class II EOR to Class VI GS Wells
follow EPA regulatory requirements for reporting, casing
To protect USDWs from injected CO
and cementing, monitoring, well plugging and
2 or movement of
other fluids in an underground formation, EOR wells must
abandonment, and financial responsibility. EPA guidance
transition to Class VI GS wells under certain conditions (40
recommends that rule-authorized EOR well operations be
CFR §144.19). Class II well owners or operators who inject
reviewed every five years.
CO2 primarily for long-term storage (rather than oil
production) must obtain a Class VI permit when there is an
In 1981, EPA issued guidance for states seeking Section
increased risk to USDWs compared to prior Class II
1425 primacy regarding permitting, technical criteria, and
operations using CO
enforcement mechanisms. These are not regulatory
2. The Class VI program director (EPA
or primacy state) determines whether a Class VI permit is
requirements, as Section 1425 gives states significant
required based on site-specific risk factors associated with
discretion in implementing their own Class II programs.
USDW endangerment. No transition has yet been required.
Regulations for Class VI GS wells require individual
Greenhouse Gas Emissions Reporting Rule
permits (40 C.F.R. §§146.81-146.95). The regulations
EOR and GS wells are subject to different regulatory
specify requirements and technical standards to prevent
requirements under EPA’s Greenhouse Gas Reporting
CO2 leaks that could endanger USDWs under conditions
Program. Under Subpart RR of the program rule (40 C.F.R.
unique to permanent sequestration. Because of differences
§98), GS well permit holders must report the amount of
in CO2 injection characteristics and the potential impact on
CO2 sequestered; develop and implement a monitoring,
USDWs, Class VI regulations include more specific and
reporting, and verification plan to verify sequestration; and
more comprehensive permitting, construction, operating,
collect data on CO2 surface emissions from the operation.
and closure requirements than do EPA Class II
Subpart UU of the rule, which applies to EOR wells,
requirements.
requires permit holders to report the amount and source of
CO2 received (rather than injected).
Examples of EPA permitting requirements for GS wells,
which are not required for EOR wells, include:
Angela C. Jones, Analyst in Environmental Policy
IF11578
https://crsreports.congress.gov
CO2 Underground Injection Regulations: Selected Differences for Enhanced Oil Recovery and Geologic Sequestration
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 connection with CRS’s institutional role. CRS Reports, as a work of the
United States Government, are not subject to copyright protection in the United States. Any CRS Report may be
reproduced and distributed in its entirety without permission from CRS. However, as a CRS Report may include
copyrighted images or material from a third party, you may need to obtain the permission of the copyright holder if you
wish to copy or otherwise use copyrighted material.
https://crsreports.congress.gov | IF11578 · VERSION 2 · NEW