[Federal Register: July 25, 2008 (Volume 73, Number 144)]
[Proposed Rules]
[Page 43491-43541]
[DOCID:fr25jy08-20]

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Part II

Environmental Protection Agency

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40 CFR Parts 144 and 146

Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO2) Geologic Sequestration (GS)
Wells; Proposed Rule

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 144 and 146

[EPA-HQ-OW-2008-0390 FRL-8695-3]
RIN 2040-AE98

Federal Requirements Under the Underground Injection Control
(UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS)
Wells

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing Federal requirements under the Safe Drinking
Water Act (SDWA) for underground injection of carbon dioxide
(CO2) for the purpose of geologic sequestration (GS). GS is
one of a portfolio of options that could be deployed to reduce
CO2 emissions to the atmosphere and help to mitigate climate
change. This proposal applies to owners or operators of wells that will
be used to inject CO2 into the subsurface for the purpose of
long-term storage. It proposes a new class of well and minimum
technical criteria for the geologic site characterization, fluid
movement, area of review (AoR) and corrective action, well
construction, operation, mechanical integrity testing, monitoring, well
plugging, post-injection site care, and site closure for the purposes
of protecting underground sources of drinking water (USDWs). The
elements of this proposal are based on the existing Underground
Injection Control (UIC) regulatory framework, with modifications to
address the unique nature of CO2 injection for GS. If
finalized, this proposal would help ensure consistency in permitting
underground injection of CO2 at GS operations across the
U.S. and provide requirements to prevent endangerment of USDWs in
anticipation of the eventual use of GS to reduce CO2
emissions.

DATES: Comments must be received on or before November 24, 2008. A
public hearing will be held during the public comment period in
September 2008. EPA will notify the public of the date, time and
location of a public hearing in a separate Federal Register notice.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OW-
2008-0390, by one of the following methods:
     www.regulations.gov: Follow the on-line instructions for
submitting comments.
     Mail: Water Docket, Environmental Protection Agency,
Mailcode: 2822T, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
     Hand Delivery: Water Docket, EPA Docket Center (EPA/DC)
EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. Such
deliveries are only accepted during the Docket's normal hours of
operation, and special arrangements should be made for deliveries of
boxed information.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OW-2008-
0390. EPA's policy is that all comments received will be included in
the public docket without change and may be made available online at
http://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected, through http://
www.regulations.gov or e-mail. The http://www.regulations.gov Web site
is an ``anonymous access'' system, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an e-mail comment directly to EPA without
going through www.regulations.gov your e-mail address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet. If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit. If EPA cannot read your comment due to
technical difficulties and cannot contact you for clarification, EPA
may not be able to consider your comment. Electronic files should avoid
the use of special characters, any form of encryption, and be free of
any defects or viruses.
    Docket: All documents in the docket are listed in the http://
www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in www.regulations.gov or in hard copy at the Water Docket, EPA/DC, EPA
West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The
Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is<PHONE_NUMBER>, and the telephone number for the EPA
Docket Center is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Lee Whitehurst, Underground Injection
Control Program, Drinking Water Protection Division, Office of Ground
Water and Drinking Water (MC-4606M), Environmental Protection Agency,
1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone number:
(202) 564-3896; fax number:<PHONE_NUMBER>; e-mail address:
<EMAIL_ADDRESS>For general information, contact the Safe
Drinking Water Hotline, telephone number:<PHONE_NUMBER>. The Safe
Drinking Water Hotline is open Monday through Friday, excluding legal
holidays, from 10 a.m. to 4 p.m. Eastern time.

SUPPLEMENTARY INFORMATION:

I. General Information

    This is a proposed regulation. If finalized, these regulations
would affect owners or operators of injection wells that will be used
to inject CO2 into the subsurface for the purposes of GS.
Regulated categories and entities would include, but are not limited
to, the following:

------------------------------------------------------------------------
                Category                  Examples of regulated entities
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Private................................  Operators of CO2 injection
                                          wells used for GS.
------------------------------------------------------------------------

    This table is not intended to be an exhaustive list, but rather
provides a guide for readers regarding entities likely to be regulated
by this action. This table lists the types of entities that EPA is now
aware could potentially be regulated by this action. Other types of
entities not listed in the table could also be regulated. To determine
whether your facility is regulated by this action, you should carefully
examine the applicability criteria found in 146.81 of this proposed
rule. If you have questions regarding the applicability of this action
to a particular entity, consult the person listed in the preceding FOR
FURTHER INFORMATION CONTACT section.

Abbreviations and Acronyms

AASG American Association of State Geologists
AoR Area of Review
API American Petroleum Institute
CaCO3 Calcium Carbonate
CAA Clean Air Act
CCS Carbon Capture and Storage
CERCLA Comprehensive Environmental Response, Compensation, and
Liability Act
CO2 Carbon Dioxide
CSLF Carbon Sequestration Leadership Forum
DOE Department of Energy

ECBM Enhanced Coal Bed Methane
EFAB Environmental Finance Advisory Board
EGR Enhanced Gas Recovery
EM Electromagnetic
EOR Enhanced Oil Recovery
EPA Environmental Protection Agency
ERT Electrical Resistance Tomography
FACA Federal Advisory Committee Act
GHGs Greenhouse Gases
GS Geologic Sequestration
GWPC Ground Water Protection Council
H2S Hydrogen Sulfide
ICR Information Collection Request
IEA International Energy Agency
IOGCC Interstate Oil and Gas Compact Commission
IPCC Intergovernmental Panel on Climate Change
LBNL Lawrence Berkeley National Laboratory
LIDAR Light Detection and Ranging
MI Mechanical Integrity
MIT Mechanical Integrity Test
MMT Million Metric Tons
MMV Monitoring, Measurement, and Verification
MPRSA Marine Protection, Research, and Sanctuaries Act
NDWAC National Drinking Water Advisory Council
NETL National Energy Technology Laboratory
NGOs Non-Governmental Organizations
NODA Notice of Data Availability
NPDWR National Primary Drinking Water Regulations
NTTAA National Technology Transfer and Advancement Act
OIRA Office of Information and Regulatory Affairs
OMB Office of Management and Budget
O&M Operation and Maintenance
ORD Office of Research and Development
NOX Nitrogen Oxides
PFC Perfluorocarbon
PNNL Pacific Northwest National Laboratory
PRA Paperwork Reduction Act
PVT Pressure-Volume-Temperature
PWS Public Water Supply
RA Regulatory Alternative
RCRA Resource Conservation and Recovery Act
RCSP Regional Carbon Sequestration Partnerships
RFA Regulatory Flexibility Act
SACROC Scurry Area Canyon Reef Operators Committee
SBREFA Small Business Regulatory Enforcement Fairness Act
SDWA Safe Drinking Water Act
SOX Sulfur Oxides
TDS Total Dissolved Solids
UIC Underground Injection Control
UICPG83 Underground Injection Control Program Guidance
 83
UMRA Unfunded Mandates Reform Act
USDW Underground Source of Drinking Water
VEF Vulnerability Evaluation Framework

Definitions

    Annulus: The space between the well casing and the wall of the bore
hole; the space between concentric strings of casing; space between
casing and tubing.
    Area of review (AoR): The region surrounding the geologic
sequestration project that may be impacted by the injection activity.
The area of review is based on computational modeling that accounts for
the physical and chemical properties of all phases of the injected
carbon dioxide stream.
    Ball valve: A valve consisting of a hole drilled through a ball
placed in between two seals. The valve is closed when the ball is
rotated in the seals so the flow path no longer aligns with the well
casing.
    Buoyancy: Upward force on one phase (e.g., a fluid) produced by the
surrounding fluid (e.g., a liquid or a gas) in which it is fully or
partially immersed, caused by differences in pressure or density.
    Capillary force: Adhesive force that holds a fluid in a capillary
or a pore space. Capillary force is a function of the properties of the
fluid, and surface and dimensions of the space. If the attraction
between the fluid and surface is greater than the interaction of fluid
molecules, the fluid will be held in place.
    Caprock: See confining zone.
    Carbon Capture and Storage (CCS): The process of capturing
CO2 from an emission source, (typically) converting it to a
supercritical state, transporting it to an injection site, and
injecting it into deep subsurface rock formations for long-term
storage.
    Carbon dioxide plume: The extent underground, in three dimensions,
of an injected carbon dioxide stream.
    Carbon dioxide (CO2) stream: Carbon dioxide that has
been captured from an emission source (e.g., a power plant), plus
incidental associated substances derived from the source materials and
the capture process, and any substances added to the stream to enable
or improve the injection process. This subpart does not apply to any
carbon dioxide stream that meets the definition of a hazardous waste
under 40 CFR Part 261.
    Casing: The pipe material placed inside a drilled hole to prevent
the hole from collapsing. The two types of casing in most injection
wells are (1) surface casing, the outer-most casing that extends from
the surface to the base of the lowermost USDW and (2) long-string
casing, which extends from the surface to or through the injection
zone.
    Cement: Material used to support and seal the well casing to the
rock formations exposed in the borehole. Cement also protects the
casing from corrosion and prevents movement of injectate up the
borehole. The composition of the cement may vary based on the well type
and purpose; cement may contain latex, mineral blends, or epoxy.
    Confining zone: A geologic formation, group of formations, or part
of a formation stratigraphically overlying the injection zone that acts
as a barrier to fluid movement.
    Corrective action: The use of Director approved methods to assure
that wells within the area of review do not serve as conduits for the
movement of fluids into underground sources of drinking water (USDWs).
    Corrosive: Having the ability to wear away a material by chemical
action. Carbon dioxide mixed with water forms carbonic acid, which can
corrode well materials.
    Dip: The angle between a planar feature, such as a sedimentary bed
or a fault, and the horizontal plane. The dip of subsurface rock layers
can provide clues as to whether injected fluids may be contained.
    Director: The person responsible for permitting, implementation,
and compliance of the UIC program. For UIC programs administered by
EPA, the Director is the EPA Regional Administrator; for UIC programs
in Primacy States, the Director is the person responsible for
permitting, implementation, and compliance of the State, Territorial,
or Tribal UIC program.
    Ductility: The ability of a material to sustain stress until it
fractures.
    Enhanced Coal Bed Methane (ECBM) recovery: The process of injecting
a gas (e.g., CO2) into coal, where it is adsorbed to the
coal surface and methane is released. The methane can be captured and
produced for economic purposes; when CO2 is injected, it
adsorbs to the surface of the coal, where it remains sequestered.
    Enhanced Oil or Gas Recovery (EOR/EGR): Typically, the process of
injecting a fluid (e.g., water, brine, or CO2) into an oil
or gas bearing formation to recover residual oil or natural gas. The
injected fluid thins (decreases the viscosity) or displaces small
amounts of extractable oil and gas, which is then available for
recovery. This is also known as secondary or tertiary recovery.
    Flapper valve: A valve consisting of a hinged flapper that seals
the valve orifice. In GS wells, flapper valves can engage to shut off
the flow of the CO2 when acceptable operating parameters are
exceeded.
    Formation or geological formation: A layer of rock that is made up
of a certain type of rock or a combination of types.
    Geologic sequestration (GS): The long-term containment of a
gaseous, liquid or supercritical carbon dioxide stream in

subsurface geologic formations. This term does not apply to its capture
or transport.
    Geologic sequestration project: An injection well or wells used to
emplace a CO2 stream beneath the lowermost formation
containing a USDW. It includes the subsurface three-dimensional extent
of the carbon dioxide plume, associated pressure front, and displaced
brine, as well as the surface area above that delineated region.
    Geophysical surveys: The use of geophysical techniques (e.g.,
seismic, electrical, gravity, or electromagnetic surveys) to
characterize subsurface rock formations.
    Injectate: The fluids injected. For the purposes of this rule, this
is also known as the CO2 stream.
    Injection zone: A geologic formation, group of formations, or part
of a formation that is of sufficient areal extent, thickness, porosity,
and permeability to receive carbon dioxide through a well or wells
associated with a geologic sequestration project.
    Lithology: The description of rocks, based on color, mineral
composition and grain size.
    Mechanical integrity (MI): The absence of significant leakage
within the injection tubing, casing, or packer (known as internal
mechanical integrity), or outside of the casing (known as external
mechanical integrity).
    Mechanical Integrity Test (MIT): A test performed on a well to
confirm that a well maintains internal and external mechanical
integrity. MITs are a means of measuring the adequacy of the
construction of an injection well and a way to detect problems within
the well system before leaks occur.
    Model: A representation or simulation of a phenomenon or process
that is difficult to observe directly or that occurs over long time
frames. Models that support GS can predict the flow of CO2
within the subsurface, accounting for the properties and fluid content
of the subsurface formations and the effects of injection parameters.
    Packer: A mechanical device set immediately above the injection
zone that seals the outside of the tubing to the inside of the long
string casing.
    Pinch-out: The location where a porous, permeable formation that is
located between overlying and underlying confining formations thins to
a zero thickness, and the confining formations are in contact with each
other.
    Pore space: Open spaces in rock or soil. These are filled with
water or other fluids such as brine (i.e., salty fluid). CO2
injected into the subsurface can displace pre-existing fluids to occupy
some of the pore spaces of the rocks in the injection zone.
    Post-injection site care: Appropriate monitoring and other actions
(including corrective action) needed following cessation of injection
to assure that USDWs are not endangered as required under Sec.  146.93.
    Pressure front: The zone of elevated pressure that is created by
the injection of carbon dioxide into the subsurface. For GS projects,
the pressure front of a CO2 plume refers to the zone where
there is a pressure differential sufficient to cause the movement of
injected fluids or formation fluids into a USDW.
    Saline formations: Deep and geographically extensive sedimentary
rock layers saturated with waters or brines that have a high total
dissolved solids (TDS) content (i.e., over 10,000 mg/L TDS). Saline
formations offer great potential CO2 storage capacity.
    Shut-off device: A valve coupled with a control device which closes
the valve when a set pressure or flow value is exceeded. Shut-off
devices in injection wells can automatically shut down injection
activities when operating parameters unacceptably diverge from
permitted values.
    Site closure: The point/time, as determined by the Director
following the requirements under Sec.  146.93, at which the owner or
operator of a GS site has completed their post-injection site care
responsibilities.
    Sorption (absorption, adsorption): Absorption refers to gases or
liquids being incorporated into a material of a different state;
adsorption is the adhering of a molecule or molecules to the surface of
a different molecule.
    Stratigraphic zone (unit): A layer of rock (or stratum) that is
recognized as a unit based on lithology, fossil content, age or other
properties.
    Supercritical fluid: A fluid above its critical temperature (31.1
[deg]C for CO2) and critical pressure (73.8 bar for
CO2). Supercritical fluids have physical properties
intermediate to those of gases and liquids.
    Total Dissolved Solids (TDS): The measurement, usually in mg/L, for
the amount of all inorganic and organic substances suspended in liquid
as molecules, ions, or granules. For injection operations, TDS
typically refers to the saline (i.e., salt) content of water-saturated
underground formations.
    Transmissive fault or fracture: A fault or fracture that has
sufficient permeability and vertical extent to allow fluids to move
between formations.
    Trapping: The physical and geochemical processes by which injected
CO2 is sequestered in the subsurface. Physical trapping
occurs when buoyant CO2 rises in the formation until it
reaches a layer that inhibits further upward migration or is
immobilized in pore spaces due to capillary forces. Geochemical
trapping occurs when chemical reactions between dissolved
CO2 and minerals in the formation lead to the precipitation
of solid carbonate minerals.
    Underground Source of Drinking Water (USDW): An aquifer or portion
of an aquifer that supplies any public water system or that contains a
sufficient quantity of ground water to supply a public water system,
and currently supplies drinking water for human consumption, or that
contains fewer than 10,000 mg/l total dissolved solids and is not an
exempted aquifer.
    Viscosity: The property of a fluid or semi-fluid that offers
resistance to flow. As a supercritical fluid, CO2 is less
viscous than water and brine.

Table of Contents

I. General Information
II. What Is EPA Proposing?
    A. Why Is EPA Proposing To Develop New Regulations To Address GS
of CO2?
    B. What Is EPA's Authority Under the SDWA To Regulate Injection
of CO2?
    C. Who Implements the UIC Program?
    D. What Are the Risks Associated With CO2 GS?
    E. What Steps Has EPA Taken To Inform This Proposal?
    F. Why Is EPA Proposing To Develop a New Class of Injection Well
for GS of CO2?
    G. How Would This Proposal Affect Existing Injection Wells Under
the UIC Program?
    H. What Are the Target Geologic Formations for GS of
CO2?
    I. Is Injected CO2 Considered a Hazardous Waste Under
RCRA?
    J. Is Injected CO2 Considered a Hazardous Substance
Under CERCLA?
III. Proposed Regulatory Alternative
    A. Proposed Alternative
    1. Proposed Geologic Siting Requirements
    2. Proposed Area of Review and Corrective Action Requirements
    3. Proposed Injection Well Construction Requirements
    4. Proposed Injection Well Operating Requirements
    5. Proposed Mechanical Integrity Testing Requirements
    6. Proposed Plume and Pressure Front Monitoring Requirements
    7. Proposed Recordkeeping and Reporting Requirements
    8. Proposed Well Plugging, Post-Injection Site Care, and Site
Closure Requirements
    9. Proposed Financial Responsibility and Long-term Care
Requirements
    B. Adaptive Approach

IV. How Should UIC Program Directors Involve the Public in
Permitting Decisions for GS Projects?
V. How Will States, Territories, and Tribes Obtain UIC Program
Primacy for Class VI Wells?
VI. What Is the Proposed Duration of a Class VI Injection Permit?
VII. Cost Analysis
    A. National Benefits and Costs of the Proposed Rule
    B. Comparison of Benefits and Costs of Regulatory Alternatives
of the Proposed Rule
    C. Conclusions
VIII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act (PRA)
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
IX. References

II. What Is EPA Proposing?

    EPA is proposing to create a new category of injection well under
its existing Underground Injection Control (UIC) Program with new
Federal requirements to allow for permitting of the injection of
CO2 for the purpose of GS. Today's proposal builds on
existing UIC regulatory components for key areas including siting,
construction, operation, monitoring and testing, and closure for
injection wells that address the pathways through which underground
sources of drinking water (USDWs) may be endangered. The Agency
proposes to tailor existing UIC program components so that they are
appropriate for the unique nature of injecting large volumes of
CO2 into a variety of geological formations to ensure that
USDWs are not endangered.
    In addition to protecting USDWs, today's proposed rule provides a
regulatory framework to promote consistent approaches to permitting GS
projects across the U.S. and supports the development of a key climate
change mitigation technology.
    This proposal does not require any facilities to capture and/or
sequester CO2; rather, this proposal focuses on underground
injection of CO2 and outlines requirements that, if
finalized, would protect USDWs under the SDWA. The SDWA provides EPA
with the authority to develop regulations to protect USDWs. The SDWA
does not provide authority to develop regulations for all areas related
to GS. These areas include, but are not limited to, capture and
transport of CO2; determining property rights (i.e., to
permit its use for GS and for possible storage credits); transfer of
liability from one entity to another; and accounting or certification
for greenhouse gas (GHG) reductions. EPA is not proposing regulations
for CO2 under the Clean Air Act (CAA) in this proposed
rulemaking.

A. Why Is EPA Proposing To Develop New Regulations To Address GS of
CO2?

1. What Is Geologic Sequestration (GS)?
    GS is the process of injecting CO2 captured from an
emission source (e.g., a power plant or industrial facility) into deep
subsurface rock formations for long-term storage. It is part of a
process known as ``carbon capture and storage'' or CCS.
    CO2 is first captured from fossil-fueled power plants or
other emission sources. To transport captured CO2 for GS,
operators typically compress CO2 to convert it from a
gaseous state to a supercritical fluid (IPCC, 2005). CO2
exists as a supercritical fluid at high pressures and temperatures, and
in this state it exhibits properties of both a liquid and a gas. After
capture and compression, the CO2 is delivered to the
sequestration site, typically by pipeline, or alternatively using
tanker trucks or ships (WRI, 2007).
    The CO2 is then injected into deep subsurface rock
formations via one or more wells, using technologies that have been
developed and refined by the oil and gas and chemical manufacturing
industries over the past several decades. To store the CO2
as a supercritical fluid, it would likely be injected at a depth
(greater than approximately 800 meters, or 2,625 feet), such that a
sufficiently high pressure and temperature would be maintained to keep
the CO2 in a supercritical state.
    When injected in an appropriate receiving formation, CO2
is sequestered by a combination of trapping mechanisms, including
physical and geochemical processes. Physical trapping occurs when the
relatively buoyant CO2 rises in the formation until it
reaches a stratigraphic zone with low fluid permeability (i.e.,
geologic confining system) that inhibits further upward migration.
Physical trapping can also occur as residual CO2 is
immobilized in formation pore spaces as disconnected droplets or
bubbles at the trailing edge of the plume due to capillary forces. A
portion of the CO2 will dissolve from the pure fluid phase
into native ground water and hydrocarbons. Preferential sorption occurs
when CO2 molecules attach onto the surfaces of coal and
certain organic-rich shales, displacing other molecules such as
methane. Geochemical trapping occurs when chemical reactions between
the dissolved CO2 and minerals in the formation lead to the
precipitation of solid carbonate minerals (IPCC, 2005). The timeframe
over which CO2 will be trapped by these mechanisms depends
on properties of the receiving formation and the injected
CO2 stream. Current research is focused on better
understanding these mechanisms and the time required to trap
CO2 under various conditions.
    The effectiveness of physical CO2 trapping is
demonstrated by natural analogs worldwide in a range of geologic
settings, where CO2 has remained trapped for millions of
years. For example, CO2 has been trapped for more than 65
million years under the Pisgah Anticline, northeast of the Jackson Dome
in Mississippi and Louisiana, with no evidence of leakage from the
confining formation (IPCC, 2005).
2. Why Is Geologic Sequestration Under Consideration as a Climate
Change Mitigation Technology?
    Greenhouse gases (GHGs) perform the necessary function of keeping
the planet's surface warm enough for human habitation. But, the
concentrations of GHGs continue to increase in the atmosphere, and
according to data from the National Oceanic and Atmospheric
Administration (NOAA) and National Aeronautics and Space Administration
(NASA), the Earth's average surface temperature has increased by about
1.2 to 1.4 [deg]F in the last 100 years. Eleven of the last twelve
years rank among the twelve warmest years on record (since 1850), with
the two warmest years being 1998 and 2005. The Intergovernmental Panel
on Climate Change (IPCC) has concluded that much of the warming in
recent decades is very likely the result of human activities (IPCC,
2007). The burning of fossil fuels (e.g., from coal-fired electric
plants and other sources in the electricity and industrial sectors) is
a major contributor to human-induced greenhouse gas emissions.
    Fossil fuels are expected to remain the mainstay of energy
production well into the 21st century, and increased concentrations of
CO2 are expected unless energy producers reduce the
CO2 emissions to the atmosphere. 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 alternative energy sources
are developed in the coming decades. Given the United States' abundant
coal resources and reliance on coal for power generation, CCS could be
a key mitigation technology for achieving domestic emissions
reductions.
    Estimates based on DOE and IEA studies indicate that areas of the
U.S. with appropriate geology could theoretically provide storage
potential for over 3,000 gigatons (or 3,000,000 megatons; Mt) of
geologically sequestered CO2. Theoretically, this capacity
could be large enough to store a thousand years of CO2
emissions from nearly 1,000 coal-fired power plants. Worldwide, there
appears to be significant capacity in subsurface formations both on
land and under the seafloor to sequester CO2 for hundreds,
if not thousands of years. CCS technologies could potentially represent
a significant percentage of the cumulative effort for reducing
CO2 emissions worldwide.
    While predictions about large-scale availability and the rate of
CCS project deployment are subject to considerable uncertainty, EPA
analyses of Congressional climate change legislative proposals (the
McCain-Lieberman bill S. 280, the Bingaman-Specter bill S. 1766, and
the Lieberman-Warner bill S. 2191) indicate that CCS has the potential
to play a significant role in climate change mitigation scenarios. For
example, analysis of S. 2191 indicates that CCS technology could
account for 30 percent of CO2 emission reductions in 2050
(USEPA, 2008a). It is important to note that GS is only one of a
portfolio of options that could be deployed to reduce CO2
emissions. Other options could include efficiency improvements and the
use of alternative fuels and renewable energy sources. Today's proposal
provides a regulatory framework to protect USDWs as this key climate
mitigation technology is developed and deployed. This proposal provides
certainty to industry and the public about requirements that would
apply to injection, by providing consistency in requirements across the
U.S., and transparency about what requirements apply to owners or
operators.
    Establishing a supporting regulatory framework for the future
development and deployment of CCS technology can provide the regulatory
certainty needed to foster industry adoption of CCS, which is crucial
to supporting the goals of any proposed climate change legislation.
This proposed rule is consistent with and supports a strategy to
address climate change through: (1) Slowing the growth of emissions;
(2) strengthening science, technology and institutions; and (3)
enhancing international cooperation. EPA plays a significant role in
implementing this strategy through encouraging voluntary GHG emission
reductions, and working with other agencies, including DOE, to
establish programs that promote climate technology and science.

B. What Is EPA's Authority Under the SDWA To Regulate Injection of CO2?

    Underground injection wells are regulated under the authority of
Part C of the Safe Drinking Water Act (42 U.S.C. 300h et seq.). The
SDWA is designed to protect the quality of drinking water sources in
the U.S. and prescribes that EPA issue regulations for State programs
that contain ``minimum requirements for effective programs to prevent
underground injection which endangers drinking water sources.''
Congress further defined endangerment as follows:

    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 regulation or may otherwise adversely affect the
health of persons (Section 1421(d)(2) of the SDWA, 42 U.S.C.
300h(d)(2)).

    Under this authority, the Agency has promulgated a series of UIC
regulations at 40 CFR parts 144 through 148. The chief goal of any
federally approved UIC Program (whether administered by a State,
Territory, Tribe or EPA) is the protection of USDWs. This includes not
only those formations that are presently being used for drinking water,
but also those that can reasonably be expected to be used in the
future. EPA has established through its UIC regulations that USDWs are
underground aquifers with less than 10,000 milligrams per liter (mg/L)
total dissolved solids (TDS) and which contain a sufficient quantity of
ground water to supply a public water system (40 CFR 144.3). Section
1421(b)(3)(A) of the Act also provides that EPA's UIC regulations shall
``permit or provide for consideration of varying geologic,
hydrological, or historical conditions in different States and in
different areas within a State.''
    EPA promulgated administrative and permitting regulations, now
codified in 40 CFR Parts 144 and 146, on May 19, 1980 (45 FR 33290),
and technical requirements, in 40 CFR Part 146, on June 24, 1980 (45 FR
42472). The regulations were subsequently amended on August 27, 1981
(46 FR 43156), February 3, 1982 (47 FR 4992), January 21, 1983 (48 FR
2938), April 1, 1983 (48 FR 14146), May 11, 1984 (49 FR 20138), July
26, 1988 (53 FR 28118), December 3, 1993 (58 FR 63890), June 10, 1994
(59 FR 29958), December 14, 1994 (59 FR 64339), June 29, 1995 (60 FR
33926), December 7, 1999 (64 FR 68546), May 15, 2000 (65 FR 30886),
June 7, 2002 (67 FR 39583), and November 22, 2005 (70 FR 70513). EPA's
authority to regulate GS was further clarified under the Energy
Independence and Security Act of 2007, which stated that all
regulations must be consistent with the requirements of the SDWA.
    Under the SDWA, the injection of any ``fluid'' is subject to the
requirements of the UIC program. ``Fluid'' is defined under 40 CFR
144.3 as any material or substance which flows or moves whether in a
semisolid, liquid, sludge, gas or other form or state, and includes the
injection of liquids, gases, and semisolids (i.e., slurries) into the
subsurface. Examples of the fluids currently injected into wells
include CO2 for the purposes of enhancing recovery of oil
and natural gas, water that is stored to meet water supply demands in
dry seasons, and wastes generated by industrial users. CO2
injected for the purpose of GS is subject to the SDWA (42 U.S.C. 300f
et seq.). EPA regulates both pollutants and commodities under the UIC
provisions; however, today's proposal does not address the status of
CO2 as a pollutant or commodity. In addition, whether or not
a fluid could be sold on the market as a commodity is outside the scope
of EPA's authority under the SDWA to protect USDWs.
    There are limited injection activities that are exempt from UIC
requirements including the storage of natural gas (Section
1421(b)(2)(B)) and specific hydraulic fracturing fluids. This exclusion
applies to the storage of natural gas as it is commonly defined--a
hydrocarbon--and not to injection of other matter in a gaseous state
such as CO2. The Energy Policy Act of 2005 excluded ``the
underground injection of fluids or other propping agents (other than
diesel fuels) pursuant to hydraulic fracturing operations related to
oil, gas, or geothermal producing activities.'' A more detailed summary
of EPA's authority to regulate the injection of CO2 can be
found in the docket.
    Other authorities: Today's proposal applies to injection wells in
the U.S. including those in State territorial

waters. Wells up to three miles offshore may be subject to other
authorities or may require approval under other authorities such as the
Marine Protection, Research, and Sanctuaries Act (MPRSA). EPA recently
submitted to Congress proposed changes to MPRSA to implement the 1996
Protocol to the London Convention on ocean dumping (the ``London
Protocol''). Among the proposed changes is a provision to allow for and
regulate carbon sequestration in sub-seabed geological formations under
the MPRSA.

C. Who Implements the UIC Program?

    Section 1422 of the SDWA provides that States, Territories and
federally recognized Tribes may apply to EPA for primary enforcement
responsibility to administer the UIC program; those governments
receiving such authority are referred to as ``Primacy States.'' Section
1422 requires Primacy States to meet EPA's minimum Federal requirements
for UIC programs, including construction, operating, monitoring and
testing, reporting, and closure requirements for well owners or
operators. Where States, Territories, and Tribes do not seek this
responsibility or fail to demonstrate that they meet EPA's minimum
requirements, EPA is required to implement a UIC program for them by
regulation.
    Additionally, section 1425 allows States, Territories, and Tribes
seeking primacy for Class II wells to demonstrate that their existing
standards are effective in preventing endangerment of USDWs. These
programs must include requirements for permitting, enforcement,
inspection, monitoring, recordkeeping, and reporting that demonstrate
the effectiveness of their requirements.
    Thirty-three States and three Territories currently have primacy to
implement the UIC program. EPA shares implementation responsibility
with seven States and directly implements the UIC Program for all well
classes in 10 states, two Territories, the District of Columbia, and
all Tribes. At the time of this proposal, no Tribes have been approved
for primacy for the UIC Program. However, at the time of this published
notice, Fort Peck Assiniboine and Sioux Tribes in EPA Region 8 and the
Navajo Nation in EPA Region 9 have pending primacy applications.
    Although EPA believes that the most effective approach for the
comprehensive management of CO2 GS projects would be
achieved at the State and Tribal level, it is recognized that some
injection activities may raise cross-state boundary issues that are
beyond the scope of this rulemaking. EPA is aware that some States with
primacy for the UIC program are actively engaged in the process of
developing their own regulatory frameworks for the GS of
CO2. In some cases, these frameworks include capture,
transportation and injection requirements. While EPA encourages States
to move forward with initiatives to protect USDWs and public health, it
is important to note that States wishing to retain UIC primacy will
need to promulgate regulations that are at least as stringent as those
that will ultimately be finalized following this proposed rulemaking.
In an attempt to reduce uncertainty in this proposed rulemaking, the
Agency will keep States apprised of its efforts to establish new
Federal UIC GS requirements.
    Additionally, EPA seeks comment on any aspects of the ongoing State
efforts to regulate the GS of CO2 and how these efforts
might be used to better inform a final Federal rulemaking.

D. What Are the Risks Associated With CO2 GS?

    An improperly managed GS project has the potential to endanger
USDWs. The factors that increase the risk of USDW contamination are
complex and can include improper siting, construction, operation and
monitoring of GS projects. Today's proposal addresses endangerment to
USDWs by establishing new Federal requirements for the proper
management of CO2 injection and storage. Risks to USDWs from
improperly managed GS projects can include CO2 migration
into USDWs, causing the leaching and mobilization of contaminants
(e.g., arsenic, lead, and organic compounds), changes in regional
groundwater flow, and the movement of saltier formation fluids into
USDWs, causing degradation of water quality.
    While the focus of today's proposal is the protection of USDWs, EPA
recognizes that injection activities could pose additional risks that
are unrelated to the protection of USDWs including risks to air, human
health, and ecosystems. The measures taken to prevent migration of
CO2 to USDWs in today's proposal will likely also prevent
the migration of CO2 to the surface. However, regulating
such surface/atmospheric releases of CO2 are outside the
scope of this proposal and SDWA authority. A more detailed discussion
follows.
Potential USDW Impacts
    Injected CO2 is likely to come in contact with water in
the formation fluids of the geologic formations into which it is
injected. When CO2 mixes with water it forms a weak acid
known as carbonic acid. Over time, carbonic acid could acidify
formation waters potentially causing leaching and mobilization of
naturally occurring metals or other contaminants (e.g., arsenic, lead,
and organic compounds). CO2 may also release contaminants
into solution by replacing molecules that are sorbed to the surface of
the formation, for example, organic molecules such as polycyclic
aromatic hydrocarbons (PAHs) in coal beds. The migration of formation
fluids containing mobilized contaminants could cause endangerment of
USDWs.
    Another concern for USDWs is the presence of impurities in the
CO2 stream. These impurities, although a relatively small
percentage of the total fluid, could include hydrogen sulfide and
sulfurous and nitrous oxides. Because of the volume of CO2
that could be injected, there may be a risk that co-contaminants in the
CO2 stream could endanger a USDW if the injectate migrates
into a USDW. Additionally, when fluids are injected in large
quantities, the potential exists for injection to force native brines
(naturally occurring salty water) into USDWs.
    Improperly operated injection activities may cause geomechanical
and/or geochemical effects which may deteriorate the integrity of the
initially intact caprock overlying a storage reservoir. For example,
injection of CO2 at high pressure could induce fracturing or
could open existing fractures, thereby increasing movement through the
caprock and enabling CO2 to migrate out of the storage
reservoir, and potentially into USDWs.
Other Potential Impacts
    Human Health: Improperly operated injection activities or
ineffective long-term storage could result in the release of injected
CO2 to the atmosphere, resulting in the potential to impact
human health and surrounding ecosystems under certain circumstances.
While CO2 is present normally in the atmosphere, at very
high concentrations and with prolonged exposure, CO2 can be
an asphyxiant. In addition, direct exposure to elevated levels of
CO2 can cause both chronic (e.g., increased breathing rate,
vision and hearing impairment) and acute health effects to humans and
animals. Wind speed and direction, topography and geographic location
can have a role in the severity of the human health impact of a
CO2 release.
    EPA considers that risk of asphyxiation and other chronic and

acute health effects from airborne exposure resulting from
CO2 injection activities (even in the case of leakage or
accidental exposure) is minimal. This finding is based on experience
gained in the oil and gas industry, experience from international GS
projects, and evaluations of large scale releases of naturally
occurring CO2.
    EPA collected information on the use of CO2 injection in
the oil and gas industry which has decades of experience in drilling
through highly pressurized formations and injecting CO2 for
the purpose of enhanced recovery. Internationally, CO2 has
been injected on very large scales at three sites: At Sleipner in the
North Sea, at In Salah in Algeria, and in the Weyburn Field in Alberta,
Canada (see section E.3 of this document). There have been no
documented cases of leakage from these projects, nor has there been
release and surface accumulation of CO2 such that
asphyxiation would have been possible.
    However, some CO2 releases from injection activity have
been documented. An example of a significant CO2 leak
occurred at Crystal Geyser, Utah. CO2 and water erupted from
an abandoned oil exploration well due to improper well plugging. This
well continues to erupt periodically and discharges 12,000 kilotons of
CO2 annually. Studies indicated that within a few meters of
the well, CO2 concentrations were below levels that could
adversely affect human health (Lewicki et al., 2006).
    EPA also evaluated the occurrence of natural discharges of
CO2 to determine whether such releases could be caused by
CO2 injection or whether injection could result in release
of similar magnitudes. Although natural underground CO2
reservoirs exist throughout the world in volcanically active areas,
there are very few instances of rapid discharge of large amounts of
CO2 to the surface (Lewicki et al., 2006). Unusually large
and rapid releases of CO2 from lake bottom storage
reservoirs occurred at Lake Nyos and Lake Monoun in Cameroon in the
1980s, causing asphyxiation. These catastrophic events stemmed from a
phenomenon known as ``limnic eruption.'' Prolonged high ambient
temperatures led to prolonged stratification that allowed naturally
occurring CO2 to slowly accumulate at the bottom of the
lakes over many years. Large volumes of CO2 escaped during
an abrupt lake turnover, possibly prompted by volcanic activity.
    While lake turnover can bring CO2 stored in the deepest
layers of lake water to the surface almost instantaneously, geologic
confining systems do not experience this type of rapid and complete
turnover. GS would store CO2 beneath many layers of rock
with a well-defined geologic confining system. Even if a geologic
confining system were compromised, any migration of CO2
towards the surface would not be analogous to a limnic eruption.
Pathways for CO2 leakage from geologic storage reservoirs
are generally conductive faults or fractures. In some cases
CO2 may spread diffusely through overlying rocks and soils
(Lewicki et al., 2006). None of these conditions is a likely conduit
for release of CO2 on the scale of the releases at Lakes
Nyos and Monoun.
    Ecosystem: Improperly operated CO2 injection activities
resulting in a release of CO2 to the atmosphere may have a
range of effects on exposed terrestrial and aquatic ecosystems. Due to
organisms' varied sensitivities to environmental and habitat changes,
certain organisms may be adversely affected at different CO2
exposure levels. Surface-dwelling animals, including mammals and birds,
could be affected similarly to humans when directly exposed to elevated
levels of CO2. The exposure could cause both chronic and
acute health effects depending on the concentration and duration of
exposure (Benson et al., 2002). Plants, while dependent upon
CO2 for photosynthesis, could also be adversely affected by
elevated CO2 levels in the soil because the CO2
will inhibit respiration (Vodnik et al., 2006). Soil acidity changes
resulting from increased CO2 concentrations may adversely
impact both plant (McGee and Gerlach, 1998) and soil dwelling organisms
(Benson et al., 2002). Elevated CO2 concentrations in
aquatic ecosystems can impede fish respiration resulting in suffocation
(Fivelstad et al., 2003), decrease pH to lethal levels and reduce the
calcification in shelled organisms, and may adversely affect
photosynthesis of some aquatic organisms (Turley et al., 2006). The
risk of adverse impacts to ecosystems from properly managed
CO2 injection activities is minimal.
    Seismic events: Improperly operated injection of CO2
could raise pressure in the formation, and if too high, injection
pressure could ``re-activate'' otherwise dormant faults, potentially
inducing seismic events (earthquakes). Rarely, small induced seismic
events have been associated with past injection. Before a Federal UIC
Program was formed, injection activities at the Rocky Mountain Arsenal
in Colorado from 1963 to 1968 induced measurable seismic activity. This
incident was the result of poor site characterization and well
operation and was among the primary drivers that prompted Congress to
pass legislation establishing the UIC Program. Recently, the IPCC
(2005) concluded that the risks of induced seismicity are low.
    Today's proposal contains safeguards to ensure that potential
endangerment to USDWs from CO2 injection is addressed before
the commencement of full-scale GS projects. While preventing releases
of CO2 to the atmosphere is not within the scope of this
proposal, today's proposed rulemaking also addresses the risks posed by
releases to the atmosphere by ensuring that injected CO2
remains in the confining formations. The measures outlined in today's
proposed rulemaking to prevent endangerment of USDWs may also prevent
migration of CO2 to the surface. A more complete discussion
of the potential risks posed by GS is in the Vulnerability Evaluation
Framework for Geologic Sequestration of Carbon Dioxide (VEF) (USEPA,
2008b).

E. What Steps Has EPA Taken To Inform This Proposal?

    EPA has taken a number of steps to support today's proposal
including: (1) Building on the experience of the UIC Program; (2)
identifying the risks to USDWs from GS activities; (3) tracking the
results on ongoing research; (4) identifying technical and regulatory
issues associated with pilot and full-scale GS projects; (5)
coordinating with stakeholders on the rulemaking process; and (6)
providing guidance and reviewing permits for initial pilot-scale
projects.
1. Building on the Existing UIC Program Framework To Specifically
Address CO2 Injection
    EPA's UIC regulations prohibit injection wells from causing ``the
movement of fluid containing any contaminant into an underground source
of drinking water, if the presence of that contaminant may cause a
violation of any primary drinking water regulation * * * or may
otherwise adversely affect the health of persons'' (40 CFR 144.12(a)).
The federal UIC Program has been implemented since 1980 and has
responsibility for managing over 800,000 injection wells. The
programmatic components of the UIC Program are designed to prevent
fluid movement into USDWs by addressing the potential pathways through
which injected fluids can migrate into USDWs. These programmatic
components are described in general below:
     Siting: EPA requires injection wells to be sited to inject
into a zone capable

of storing the fluid, and to inject below a confining system that is
free of known open faults or fractures that could allow upward fluid
movement that endangers USDWs.
     Area of Review (AoR) and Corrective Action: The Agency
requires examination of both the vertical and horizontal extent of the
area that will potentially be influenced by injection and storage
activities and identification of all artificial penetrations in the
area that may act as conduits for fluid movement into USDWs (e.g.,
active and abandoned wells) and, as needed, perform corrective action
to these open wells (i.e., artificial penetrations).
     Well Construction: EPA requires injection wells to be
constructed using well materials and cements that can withstand
injection of fluids over the anticipated life span of the project.
     Operation: Injection pressures must be monitored so that
fractures that could serve as fluid movement conduits are neither
propagated into the layers in which fluids are injected or initiated in
the confining systems above.
     Mechanical Integrity Testing (MIT): The integrity of the
injection well system must be monitored at an appropriate frequency to
provide assurance that the injection well is operating as intended and
is free of significant leaks and fluid movement in the well bore.
     Monitoring: Owners or operators must monitor the injection
activity using available technologies to verify the location of the
injected fluid, the pressure front, and demonstrate that injected
fluids are confined to intended storage zones (and, therefore,
injection activities are protective of USDWs).
     Well Plugging and Post-Injection Site Care: At the end of
the injection project, EPA requires injection wells to be plugged in a
manner that ensures that these wells will not serve as conduits for
future fluid movement into USDWs. Additionally, owners or operators
must monitor injection wells to ensure fluids in the storage zone do
not pose an endangerment to USDWs.
    Today's proposal builds upon these longstanding UIC programmatic
components and tailors them based on the current state of knowledge
about the injection of CO2 for GS purposes. The timeframes
involved in preparing and completing each of these components are, in
general, project specific (i.e., dependent upon regional geology;
location; cumulative injection volumes; additional state and local
requirements; industry specificity).
2. Identifying the Risks to USDWs From Injection of CO2
    The existing UIC program provides a foundation for designing a
regulatory framework for GS projects that prevents endangerment to
USDWs. The Agency has evaluated the risks of CO2 injection
to USDWs to determine how best to tailor the existing UIC regulations
to address the buoyant and viscous properties of CO2 and the
large volumes that could be injected.
    EPA developed the Vulnerability Evaluation Framework (VEF), an
analytical framework that identifies and offers approaches to evaluate
the potential for a GS project to experience CO2 leakage and
associated adverse impacts. The VEF is a high-level screening approach
that can be used to identify key GS system attributes that should be
evaluated further to establish site suitability and targeted monitoring
programs. The VEF is focused on the three main parts of GS systems: The
injection zone, the confining system, and the CO2 stream.
The VEF first identifies approaches to evaluate key geologic attributes
of GS systems that could influence vulnerability to leakage or pressure
changes. It then describes an approach to define the area that should
be evaluated for adverse impacts associated with leakage or pressure
changes. Finally, the VEF identifies receptors that could be adversely
impacted if leakage or pressure changes were to occur. The assessment
of vulnerabilities to leakage and pressure changes, and of the
potential impacts to receptors, is described in a series of detailed
decision-support flowcharts. (Some of the impacts addressed in the VEF,
e.g., to the atmosphere or ecological receptors, are outside of the
scope of today's proposal.) The VEF report (USEPA, 2008b) is included
in the docket for this proposed rulemaking.
    EPA and the Department of Energy (DOE) are jointly funding the
Lawrence Berkeley National Laboratory (LBNL) to study potential impacts
of CO2 injection on ground water aquifers and drinking water
sources. As part of the same study, LBNL is also assessing potential
changes in regional ground water flow, including displacement of pre-
existing saline water or hydrocarbons that could impact USDWs or other
resources. EPA and DOE are also jointly funding the Pacific Northwest
National Laboratory (PNNL) to perform technical analyses on conducting
site assessments, evaluating reservoir suitability, and modeling the
flow of injected CO2 in geologic formations.
3. Tracking the Results of CO2 GS Research Projects
    EPA is tracking the progress and results of national and
international GS research projects. DOE leads experimental field
research on GS in the U.S. in conjunction with the Regional Carbon
Sequestration Partnerships (RCSPs) program. Collectively, the seven
RCSPs represent regions encompassing 97 percent of coal-fired
CO2 emissions, 97 percent of industrial CO2
emissions, 96 percent of the total U.S. land mass, and nearly all the
GS sites in the U.S. potentially available for carbon storage.
Approximately 400 organizations, including State geologists, industry
and environmental organizations, and national laboratories are involved
with the RCSPs.
    DOE's 2007 Roadmap (DOE, 2007a) describes DOE-sponsored research
designed to gather data on the effectiveness and safety of
CO2 GS in various geologic settings through the RSCPs. The
Roadmap describes three phases of research, each of which builds upon
the previous phase. During the Characterization Phase (2003 to 2005),
the partnerships studied regionally-specific sequestration approaches
as well as potentially needed regulations and infrastructure
requirements for GS deployment. During the Validation Phase (2005-
2009), approximately 25 pilot tests will be performed to validate the
most promising GS technologies, evaluate regional CO2
repositories, and identify best management practices for future
deployment. During the Deployment Phase (2008-2017), the partnerships
will conduct large volume carbon storage tests to demonstrate that
large-scale CO2 injection and storage can be achieved safely
and economically. EPA will use the data collected from these projects
to support decisions in the final GS rule. Additional information on
DOE's research and the partnerships is available at http://
www.fossil.energy.gov/sequestration/partnerships/index.html.
    EPA is also communicating with other research organizations and
academic institutions conducting GS research. These institutions
include Princeton University, which has a research program for
assessing potential problems with degradation of well material from the
geologic sequestration of CO2, and the Massachusetts
Institute of Technology, which has a CCS program emphasizing safe and
effective future use of coal as a prime energy source.
    EPA is also monitoring the progress of international GS efforts.
Three projects of note are underway in the North Sea,

Algeria, and Canada, whose results are being used to inform today's
proposal.
    The Sleipner Project, located off the Norwegian coast in the North
Sea, is the first commercial scale GS project into a saline formation.
Approximately 1 Million tones (Mt) CO2 is removed annually
from the natural gas produced in the Sleipner West Gas Field and
injected approximately 800 m (2,625 ft) below the seabed. Injection
began in August 1996, and operators expect to store 20 Mt
CO2 over the expected 25-year life of the project.
Activities include baseline data gathering and evaluation, reservoir
characterization and simulation, assessment of the need and cost for
monitoring wells, and geophysical modeling. Seismic time-lapse surveys
have been used to monitor movement of the CO2 plume and
demonstrate effectiveness of the cap rock (IPCC, 2005).
    The In Salah Gas Project, in the central Saharan region of Algeria,
is the world's first large-scale CO2 storage project in a
gas reservoir. CO2 is stripped from natural gas produced
from the Krechba Field and re-injected via three horizontal injection
wells into a 1,800 meter-deep (5,906 ft) sandstone reservoir.
Approximately 1.2 Mt CO2 have been injected annually since
April 2004 and it is estimated that 17 Mt CO2 will be stored
over the life of the project. To characterize the site, 3-D seismic
surveys and well data have been used to map the field, identify deep
faults, establish a baseline, and conduct a risk assessment of storage
integrity. Monitoring at the site includes use of noble gas tracers,
pressure surveys, tomography, gravity baseline studies, microbiological
studies, four-dimensional seismic surveys, and geomechanical monitoring
(IPCC, 2005).
    Weyburn is an EOR project where the CO2 produced at a
coal gasification plant in Beulah, ND is piped to Weyburn in
southeastern Saskatchewan for EOR. Approximately 1.5 Mt CO2
are injected annually via a combination of vertical and horizontal
injection wells. It is expected that 20 Mt CO2 will be
stored in the field over the 20 to 25 year life of the CO2-
EOR project. The monitoring regime at the site includes high-resolution
seismic surveys and surface monitoring to determine any potential
leakage (IPCC, 2005). The conclusions of Phase I of the project are
that depleted oil and gas reservoirs from EOR operations are a
promising CO2 storage option and that 4-D seismic monitoring
is a valuable tool for plume tracking (IEA, 2005).
    Other ongoing GS projects include the Gorgon Gas Development
project, a deep saline formation project in Barrow Island, Western
Australia; the Otway (Australia) Project, where GS is taking place in a
saline formation within a depleted natural gas reservoir; the South
Quinshu Basin, China Enhanced Coalbed Methane (ECBM)/CO2
sequestration project; the CO2 SINK project in Ketzin,
Germany (a sandstone saline formation); and testing of CO2
GS in the Deccan Trap basalts of India.
4. Identifying Technical and Regulatory Issues Associated With
CO2 GS
    EPA has conducted a series of technical workshops with regulators,
industry, utilities, and technical experts to identify and discuss
questions relevant to the effective management of CO2 GS.
    EPA held a technical workshop on measurement, monitoring, and
verification that focused on the availability and utility of various
subsurface and near-surface monitoring techniques that may be
applicable to GS projects. This workshop, co-sponsored by the Ground
Water Protection Council (GWPC), took place in New Orleans, LA on
January 16, 2008.
    The Agency held a technical workshop on geological considerations
for siting and Area of Review (AoR) studies to discuss subsurface
geologic information needed to determine whether a site is appropriate
for GS; the role of artificial conduits in the AoR on siting decisions;
factors that affect the size and shape of the AoR; and corrective
actions to address wells in the AoR. Representatives of the RCSPs and
the Interstate Oil and Gas Compact Commission (IOGCC) presented their
experiences with pilot and experimental GS projects. This workshop took
place in Washington, DC on July 10 and 11, 2007.
    EPA also held a technical workshop on well construction and MIT
that included experimental research in the U.S. and Canada on wellbore
integrity and CO2-cement interactions, modeling, the impact
of wellbore integrity on GS site selection, and industry research on
well construction. This workshop was held in Albuquerque, New Mexico on
March 14, 2007, with participation from the International Energy
Association (IEA), an international organization evaluating technical
issues associated with CCS.
    EPA and DOE collaborated on the State Regulators' Workshop on GS of
CO2 to discuss and formulate the questions related to
CO2 injection that should be addressed in the development of
a GS management framework. At this workshop, held in conjunction with
the GWPC's UIC Technical meeting in San Antonio, Texas on January 24,
2007, participants identified a set of research questions on the
following topics: Site characterization, modeling, AoR, injection well
construction, MIT, monitoring, well plugging, post-injection site care,
site closure and liability and financial responsibility. The questions
they raised set the agenda for future technical workshops as well as
established the foundation for today's proposal.
    Participants at the International Symposium on Site
Characterization for CO2 Geological Storage, an EPA
sponsored meeting with LBNL, held in Berkeley, California on March 20-
22, 2006, discussed various aspects of site characterization and
selection of potential CO2 storage sites. The symposium
emphasized advances in the site characterization process, development
of measurement methods, identification of key site features and
parameters, and case studies.
    At a workshop on Risk Assessment for Geologic CO2
Storage, participants discussed the development of a risk assessment
framework to identify potential risks related to GS of CO2
and to consider relevant field experience that could be applicable to
injection and long-term storage of CO2. Some of the key
topics addressed at the workshop were: Abandoned wells, faults, and
groundwater displacement. This workshop, co-sponsored by GWPC, took
place in Portland, Oregon on September 28-29, 2005.
    On April 6-7, 2005, EPA held a workshop on Modeling and Reservoir
Simulation for Geologic Carbon Storage in Houston, Texas. The topics of
this workshop included: An assessment of the potential applications of
reservoir models and reservoir simulations to GS; use of models for
risk assessments and risk communication throughout the life cycle of a
CO2 storage reservoir; a discussion of areas of new research
and data needs to improve the application of modeling and reservoir
simulation for carbon storage.
    Summaries of the workshops described above are available on EPA's
Web site, at http://www.epa.gov/safewater/uic/wells_
sequestration.html.
5. Stakeholder Coordination and Outreach
    Stakeholder participation is an important component of today's
proposed rulemaking. EPA held public meetings to discuss EPA's
rulemaking approach, met with State and Tribal representatives, and
consulted with other stakeholder groups including non-governmental
organizations (NGOs), to gain an understanding of stakeholder concerns.

    Public Meetings: EPA conducted two public stakeholder workshops
with participants from industry, environmental groups, utilities,
academia, States, and the general public. These workshops were held in
December 2007 and February 2008. The December 2007 workshop provided
EPA with an opportunity to hear stakeholders' perspectives and
concerns. EPA and stakeholders discussed issues including the
rulemaking process, existing regulations and regulatory components,
statutory authority, GS technology, and technical issues associated
with GS. During the February 2008 workshop, EPA provided a
comprehensive review of how current UIC program elements could be
tailored for the purposes of CO2 injection for GS. Smaller
technical sessions were dedicated to discussion of key questions and
considerations related to Area of Review and Site Characterization,
Monitoring, Long-term Financial Assurance, and Public Participation.
Technical discussions and stakeholder feedback from these workshops
were used to inform today's proposal. Summaries of these workshops are
available on EPA's Web site, at http://www.epa.gov/safewater/uic/
wells_sequestration.html.
    State and Tribal Meetings: EPA coordinated with the Ground Water
Protection Council (GWPC), a State association that focuses on ensuring
safe application of injection well technology and protecting ground
water resources. In the past several years, GWPC meetings have included
sessions on many of the key GS technical and policy issues described
above. EPA's participation in these sessions has resulted in a clearer
understanding of the regulatory issues associated with the
implementation of GS of CO2.
    EPA also coordinated with IOGCC, a chartered State association
representing oil and gas producing States. These State members have
specific expertise regulating the injection of CO2 for the
enhanced recovery of oil and gas. Additionally, EPA reviewed the
IOGCC's model State geologic sequestration regulatory framework to help
inform today's proposal.
    During the development of the proposed rule, EPA contacted all
federally recognized tribes to invite their engagement in the
rulemaking process and held a dedicated conference call with the
tribes. EPA will continue an ongoing dialogue with interested tribes on
this rulemaking.
    During the development of the proposed rule, EPA contacted State
and local government associations to invite their engagement in the
rulemaking process and held a dedicated conference call with their
representatives. EPA will continue an ongoing dialogue with interested
State and local associations on this rulemaking.
    The Agency also held meetings and presented information about the
proposed rulemaking to members of the water utility sector. These
organizations included the American Water Works Association (AWWA), the
Association of Metropolitan Water Agencies (AMWA), and the America
Public Power Association (APPA).
    In addition, EPA consults with the National Drinking Water Advisory
Council (NDWAC), a group that operates under the SDWA to provide advice
to EPA's drinking water program and reports to EPA's Administrator.
NDWAC consists of members of the general public, drinking water
experts, State and local agencies, and private groups concerned with
safe drinking water. In support of the proposed rulemaking and in
accordance with statutory requirements, EPA consulted with the
Department of Health and Human Services. EPA will conduct further
consultations prior to finalization of the GS regulation.
    The Agency also meets annually with the American Association of
State Geologists (AASG) to discuss key topics related to protecting and
preserving ground water resources. AASG members are State geologists
from around the country who over the past several years have met with
EPA to discuss injection-related activities, including CO2
GS.
    Other stakeholder discussions: EPA invited key Non-Governmental
Organizations to discuss the potential application of GS as a safe and
effective climate change mitigation tool. Attendees of these meetings
included Environmental Defense, the National Resources Defense Council,
the Clean Air Task Force, the World Resources Institute, and others. In
addition, EPA attended and participated in numerous conferences and
technical symposia on GS. These meetings, attended by various
stakeholders, included sessions on technical issues related to GS and
were organized or attended by DOE's National Energy Technology
Laboratory (NETL), the American Petroleum Institute (API), the Society
of Petroleum Engineers (SPE), and the International Energy Agency
(IEA). EPA also attends meetings of the Intergovernmental Panel on
Climate Change (IPCC) and events hosted by the World Resource Institute
(WRI), including recent meetings focused on long-term liability and
frameworks and standards for GS programs.
6. Providing Technical Guidance and Reviewing Permits for Initial
Pilot-Scale Projects
    EPA issued program technical guidance to assist State and EPA
Regional UIC programs in processing permit applications for pilot and
other small scale experimental GS projects. This guidance was developed
in cooperation with DOE and with States, through GWPC, IOGCC, and other
stakeholders. UIC Program Guidance # 83: Using the Class V Experimental
Technology Well Classification for Pilot Carbon Geologic Sequestration
Projects (USEPA, 2007) assists permit writers in evaluating permit
applications for pilot-scale GS projects. It clarifies the use of the
UIC Class V experimental well classification for GS demonstration
projects and provides recommendations to permit writers on how they can
issue permits that allow experimental data to be collected while
ensuring that USDWs are protected during injection. This guidance will
continue to apply to pilot-projects as long as the projects continue to
qualify under the guidelines for experimental wells laid out in UICPG
83. It will also remain a permitting option for future
projects, as long as new projects are experimental in nature and
continue to collect data and conduct research. The program guidance is
available at: http://www.epa.gov/safewater/uic/wells_
sequestration.html. Ultimately, as more, larger GS projects are
permitted, EPA anticipates that such projects will not meet the Class V
experimental technology criteria. As discussed in the program guidance,
such a determination (of Class V or Class VI) is made by the Director.
    Currently, EPA Regional and State UIC programs are using this
guidance to authorize a number of Class V experimental technology
wells. The guidance is being used to help create a nationally
consistent permitting framework that draws on the key technical
components that affect the endangerment potential of CO2 GS.
These experimental projects will continue to provide EPA and States
with critical information that will improve EPA's understanding of the
risks posed by CO2 injection for GS and the operational,
technical, and administrative considerations for the advancement and
appropriate permitting of this technology. This information will
support EPA's final decision on how to regulate GS activities.

F. Why Is EPA Proposing To Develop a New Class of Injection Well for GS
of CO2?

    EPA is proposing to establish a new class of injection well for GS
projects because CO2 injection for long-term storage
presents several unique challenges that warrant designation of a new
well type. When EPA initially promulgated its UIC regulations, the
Agency defined five classes of injection wells at 40 CFR 144.6, based
on similarities in the fluids injected, construction, injection depth,
design, and operating techniques. These five well classes are still in
use today and are described below.
    Class I wells inject industrial non-hazardous liquids, municipal
wastewaters or hazardous wastes beneath the lowermost USDW. These wells
are most often the deepest of the UIC wells and are managed with
technically sophisticated construction and operation requirements.
    Class II wells inject fluids in connection with conventional oil or
natural gas production, enhanced oil and gas production, and the
storage of hydrocarbons which are liquid at standard temperature and
pressure.
    Class III wells inject fluids associated with the extraction of
minerals or energy, including the mining of sulfur and solution mining
of minerals.
    Class IV wells inject hazardous or radioactive wastes into or above
USDWs. Few Class IV wells are in use today; these wells are banned
unless authorized under an approved Federal or State ground water
remediation project.
    Class V includes all injection wells that are not included in
Classes I-IV. In general, Class V wells inject non-hazardous fluids
into or above USDWs; however, there are some deep Class V wells that
inject below USDWs. This well class includes Class V experimental
technology wells including those permitted as geologic sequestration
pilot projects.
    Today's proposed rulemaking would establish a new class of
injection well--Class VI--for GS projects based on the unique
challenges of preventing potential endangerment to USDWs from these
operations. The Agency invites public comment on the appropriateness of
this classification.

G. How Would This Proposal Affect Existing Injection Wells Under the
UIC Program?

    CO2 is currently injected in the U.S. under two well
classifications: Class II and Class V experimental technology wells.
The requirements in today's proposal, if finalized, would not
specifically apply to Class II injection wells or Class V experimental
technology injection wells. Class VI requirements would only apply to
injection wells specifically permitted for the purpose of GS. Injection
of CO2 for the purposes of enhanced oil and gas recovery
(EOR/EGR), as long as any production is occurring, will continue to be
permitted under the Class II program. EPA seeks comment on the merits
of this approach since owners or operators of some Class II EOR/EGR
wells may wish to use wells for the purposes of production and GS prior
to the field being completely depleted.
    Existing wells currently permitted as Class I, Class II, or Class V
experimental technology wells could potentially be re-classified for GS
of CO2. However, the owner or operator would need to follow
the permitting process outlined in today's proposal to receive a Class
VI permit.
    EPA is proposing to give the Director discretion to carry over or
``grandfather'' the construction requirements (e.g., permanent,
cemented well components) for existing Class I and Class II wells
seeking a permit for GS of CO2, provided he/she is able to
make a determination that these wells would not endanger USDWs.
Although CO2 is not currently injected in Class I wells,
Class I well construction requirements are similar to those for Class
VI. Today's proposal requires that the owner or operator make a
demonstration that the well will maintain integrity and stability in a
CO2 rich environment for the life of the GS project. Only
the construction requirements would be grandfathered under today's
proposal, therefore, Class I or Class II owners or operators seeking to
change the purpose of their injection well from Class I or Class II to
Class VI would need to meet all other requirements of today's proposed
rule (e.g., area of review and site characterization, operating,
monitoring, MIT, well plugging, post-injection site care and site
closure requirements).
    EPA's program guidance on issuing Class V Experimental Technology
Well permits (USEPA, 2007) encourages owners or operators and
permitting authorities to consider the potential for changing the
purpose of demonstration wells to full-scale GS when designing and
approving experimental GS projects. EPA understands, based on reviews
of several Class V pilot project permits that many of these wells are
specifically designed for injection of CO2 and are being
built to Class I non-hazardous well specifications.
    Accordingly, EPA is proposing that the Director have the discretion
to ``grandfather'' the construction requirements for Class V
experimental wells when they are converted to full-scale GS Class VI
wells. As with converted Class I and Class II wells, these
grandfathered wells would be required to meet the other requirements of
today's proposed rule (e.g., operating, monitoring, MIT, well plugging,
post-injection site care and site closure).
    EPA seeks comment on the approach to grandfather construction
requirements at the Director's discretion for existing Class I, Class
II, and Class V wells seeking to convert to Class VI wells, and whether
additional construction requirements would be necessary to prevent
endangerment to USDWs from the GS of CO2. Additionally, EPA
seeks comment on how the grandfathering approach for existing wells may
affect compliance with the requirements in this proposal.

H. What Are the Target Geologic Formations for GS of CO2?

    A range of geologic formations is being assessed as potential
target formations for receiving and sequestering CO2. Target
formations with the greatest GS capacity include deep saline
formations, depleted oil and gas reservoirs, unmineable coal seams, and
other formations.
    Deep saline formations: Estimates in the Cost Analysis for today's
proposal indicate that up to 88.6 percent of the capacity for
CO2 injected for GS is in deep saline formations. These
formations are deep and geographically extensive sedimentary rock
layers saturated with waters or brines that have a high TDS content
(i.e., over 10,000 mg/L TDS). Deep saline formations are found
throughout the U.S. and many of these formations may be overlain by
laterally extensive, impermeable formations that may restrict upward
movement of injected CO2. All of these characteristics make
deep saline formations the leading candidates for GS. Since most deep
saline formations have not been extensively investigated, a thorough
site-specific characterization of saline formations proposed for GS
will be necessary. Such characterizations will need to demonstrate the
safety and efficacy of these sites for GS and rule out the presence of
fractures, faults, or other characteristics that may endanger USDWs.
    Depleted oil and gas reservoirs: Depleted oil and gas reservoirs
represent approximately four percent of the potential CO2
storage capacity in the U.S. and Canada. Because many of these
reservoirs have trapped liquid and gaseous hydrocarbon resources for

millions of years, EPA believes that they can also be used to sequester
CO2. Hydrocarbons are commonly trapped structurally, by
faulted, folded, or fractured formations, or stratigraphically, in
porous formations bounded by impermeable rock formations. These same
trapping mechanisms can effectively store CO2 for GS in
depleted oil and gas reservoirs.
    Oil and gas exploration activities have generated a great deal of
geologic data on depleted oil and gas reservoir sites. This information
would be directly transferable to the GS site characterization process.
Furthermore, models can predict the movement and displacement of
hydrocarbons in oil and gas reservoirs and can be used to further
advance site specific knowledge about CO2 storage.
    It should also be noted that there are technical challenges
associated with GS in depleted oil and gas reservoirs. Injection
volumes, operation conditions, and formation pressures for
CO2 injection will differ from those of traditional EOR/EGR
operations. The American Petroleum Institute (API) estimates that over
0.6 gigatons (Gt) of CO2 have been injected for EOR/EGR
operations to date and a large percentage of this CO2 is
recovered through production (causing a pressure decrease in the
reservoir) (Meyer, 2007). However, DOE estimates that over 90 Gt
CO2 could be geologically sequestered in U.S. oil and gas
reservoirs resulting in the potential for reservoir-wide pressure
increases.
    Depleted oil and gas reservoirs will contain numerous artificial
penetrations (e.g., active and abandoned injection and production
wells, water wells, etc.) and other types of conduits that could be
potential pathways for CO2 migration. Some of these wells
may be decades old, constructed or plugged with materials that may not
be able to withstand long-term exposure to CO2, or may be
difficult to locate. Locating and assessing the integrity of these
wells and performing appropriate corrective action are essential to
assuring that they would not serve as conduits for movement of injected
CO2 or displaced fluids to USDWs.
    Unmineable coal seams: Unmineable coal seams represent
approximately 1.5 percent of the remaining potential U.S. storage
capacity. Currently, enhanced coalbed methane (ECBM) operations exploit
the preferential chemical affinity of coal for CO2 relative
to the methane that is naturally found on the surfaces of coal. When
CO2 is injected, it is adsorbed to the coal surface and
releases methane, which can then be captured and produced for economic
purposes.
    Studies suggest that for every molecule of methane displaced in
ECBM operations, three to thirteen CO2 molecules are
adsorbed. This process effectively ``locks'' the CO2 to the
coal, where it remains sequestered.
    There are a number of technical challenges related to use of coal
seams for GS. While coal seams are well studied and understood, the
process of CO2 adsorption to coal has not been proven and
the chemical reactions of supercritical CO2 within coal
formations are not well understood. In addition, coals swell as
CO2 is adsorbed, which can reduce the permeability and
injectivity of the coal seams, requiring higher injection pressures
(IPCC, 2005). There are currently no commercial scale CO2
ECBM projects, and ECBM with simultaneous CO2 storage is an
emerging technology that is in the demonstration phase (Dooley, et al.,
2006; IPCC, 2005). In addition, many ECBM recovery operations will
likely be shallow. Shallow storage will result in the CO2
remaining in a gaseous state, which can limit the amount of
CO2 that can be sequestered. Coal seams and water-bearing
formations in close proximity to coal seams may contain less than
10,000 mg/L TDS and meet the definition of a USDW.
    EPA is concerned that coal seams in close proximity to USDWs and
CO2 injection for GS could endanger USDWs. In some cases,
coal seams are considered USDWs and may serve as public drinking water
supplies. As a result, EPA is proposing to preclude the injection of
CO2 for long-term storage into coal seams where they are
above the lowermost USDW. EPA requests comment on this proposed
prohibition. Today's proposal would not affect injection activities
where the primary purpose of the activity is methane production (a
Class II activity).
    Other formations: Other formations under investigation for
CO2 storage include basalts, salt domes, and shales. These
formations are limited in geographic and geologic distribution
throughout the U.S., and their technological or economic viability as
GS sites have not been demonstrated. In basalts, the injected
CO2 could react with embedded silicate minerals and form
carbonate minerals that would be trapped in the basalt. Mined salt
domes or salt caverns could be used for CO2 storage using
processes similar to those used by industry to store natural gas (IPCC,
2005). Other abandoned mines (e.g., potash, lead, or zinc deposits or
abandoned coal mines) are also CO2 storage options (IPCC,
2005). CO2 storage in organic-rich shales, to which
CO2 could adsorb to organic materials in a process similar
to coal seam adsorption, is also a possible storage option (DOE,
2007b). The location and proximity of these other formations to USDWs
may preclude their use for GS. As with unmineable coal seams, EPA seeks
comment on prohibiting injection into such formations if they are above
the lowermost USDW.

I. Is Injected CO2 Considered a Hazardous Waste Under RCRA?

    In developing today's proposal, EPA used the Class I industrial
well class as the reference for the proposed rule and also considered
the potential for hazardous constituents to be present in the
injectate, and whether their presence could render the injected
CO2 stream a hazardous waste. The composition of the
captured CO2 stream will depend on the source, the flue gas
scrubbing technology for removing pollutants, additives, and the
CO2 capture technology. In most cases, the captured
CO2 will contain some impurities, however, concentrations of
impurities are expected to be very low (Apps, 2006).
    Because the types of impurities and their concentrations in the
CO2 stream are likely to vary by facility, coal composition,
plant operating conditions, and pollution removal technologies, EPA
cannot make a categorical determination as to whether injected
CO2 is hazardous under RCRA. Owners or operators will need
to characterize their CO2 stream as part of their permit
application to determine if the injectate is considered hazardous as
defined in 40 CFR Part 261. If the injectate is considered hazardous
under RCRA, then the more stringent UIC Class I requirements for
injection of hazardous waste apply. The design changes EPA is proposing
are meant to address the mobility and corrosivity caused by long term
GS of CO2, and not the long term storage of hazardous
wastes.
    By defining ``carbon dioxide stream'' to exclude hazardous wastes
(146.81(d)), today's rule, if finalized, assures that it would apply
only to CO2 streams that are not hazardous wastes as defined
in 40 CFR Part 261. As a result, today's proposed rule would preclude
the injection of hazardous wastes in Class VI injection wells. EPA
seeks comment on this approach and other considerations associated with
the presence of impurities in the CO2 stream.

J. Is Injected CO2 Considered a Hazardous Substance Under CERCLA?

    The Comprehensive Environmental Response, Compensation, and
Liability

Act (CERCLA), also more commonly known as Superfund, is the law that
provides broad federal authority to clean up releases or threatened
releases of hazardous substances that may endanger human health or the
environment. CERCLA references four other environmental laws to
designate more than 800 substances as hazardous and to identify many
more as potentially hazardous due to their characteristics and the
circumstances of their release. It allows EPA to clean up sites
contaminated with hazardous substances and seek compensation from
responsible parties, or compel responsible parties to perform cleanups
themselves. A responsible party may be able to avoid liability through
several enumerated defenses, including that the release constituted a
``federally permitted release'' as defined in CERCLA, 42 U.S.C.
9601(10).
    While CO2 itself is not listed as a hazardous substance
under CERCLA, the CO2 stream may contain other substances
such as mercury that are hazardous substances or the constituents of
the CO2 stream could react with groundwater to produce
listed hazardous substances such as sulfuric acid. Thus, whether or not
there is a ``hazardous substance'' that may result in CERCLA liability
from a sequestration facility depends entirely on the make-up of the
specific CO2 stream and of the environmental media (e.g.,
soil, groundwater) in which it is stored. CERCLA exempts from liability
certain ``federally permitted releases'' including releases in
compliance with a UIC permit under SDWA. Therefore, Class VI
requirements and permits will need to be carefully structured to ensure
that they do not ``authorize'' inappropriate hazardous releases. This
would include clarifying if there are potential releases from the well
which are outside the scope of the Class VI permit. EPA requests
comment on particular situations where this might occur. EPA also
requests comment on other considerations associated with the presence
of impurities in the CO2 stream related to CERCLA.
    As applicable, a determination of liability would be made on a
case-by-case basis by Federal courts in response to claims for natural
resource damages (NRD) or response costs. A NRD claim could be brought
by the U.S. or a State or Tribe.

III. Proposed Regulatory Alternatives

    The regulatory alternatives for managing CO2 injection
for GS have been informed by the existing UIC program regulations and
supplementary contributions from parties with expertise related to the
challenges associated with GS of CO2. In preparing today's
proposal, EPA consulted with regulators, industry, utilities, and other
technical experts; considered input provided at the technical workshops
and stakeholder meetings; and reviewed research, early pilot GS project
permits, and IOGCC's model rules and regulations (IOGCC, 2007).
    EPA considered four alternatives for developing GS regulations. The
four alternatives vary in stringency and specificity as described
below.
    Alternative 1: Non-specific Requirements Approach. This alternative
is the least specific and stringent of the alternatives EPA considered.
It includes no specific requirements for site characterization, well
construction, or monitoring; rather, it applies a performance standard
approach, specifying that GS wells be sited, constructed, operated,
maintained, monitored, plugged and closed in a manner that protects
USDWs from endangerment.
    Alternative 2: General Requirements Approach. This alternative
provides more specificity than the previous alternative and includes
standards for siting, construction, operation, and monitoring
associated with basic deep well design and operation. The general
requirements approach also gives permitting authorities flexibility to
interpret certain elements in setting permit requirements; however,
this alternative does not contain specific program requirements for
technical challenges not currently addressed in the UIC Program such as
long-term CO2 storage and large volumes.
    Alternative 3: Tailored Requirements Approach. This approach builds
on the general requirements approach by incorporating technical
standards for deep-well injection of non-hazardous fluids where
appropriate and tailoring them to address the challenges of long-term
CO2 storage. This approach also gives permitting authorities
discretion in how to permit certain elements and in requiring
additional information.
    Alternative 4: Highly Specific Requirements Approach. The highly
specific requirements approach describes specific technologies and
information needed for site characterization, AoR modeling, well
construction, monitoring, and testing. Many components of this
alternative equal or exceed the requirements for Class I hazardous
waste injection wells.
    These alternatives are described in more detail in the document,
Regulatory Alternatives for Managing the Underground Injection of
Carbon Dioxide for Geologic Sequestration (USEPA, 2008c).

A. Proposed Alternative

    EPA is proposing Regulatory Alternative 3, the Tailored
Requirements Approach. The technical requirements of this alternative
build upon the existing UIC regulatory framework for deep wells and are
appropriately tailored to address the unique nature of full-scale
CO2 GS. The tailored requirements approach promotes USDW
protection, incorporates flexibility or the discretion of the
permitting authority when appropriate, seeks to limit unnecessary
burden on owners or operators or permitting agencies and provides the
foundation for national consistency in permitting of GS projects.
Because of the volumes of CO2 being anticipated for long-
term storage, the buoyant and viscous nature of the injectate, and its
corrosivity when mixed with water, EPA is proposing changes to the
existing UIC approach or requirements in several program areas,
including site characterization, area of review, well construction,
mechanical integrity testing, monitoring, well plugging, post-injection
site care, and site closure.
    EPA did not select alternative 1 (Non-Specific Requirements
Approach) because it does not provide enough specificity to ensure that
permitting authorities manage GS wells appropriately to prevent
endangerment of USDWs. In addition, this alternative may be burdensome
for owners or operators because of the potential for inconsistency
across States and burdensome for permitting authorities who will likely
be faced with developing their own technical approaches to regulating
GS. Alternative 1 could create an uncertain regulatory landscape for
owners or operators seeking to operate facilities in multiple states or
seeking to manage projects that cross state boundaries.
    Although alternative 2 (General Requirements Approach) provides
standards for siting, construction, operation, and monitoring
associated with basic deep well design and operation, EPA did not
select this alternative because it is not tailored to meet the unique
challenges of long-term CO2 storage. While this option
includes flexibility for permit authorities to add requirements, EPA
cannot be certain that the necessary adjustments would be made.
    Alternative 4 (Highly Specific Requirements Approach) lacks the
flexibility for incorporating and adapting to evolving GS technologies
and provides no clear additional

benefits beyond alternative 3 for USDW protection, therefore, EPA did
not select this alternative.
1. Proposed Geologic Siting Requirements
    Existing UIC requirements for siting injection wells include
identification of geologic formations suitable to receive the injected
fluids and confine them such that they are isolated below the lowermost
USDWs, minimizing the potential for endangerment. While initial
assessments indicate there are many geologic formations in the U.S.
that can potentially receive injected CO2, not all can serve
as adequate CO2 GS sites.
    A detailed geological assessment is essential to evaluating the
presence and adequacy of the various geologic features necessary to
receive and confine large volumes of injected CO2 so that
the injection activities will not endanger USDWs. Thus, EPA is
proposing that owners or operators submit maps and cross sections of
the USDWs near the proposed injection well.
    Injection wells are drilled to a receiving zone, also known as the
injection zone. The injection zone is typically a layer or layers of
porous rocks, such as sandstone, that can receive large volumes of
fluids without fracturing. Today's proposal would require that owners
or operators submit data to demonstrate that the injection zone is
sufficiently porous to receive the CO2 without fracturing
and extensive enough to receive the anticipated total volumes of
injected CO2. Owners or operators would submit geologic core
data, outcrop data, seismic survey data, cross sections, well logs, and
other data that demonstrate the lateral extent and thickness, strength,
capacity, porosity, and permeability of subsurface formations. The
injection zone should be of a sufficient lateral extent that the
CO2 can move a sufficient distance away from the well and
still remain in the same zone, without displacing fluids into USDWs.
Structural features of a potential injection zone reservoir, such as
the lateral extent, dip, or the presence of ``pinch-outs'' (i.e.,
thinning or tapering out) can affect storage potential, and therefore
should be examined.
    The injection zone should be overlain by a low permeability
confining system (i.e., primary confining zone) consisting of a
geological formation, part of a formation, or group of formations that
limits the injected fluid from migrating upwards out of the injection
zone. The buoyancy of CO2 necessitates good characterization
of potential conduits for fluid migration upward through the confining
system to USDWs. The confining system should be of sufficient regional
thickness and lateral extent to contain the entire CO2 plume
and associated pressure front under the confining system following the
plume's maximum lateral expansion.
    EPA proposes that owners or operators of proposed GS projects
present to the permitting authority data on the local geologic
structure, including information on the presence of any faults and
fractures that transect the confining zone and a demonstration that
they would not interfere with containment. These data will support
determinations about whether these features, if present, could
potentially become conduits for movement of CO2 or other
fluids to shallower layers, including USDWs. Under today's proposal,
owners or operators must perform and submit the results of
geomechanical studies of fault stability and rock stress, ductility,
and strength.
    Today's proposal would require that owners or operators submit
information on the seismic history of the area and the presence and
depth of seismic sources to assess the potential for injection-induced
earthquakes. These examinations, along with interpretation of geologic
maps and cross sections and geomechanical data, are proposed to help
rule out sites with unacceptably high potential for seismic activity.
Information on in-situ fluid pressures is also required to assess the
potential for the pressures associated with injection to reactivate
faults or to determine appropriate operating requirements.
    A variety of techniques are available to characterize the receiving
zones and confining zones of proposed GS sites. For example, geologic
core data, test wells, and well logs can help determine rock
formations' strength and extent. Seismic and electrical methods can be
used to reveal subsurface features. Gravity anomalies indicate density
variations at depth, and gravity surveys can be used to locate voids,
such as cavities and abandoned mines. Numerous geophysical logging
tools can determine formation porosity. Large scale, regional pressure
tests can also provide insight into the fluid flow field and the
presence and properties of major faults and fractures that may affect
flow and transport of CO2 and displaced brines.
    Underground injection wells, if improperly sited and operated, have
the potential to induce seismicity, which may cause damage to reservoir
and fault seals, creating conduits for fluid movement into USDWs.
Today's proposal would require that owners or operators not exceed an
injection pressure that would initiate or propagate fractures in the
confining zone. To meet this requirement, maximum sustainable injection
pressures that will not cause unpermitted fluid movement should be
determined prior to CO2 injection. Estimates of maximum
sustainable fluid pressures in CO2 storage sites are
primarily based on predicted changes of effective stresses in rocks
during CO2 injection and associated pore-pressure increase
(Streit and Siggins, 2004). Geomechanical studies of fault stability
and rock stresses and strength, based on examination and interpretation
of geological maps and cross sections, seismic and well surveys,
determination of local stress fields, and modeling, can also help rule
out sites with unacceptably high potential for seismic activity (IPCC,
2005).
    The geochemistry of formation fluids can also affect whether a site
is suitable for GS. CO2 may act as a solvent, and can mix
with native fluids to form carbonic acid, which can react with minerals
in the formation. Dissolution of minerals may liberate heavy metals
into the formation fluids. Reactions may also break down the rock
matrix or precipitate minerals and plug pore spaces, therefore reducing
permeability (IPCC, 2005). Studies of rock samples and review of
geochemical data from monitoring wells are needed to evaluate the
impact of these effects. Today's proposal would require owners or
operators to submit geochemical data on (a) the injection zone, (b) the
confining zones, (c) containment zones above the confining zones in
which any potentially migrating CO2 could be trapped, (d)
all USDWs, and (e) any other geologic zone or formation that is
important to the proposed monitoring program. The geochemical data are
important for identifying potential chemical or mineralogical reactions
between the CO2 and formation fluids that can break down the
rock matrix or precipitate minerals that could plug pore spaces and
reduce permeability. Additionally, pre-injection geochemical data can
serve as baseline data to which results of future monitoring would be
compared throughout the injection phase. This information can also
improve predictions about trapping mechanisms (which, in turn may
improve predictions of pressure changes in the subsurface and the
ultimate size of the CO2 plume).
    Today's proposal would provide the Director the discretion to
require the owner or operator to identify and characterize additional
confining and containment zones above the primary

(i.e., lowermost) confining zone that could further impede vertical
fluid movement and allow for pressure dissipation. These layers could
provide additional sites for monitoring, mitigation, and remediation.
Today's proposal would not require that these additional zones be
identified for all GS sites because their absence does not necessarily
indicate inappropriateness of a GS site. However, if such zones are
present, information about their characteristics can provide inputs for
predictive models, identify appropriate monitoring locations, and
improve public confidence in and acceptance of a proposed GS site. EPA
specifically seeks comment on the merits of identifying these
additional zones.
2. Proposed Area of Review and Corrective Action Requirements
    Delineating the Area of Review: Under the UIC program, EPA
established an evaluative process to determine that there are no
features near the well such as faults, fractures or artificial
penetrations, where significant amounts of injected fluid could move
into a USDW or displace native fluids into USDWs. Current UIC
regulations require that the owner or operator define the Area of
Review (AoR), within which the owner or operator must identify all
penetrations (regardless of property ownership) in the confining zone
and the injection zone and determine whether they have been properly
completed or plugged. The AoR determination is integral to the
determination of geologic site suitability because it requires the
delineation of the storage operation and an identification and
evaluation of any penetrations that could result in the endangerment of
USDWs (40 CFR 146.6).
    For Class I, II, and III injection wells, Federal UIC regulations
require that the AoR be defined as either a fixed radius of \1/4\ mile
surrounding the well (or wells, for an area permit) or an area above
the injected fluid and pressure front determined by a computational
model. For Class I hazardous waste injection wells, the AoR is defined
as a radius of two (2) miles around the well or an area defined based
on the calculated cone of pressure influence, whichever is larger.
    It is generally agreed that over time, the CO2 plume and
pressure front associated with a full-scale GS project will be much
larger than for other types of UIC injection operations, potentially
encompassing many square miles. In addition, the complexity of
CO2 behavior in the subsurface may produce a non-circular
AoR. It is also possible that multiple owners or operators will be
injecting CO2 into formations that are hydraulically
connected, and thus the elevated pressure zones may intersect or
interfere with each other. Traditional AoR delineation methods such as
a fixed radius or simple mathematical computations would not be
sufficient to predict the extent of this movement.
    EPA believes that predicting the complex multi-phase buoyant flow
of the CO2, co-injectates, and compounds that may be
mobilized due to injection requires the sophistication of computational
models. EPA proposes that the owners or operators of GS wells delineate
the AoR for CO2 GS sites using computational fluid flow
models designed for the specific site conditions and injection regime.
    Multiphase models are the most comprehensive type of computational
model available to predict fluid movement in the subsurface under
varying conditions or scenarios, and EPA considers them to be
appropriate for delineating the AoR for GS projects. This approach was
also recommended by IOGCC, workshop participants, and regional and
State permit writers for GS operations. EPA seeks comment on the use of
modeling for AoR delineation.
    Modeling CO2 Movement and Reservoir Pressure:
Computational models used to delineate the AoR consider the buoyant
nature and specific properties of separate phases of the injected
CO2 and native fluids within the injection zone. The models
should be based on site characterization data collected regarding the
injection zone and confining system, taking into account any geologic
heterogeneities, and potential migration through faults, fractures, and
artificial penetrations.
    Appropriate models may incorporate numerical, analytical, or semi-
analytical approaches. These models solve a series of governing
equations to predict the composition and volumetric fraction (i.e., the
fraction of the formation pore-space taken up by that fluid) of each
phase state (e.g., liquid, gas, supercritical fluid), as well as fluid
pressures, as a function of location and time for a particular set of
conditions.
    EPA has found that multiphase, computational models are the most
appropriate type of computational model to predict the fate and
transport of CO2, co-injectates, and compounds mobilized due
to injection. In order to provide guidance related to computational
modeling of CO2 injection for GS, EPA invited expert advice
and reviewed relevant technical documents. On April 6-7, 2005, EPA held
a workshop on ``Modeling and Reservoir Simulation for Geologic Carbon
Storage'' for 60 EPA headquarters and regional staff in Houston, Texas.
Computational modeling for AoR determination was also discussed at
several additional technical workshops (Section II E). Additionally,
the Agency evaluated peer-reviewed journal articles and critical
reviews pertaining to computational modeling of CO2
injection (USEPA, 2008d).
    Model results provide predictions of CO2 fate and
transport, as well as changes in formation pressure, in three
dimensions as a function of time that can be used to delineate the
subsurface storage site and the AoR. Models can also be used to develop
monitoring plans, help to evaluate long-term containment, select and
characterize suitable storage formations, assess the risk associated
with CO2 leakage and other impacts to USDWs, and to design
remediation strategies. Importantly, models can be used to predict
CO2 movement in response to varying conditions or scenarios,
such as changing injection rates, or the presence or absence of
fractures or faults in confining layers.
    Multiphase models have been used by States and industry for
predicting the movement of water and solutes in soil, the behavior of
non-aqueous phase liquid contaminants (e.g., trichloroethene) at
hazardous waste sites, the recovery of oil and gas from petroleum-
bearing formations, and more recently, CO2 in the
subsurface. The existing computational codes used to create multiphase
models vary substantially in complexity. For example, available codes
differ in what processes (e.g., changes of state, chemical reactions)
may be included in simulations. As model complexity increases, so does
the computational power necessary to use the model, as well as the
amount and type of data needed to properly instruct model development.
However, more complex models, when properly used, have the potential to
provide a more accurate representation of the storage project.
    Multiphase models are developed based on a specified set of
conditions, such as the formation's geological structure and injection
scenario, and inputs describing these conditions are included in an
appropriate computational code. Properties of the formation (e.g.,
permeability, porosity, reservoir entry pressure) and fluids present
(e.g., solubility, mass-transfer coefficients), are described by model
parameters, the independent variables in the model governing equations
that may be constant throughout the domain or vary in space and time.
Model predictions depend largely on the

values of key parameters. Often these parameter values are estimated or
averaged from several data sources.
    Models used for GS sites should be based on accepted science and
should be validated. In some cases, owners or operators may choose to
use proprietary models (i.e., not available for free to the general
public). EPA is aware that the use of proprietary codes may prevent
full evaluation of model results (e.g., NRC, 2007). Several popular
codes in the petroleum-reservoir engineering discipline are proprietary
and owners or operators of particular sites may prefer to use these
codes as they have previous experience with them, and they have been
used in peer-reviewed studies to model CO2 sequestration.
When using a proprietary model, owners or operators should clearly
disclose the code assumptions, relevant equations, and scientific
basis. EPA seeks comment on allowing the use of proprietary models for
GS sites.
    Today's proposal does not specify a period of time over which the
AoR delineation models should be run. Rather, available models can
predict, based on proposed injection rates and volumes and information
about the geologic formations, the ultimate plume movement up to the
point the plume movement ceases or pressures in the injection zone
sufficiently decline.
    EPA recognizes that a range of models could be used to delineate
the AoR and that some of these models may have been in use for some
time. Models currently used to delineate AoR, regardless of age, are
considered computational and may be appropriate for use in determining
the AoR for GS of CO2. However, EPA anticipates that
modeling technology will improve substantially, and encourages and
expects owners or operators to use the best multiphase computational
models available to determine the AoR. Reliance on improved models will
likely increase the accuracy and quality of the AoR characterization,
resulting in better protection of USDWs.
    Model simulations and site monitoring are interdependent, and
comprise an iterative, cyclical system. Model simulations can be used
for an initial prediction of injected fluid movement to identify the
type, number and location of monitoring points. As data are collected
at an injection site, model parameters can be adjusted to match real-
world observations (i.e., model calibration or history-matching), which
in turn improves the predictive capability of the model. Additionally,
model simulations are adjusted over time to reflect operational
changes. Project performance is thus evaluated through a combination of
site monitoring and modeling.
    EPA seeks comment on the applicability of computational fluid flow
models for delineating the AoR of GS sites.
    Corrective Action: Today's proposal would require that owners or
operators of GS wells identify all artificial penetrations in the AoR
(including active and abandoned wells and underground mines). This
inventory and review process is similar to what is required of Class I
and Class II injection well operators.
    The owner or operator would compile, tabulate, and review available
information on each well in the AoR that penetrates into the confining
system, including casing and cementing information as well as records
of plugging. If additional confining zones are identified, wells
penetrating those additional zones would be included in this review.
Based on this review, the owner or operator would identify the wells
that need corrective action to prevent the movement of CO2
or other fluids into or between USDWs. Owners or operators would
perform corrective action to address deficiencies in any wells,
regardless of ownership, that are identified as potential conduits for
fluid movement into USDWs. In the event that an owner or operator
cannot perform the appropriate corrective action, the Director would
have discretion to modify or deny the permit application. Corrective
action could be performed prior to injection or on a phased basis over
the course of the project (as outlined in the next section). Available
corrective action techniques include plugging of offset wells or
monitoring in the injection zone. Another example of corrective action
is remedial cementing, in which owners or operators would squeeze
cement into channels or voids between the casing and the borehole, to
prevent upward migration along uncemented casing.
    Today's proposal does not prescribe the specific cements to be used
to plug abandoned wells in the AoR because industry standards, such as
those developed by API or ASTM International, reflect the current state
of the science and the expertise of industrial users on corrosion-
resistant materials.
    Though today's proposal does not dictate specific corrective action
methods, it requires that the corrective action methods be appropriate
to the CO2 injection. At the Technical Workshop on
Geological Considerations and AoR Studies, participants generally
concluded that the reaction of the CO2 injectate stream with
typical well materials and cements that are likely to be encountered in
abandoned wells in the AoR is an important consideration. Today's
proposal would require that corrective action for wells in the AoR of
GS projects be performed with appropriate corrective action methods
such as use of corrosion-resistant cements.
    Area of Review Reevaluation: Predicting the behavior of injected
CO2 in the subsurface, particularly the ultimate extent of a
CO2 plume and associated area of elevated pressure in a
laterally expansive reservoir, poses uncertainties. Today's proposal
would require that the owner or operator periodically reevaluate the
AoR during the injection operation. Reevaluations would occur at a
minimum fixed frequency, not to exceed 10 years, as agreed upon by the
Director.
    When monitoring data differ significantly from modeled predictions,
or when there are appreciable operational changes (e.g., injection
rates), reevaluation may be mandated prior to the minimum fixed
frequency. At no time would area of review reevaluations occur less
frequently than every 10 years.
    Reevaluations of the AoR would be based on revision and calibration
of the original computational model used to delineate the AoR. If site
monitoring data agrees with the existing AoR delineation, a model
recalibration may not be necessary. In these cases, an AoR reevaluation
may consist simply of a demonstration that the current AoR delineation
is adequate based on site monitoring data.
    There are many potential benefits to periodically reevaluating the
AoR. Each revised model prediction would estimate the full extent of
the CO2 plume and area of elevated pressure; however, the
near-term predictions (e.g., over the subsequent 10 years) would have
the highest degree of certainty and could be the basis of corrective
action. Re-running the models would allow refinement to the AoR
delineation based on real-world conditions and monitoring results, and
thus increase confidence in the modeled predictions. The revised model
predictions would also be used to identify monitoring sites so that
monitoring would occur in any areas subject to the greatest potential
risk.
    EPA seeks comment on requiring the reevaluation of the site AoR on
a periodic basis, under what conditions the AoR should be reevaluated,
and the appropriateness of a 10 year minimum fixed frequency for AoR
reevaluation.
    Phased Corrective Action: In the UIC program, corrective action is
typically

performed on all wells in the AoR in advance of the injection project.
Today's proposal recognizes that this may not always be appropriate for
GS projects. The AoR for a GS site may be quite large, requiring
considerable time and resources to perform corrective action on all
wells that may eventually be affected by the GS project over the course
of decades of injection. In addition, if the periodic reevaluations of
the AoR indicate that the AoR has grown or shifted to areas not
originally included, additional wells may need to be identified for
potential corrective action.
    Today's proposal would give the Director the discretion to allow
owners or operators to perform corrective action on an iterative,
phased basis over the operational life of a GS project. Prior to
injection, the owner or operator would identify all wells penetrating
the confining or injection zone within the site AoR. However, the owner
or operator may limit pre-injection corrective action to those wells in
the portion of the AoR that would be intersected by the CO2
plume or pressure front during the first years of injection. As the
project continues and the plume expands, the owner or operator would
continue to perform corrective action on wells further from the well to
assure that all wells in the AoR that need corrective action eventually
receive it. This approach would ensure that any necessary corrective
action is taken in advance of the CO2 plume and associated
area of elevated pressure approaching USDWs.
    There are potential benefits to implementing phased corrective
action. Phasing in the corrective action would benefit the owner or
operator by spreading out the burden and costs of corrective action and
not delaying initiation of the GS project while corrective action is
performed at wells that may not be affected by the injection for
several decades. Initial corrective action would focus on those
penetrations that pose a potential endangerment to USDWs from injection
of CO2 in the near term. Deferring corrective action on some
of the wells at the outer reaches of the predicted plume can improve
USDW protection by giving these later corrective action efforts the
benefit of newer corrective action techniques. Additionally, this
approach can prevent the unnecessary burden of performing corrective
action in areas far from the injection zone that may never be impacted.
This approach would still assure that all wells in the AoR that need
corrective action eventually receive it, as is the case in current UIC
requirements.
    Participants at the technical workshops on ``Geological
Considerations and AoR Studies'' and ``Modeling and Reservoir
Simulation for Geologic Carbon Storage'' agreed that the AoR should be
reevaluated over time based on incoming monitoring and site
characterization data. In addition, participants at the February 2008
Stakeholder Workshop generally supported reevaluation of the AoR and a
phased corrective action approach.
    EPA recognizes that a phased approach to corrective action may not
be appropriate in all situations; therefore EPA is proposing that the
Director have the discretion to decide to allow this approach, based on
the understanding of relevant geologic and site conditions. EPA invites
public comment on the merits and frequency of reevaluation of the AoR
as well as the phased corrective action approach for GS wells.
    Proposed Area of Review and Corrective Action Plan: For typical UIC
wells, the AoR is delineated only once, and corrective action on all
wells in the AoR is performed prior to commencing injection. However,
AoR and corrective action for GS wells will involve multiple steps over
many years, so EPA proposes that the owner or operator of a GS well
submit an AoR and corrective action plan as part of their permit
application. After approved by the Director, the owner or operator
would implement the plan.
    In the AoR and corrective action plan, the owner or operator would
describe plans to delineate the AoR, including the model to be used,
assumptions made, and the site characterization data on which the
modeling would be based. It would include a strategy for the owner or
operator to periodically reevaluate the AoR in response to operational
changes (e.g., injection rates), when monitoring data varies from
modeled predictions, or at a minimum fixed frequency, not to exceed 10
years, as agreed upon by the Director. It should describe what
monitoring data would be used to determine whether the AoR needs to be
adjusted and how that data would be incorporated into the model. A
description of how the public would be informed of changes in the AoR
would be included.
    The AoR and corrective action plan would also specify where
corrective action would be performed prior to injection, what, if any
areas would be addressed on a phased basis, and how the timing of each
phase of corrective action would be determined. In addition, the plan
would identify how site access would be guaranteed for areas requiring
future corrective action, and how corrective action may change to
address potential changes in the AoR.
    EPA also proposes that, as owners or operators periodically
reevaluate the AoR delineation, they must either amend the Director-
approved AoR and corrective action plan (i.e., to perform additional
corrective action) or report to the Director that no changes to the
plan are necessary. This approach promotes continued communication
between the Director and the owner or operator regarding expectations
over the long duration of CO2 injection, and assures that
the AoR delineation methodology reflects local conditions. The proposed
requirement to periodically revisit the modeling effort, which was
advocated by stakeholders, would help to verify that the CO2
plume is moving as predicted and provides an opportunity to adjust the
injection operation and corrective action to address changes in the
predicted AoR. The reevaluation process would also help account for new
wells in the AoR.
3. Proposed Injection Well Construction Requirements
    Well Construction Procedures: Properly constructing an injection
well is a technologically complex yet well understood undertaking. An
appropriately designed and constructed well would prevent endangerment
to USDWs and would maintain integrity throughout the lifetime of the
project, from the injection operation period through and beyond the
post-injection site care period once the well is permanently plugged.
Current drilling and well construction practices for CO2
injection wells are based on existing knowledge and practices from the
oil and gas industry.
    A typical well is constructed by placing multiple strings of high
strength steel alloy or fiberglass concentric pipe and tubing into a
drilled wellbore. Typically, the first step in well construction is the
drilling of a large borehole (e.g., 10 to 30)
through the base of the lowermost USDW. A large diameter pipe, termed
surface casing, is then placed in the wellbore to protect shallow
aquifers or underground sources of drinking water during the drilling
and injection phases. This casing is usually cemented by circulating
cement between the outside of the surface casing and the side of the
borehole to ensure that the wellbore is stabilized, that the casing is
completely sealed to the rock of the wellbore, and that the geologic
formations are isolated from each other and the surface.
    Next, a smaller diameter wellbore (e.g., 7 to
15) is drilled further downwards, into the injection zone,
and

a smaller diameter pipe, usually designated as the long-string casing,
is run into the hole. Similar to the surface casing, the long-string
casing is cemented in place to the borehole by circulating cement from
the bottom back up to the surface casing, filling the gap between the
outside of the long-string casing and the wellbore. This cementing
process again ensures that rock formations are isolated and no fluid
movement occurs between formations.
    Depending on the depth to the injection formation, additional
strings of casing may be necessary, but in each case, these casings are
engineered and designed to withstand internal and external pressures at
depth. The final result is multiple barriers of cement and casing