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

PDF Version (51 pp, 758K, About PDF)

[Federal Register: July 25, 2008 (Volume 73, Number 144)]
[Proposed Rules]
[Page 43491-43541]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr25jy08-20]
[[Page 43492]]

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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 (202) 566-1744, and the telephone number for the EPA
Docket Center is (202) 566-2426.

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: (202) 564-3756; e-mail address:
whitehurst.lee@epa.gov. For general information, contact the Safe
Drinking Water Hotline, telephone number: (800) 426-4791. 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:

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                Category                  Examples of regulated entities
------------------------------------------------------------------------
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

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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
NO_X 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
SO_X Sulfur Oxides
TDS Total Dissolved Solids
UIC Underground Injection Control
UICPG#83 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

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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

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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

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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

[[Page 43497]]

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

[[Page 43498]]

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

[[Page 43499]]

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,

[[Page 43500]]

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.

[[Page 43501]]

    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.

[[Page 43502]]

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

[[Page 43503]]

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

[[Page 43504]]

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

[[Page 43505]]

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

[[Page 43506]]

(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

[[Page 43507]]

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

[[Page 43508]]

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

[[Page 43509]]

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
between formations above the injection zone and the fluids being
injected. Typically a portion of the wellbore in the injection zone is
left open or the casing is perforated to allow injected fluid to enter
into the injection zone.
    Inside the long string casing, injection tubing is run from the
surface to a depth within the injection zone. This tubing may be
engineered of steel, an alloy, fiberglass, or a composite material most
suitable for the injectate's composition. The tubing extends from the
wellhead down to the storage zone where it is sealed by a mechanical
device known as a packer. The area between the tubing and long string
casing is isolated and the fluid injected into the well can only enter
the geologic formation for which it is targeted. With this type of well
construction, the fluid within the well tubing has minimal contact with
the components of the well that protect USDWs.
    The space between the injection tubing and the long string casing
and above the packer is called the annulus. The annulus between the
wellhead and the packer is a water-tight space filled with a non-
corrosive fluid that helps to protect the inside of the casing and
outside of the tubing from damage due to chemical reactions. In
addition, monitoring the pressure of the annulus using standard
pressure devices can easily detect any leaks in the tubing, long string
casing, or packer.
    Due to the buoyancy of CO₂, today's proposal includes
enhancements to typical deep well construction procedures to provide
additional barriers to CO₂ leakage outside of the injection
zone. The proposal would require that surface casing for GS wells be
set through the base of the lowermost USDW and cemented to the surface.
The long-string casing would be cemented in place along its entire
length. GS wells would also be constructed with a packer that is set
opposite a cemented interval, at a location approved by the Director.
EPA seeks comment on the proposed GS well requirements for depth of
surface casing, the cementing of long-string casing, and construction
with a packer set opposite a cemented interval. EPA also seeks comment
on how the proposed grandfathering provisions for existing wells
(construction requirements) may affect compliance with the above,
proposed construction requirements.
    More information on well drilling may be found by consulting
various sources including the Department of Energy, the American
Petroleum Institute (API), and the Society of Petroleum Engineers
(SPE). Please consult information or links on EPA's Web site: http://
www.epa.gov/safewater/uic.html, or similar sources.
    Horizontal Well Construction: While horizontal well construction is
not typical in deep injection wells in the UIC program, there are
examples of horizontal well completions being used with success to
improve the production of EOR and ECBM operations (e.g., Westermark et
al., 2004; Sams et al., 2005). EPA understands that the In Salah
project in Algeria is using horizontal well construction for GS
purposes. Horizontal wells are constructed by use of a directional
drilling system, which generally consists of both a curve and lateral
drilling assembly. After the vertical portion of the well is
constructed, the curve drilling assembly is used to drill a curve of
prescribed radius to change the path from vertical to horizontal. The
lateral drilling assembly is then used to construct the horizontal
section, which can be lined or remain as an open hole. Importantly,
several horizontal sections can be completed stemming from a single
vertical completion.
    The use of horizontal wells for a GS project could provide several
benefits over vertical wells. Horizontal wells provide enhanced
connectivity with permeable sections of the formation, increasing
injectivity. The use of horizontal wells increases the sweep, or
formation contact area, of the injected CO₂ plume, as
vertical channeling through high permeability regions is reduced.
Increasing the sweep results in enhanced residual-phase CO₂
trapping and dissolution favorable for the purposes of permanent
storage. Horizontal wells also reduce the pressures needed to inject
any given volume of fluid. In addition, fewer vertical completions are
required with the use of horizontal wells, which reduces the number of
artificial penetrations in the formation through which fluid could
migrate, as well as reducing overall costs.
    EPA seeks comment on the merits of horizontal well drilling
techniques for GS wells and the applicability of well construction
requirements discussed in this proposal.
    Well Component Degradation: The potentially corrosive nature of the
injectate must be taken into consideration in the design and
construction of CO₂ GS wells. The quality of the well
materials, proper well construction, composition and placement of
appropriate cement along the wellbore, and appropriate maintenance are
crucial, because a leaking annulus would be a significant route of
escape for CO₂ (IPCC, 2005).
    CO₂ mixed with water or impurities (NO_X,
SO_X and H₂S) can be corrosive to well materials
and cements. Conventional cement formulations (e.g., Portland cement)
are potentially vulnerable to acid attack. Acid attack on the calcium
carbonate in cement can lead to altered permeability and mechanical
instability. Defects in the well cement, such as channels, cracks, and
microannuli (i.e., small spaces between the casing and cement) can
provide pathways for acid to migrate and accelerate degradation.
    Experience with CO₂ injection for EOR includes the use
of acid-resistant cements. Cements with a reduced Portland content are
more resistant to acid because they contain less calcium carbonate
(CaCO₃). Acid resistant cements can be formulated by adding
fly ash, silica fume (microsilica), latex, epoxy, or other substances.
Calcium phosphate cement is a blend of high-alumina cement, phosphate,
and fly ash that can retain integrity under conditions where other
cements lose a substantial portion of their weight, according to one
manufacturer (http://www.eandpnet.com/area/exp/153.htm).
    EPA examined available information to determine the rate at which
cement degrades in acidic environments. Laboratory studies provide
evidence of deterioration of cement and other well components due to
exposure to acid. For example, Duguid et al., (2004) performed a
laboratory study in which Portland cement experienced significant
damage within seven days. Similar experiments by Kutchko et al., (2007)
showed less cement alteration. Differences between these studies may be
due to different experimental conditions, such as temperature and
pressure.
    Limited results of field studies show clear evidence of reactions
between CO₂ and well cement, but do not show such severe
corrosion. Cement samples from

[[Page 43510]]

a well at the Scurry Area Canyon Reef Operators Committee (SACROC) site
did not show serious degradation (Carey et al., 2007). In another
study, cement samples were collected and analyzed from a CO₂
production well in a natural CO₂ reservoir in Colorado
exposed to a CO₂-water environment for 30 years (Crow et
al., 2008). The study found considerable reactions between the
CO₂ and cement, and CO₂ migration up the wellbore
along the cement-formation interface. However, the cement alteration
was not significant enough to enable CO₂ migration through
the cement itself and the distance of CO₂ migration along
the cement-formation interface was very limited. Although the field
corrosion looks surprisingly low, these are only limited examples.
Laboratory studies are conducted under aggressive chemical conditions
in an attempt to mimic the cumulative effects of long-term exposure to
CO₂-rich formation fluids. Given the high injection rates,
long lifespan, and potential impurities in GS, careful selection of
acid-resistant materials and practices may be necessary.
    Metal components of the injection well, such as carbon steel, are
subject to corrosion. To minimize problems, Meyer (2007) recommends the
use of Grade 316 stainless steel. One company working on GS projects
indicates that they use stainless steel well casing to avoid corrosion
problems (Buller et al., 2004). Stainless steels consist of iron, small
amounts of carbon, and at least 10 percent chromium. Grade 316
stainless steel also contains molybdenum, which endows it with
corrosion resistance in a variety of corrosive media, although it is
subject to corrosion in warm chloride environments and to stress
corrosion cracking at warmer temperatures (above 60 degrees C).
According to the report, recovered CO₂ injection well
components at the SACROC site in Texas were made of Grade 316 stainless
steel and did not exhibit signs of corrosion. Industry representatives
at the Technical Workshop on Well Construction and MIT noted that many
casing options (e.g., titanium and fiberglass casing) are available.
Useful packer products include swell-resistant elastomer materials such
as Buna-N and Nitrile rubbers (Meyer, 2007). Teflon and nylon are
options for anti-corrosion seals.
    The use of corrosion-resistant materials is crucial to the success
of long-term GS operations. UIC program experience, industry
experience, and stakeholder input suggest that appropriate materials
are available. Today's proposal does not specify materials that may be
used, rather, proposes providing the owner or operator with the
flexibility to choose, as long as the materials used in GS wells are
corrosion-resistant and meet or exceed standards developed for such
materials by API or ASTM International, or comparable standards
approved by the Director. Well materials must be compatible with
injected fluids, including any co-injected impurities or additives,
throughout the life of the project, and be appropriate for the well's
depth, the size of the well bore, and the lithology of injection and
confining zones.
    GS projects are anticipated to have long lifespans in comparison to
other types of deep injection wells. Not only must GS wells be able to
function safely and properly over the lifespan of the GS project, but
they must be constructed such that USDWs remain protected after well
plugging. Today's proposal would require that the cements and cement
additives used in GS wells be appropriate to address long-term
injection of CO₂ and assure that the well can maintain
integrity throughout the proposed life span of the project, including
the post-injection site care period and beyond once the well is
permanently plugged. Owners or operators must use corrosion-resistant
cement approved by the Director and be able to verify the integrity of
the cement using logs or other acceptable methods.
    EPA seeks comment regarding requirements for degradation-resistant
well construction materials, such as acid-resistant cements and
corrosion resistant casing.
4. Proposed Injection Well Operating Requirements
    EPA's operating requirements for deep injection wells provide
multiple safeguards to ensure that injected fluids do not escape and
are confined within the injection zone and that the integrity of the
confining zone is not compromised by non sealing artificial
penetrations or geologic features. In today's proposal, some well
operating requirements are consistent with existing UIC well types and
some requirements are tailored specifically for CO₂
injection.
    Injection Parameter Limitations: Limitations on injection
parameters are intended to prevent the movement of injected or other
fluids to USDWs via fractures in confining layers or vertical
migration. In order to drive the injected fluids away from the well and
into the formation, fluids must be injected at a higher pressure than
the pressure of fluids in the injection zone. However, the sustained
pressure should not be as high as fracture pressure, that is, high
enough to initiate or propagate fractures in the injection or confining
zone. If the pressure within the reservoir becomes high enough, induced
stresses may reactivate existing faults (Rutqvist et al., 2007), though
injection pressure limitations may be employed to prevent this (Li et
al., 2006). Several geomechanical methods are available to assess the
stability of faults and estimate maximum sustainable pore fluid
pressures for CO₂ storage. For example, one way of deriving
these is to calculate the effective stresses on faults and reservoir
rocks based on fault orientations, pore fluid pressures, and in-situ
stresses (Streit and Hillis, 2004).
    Today's proposal would require an injection pressure limitation
similar to existing UIC Class I deep well requirements. Owners or
operators of GS wells must limit CO₂ injection pressures,
except during well stimulation, so that injection does not initiate new
fractures, propagate existing fractures in the injection zone, or cause
movement of injection or formation fluids that endanger USDWs. Under
this proposal, during injection, the pressure in the injection zone
must not exceed 90 percent of the fracture pressure of the injection
zone. Calculation of fracture pressure is fundamental to evaluating the
appropriateness of the site. The 90 percent requirement, suggested by
permit writers and IOGCC, provides an added margin of safety in the
well operation.
    There are some circumstances, however, where fracturing of the
injection zone would be acceptable provided the integrity of the
confining system remains unaffected. For example, hydraulic fracturing
is a process where a fluid is injected under high pressure that exceeds
the rock strength, and the fluid opens or enlarges fractures in the
rock. EPA recognizes that there may be well completions which require
intermittent treatments, including hydraulic fracturing of the
injection zone, to improve wellbore injectivity. Such stimulation of
the injection zone during a well workover (as defined in 40 CFR
144.86(d)) approved by the Director would be permissible.
    Fracturing of the confining zone would be prohibited at all times
during injection and/or stimulation.
    It is also possible that CO₂ GS may be associated with
ECBM, where more extensive hydraulic fracturing would be necessary to
open pre-existing fractures in the coal and provide additional surfaces
onto which CO₂ may adsorb and to extract methane. These
hydraulic fracturing operations are used to

[[Page 43511]]

enhance oil and gas recovery and for ECBM recovery, and in general are
exceptions to the definition of underground injection under the SDWA.
    EPA is requesting comment on the extent and scope to which
hydraulic fracturing should be allowed during GS injection, and whether
the use of fracturing for the purposes of well stimulation is
appropriate. EPA is also requesting information to better qualify the
use of fracturing for GS injection in specific geologic settings and
rock formation lithologies.
    Continuous Monitoring: Monitoring within the injection well system
is important to assure that the injection project is operating within
permitted limits. It can also protect the owner or operator's
investment, as significant divergences in any of these parameters could
damage well components. Deep injection well owners or operators
typically monitor injection pressure, flow rate, temperature, and
volumes. Owners or operators usually choose to maintain pressure on the
annulus between the tubing and the long string casing and monitor this
pressure to ensure protection of USDWs from well leakage. Monitoring is
generally performed on a continuous basis, through the use of automated
equipment that typically takes readings several times per minute and
records them in a computer system.
    Alarms and automatic shut-off devices connected to the monitoring
equipment can engage if operational limits are exceeded. Available
computer-driven monitoring systems have the ability to continuously
monitor injection parameters and engage the shut-off devices. Though
these systems are not required for all UIC well classes, the complexity
of GS operations and the potential for movement of the CO₂
in the event of a mechanical integrity loss makes a shut-off system an
important safety consideration for GS projects.
    Traditionally, owners or operators have installed monitoring and
shut-off equipment at the wellhead (i.e., at the surface), however,
down-hole devices have been used in offshore applications for several
years. Today's proposal requires that automatic shut-off valves be
installed down-hole in addition to at the surface. This requirement is
supported by many participants at the technical workshops and the
IOGCC's recommendations.
    The down-hole valves provide a safety backstop in case damage to
the wellhead prevents the proper operation of wellhead shut-off valves.
Direct pressure measurements used to trigger shut-off devices are more
accurate than wellhead calculations of down-hole pressure. The down-
hole valves are an integral part of the tubing string and can be
positioned anywhere along the tubing string. Gauges can be either
inside or outside of the casing; installation on the outside of the
casing may cause less interference with well maintenance. The down-hole
valves are kept in an open position by hydraulic pressure from a
connection to the surface. Damage to the wellhead or an upset in
operations causes the positive hydraulic pressure to fall, forcing the
valve into a ``failsafe'' closed position. In case of well failure, a
down-hole shut-off device would isolate the injectate below USDWs,
rather than just below the surface. By engaging near the injection
zone, they can prevent pressure-induced damage to the well casing. This
would also require less expensive repairs if pressure exceedances were
to occur.
    While there would be some cost and downtime associated with
replacing failed down-hole valves, such costs are considered small in
comparison to the costs if large amounts of CO₂ should
escape into USDWs or to the surface. It is possible to place a new
valve down-hole without removing the existing valve, so downtime can be
minimized if an appropriate parts inventory is kept on hand. A
Norwegian study found that the failure rate of down-hole safety valves
was 2 failures per million operating hours (Norwegian Oil Industry
Association, 2001). This is a relatively low failure rate as the valves
are designed to withstand harsh conditions and operate well after years
of inactivity. Overall, it is likely that costs for replacing failed
valves would be insignificant in comparison with costs of a
CO₂ leak.
    Several types of valves are available and in use, including
flappers and ball valves. The flapper types seem to be more reliable,
at least for oilfield applications (Garner et al., 2002). EPA seeks
comment on the merits of requiring down-hole shut-off valves in GS
wells.
    Corrosion Monitoring and Control: Existing UIC Class I deep well
operating requirements allow Director's discretion to require corrosion
monitoring and control in the case of corrosive fluids. Corrosion
monitoring can help avoid or provide early warning of corrosion of well
materials that could compromise the well's integrity. This is
accomplished by exposing ``coupons,'' or small samples of the well
material to the injection stream. The samples are periodically removed
from the flow line, cleaned and weighed; the weight is compared to
previous values to calculate a corrosion rate. Other methods of
corrosion monitoring/control include: The use of wireline enhanced
caliper or imaging logs to inspect the casing, the use of ultrasonic
and electromagnetic techniques in well pipes (Brondel et al., 1994),
the use of cathodic protection (where the casing would become the
cathode of an electrochemical cell), or the use of biocide/corrosion
inhibitor fluid in the annular space between the casing and tubing.
    CO₂ reacts with water to become acidic, potentially
accelerating corrosion of well materials. The CO₂ stream for
a GS project may also contain small volumes of impurities that could be
corrosive. Thus, EPA is proposing to require corrosion monitoring for
GS wells. Corrosion monitoring is further discussed in the monitoring
and testing section of this preamble.
    Injection Depth in Relation to USDWs: Today's proposal specifies a
requirement that such injection should be allowed only beneath the
lowermost formation containing a USDW. This is consistent with the
siting and operational requirements for all Class I hazardous injection
wells, and a very important protective component of the UIC program.
Placing distance between the point of injection and USDWs allows for
the necessary confining and buffer formations, and further provides for
opportunity for additional monitoring to detect any excursions from the
intended injection zone.
    However, EPA is not prescribing a minimum injection depth to keep
the CO₂ in a supercritical, liquid state after it is
injected, as some well operators may choose to inject the
CO₂ as a gas. If the trapping mechanism is sufficiently
protective, the injected CO₂ should be contained regardless
of its phase.
    Some stakeholders and co-regulators have proposed other approaches
for specifying an injection depth and these merit consideration by EPA.
For example, one approach would be to require a minimum injection depth
of approximately 800 m (2,625 feet) for GS of CO₂. The
geothermal gradient and weight of the fluid and rock layers above this
target depth would maintain CO₂ at a sufficiently high
pressure to keep it in a supercritical, liquid state. Storing
CO₂ at supercritical pressure would allow storage of greater
volumes and thereby increase available underground storage capacity.
Additionally, storing CO₂ in a supercritical, liquid state
may prevent the frequency of well mechanical integrity failure. When
supercritical CO₂ is injected into shallow formations where
pressures are not high enough to

[[Page 43512]]

maintain its supercritical state, it will revert to a gas. The
expansion of gaseous CO₂ will cause a drop in temperature
(the Joule-Thomson effect), and if this temperature drop is large
enough, freezing and thermal shock may take place in the vicinity of
the well. Thermal shock is a common cause of cracking in many types of
pressure equipment, and repeated exposure to such stresses could
compromise the integrity of the injection well's tubular components.
Participants at the Technical Workshop on Well Construction and MIT
suggested that these phase changes (i.e., supercritical liquid to gas)
are potentially a greater mechanical integrity concern than
corrosivity. Modeling by Oldenburg (2007) shows that if the pressure
drop is not large (less than 10 bars), this effect will not be great
enough to cause significant problems. However, technical workshop
participants concluded that more research is needed on the effects of
phase changes on well mechanical integrity.
    EPA is aware that the proposed requirement of injecting
CO₂ below the lowermost USDW may preclude injection into
certain targeted geologic formations, which may be storage sites
currently under consideration for GS. These formations may include
unmineable coal seams (those not being used for Class II enhanced coal
bed methane production), zones in between or above USDWs, and other
formations also under consideration. In areas of the country with very
deep USDWs, the need to construct GS wells beneath them may render GS
technically impractical. As a result, the Agency is considering and
requesting comment on alternative approaches that would allow injection
between and/or above the lowermost USDW, and thus potentially allow for
more areas to be available for GS while preventing USDW endangerment.
    One alternative under consideration is a provision for Director's
discretion to allow injection above or between USDWs in specific
geologic settings where the depth of the USDWs may preclude GS, make GS
technically challenging, or significantly limit CO₂ storage
capacity. Such approval by the Director would allow injection between
USDWs (and thereby allowing injection above the lowermost USDW) in
circumstances in which it may be demonstrated that USDWs would not be
endangered. An example where such injection may be appropriate presents
itself in areas such as the Williston and Powder River Basins in
Wyoming, North Dakota, and South Dakota, where receiving formations
(formations with large CO₂ storage capacity) for GS have
been identified above the lowermost USDW and where there may be
thousands of feet of rock strata between the injection zone and the
overlying and underlying USDWs. In these cases, injection above or
between USDWs may be appropriate, however, the Agency currently lacks
data to demonstrate that such practices are or are not protective of
USDWs.
    Also, EPA is considering allowing Directors to exempt all USDWs
below the injection zone. Currently, Directors may issue ``aquifer
exemptions'' which when approved, essentially determine that an aquifer
is no longer afforded protection as a USDW, in accordance with the
requirements of 40 CFR 144.7(b)(1). Aquifer exemptions are permitted
for mineral or hydrocarbon exploitation by Class III solution mining
wells, or by Class II oil and gas-related wells, respectively, and when
there is no reasonable expectation that the exempted aquifer will be
used as a drinking water supply (please see specific aquifer exemption
criteria at 40 CFR 146.4). When EPA exempts an aquifer, it is no longer
considered a USDW now or in the future. EPA limits aquifer exemptions
for injection operations to the circumstances where the necessary
criteria at 40 CFR 146.4 are met and not, in general, for the purpose
of creating additional capacity for the emplacement of fluids.
    EPA carefully considers all aspects of ensuring the protection of
USDWs before approving an aquifer exemption request for any injection
purpose in UIC programs which it implements. The Agency's
interpretation of the SDWA, and its own UIC regulations, currently
allows for aquifer exemptions sought for specific reasons (as outlined
above) and not solely for the purpose of relaxing well owner/operator
requirements, such as operating, monitoring, or testing. Therefore, in
general, the Agency does not consider aquifer exemption requests for
non-injection formations. It has also been EPA's long-standing policy
not to grant aquifer exemptions for the purpose of hazardous waste
disposal because of the infeasibility of meeting Class I hazardous
waste siting requirements (i.e., injection must be below the lowermost
USDW).
    However, aquifer exemptions could be issued for GS wells where
receiving formations are situated above the lowermost USDW and where
there are thousands of feet between the injection zone and the
overlying and underlying USDWs. In these circumstances, the permit
applicant would be required to meet all Class VI permit requirements.
    It is also anticipated that some aquifers previously exempted for
Class II injection operations may be appropriate formations for GS and
permit applicants may seek to use these formations. In such
circumstances, the permit applicant for a GS Class VI well would be
required to seek a new aquifer exemption for the purpose of GS, and
provide a non-endangerment demonstration that reflects the predicted
extent of the CO₂ plume, the associated pressure front, and
the scope of the injection activities.
    Furthermore, there may be other geologic settings with formations
that could receive and store CO₂ that are not below the
lowermost USDW. Such formations include deep, marginal USDWs directly
overlying crystalline basement rock and/or unmineable coal seams. Under
today's proposal, these formations would not qualify for GS without
aquifer exemptions. In these areas where USDWs directly overlie
crystalline basement rock, permit applicants may seek aquifer
exemptions and permits to inject CO₂ for GS into these
exempted aquifers. In unmineable coal seams that are USDWs or contain
or are bounded by formations that are USDWs, permit applicants may also
seek aquifer exemptions and permits for GS.
    In summary, EPA is soliciting comment on whether CO₂
injection should be allowed into an injection zone above the lowermost
USDW, when the Director determines that geologic conditions (e.g.,
thousands of feet of intervening formations between the injection zone
and the overlying and/or underlying USDWs) exist that will prevent
fluid movement into adjacent USDWs. EPA is also requesting comments on
whether aquifer exemptions should be allowed for the purpose of Class
VI injection, and under what conditions should such aquifer exemptions
be approved. Finally, EPA seeks comment on whether the Agency should
set a minimum injection depth requirement for CO₂ GS, rather
than require that such injection take place below the lowermost USDW.
    Tracers: While the UIC Program's protective elements greatly reduce
the potential for leakage, leakage is a possibility in any underground
injection project. Tracers may help facilitate leak detection. Though
use of tracers is not required under existing deep well requirements,
the buoyancy of CO₂ and the large volumes that are expected
to be injected may warrant improved leak detection for GS wells.
Detection of leakage of injected CO₂ at the surface would
indicate potential endangerment to USDWs. Additionally, if tracers are

[[Page 43513]]

used for CO₂ GS projects, they may also help owners or
operators to infer geochemical processes caused by CO₂
(e.g., dissolution or precipitation of calcium carbonate) that may pose
risks.
    Gaseous CO₂ is odorless and invisible. Tracers can be
odorants, such as those added to domestic natural gas, in order to
serve as a warning of a natural gas leak. Mercaptans are the most
effective odorants, however, they are not generally suitable for GS
because they are degraded by oxygen, even at very low concentrations.
The experience from the natural gas storage industry is that they are
scrubbed from the gas by adsorption to the formation in the subsurface.
Disulphides, thioethers and ring compounds containing sulfur are
options for CO₂ GS odorants (IPCC, 2005). However, there has
been no testing of these substances for GS, and it is unknown whether
using them for GS would be effective.
    Participants at the technical workshop on monitoring, measurement,
and verification (MMV) discussed the use of tracers in monitoring.
Measurement of stable isotopes of carbon (i.e., C12/C13 ratio) can
serve as tracers and may be useful for identifying the source of
CO₂ (e.g., anthropogenic or biological). Panelists also
addressed the potential utility of perfluorocarbon (PFC) and other
inert tracers in detecting CO₂ leakage. According to some
researchers, PFCs are conservative and will remain with the
CO₂. Unique suites (or batches) of PFCs can be created using
different combinations of PFCs. Different PFC suites can be used to
establish unique signatures for different time periods of prolonged
injection or for multiple CO₂ injections, making it feasible
to detect if a leak is transient versus long-term in nature.
    There may be potential benefits of tracers for CO₂ GS
operations, though tracers' effectiveness and cost-effectiveness are
debated. There are also technical challenges, such as false positives,
associated with their use that will vary on a case-by-case basis. In
addition, in the case of PFCs, which have a global warming potential
many orders of magnitude higher than CO₂, there may be
concerns about the consequences of potential releases to the
atmosphere. Today's proposal allows Directors' discretion on whether to
require the use of tracers, and if so, what types of tracers. EPA seeks
comment on the use of tracers in CO₂ GS operations, and any
potential impact of tracers on human health or ecosystems as they
relate to USDWs.
5. Proposed Mechanical Integrity Testing Requirements
    Injection well mechanical integrity testing (MIT) is a critical
component of the UIC Program's goal to protect USDWs. Testing and
monitoring the integrity of an injection well, at the appropriate
frequency, can verify that the injection activity is operating as
intended and does not endanger USDWs. MIT requirements for GS wells
should be tailored to address the unique properties of CO₂,
specifically its buoyancy and potential corrosivity, so that owners or
operators of GS projects will be able to detect defects within the
well, and between the well and the borehole, before these defects could
allow GS-related fluids to move into unintended formations or toward
USDWs.
    Currently, all UIC injection well owners or operators must
demonstrate that their wells have both internal and external mechanical
integrity (MI) (40 CFR 146.8). An injection well has internal MI if
there is an absence of leakage in the injection tubing, casing, or
packer. Typically, internal mechanical integrity testing is
accomplished with a periodic pressure test of the annular space between
the injection tubing and long string casing of this annual space.
Usually, loss of internal MI is due to corrosion or mechanical failure
of the injection well's components. Rarely, because of the multiple-
barrier nature of injection well construction, do internal MI losses
result in leakage outside of the well and present an endangerment to a
USDW.
    Injection well external integrity is demonstrated by establishing
the absence of fluid flow along the outside of the casing, generally
between the cement and the well structure, although such flow may also
occur between the cement and the well bore itself. This is typically
accomplished through the use of down-hole geophysical logs or surveys
designed to detect such leaks, once every five years. Failure of an
external MIT can indicate improper cementing or degradation of the
cement that was emplaced to fill and seal the annular space between the
outside of the casing and the well borehole. This type of failure can
lead to movement of injected fluids out of intended injection zones and
toward USDWs. As with internal MI failure, temporary loss of external
MI rarely results in endangerment to USDWs.
    Failure of either external or internal mechanical integrity may
mean that one of the multiple protective layers in an injection well is
not operating as intended. Proper testing can serve as an early warning
to owners or operators that the well is not performing optimally and
that maintenance or repair of a component of the well is needed before
the injectate moves to unintended zones or a USDW is impacted.
    The decades of State and EPA experience with Class I and Class II
mechanical integrity testing requirements provides the best knowledge
base for identifying appropriate MIT requirements for GS projects. This
is supported by findings from technical workshops, conferences, and
research. However, because of the buoyant and corrosive properties of a
GS stream, current deep well internal and external MIT requirements
will need to be tailored in order to ensure the protection of USDWs.
    As previously discussed, internal MI testing is designed to
evaluate the condition of internal well components. The evaluation is
typically accomplished with an annual pressure test. However, due to
the nature of the GS injection stream, corrosivity must be considered
when planning for MITs in GS projects. Studies conducted by EPA of
previous MIT results suggest that wells injecting corrosive fluids fail
MITs at rates 2 to 3 times higher than those that inject non-corrosive
fluids. Thus, a more corrosive injectate is a potential risk factor for
MIT failure.
    Therefore, today's proposal would require owners or operators of
Class VI GS projects to monitor internal mechanical integrity of their
injection wells by continuously monitoring injection pressure, flow
rate, and injected volumes, as well as the annular pressure and fluid
volume to assure that no anomalies occur that may indicate an internal
leak. EPA requests comment on the practicability of this requirement.
    Continuous internal mechanical integrity monitoring of GS project
injection wells, instead of periodic testing (which is required for
most other types of deep injection wells) is important because the
corrosive nature of GS waste streams makes immediate identification of
corrosion-related well integrity loss critical. Today's proposal would
also require automatic down-hole shut-off mechanisms (see proposed
injection well operating requirements section) in the event of an MI
loss. Continuous computer-driven monitoring of internal MI would need
to be performed in order for automatic shut-off systems to be
activated. This combination of computer-driven continuous internal
monitoring linked to an automatic down-hole injection shut-off provides
the maximum protection to USDWs and the earliest

[[Page 43514]]

warning to owners or operators that repairs need to be performed.
    This proposed requirement would eliminate the necessity of
conducting other periodic internal MITs. However, today's proposal
would provide the Director with the discretion to request any other
additional tests necessary to ensure the protection of USDWs.
    As mentioned above, external mechanical integrity testing is used
to determine the absence of fluid leaks behind the long string casing.
Instead of requiring external MI to be demonstrated every five years
(which is typical for other types of deep injection wells), today's
proposal would require owners or operators of CO₂ wells to
demonstrate injection well external mechanical integrity at least once
annually. This increase in testing frequency (from once every five
years to once a year) is justifiable for the protection of USDWs given
the potential corrosive effects on injection well components (steel
casing and cement) that are exposed to the GS stream and the buoyant
nature of the injected fluid that tends to force it upward toward
USDWs.
    Today's proposal does not change the existing allowable methods for
demonstrating external MI in deep injection wells. They would include
the use of a tracer survey, a temperature or noise log, a casing
inspection log if required by the Director, or an alternative approved
by the Administrator and, subsequently, the Director. Today's proposal
would also provide the Director with the discretion to request
additional tests.
    EPA proposes that owners or operators report semi-annually on the
injection pressure, flow rate, temperature, volume and annular
pressure, and on the results of MITs. This reporting frequency, which
is the same as for other deep injection well classes, has proven to be
timely for notification to permitting authorities on the status of the
operation.
    EPA seeks comment on the appropriate frequency of internal and
external MITs for GS injection wells, the appropriate types of MITs,
and how to optimize MIT methods for GS.
6. Proposed Plume and Pressure Front Monitoring Requirements
    Monitoring associated with UIC injection wells is required to
ensure that the injectate is safely confined in the intended subsurface
geologic formations and USDWs are not endangered. Certain existing UIC
program monitoring requirements apply to all wells, while others are
based on site-specific information and Director's discretion.
Information obtained through monitoring may be used to maintain the
efficiency of the storage operation, minimize costs, and confirm that
injection zone pressure decline follows predictions. Monitoring results
of GS wells would also be used as data inputs for reevaluation of the
site computational model and AoR and corrective action.
    EPA considers CO₂ plume and associated pressure front
monitoring to be necessary for verification of model predictions. An
integrated monitoring and modeling strategy should be used to track the
evolution of the CO₂ plume and associated pressure front.
Monitoring may be conducted with a combination of direct and indirect
techniques appropriate for the conditions of specific GS projects.
Monitoring is necessary to verify initial model predictions given the
uncertainty of CO₂ fate and transport; because large volumes
of CO₂ will be injected during GS operations; and because of
the challenges of comprehensive site characterization in large
formations that may be used for GS projects. Monitoring results should
be used to assess CO₂ movement through high-permeability
regions (i.e., faults, fractures) not detected in site characterization
and included in initial site modeling. Early pilot-projects have
indicated that the most complete understanding of the site-specific
behavior of CO₂ will result from monitoring the movement of
CO₂ itself (e.g., Doughty et al., 2007).
    EPA seeks comment on the requirement for monitoring of GS sites for
the purpose of tracking the location of the CO₂ plume and
associated pressure front over time.
    Testing and Monitoring Plan: A monitoring program for a GS project
should be designed to detect changes in ground water quality and track
the extent of the CO₂ plume and area of elevated pressure.
Today, EPA is proposing that owners or operators of Class VI wells
would submit, with their permit application, a testing and monitoring
plan to verify that the GS project is operating as intended and is not
endangering USDWs. This plan would be implemented upon Director
approval and would include, at a minimum, analysis of the chemical and
physical characteristics of the CO₂ stream; monitoring of
injection pressure, rate, and volume; monitoring of annular pressure
and fluid volume; corrosion monitoring; a demonstration of external
mechanical integrity (see proposed mechanical integrity testing
requirements section of the preamble); a determination of the position
of the CO₂ plume and area of elevated pressure; monitoring
of geochemical changes in the subsurface; and, at the discretion of the
Director, monitoring for CO₂ fluxes in surface air and soil
gas, and any additional tests requested by the Director.
    Monitoring within multiple layers (i.e., in the primary confining
system; in USDWs and other shallow layers; and, at the surface)
supports a multi-barrier approach to protecting USDWs. Surface air and/
or soil gas monitoring may be used as the last line of monitoring to
ensure that there has not been vertical CO₂ leakage, which
could endanger USDWs. The program should also be site-specific, based
on the identification and assessment of potential CO₂
leakage routes complemented by computational modeling of the site.
    Under today's proposal, owners or operators would be required to
analyze the CO₂ stream at a frequency sufficient to yield
data representative of its chemical and physical characteristics. This
analysis will provide information on the content and corrosivity of the
injected stream, which in turn will support improvements in well
construction and optimization of well operating parameters. EPA also
proposes that owners or operators would monitor well materials for
signs of corrosion, such as loss of mass, thickness, cracking, or
pitting. The proposed requirements are critical to address the
potential well integrity concerns associated with the corrosive nature
of the CO₂ stream, to avoid (or provide early warning of)
corrosion of well materials, and to protect the integrity of GS wells.
Today's proposal would also require continuous monitoring of the
injection pressure, rate and volume, as well as annular pressure and
fluid volume discussed in the well construction and operation section
of the preamble.
    Monitoring CO₂ Movement and Reservoir Pressure:
Monitoring subsurface geochemistry and the position of the
CO₂ plume and pressure front are necessary to verify
predictions of plume movement, provide inputs for modeling, identify
needed corrective actions, and target geochemical and surface
monitoring activities.
    Under today's proposal, owners or operators would be required to
track the subsurface extent of the CO₂ plume and pressure
front using pressure gauges in the first formation overlying the
confining zone or using indirect geophysical techniques (e.g., seismic,
electrical, gravity, or electromagnetic surveys) or other down-hole
CO₂ detection tools, monitor for geochemical changes in
subsurface formations, and if directed, monitor at the surface. Today's

[[Page 43515]]

proposal would also require owners or operators to monitor ground water
quality and geochemical changes above the confining system. The results
of this monitoring would be compared to baseline geochemical data to
identify changes that may indicate unacceptable movement of
CO₂ or formation fluids.
    In order to provide guidance related to monitoring of GS sites, EPA
invited expert advice and reviewed technical documentation. EPA held a
technical workshop on measurement, monitoring, and verification 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.
    Monitoring within the confining zone for pressure, pH, salinity, or
the presence of dissolved minerals, heavy metals, or organic
contaminants requires direct access to the subsurface via monitoring
wells. Wells installed for this purpose would be strategically placed
in areas predicted to overlie the eventual CO₂ plume and
area of elevated pressure. Well number and placement would be based on
project specific information such as injection rate and volume, site
specific geology, baseline geochemical data, and the presence of
artificial penetrations. Predictive models of the extent and direction
of plume movement can support decisions about monitoring well
placement. This has the dual benefit of targeting resources associated
with what is an expensive monitoring activity and minimizing the number
of artificial penetrations near the injection well, which could
potentially become conduits for fluid movement into USDWs.
    Today's proposal would require that owners or operators perform a
pressure fall-off test at least once every five years. Pressure fall-
off tests are designed to ensure that reservoir injection pressures are
tracking to predicted pressures and modeling input. They may be used in
project siting and AoR calculations. Results of pressure fall-off tests
may indicate mischaracterization of the site specific geology and
potentially unidentified leakage pathways. EPA seeks comment on the use
and frequency of pressure fall-off testing for GS wells.
    Pressure monitoring, both at the surface and in the formation, is a
routine part of CO₂ injection projects that serves several
purposes. For instance, monitoring pressure in injection wells allows
for use of shut-off valves in the event that injection pressure exceeds
the formation fracture pressure, or pressure drop-offs indicate a
subsurface leak (IPCC, 2005). Pressure monitoring in monitoring wells
provides an indication of whether there is potential for brine
intrusion into USDWs and CO₂ leakage. When combined with
information on temperature, pressure data provide an indication of the
phase (e.g., gas, supercritical) and amount of the injected
CO₂.
    Various pressure sensors are available, and monitoring can be
conducted continuously. Conventional sensor types include piezo-
electric transducers, strain gauges, diaphragms, and capacitance gauges
(Burton et al., 2007). Fiber optic pressure and temperature sensors are
also now commercially available and can be installed down-hole and
connected to the surface through fiber optic cables. According to
Burton et al. (2007), current monitoring technologies are more than
adequate for monitoring pressure in a GS project.
    Direct geochemical monitoring is an important part of a monitoring
program. Temperature, salinity, and pH should be monitored, as these
parameters provide basic information for understanding water and gas
geochemistry. Additionally, obtaining ground water samples via
monitoring wells allows direct measurement of aqueous and pure-phase
CO₂. By studying the interactions between brine and
CO₂, it can be determined whether precipitation and/or
dissolution of minerals is occurring (Nicot and Hovorka, 2008). These
analyses will also indicate the rate of CO₂ trapping
mechanisms, and whether mineral dissolution may be causing permeability
changes in the formation or impacting USDWs. Geochemical monitoring may
also be conducted for heavy metals and organic contaminants that may
potentially be mobilized in the formation due to injection.
    Information and discussions from EPA technical and public workshops
indicate that the collection of adequate baseline (pre-injection) data
is critical for planning monitoring and for detecting CO₂
movement and leakage during and after injection.
    While the use of tracers is not a specific monitoring requirement
in today's proposal (per III.A.4), some Directors may require owners or
operators to use them. EPA has considered the merits of tracers for
CO₂ monitoring and recognizes that they may also be
voluntarily employed by owners or operators. Tracers can also be
measured through direct geochemical sampling to indicate the speed and
direction of movement of CO₂ after injection. Naturally
occurring tracers include stable isotopes (atoms of a particular
element with different numbers of neutrons) of carbon and oxygen.
Analyses of the amounts of carbon-13 and oxygen-18 isotopes in water
are commonly used to track movement through the environment and to
elucidate geochemical processes. It is also possible to include
tracers, such as perfluorocarbons or noble gases, with the injected
CO₂ (Nimz and Hudson, 2005). Loss of tracers between the
injection well and monitoring well may indicate diffusion into low-
permeability materials, sorption, partitioning into non-aqueous phase
liquids, partitioning into trapped gas phases, or leakage of
CO₂ (Nicot and Hovorka, 2008). Tracers were more fully
discussed in the well construction and operation section of the
preamble.
    There are several technical challenges associated with in-situ
monitoring of formation fluids via wells. In the course of sample
retrieval, there will be pressure changes, causing changes in
CO₂ solubility and pH. To address this, LBNL developed a
``U-tube'' sampling apparatus to enable collection of fluid and gas
samples at in-situ pressure conditions. Also, samples collected from
monitoring wells are point measurements that may not fully represent
the entire reservoir, especially if there are extensive physical
heterogeneities.
    Geophysical Methods for Plume Tracking: Various non-invasive deep
subsurface monitoring techniques are available to track the movement of
the CO₂ plume. Many of these methods have been developed for
use in the oil and gas industry, and some may also support certain
aspects of baseline geologic characterization. Seismic and electrical
techniques have been used to gather data related to rock composition,
porosity, fluid content, and in-situ stress state.
    In seismic surveying, a controlled source of seismic energy is used
to send vibrations through the ground. The time it takes for the
seismic waves to reflect off of a subsurface feature and reach a
receiver at the surface provides information about the depth of the
feature. By using an array of receivers, possible plume and leakage
flowpaths may be discerned. Seismic surveys may also be useful for
monitoring how rock properties change with time during injection and
for mapping of the CO₂ plume. This method has been used to
study the subsurface in the area near the injection well for the
CO₂-SINK project in Germany (Juhlin et al., 2006) and at the
Sleipner and In Salah sites. Seismic

[[Page 43516]]

studies can also be done in a crosswell arrangement by placing an array
of receivers in one borehole and drawing a seismic source upwards in
another borehole, firing at periodic intervals. Current crosswell
experience relevant to CO₂ sequestration includes successful
imaging of CO₂ saturation and pressure effects in a
carbonate reservoir in West Texas (Harris and Langan, 2001). Vertical
seismic profiling (VSP), conducted by placing geophones in a vertical
array inside a borehole and measuring sound sources originating at the
surface, is another promising technology for plume detection and
monitoring.
    Electrical methods rely on the electrical properties of the medium
being studied and offer promise for CO₂ plume monitoring.
Electromagnetic (EM) surveys induce a current in subsurface materials,
and conductivity meters detect areas with increased conductivity. Near
the surface, EM can detect buried metal objects and contaminated soils.
In the deeper subsurface, EM surveys can be used to detect certain
contaminant plumes. EM surveys can also be done in crosswell fashion.
At Lawrence Livermore National Laboratory, researchers are conducting a
long-term study using time-lapse multiple frequency EM survey
characterization to image CO₂ injected as part of an EOR
operation (Kirkendall and Roberts, 2001).
    Electrical resistance tomography (ERT) measures electrical
resistance by means of electrodes that may be placed at the surface,
but are more commonly arrayed down boreholes in a crosswell
configuration. Because the electrical properties of a medium are
sensitive to fluid chemistry, ERT can be used for monitoring fluid
migration in the subsurface. The oil industry has used ERT, and it has
been also used for environmental applications such as detection of
contaminant plumes at waste sites. Newmark (2003) reported preliminary
data on the use of crosswell ERT at an EOR site to monitor for
CO₂.
    Microgravity surveys detect density variations in the subsurface
using sensitive gravity measurements made at the (ground) surface.
Microgravity surveys have been used to characterize subsurface
formations, and given the density differences between CO₂
and formation brines, may be useful for tracking a CO₂
plume. Nooner et al. (2003) discuss use of microgravity surveys at the
Sleipner CO₂ GS project in Norway.
    GEO-SEQ (2004) discusses the capabilities of seismic and electrical
crosswell methods for CO₂ GS. The authors note the high
spatial resolution of these methods and state that they can image leaks
and fluid saturation within a reservoir. Simulations discussed in the
manual confirm that seismic and electrical conductivity crosswell
methods could provide information on the saturation of CO₂
within the reservoir between wells. The authors note that seismic
crosswell methods could also be used to detect CO₂ phase
changes. Although these methods are costly and time consuming, they may
prove useful at GS sites in the future. To fully implement these
technologies, additional research is needed regarding the electrical
and seismic properties of subsurface media containing CO₂.
    Some stakeholders expressed concerns about the usefulness of
seismic surveys as a CO₂ tracking tool under certain
geologic conditions, particularly given the cost of specific
technologies. Based on information evaluated to date, EPA believes that
tracking the plume and pressure front is an important companion step to
address any uncertainties associated with initial AoR modeling and
requests comment on this approach and more efficient alternatives that
may be used to track the plume and pressure front.
    As such, allowing flexibility in choosing the plume tracking
methods and other monitoring technologies may provide an appropriate
balance between the protective nature of indirect monitoring and cost
considerations, as well as allowing for the adoption of continuously
advancing technology.
    Surface Air and Soil Gas Monitoring: Surface air measurements can
be used to monitor the flux of CO₂ out of the deep
subsurface, with deviations from background levels representing
potential leakage. If deviation in the flux of CO₂ is
detected, it may indicate potential endangerment of USDWs. While
subsurface monitoring forms the primary basis for protecting USDWs,
near-surface and surface techniques could be the last line of
monitoring. Under today's proposal, owners or operators could, at the
Director's discretion, be required to conduct surface air monitoring
and/or soil gas monitoring in the AoR. Knowledge of leaks to shallow
USDWs is of critical importance since these USDWs are more likely to
serve public water supplies than deeper formations. If leakage to a
USDW should occur, near-surface and surface monitoring can identify the
general location of the leak.
    A range of techniques employed at varied monitoring frequencies are
available for implementation. Optimal spacing of monitoring wells, eddy
covariance towers, or soil gas chambers would need to be selected, and
may be based on the outcome of other monitoring techniques such as
seismic or Electrical Resistance Tomography (ERT).
    For surface air monitoring, chambers can be placed directly on the
soil and trapped gases are passed through an infrared gas analyzer to
determine CO₂ content (GEO-SEQ, 2004). Changes in
CO₂ concentration and air flow rates are used to calculate a
flux. Measurements using chambers are typically conducted along a grid,
which has the benefit of defining spatial and temporal variations in
CO₂ flux that could be used for pinpointing and quantifying
any leaks. Chamber measurements, however, are labor-intensive and are
not efficient for sampling over large areas. For each of these methods,
baseline (pre-injection) monitoring is very important in order to
establish conditions for future comparison. There are natural sources
of CO₂ that can have wide variability and thus could mask
leakage from a GS operation.
    Eddy covariance techniques have been used for ecological
applications to measure carbon fluxes from vegetated areas, and show
promise for CO₂ monitoring for GS operations (Miles et al.,
2005). The equipment is installed on a tower and CO₂ is
measured with an infrared gas analyzer (GEO-SEQ, 2004). Wind velocity,
relative humidity, and temperature are also measured and the
information is integrated to calculate a CO₂ flux. The
height of the tower controls the aerial coverage, with higher towers
averaging over larger areas. Because of the large coverage, the exact
location of a leak would be difficult to pinpoint, and this method may
be better for detecting slow, diffuse leaks. Eddy covariance also
assumes a horizontal and homogeneous land surface, which may not hold
true for all GS locations. It does have the advantage of being
automated, greatly reducing the labor involved.
    Hyperspectral image analysis is a form of remote sensing that has
been used, among other applications, for mapping vegetation habitat
boundaries and for differentiating species types. Scanners collect
images of a given feature using a number of relatively small wavelength
bands, including the visible and infrared portions of the spectrum.
Because different elements have different spectral signatures, a
hyperspectral image can convey information about composition. The
potential utility for CO₂ monitoring would be the ability to
map the response of vegetation to elevated soil CO₂
concentrations (Pickles and Cover, 2005).

[[Page 43517]]

    LIDAR (light detection and ranging) is a remote sensing method that
is used extensively in atmospheric science, and is currently under
investigation as an option for CO₂ detection to monitor GS
sites (Benson and Myer, 2002). Similar in principle to RADAR, LIDAR
uses light instead of radio waves, permitting resolution of very small
features, such as aerosols. Light is pulsed from a laser and various
constituents in the atmosphere reflect back some of the light. A number
of properties of the backscattered light allow one to infer the
atmospheric composition, including concentrations of CO₂.
Currently, differential absorption LIDAR (DIAL) is being studied by
researchers at Montana State University for detecting CO₂
leaks in pipelines.
    EPA proposes that owners and operators report semi-annually on the
characteristics of injection fluids, injection pressure, flow rate,
temperature, volume and annular pressure, and on the results of MITs,
ground water monitoring, and any required atmospheric/soil gas
monitoring.
    EPA seeks comment on the appropriate amount and types of monitoring
that should be conducted at a GS site. Specifically, EPA seeks comment
regarding the usefulness of indirect geophysical monitoring and surface
air and soil gas monitoring. In addition, EPA seeks comment regarding
the use of a Director-approved monitoring plan for GS sites.
7. Proposed Recordkeeping and Reporting Requirements
    Submissions Required for Consideration of Permit Applications:
Today's proposal would require that owners and operators submit
relevant site information to the permitting authority for consideration
of permit applications. This information includes maps of the injection
wells, the AoR as determined through computational modeling, all
artificial penetrations within the AoR, maps of the general vertical
and lateral limits of USDWs, maps of the geologic cross sections of the
local area, the proposed operating data and injection procedures,
proposed formation testing program, and stimulation program, well
schematics and construction procedures, and contingency plans for shut-
ins or well failures. EPA is also proposing that permit applicants
submit a demonstration of financial responsibility to plug the well, to
provide for post-injection site care, and site closure.
    EPA is proposing today that permit applications for GS sites
include several plans not currently required under existing UIC
regulations. These plans include a monitoring and testing plan, an AoR
and corrective action plan, and a post-injection site care and site
closure plan. The requirement for additional plans is intended to
provide the Director the opportunity to assess proposed project
operating procedures, and addresses GS requirements that are seen to be
site-specific (e.g., what monitoring techniques will be used). In
addition, these plans are intended to establish an ongoing dialogue
between the operator and the permitting authority which is more
substantial than that required for other classes of injection wells.
EPA seeks comment on the merits of requiring plans for monitoring, AoR,
and post-injection site care as part of a permit application.
    Operational Recordkeeping and Reporting Requirements: Under current
UIC requirements, operators must report on a regular basis to the
permitting authority, the physical and chemical characteristics of the
injected fluids, as well as other operational data. For Class I
industrial and Class I hazardous waste wells and Class III wells,
operators must submit this information on a quarterly basis. For Class
II wells, operators must submit this information on an annual basis.
Today's proposal would require that owners or operators of Class VI
wells report semi-annually to the permitting authority, on the physical
and chemical characteristics of injection fluids, injection pressure,
flow rate, temperature, volume and annular pressure, annulus fluid
volume added, and the results of MITs, plume tracking, and atmospheric/
soil gas monitoring. Additionally, owners and operators will be
required to submit the results of AoR modeling revisions; any updates
to the information on the type, number, and location of all wells
within the site AoR; and information on additional corrective action
performed or planned based on AoR reevaluations. EPA considers a less
frequent reporting requirement for Class VI wells compared to Class I
wells appropriate considering the ongoing dialogue for Class VI wells
established by multiple plans as discussed above.
    Under today's proposal, owners and operators would also be required
to maintain recordkeeping and reporting information for the duration of
the project, as well as three years after site closure (following the
post-injection site care period); and to keep their most recent
plugging and abandonment report for one year following site closure.
    Reporting Associated with Well Plugging, Post-injection Site Care,
and Site Closure: EPA proposes that owners or operators notify the
Director at least 60 days prior, or at a Director-determined time, of
their intent to plug the well and of any updates to the post-injection
site care and site closure plan. After the well is plugged, owners and
operators would submit a well plugging report stating that the well was
plugged in accordance with the approved post-injection site care and
site closure plan or specify the differences between the plan and the
actual well plugging. During the post-injection site care (monitoring)
period, owners or operators would report periodically on the results of
monitoring. At the end of the post-injection site care period, owners
or operators would submit a site closure report, along with a non-
endangerment demonstration showing that conditions within the
subsurface indicate that no additional monitoring is necessary to
assure that there is no endangerment to USDWs associated with the
injection.
    EPA seeks comment on the frequency of all proposed reporting
requirements.
    Electronic Reporting and Recordkeeping: Under today's proposal, EPA
would require owners or operators to report data specified in section
146.91 in an electronic format acceptable to the Director for site,
facility, and monitoring information. At the discretion of the
Director, formats other than electronic may be accepted after a
determination has been made that the entity does not have the
capability to use the required format. Long-term retention of records
in an electronic format may also be required at the Director's
discretion. If records are stored in an electronic format, information
should be maintained digitally in multiple locations (i.e., backed-up)
in accordance with best practices for electronic data.
    EPA has previously required electronic reporting of monitoring data
in the program implemented under the Unregulated Contaminant Monitoring
Rule (64 FR 50611, September 17, 1999, 40 CFR 141.35(e)). EPA believes
that the permit applicants will have the resources to provide
electronic data to the permit authority and that electronic reporting
will reduce future burden related to recordkeeping. In addition,
electronic data submissions will facilitate the application review
process and make it easier to track progress of GS projects. EPA is
committed to providing resources to States to develop the capability to
exchange data electronically. Several States have received grants to
develop electronic data exchange capability for their current UIC
programs.

[[Page 43518]]

    EPA seeks comment on the requirement for electronic reporting in
today's proposed rule. In addition to the above recordkeeping and
reporting requirements, EPA considered a requirement for owners or
operators of GS sites to provide an annual report during the lifetime
of the project, including the post-injection period, regarding the GS
operation. This report would describe the status of the operation, any
new data about the site including operational and monitoring data, new
GS operations, or other activities that may affect the plume movement,
any non-compliance, and knowledge gained on GS technology that could
contribute to the state of the science on GS. This requirement would
address the unique and large-scale nature of CO₂ GS
operations, provide the public with information regarding the
operation, and facilitate information transfer about GS technology.
Although EPA has not included a requirement for this report in today's
proposal, EPA seeks comment regarding the necessity for such an annual
report.
8. Proposed Well Plugging, Post-Injection Site Care, and Site Closure
Requirements
    Today's proposal outlines well plugging and post injection site
care requirements for CO₂ injection sites after injection
activities end. If finalized, these new requirements at 40 CFR 146.92-
146.93 would ensure that owners or operators plug wells and manage
sites in a manner so that wells do not serve as a conduit for escape of
stored CO₂ through unexpected migration from the injection
site after injection ends, preventing endangerment of USDWs. EPA is
proposing to give owners or operators flexibility in meeting the well
plugging requirements by allowing the owner or operator to choose from
available materials and tests to carry out the proposed requirements.
EPA is not specifying the types of materials or tests that must be used
during well plugging because there are a variety of methods that are
appropriate and new materials and tests may become available in the
future. EPA is also proposing that a combination of a fixed timeframe
and performance standard be used to determine the duration of the post-
injection site care period.
    Steps in Injection Well Plugging: EPA is proposing that owners or
operators develop a well plugging plan, and conduct several activities
associated with the plugging of GS wells. Injection well plugging must
comply with requirements of 40 CFR 144.12(a). The plan includes: (1)
Providing notice of intent to plug a well at least 60 days prior to
well plugging, (2) flushing each well to be plugged with a buffer
fluid, (3) testing the mechanical integrity of each well, (4) plugging
each well in a manner that will prevent the movement of fluid that may
endanger USDWs, and (5) submitting a plugging report within 60 days
after plugging the well or at the time of the next semi-annual report
(whichever is less).
    Notice of intent to plug: The notice of intent to plug provides a
60-day advance notice to the Director that the owner or operator
intends to close the well. If circumstances warrant a shorter time
period for giving notice of intent to plug, the Director may approve a
shorter notice period.
    Well Flushing: Flushing removes fluids remaining in the long string
casing that could react with the well components over time. Fluids used
for flushing may vary, but must provide sufficient buffering ability to
avoid the possibility of reactions due to residual CO₂ or
other contaminants in the fluid.
    Mechanical Integrity Testing: Mechanical integrity testing allows
owners or operators to ensure that the long string casing and cement
that are left in the ground after well plugging and site closure
maintain integrity over time. For GS wells, there are a number of
methods that can be used to test mechanical integrity, including
pressure tests with liquid or gas, radioactive tracer surveys, and
noise, temperature, pipe evaluation, or cement bond logs.
    Well Plugging: The Agency is proposing that owners or operators
plug wells in a manner that does not endanger USDWs. This may be
accomplished in a number of ways using a number of different types of
materials. In the case of GS wells, the plugging materials must be
compatible with the fluids with which the materials may be expected to
come into contact and plugged to prevent the movement of fluids either
into or between USDWs.
    Plugging Report: The owner or operator would be required to submit
a report which includes information on the implementation of the
plugging plan, including the date the well was plugged, the activities
conducted to prepare the well for plugging, the materials used for
plugging, and the location of the well. The owner or operator may
either submit the plugging report as a separate report within 60 days
after the plugging activity, or update the semi-annual report required
at 40 CFR 146.92 of this proposed rule to include plugging information
and submit the updated report within 60 days after the plugging
activity. EPA is proposing that the owner or operator must certify that
the plugging report is accurate. If the well was plugged by an entity
other than the owner or operator, that entity must also certify that
the plugging report is accurate.
    In addition, EPA is proposing the owners or operators prepare for
eventual site closure in advance of the time when well plugging
activities take place to ensure that a plan is in place in the event of
an unexpected need to plug a well or close the site. Today's proposal
would require owners or operators to submit a well plugging plan at the
same time the permit application is submitted and to have this plan
approved by the Director. As part of the well plugging plan, the owner/
operator would be required to conduct certain activities related to
well plugging, and provide the information related to well plugging,
including the following: (1) Testing methods used to determine that the
components of the well will maintain mechanical integrity over time;
(2) type and number of plugs to be used; (3) placement of each plug,
including the elevation of the top and bottom of each plug; (4) type,
grade, and quantity of material to be used in plugging; and (5) method
used to put plugs in place. In addition, if for any reason the well
plugging activities stated in the plan no longer reflect what is likely
to occur upon plugging of the well, the owner or operator would be
required to make changes to the plan and submit to the Director for
approval before notifying the Director of intent to plug the well.
    Post-Injection Site Care: Today's proposal would also require that
owners or operators (1) develop a post-injection site care and closure
plan, (2) monitor the site following cessation of the injection
activity, and (3) plug all monitoring wells in a manner which prevents
movement of injection or formation fluids that could endanger a USDW.
    The post-injection site care and site closure plan would be
required to be submitted as part of the permit application and approved
by the Director. It describes several activities associated with the
post-injection site care and site closure of GS sites. Activities that
would be required in the post-injection site care and site closure plan
include: (1) Record of the pressure differential between pre-injection
and anticipated post-injection pressures in the injection zone; (2)
predicted position of the plume and associated pressure front at the
time the site is closed; (3) description of post-injection monitoring
location(s), methods, and proposed frequency of monitoring; and (4)
schedule for submitting post-injection site care and monitoring

[[Page 43519]]

results to the Director. In addition, if for any reason the post-
injection site care and site closure activities stated in the plan no
longer reflect what is likely to occur upon closing the site, the owner
or operator would be required to make changes to the plan and submit
the plan to the Director for approval within 30 days of such change.
Examples of factors which may require a modified post-injection site
care and site closure plan would include changes in injection
procedures or volumes or plume movement in an unanticipated direction.
    Upon permanent cessation of injection, the owner or operator would
either submit an amended post-injection site care and site closure or
demonstrate to the Director through monitoring and modeling results
that no amendment to the plan is needed. Owners or operators would also
be required to use any other information deemed necessary by the
Director to make this demonstration.
    The post-injection site care and site closure plan would include a
description of the monitoring that will occur after injection ceases.
The owner or operator would monitor the site to show the position of
the CO₂ plume and pressure front and demonstrate that USDWs
are not being endangered. A record of the pressures in the injection
formation and surrounding areas as well as the pressure decay rate can
help the owner or operator determine that the injected fluid does not
pose endangerment to USDWs.
    Post-Injection Site Care Timeframe: Current UIC regulations do not
limit the duration of the post-injection site care period; however,
many environmental programs use a 30-year period as a frame of
reference. In many cases, a 30-year timeframe has been sufficient to
determine that remaining pressure in plugged wells containing liquids
will not lift fluid to overlying strata (53 FR 28143, July 26, 1988).
However, characterizing post-injection site care timeframes for GS is
more challenging. Given the buoyancy of CO₂, viscosity, and
large injection volumes associated with GS, the area over which
CO₂ will spread in the subsurface is likely to be larger
than for existing well classes and therefore, the area over which there
is potential for endangerment of USDWs is likely to be greater. The
presence of physical and geochemical trapping mechanisms is likely to
reduce the mobility of CO₂ over time and research also
suggests that pressure within the storage system will drop
significantly when injection ceases, thus decreasing the risks of
induced seismic activity, and faulting and fracturing and making
storage more secure over longer timeframes. However, the timeframe over
which this happens is difficult to define because it is based on site-
specific considerations.
    EPA considered three distinct alternatives for determining post-
injection site care and monitoring timeframes (1) establishing a fixed
timeframe for post-injection site care; (2) allowing a performance-
based approach to the post-injection site care time period; and (3) a
combination of fixed timeframe and performance standard.
    EPA considered the approach of specifying a fixed duration of time
after which the post-injection site care ends. As part of this
approach, EPA evaluated four different timeframes: 10, 30, 50, and 100
years.
    EPA reviewed studies, industry reports and environmental programs
to determine appropriate post-injection site care timeframes. Studies
reviewed included those done by: Flett M., Gurton R., and G. Weir.
2007; Obi E.I., and M.J. Blunt. 2006; and Doughty, C. 2007 (see USEPA,
2008d). A review of these studies suggests that the actual time for
CO₂ plume stabilization (i.e., slowing down or cessation of
plume movement, and/or immobilization of most of the CO₂
mass through various trapping mechanisms) will be very site specific,
being influenced by geologic factors such as formation permeability,
geochemistry, and the degree of capillary trapping. In addition,
predicted results will depend on several modeling considerations and
assumptions, and thus will be to some degree model specific. Based on a
review of the three studies used for this preliminary analysis,
modeling results indicate that the CO₂ plume stabilized on
the time frame of 10-100 years after the cessation of injection (USEPA,
2008d).
    EPA also reviewed an IOGCC Task Force report which suggests a 10-
year time frame for the post-injection site care period which commences
when injection ceases until the release of the operator from liability.
Alternatively, some environmental programs--including the UIC Program--
use a 30-year period as a frame of reference.
    While 10 years may be within the timeframe suggested in some
studies, there are circumstances under which the potential risks of
endangering USDWs will not decline within that timeframe given that
stabilization may continue for several decades (USEPA, 2008d). Also, a
30-year timeframe can be appropriate for the types of fluids typically
injected under the UIC Program (i.e., fluids that are liquids at
standard pressure and temperature). Longer timeframes may be more
appropriate for GS wells, because the fluid is likely to be stored in a
supercritical phase, the plume for a full-scale GS project will likely
be large, and substantial pressure increases will likely be observed
during operation. However, once injection ceases, pressure will likely
begin to dissipate and 30 years may be enough time for the plume and
pressure front to stabilize.
    Another option considered by the Agency is to apply a performance
standard, i.e., that post-injection site care will continue until the
plume is stabilized and cannot endanger USDWs. Current UIC regulations
at 40 CFR 146.71 utilize a performance type approach by requiring that
the owner or operator of a Class I hazardous well observe and record
pressure decay for a time specified by the Director. A similar
performance standard could be considered for GS wells. Pressure decay
data help to define the appropriate period of regulatory concern,
because the likelihood that the injected fluid will migrate into USDWs
above or adjacent to the injection zone decreases as injection-induced
pressures in the formation decay. The post-injection site care period
ends when the models predicting CO₂ movement are consistent
with monitoring results demonstrating that there is no potential threat
of endangerment to USDWs.
    Combination of Fixed Timeframe and Performance Standard: EPA is
proposing using a combination of fixed timeframe and a performance
standard as described above. EPA is tentatively proposing a post-
injection site care (monitoring) period of 50 years with Director's
discretion to change that period to lengthen or shorten the 50-year
period if appropriate. The default timeframe could be lengthened by the
Director if potential for endangerment to USDWs still exists after 50
years or if modeling and monitoring results demonstrate that the plume
and pressure front have not stabilized in this period. Conversely, the
Director could reduce the 50-year time period if data on pressure,
fluid movement, mineralization, and/or dissolution reactions support a
determination that movement of the plume and pressure front have ceased
and the injectate does not pose a risk to USDWs. EPA requests comment
on the proposed use of a tentative 50-year fixed timeframe that could
be modified at the Director's discretion based on monitoring and
modeling data.
    To ensure that the post-injection site care monitoring timeframe is
long enough to determine that there is no threat of endangerment to
USDWs from injection activities, EPA is proposing a

[[Page 43520]]

default post-injection site care period of 50 years. During this 50-
year period, the owner or operator would be required to submit periodic
reports providing monitoring results and updated modeling results as
appropriate until a demonstration of non-endangerment to USDWs can be
made. Once the owners or operators provide documentation that
demonstrates that the models predicting CO₂ movement are
consistent with monitoring results and that there are no longer risks
of endangerment to USDWs, they could request that the Director
authorize site closure.
    EPA is also proposing to allow the Director to shorten or lengthen
the 50-year timeframe based on performance of the site. The Director
may require that the post-injection site care period extend beyond the
50-year time frame if a demonstration of non-endangerment to USDWs
cannot be made. Alternately, if the owner or operator can demonstrate
that the remaining pressure front and plume will not endanger USDWs,
then owners or operators may request a decreased post-injection site
care period.
    While EPA considered the 10-year, 30-year, and 100-year timeframes,
the Agency is proposing a 50-year timeframe because there are
circumstances under which the potential risks of endangerment to USDWs
will not decline within 10 years. Furthermore, the time needed to allow
pressures to equalize within the subsurface because of the higher
levels of mobility of injected CO₂ may exceed 30 years, and
EPA wishes to emphasize that site closure cannot occur until monitoring
and modeling data establish to the Director's satisfaction that
potential risks of endangerment to USDWs have ceased. EPA is not
proposing 100 years as the default because EPA believes that in general
plume stabilization will occur before this time. However post-injection
site care requirements could be extended for 100 years (or longer) if
monitoring and modeling information suggest that the plume may still
endanger USDWs throughout this period. EPA considers that a 50-year
timeframe represents a reasonable mid-point for the default time frame,
which may be modified with the approval of the Director based on a
demonstration (by the owner or operator) using monitoring and modeling,
that the injected CO₂ will not endanger USDWs.
    Site Closure: The Director would determine that the post-injection
site care period has ended and authorize site closure when the
following have occurred:
     The Director receives all information required of the
post-injection site care and site closure plan;
     The data demonstrate to the satisfaction of the Director
that there is no threat of endangerment to USDWs.
    Once the Director approves site closure, the owner or operator is
required to submit a site closure report within 90 days. The report
would provide documentation of injection and monitoring well plugging;
copies of notifications to State and local authorities that may have
authority over future drilling activities in the region; and records
reflecting the nature, composition, and volume of the injected carbon
dioxide stream. The purpose of this report would be to provide
information to potential users and authorities of the land surface and
subsurface pore space regarding the operation. In addition, the owner
or operator of the injection site must record a notation on the deed to
the facility property or any other document that is normally examined
during title search that will, in perpetuity, provide notification to
any potential purchaser of the property information that the land has
been used to sequester CO₂.
    EPA is requesting comments on the proposed requirements for well
plugging, post-injection site care, and site closure, including the
proposed requirements for the post-injection time period. In addition,
EPA seeks comment on whether the Director should be allowed to shorten
the timeframe based on performance information, and whether EPA should
require a shorter or longer post-injection period if data suggests the
time frame should be adjusted.
9. Proposed Financial Responsibility and Long-Term Care Requirements
    Today's proposal would require that owners or operators demonstrate
and maintain financial responsibility, and have the resources for
activities related to closing and remediating GS sites. EPA is
proposing that the rule only specify a general duty to obtain financial
responsibility acceptable to the Director, and will provide guidance to
be developed at a later date that describes recommended types of
financial mechanisms that owners or operators can use to meet this
requirement.
    Although the SDWA does not have explicit provisions for financial
responsibility, as included in RCRA, EPA believes that the general
authorities provided under the SDWA authority to prevent endangerment
of USDWs include the authority to set standards for financial
responsibility to prevent endangerment of USDWs from improper plugging,
remediation, and management of wells after site closure. The SDWA
authority does not extend to financial responsibility for activities
unrelated to protection of USDWs (e.g., coverage of risks to air,
ecosystems, or public health unrelated to USDW endangerment). It also
does not cover transfer of owner or operator financial responsibility
to other entities, or creation of a third party financial mechanism
where EPA is the trustee.
    Today's proposal would require owners or operators to demonstrate
financial responsibility for corrective action described in 40 CFR
146.84 of this notice, including injection well plugging, post-
injection site care and site closure, and emergency and remedial
response using a financial mechanism acceptable to the Director. The
Director would determine whether the mechanism the owner or operator
submits is adequate to pay for well plugging, post-injection site care,
site closure, and remediation that may be needed to prevent
endangerment of underground sources of drinking water.
    Owners or operators would no longer need to demonstrate that they
have financial assurance after the post-injection site care period has
ended. This generally occurs when the Director approves the completed
post-injection site care and site closure plan and then determines that
the injected fluid no longer poses a threat of endangerment to USDWs
(e.g., the fluid no longer exhibits a propensity to move or migrate out
of the injection zone to any point where it could endanger a USDW).
    The Agency is proposing that the owner or operator periodically
update the cost estimate for well plugging, post-injection site care
and site closure, and remediation to account for any amendments to the
area of review and corrective action plan (40 CFR 146.84), the plugging
and abandonment plan, and the post-injection site care and site closure
plan (40 CFR 146.93). EPA is also proposing that the owner or operator
submit an adjusted cost estimate to the Director if the original
demonstration is no longer adequate to cover the cost of the injection
well plugging, post-injection site care, and site closure. As proposed,
the Director would set the frequency for owner or operator re-
demonstration of financial responsibility and resources. It may be
appropriate to re-demonstrate financial responsibility on a periodic
basis. Such re-demonstration would take into account any amendments to
the area of review and corrective action plan (40 CFR 146.84) and
adjustments for inflation. It may also be necessary to

[[Page 43521]]

adjust cost estimates if the Director has reason to believe that the
original demonstration is no longer adequate to cover the cost of the
well plugging and post-injection site care and site closure. EPA is
also proposing that the owner or operator notify the Director of
adverse financial conditions, including but not limited to bankruptcy
proceedings, which name the owner or operator as debtor, within 10
business days after the commencement of the proceeding.
    EPA plans to develop guidance that is similar to current UIC
financial responsibility guidance for Class II owners or operators.
Currently, EPA guidance (USEPA, 1990) describes several options owners
or operators can use to meet the requirements to demonstrate financial
responsibility for well plugging. Financial assurance is typically
demonstrated through two broad categories of financial instruments: (1)
Third party instruments, including surety bond, financial guarantee
bond or performance bond, letters of credit (the above third party
instruments must also establish a trust fund), and an irrevocable trust
fund; (2) self-insurance instruments, including the corporate financial
test and the corporate guarantee.
    Supplemental Information: In recent years, the EPA's Office of the
Inspector General (OIG) and the U.S. Government Accountability Office
(GAO) have raised issues regarding the use of financial responsibility
instruments applicable to site closure for several EPA programs.
Information regarding these reviews and EPA's responses are available
at http://www.gao.gov/new.items/d03761.pdf; http://www.epa.gov/oig/
reports/2001/finalreport330.pdf; http://www.epa.gov/oig/reports/2005/
20050926-2005-P-00026.pdf. The OIG and GAO recommendations suggest that
EPA may need to update or provide additional guidance in the following
areas: Cost estimation methodology; pay-in period for trust funds; the
type of insurance provider that may be used; requirements for
acceptable surety bonds and/or their providers; and the way by which
corporations demonstrate financial strength/credit worthiness.
    In response to evaluations of financial responsibility instruments,
EPA's RCRA program has issued a comprehensive financial responsibility
strategy to improve the implementation of the financial responsibility
requirements, as well as assess whether regulatory changes to certain
mechanisms and financial responsibility requirements are warranted. EPA
has begun implementing this strategy by providing additional guidance
to support implementation and oversight of RCRA financial
responsibility programs, providing training to EPA Regions and states,
and developing tools (e.g., cost-estimating software) to assist staff
in performing reviews of complex cost information.
    In addition, EPA's RCRA program has enlisted the experience and
expertise of the Environmental Finance Advisory Board (EFAB) to
evaluate specific issues related to financial responsibility. EFAB has
completed assessments of the corporate financial test and captive
insurance, and is currently in the process of undertaking analyses of
third-party insurance and uncertainties associated with estimating
costs that must be covered by the financial assurance requirements. In
January 2006, the EFAB summarized its findings and recommendations on
the corporate financial test, as a means of demonstrating financial
assurance. EFAB's recommendations in this area were not based on
specific failures of the test, but on their ``knowledge of prudent
financial practices and the availability of existing expertise in the
financial services sector.'' In March 2007, the EFAB summarized its
preliminary findings and conclusions on its review of insurance,
specifically captive insurance, as a means of demonstrating financial
assurance. The Agency plans to continue to track these efforts by the
EFAB, because they may provide key directions for future GS
requirements with respect to financial responsibility.
    EPA is considering updating mechanisms for demonstrating financial
responsibility for GS projects. EPA is evaluating revising guidance to
address the current financial responsibility requirements on the
following topics: Cost estimation for plugging, pay-in period for trust
funds, insurance providers, surety bonds and/or their providers, and
corporate demonstration of financial strength/credit worthiness.
    Cost estimation for plugging: One of the most critical aspects to
ensuring that owners or operators have the resources to pay for
injection well plugging is cost estimation. Sound cost estimation
requirements ensure that sufficient funds are set aside in the
financial assurance instrument to properly undertake covered activities
(e.g., plugging and post-injection site care) at any time during the
operating life of the facility and during the post-injection site care
period.
    EPA is assessing whether the cost estimate underpinning financial
assurance should be based on the cost of retaining an independent,
third party to conduct covered activities, such as well plugging. EPA
also is considering provisions for annual inflationary adjustments and
is weighing the inclusion of a third-party certification requirement,
or provisions for a third-party audit, in cases where the owner or
operator self-prepares its cost estimate. Revision in this area will
reduce the possibility of undervalued cost estimates. EPA will also
consider EFAB's findings on this issue when they become available.
    Pay-in period for trust funds: Current UIC guidance describes trust
funds as a form of financial assurance. The owner or operator may
deposit funds into the trust fund in phases; that is, either over the
term of the initial permit or over the remaining operating life of the
injection well, as estimated in the well plugging plan, whichever
period is shorter. Because of the possibility that the owner or
operator may face financial distress prior to the trust being fully
funded, EPA is considering a guidance approach that would recommend
adopting a pay in period of three years for GS projects, consistent
with other similar programs in the Agency.
    Insurance providers: Current UIC regulations for Class I hazardous
waste injection allow for the use of insurance for purposes of
demonstrating financial responsibility. However, insurance was not
included as part of the guidance provided for Class II injection
because this insurance mechanism was and still is, rarely used for the
purpose of demonstrating financial assurance for injection wells. EPA
is assessing whether to provide guidance on the use of insurance
providers and, if so, whether to update eligibility requirements for
insurers for GS wells consistent with other current Federal agency
practices.
    In addition, EPA is evaluating recommendations from the Office of
the Inspector General (OIG), the Government Accountability Office
(GAO), and EFAB on the use of insurance as a financial responsibility
mechanism. EPA will also consider any additional recommendations EFAB
may have on the use of third party insurance.
    Surety bonds and/or their providers: Current UIC guidance describes
several options for using surety bonds for purposes of demonstrating
financial responsibility. The regulations at 40 CFR 144 for Class I
wells stipulate that eligible surety bond providers must be listed by
the U.S. Department of Treasury on its Circular 570. Because surety
bonds are a specialized line of insurance, EPA is assessing whether
additional eligibility requirements for sureties, similar to those
under consideration for insurers, are necessary for GS wells.

[[Page 43522]]

    Corporate demonstration of financial strength/credit worthiness:
UIC program guidance also describes options for owners or operators to
self-assure their obligations to plug the well. To be approved by the
Director, the owner or operator would likely need to self-assure in the
form of either a corporate financial test filed by the owner or
operator of the injection well, or a corporate guarantee (including a
corporate financial test) filed by the parent corporation of the owner
or operator of the injection well. A corporate guarantee may also be
provided by a ``sibling'' corporation (that is a company that shares
the same higher-tier parent) or a company with whom they have a
substantial business relationship. The guidance explains that
demonstrating self-assurance typically includes either use of a bond
rating or a series of financial ratios. Both the UIC financial
responsibility provisions for Class I hazardous waste injection and the
RCRA subtitle C provisions allow the use of self-assurance through a
financial test or corporate guarantee.
    EPA is assessing whether a financial ratings threshold for all
companies using a self-guarantee, similar to those used by other
Federal agencies, is appropriate. The Agency also is considering what
constitutes an appropriate financial rating threshold, and whether a
financial rating greater than BBB or Baa (i.e., the current rating
threshold established under the UIC regulations) is appropriate for GS
wells.
    In addition, EPA is considering whether adjustments should be made
to the absolute net worth threshold of $10 million currently required
under the UIC regulations. Specifically, EPA is assessing the net worth
requirements of other Federal agencies and EPA programs to determine
whether to make adjustments. For example, the Minerals Management
Service within the Department of the Interior, requires a net worth
threshold at least 10 times the amount of the obligations being assured
(see 30 CFR 253.25). Additionally, the Agency is in the process of
evaluating potential changes to the RCRA subtitle C financial test
requirements, including an option recommended by EFAB to require a
financial ratings threshold for all companies using a financial test to
self-assure their environmental obligations. EPA will consider the
outcome of that process for possible application to GS wells guidance.
    EPA is requesting comments on whether financial responsibility
mechanisms to be recommended in EPA guidance should be adjusted in the
manner described, whether additional instruments should be included,
and whether other adjustments to the financial responsibility
mechanisms should be considered, all subject to EPA's authority under
the SDWA. The Agency is also requesting comment on allowing separate
financial demonstrations to be submitted for the plugging of the
injection well and for the post-injection site care requirements. Since
post-injection site care has the potential to extend many years into
the future, subsequent to the time a permit is issued, the Agency
believes that it may be advantageous to require the approval of the
well plugging financial demonstration at permit issuance and the post-
injection site care financial demonstration at a later time (e.g.,
within 180 days of notifying the Director that the well will be plugged
and abandoned). Trying to determine the cost for post-injection site
care, possibly 30 to 50 years in the future, could be difficult, as
could the approval of a financial demonstration.
    Considerations for Long-term Care: While EPA has authority to
require financial responsibility for well plugging and post-injection
site care (e.g., monitoring, remediation) to ensure the protection of
USDWs, the SDWA does not provide authority under financial
responsibility or other provisions for coverage of risks to air,
ecosystems, or public health. Thus, while obligation for financial
responsibility ends for owners or operators after the post-injection
site care period has ended and the Director has authorized site
closure, owners or operators may still be held responsible after the
post-injection site care period has ended (e.g., for unanticipated
migration that endangers a USDW). In addition, the SDWA does not
provide EPA with the authority to transfer liability from one entity to
another. Trust responsibility for potential impacts to USDWs remains
with the owner or operator indefinitely under current SDWA provisions.
    Responsibility for long-term care is often considered an important
topic related to GS because of cost implications of indefinite
responsibility for GS sites. Because of the focus of the SDWA on
endangerment to USDWs and the absence of provisions to allow transfer
of liability, stakeholders have expressed interest in alternative
instruments for addressing financial responsibility after the post
injection care period has ended. As a result of the interest in
alternative instruments, including indemnity programs, EPA has compiled
information on a variety of alternative instruments not currently
available under the SDWA. This discussion is in Approaches to GS Site
Stewardship After Site Closure in the docket for this proposed rule.
EPA has not determined whether any of the models are appropriate for GS
wells, however, EPA is aware that these models may contain important
concepts that may become the model for future strategies for long-term
care.

B. Adaptive Approach

    To meet the potentially fast pace of implementation of GS, EPA is
using an adaptive approach to regulating CO₂ injection for
GS. In 2007, EPA issued UIC Program Guidance #83, which allows
limited-scale experimental GS projects to proceed under the Class V
experimental technology well classification. An adaptive approach
allows regulatory development to move ahead in time to meet the future
demand for permits, while recognizing the need to continue to gather
data from pilot projects and other research as it becomes available.
    EPA will continue to evaluate ongoing research and demonstration
projects, review input received on this proposal, and gather other
relevant information, as needed, to make refinements to the rulemaking
process. If appropriate, EPA will publish notices to collect new data
before issuing a final rule on CO₂ injection for GS. EPA
plans to issue a final rule in advance of full-scale deployment of GS.
EPA will track implementation of the final GS rule to determine whether
these requirements continue to meet SDWA objectives and, if not, revise
them as needed. If new information gathered during implementation
suggests the requirements need revisions, EPA will initiate the
appropriate procedure, including public notice and comment.

IV. How Should UIC Program Directors Involve the Public in Permitting
Decisions for GS Projects?

    Public participation has been an important part of the UIC Program
since its inception. Public participation has a number of benefits,
including (1) providing citizens with access to decision-making
processes that may affect them; (2) enabling the owner/operator and the
permit writer to educate the community about the project; (3) ensuring
that the public receives adequate information about the proposed
injection; (4) allowing the permitting authority to become aware of
public viewpoints, preferences and environmental justice concerns; and
(5) ensuring that public viewpoints, preferences and concerns have been
considered by the decision-making officials.

[[Page 43523]]

    GS of CO₂ is a new technology that is unfamiliar to most
people, and maximizing the public's understanding of the technology can
result in more meaningful public input and constructive participation
as new GS projects are proposed and developed. Critical to the success
of GS is early and frequent involvement through education and
information exchange. Such exchange can provide early insight into how
the local community and surrounding communities perceive potential
environmental, economic or health effects.
    Owners or operators and permitting authorities can maximize the
public participation process, thereby increasing the likelihood of
success, by integrating social, economic, and cultural concerns of the
community into the permit decision making process.
    EPA examined existing requirements for public participation across
the Agency's environmental programs. EPA is proposing to adopt the
requirements at 40 CFR Part 25 and the permit procedures at 40 CFR Part
124 for long-term storage of CO₂. Under today's proposal,
the permitting authority would be required to provide public notice and
opportunity for public input. This includes providing public notice of
pending actions via newspaper advertisements, postings, or mailings to
interested parties and providing a fact sheet or statement of basis
that describes the planned injection operation and the principal facts
and issues considered in preparing the draft permit. Under today's
proposal, permitting authorities would provide a 30-day comment period
during which public hearings may be held. At the conclusion of the
comment period, the permitting authority would be required to prepare a
responsiveness summary that becomes part of the public record.
    EPA recognizes that advances in information technology and the
available avenues for communication have changed the way that people
receive news and information and that new means of engaging
stakeholders are now available. Roundtables, constituency meetings,
charrettes (workshops designed to involve the public in a planning or
design process), information gathering sessions, cable TV, and the
Internet are just a few tools the Agency has come to rely upon over the
past decade to ensure more effective stakeholder involvement and public
participation. These technologies provide a host of opportunities to
educate the public about and involve them in GS technology and pending
decisions.
    In addition, electronic information technology has become widely
available to inform and involve the public. Web pages, discussion
boards, list serves, and broadcast text messages via cell phones are
all available to keep the public informed.
    EPA encourages permit applicants and permit writers to use the
Internet and other available tools to explain potential GS projects;
describe the technology; and post information on the latest
developments including schedules for hearings, briefings, and other
opportunities for involvement.
    EPA requests comment on adopting the existing requirements for
public participation at 40 CFR Part 25 and 40 CFR Part 124 and whether
additional requirements should be included to reflect the availability
of new tools for disseminating and gathering information. Such tools
include cable networks, the Internet, and other new technology. EPA
also requests comment on ways to enhance the public participation
process, including engaging communities in the site characterization
process as soon as candidate locations are identified.

V. How Will States, Territories, and Tribes Obtain UIC Program Primacy
for Class VI Wells?

    As described in section II.C above, EPA may approve primary
enforcement authority for States, Territories, and Tribes that wish to
implement the UIC Program. To gain authority for Class VI wells,
States, Territories, and Tribes will be required to show that their
regulations are at least as stringent as, and may be more stringent
than, the proposed minimum Federal requirements (e.g., inspection,
operation, monitoring, and recordkeeping requirements that well owners
or operators must meet). Such Primacy States, Territories, and Tribes
are authorized under section 1422 of the SDWA.
    Historically, EPA has approved State and Territorial UIC Program
primacy in whole or in part as follows: (1) For all five classes of
wells under section 1422 of SDWA; (2) for Classes, I, III, IV, and V
under Section 1422 of SDWA; or for (3) Class II wells only under
section 1425 of SDWA. Several States with large Class II inventories
may have primacy for a combination of wells, i.e., authority under
section 1425 for their Class II wells and 1422 authority for other well
classes.
    EPA is aware that some States may wish to obtain primacy for only
Class VI wells. Section 1422 does not explicitly allow for approval of
State UIC programs for individual well classes, however there appears
to be no express prohibition.
    There may be benefits to parsing out primacy for Class VI wells,
however EPA has not made a decision on this. Allowing States,
Territories, and Tribes to acquire primacy for only Class VI wells may
encourage them to assume the responsibility of implementation and
provide for a more comprehensive approach to managing CCS projects
(e.g., capture, transportation, and geologic sequestration). EPA is
seeking comment on the merits and possible disadvantages of allowing
primacy approval for Class VI wells independent of other well classes.

VI. What Is the Proposed Duration of a Class VI Injection Permit?

    Existing UIC regulations allow injection wells to be permitted
individually or as part of an area permit. Because GS projects would
likely use multiple injection wells per project, the Agency anticipates
that most owners or operators would seek area permits for their
injection wells.
    Additionally, 40 CFR 144.36 sets forth the permit duration for the
current classes of injection wells. Permits for Class I and Class V
wells are effective for up to 10 years. Permits for Class II and III
wells may be issued for the operating life of the facility; however
they are subject to a review by the permitting authority at least once
every 5 years.
    Implementation of the AoR and corrective action plan as described
in today's proposal would involve periodic re-evaluation of site data,
status of corrective action, monitoring results and modification of
operating parameters, as needed. These periodic evaluations would
provide the same effect and assurances obtained through the permit
renewal process without the associated administrative burden.
Additionally, the frequent level of ongoing interaction between the
owner or operator and the Director as required by the AoR and
corrective action plan is more substantial than that required for other
classes of injection wells. The periodic evaluations and revisions
driven by the various rule-required plans and the underlying
computational model should provide abundant opportunities for technical
reassessment by operators and regulators, and through permit amendments
and modifications.
    Therefore, EPA proposes that Class VI injection well permits would
be issued for the operating life of the GS project including the post-
injection site care period. EPA seeks comment on the merits of this
approach.

[[Page 43524]]

VII. Cost Analysis

    While today's proposed rulemaking proposes regulations for the
protection of USDWs, it does not require entities to sequester
CO₂. Thus, the costs and benefits associated with protection
of USDWs is the focus of this proposed rule and the costs associated
with the mitigation of climate change are not directly attributable to
this proposed rulemaking.
    To calculate the costs and benefits of compliance for today's
proposal, EPA selected the existing UIC program Class I industrial
waste disposal well category as the baseline for costs and benefits.
EPA used this baseline to determine the incremental costs of today's
proposal.
    The incremental costs of the proposed rule include elements such as
geologic characterization, well construction and operation, monitoring
equipment and procedures, well plugging, and post-injection site care
(monitoring). The benefits of this proposed rulemaking could include
the decreased risk of endangerment to USDWs and the decreased potential
for health-related risks associated with contaminated USDWs.
    The scope of the Cost Analysis includes the full range of an
injection project, from the end of the CO₂ pipeline at the
GS site, to the underground injection and monitoring, as it occurs
during the time frame of the analysis. The scope does not include
capturing or purifying the CO₂, nor does it include
transporting the CO₂ to the GS site.
    The 25-year timeframe of the Cost Analysis is comparable to the
timeframes used in recent drinking water-related economic analyses.
Costs attributed to the proposed rule are inclusive of geologic
sequestration projects begun during the 25 years of the analysis and
all cost elements that occur during the 25-year timeframe are
discounted to present year values. EPA recognizes the need to revisit
the Cost Analysis prior to the promulgation of a final rule as new data
become available. The number of GS projects projected over the
timeframe of the Cost Analysis includes pilot projects and other
projects driven by regulations that are in place today. Projections of
GS projects may need to be revisited in light of any new climate change
legislation prior to promulgation of a final rule. However, it is
important to note that the proposed rule does not require anyone to
inject CO₂.

A. National Benefits and Costs of the Proposed Rule \1\
---------------------------------------------------------------------------

    \1\ Although both estimated costs and benefits are discussed in
detail, the final policy decisions regarding this rulemaking are not
premised solely on a cost/benefit basis.
---------------------------------------------------------------------------

1. National Benefits Summary
    This section summarizes the risk (and benefit) tradeoffs between
compliance with existing requirements and the preferred regulatory
alternative (RA) selected during the regulatory development process.
Evaluations in the Cost Analysis include a non-quantitative analysis of
the relative risks of contamination to USDWs for the regulatory
alternatives under consideration. The expected change in risk based on
promulgation of the preferred RA and the potential nonquantified
benefits of compliance with this RA are also discussed.
a. Relative Risk Framework--Qualitative Analysis
    Table VII-1 below presents the estimated relative risks of the
preferred regulatory alternative selected for compliance with the
proposed rule relative to the baseline. The term ``baseline'' in the
exhibit refers to risks as they exist under current UIC Program
regulations for Class I industrial wells. The term ``decrease''
indicates the change in risk relative to this baseline. The Agency has
used best professional judgment to qualitatively estimate the relative
risk of each regulatory alternative. This assessment was made with
contributions from a wide range of injection well and hydrogeological
experts, ranging from scientists and well owners or operators to
administrators and regulatory experts.

   Table VII-1.--Relative Risk of Regulatory Components for Preferred
     Proposed Regulatory Alternative Versus the Current Regulations
------------------------------------------------------------------------
                                            Direction of change  in risk
                 Baseline                      (relative to baseline)
------------------------------------------------------------------------
1. Geologic Characterization
    Geologic system consisting of a        Decrease.
     receiving zone; trapping mechanism;
     and confining system to allow
     injection at proposed rates and
     volumes.
    Operators provide maps and cross
     sections of local and regional
     geology, AoR, and USDWs;
     characterize the overburden and
     subsurface; and provide information
     on fractures, stress, rock strength,
     and in situ fluid pressures within
     cap rock.
2. Area of Review (AoR) Study and
 Corrective Action
    The AoR determined as either a \1/4\   Decrease.
     mile radius or by mathematical
     formula. Identify all wells in the
     AoR that penetrate the injection
     zone and provide a description of
     each; identify the status of
     corrective action for wells in the
     AoR; and remediate those posing the
     greatest risk to USDWs.
3. Injection Well Construction
    The well must be cased and cemented    Decrease.
     to prevent movement of fluids into
     or between USDWs and to withstand
     the injected materials at the
     anticipated pressure, temperature
     and other operational conditions.
4. Well Operation
    Limit injection pressure to avoid      Decrease.
     initiating new fractures or
     propagate existing fractures in the
     confining zone adjacent to the USDWs.
5. Mechanical Integrity Testing (MIT)
    Demonstrate internal and external      Decrease.
     mechanical integrity, conduct a
     radioactive tracer survey of the
     bottom-hole cement, and conduct a
     pressure fall-off test every 5 years.
6. Monitoring
    Monitor the nature of injected fluids  Decrease.
     at a frequency sufficient to yield
     data representative of their
     characteristics; Conduct ground
     water monitoring within the AoR.
     Report semi-annually on the
     characteristics of injection fluids,
     injection pressure, flow rate,
     volume and annular pressure, and on
     the results of MITs, and ground
     water and atmospheric monitoring.
7. Well Plugging

[[Page 43525]]


    Ensure that the well is in a state of  Decrease.
     static equilibrium and plugged using
     approved methods. Plugs shall be
     tagged and tested. Conduct post-
     injection site care monitoring to
     confirm that CO2 movement is limited
     to intended zones.
8. Financial Responsibility
    Demonstrate and maintain financial     Decrease.
     responsibility and resources to plug
     the injection well and for post-
     injection site care.
Overall..................................  Decrease.
------------------------------------------------------------------------
Note: See Chapter 2 of the GS proposed rule Cost Analysis for a detailed
  description of the components for each regulatory alternative.

    In the consideration of benefits of the proposed GS rule, the
direction of change in risk mitigation compared to the baseline
regulatory scenario was assessed for each component of the four
regulatory alternatives considered. An overall assessment for each
alternative as a whole requires consideration of the relative
importance of risk being mitigated by each component of the proposed
rule.
    As shown in Table VII-1, EPA estimates that under the Preferred
Alternative, RA3, risk will decrease relative to the baseline for each
of the eight components assessed.
b. Other Nonquantified Benefits
    Promulgation of the proposed rule will result in direct benefits,
that is, protection of the USDWs which EPA is required by statute to
protect; and indirect benefits, which are those protections afforded to
entities as a by-product of protecting USDWs. Indirect benefits are
described in the Risk and Occurrence Document for Geologic
Sequestration Proposed Rulemaking (USEPA, 2008e) and summarized in
Chapter 4 of the GS Rule Cost Analysis. They include mitigation of
potential risk to surface ecology and to human health through exposure
to elevated concentrations of CO₂. Potential benefits from
potential climate change mitigation are not included in the assessment.
2. National Cost Summary
a. Cost of Preferred Regulatory Alternative
    EPA estimated the incremental, one-time, capital, and operation and
maintenance (O&M) costs associated with today's proposed rulemaking. As
Table VII-2 shows, the total incremental cost associated with the
Preferred Alternative is $15.0 million and $15.6 million, using a 3
percent and 7 percent discount rate, respectively. These costs are in
addition to the baseline costs that would be incurred if CO₂
sequestration was instead subject to the current rules for UIC Class I
industrial wells. As can be seen from Table VII-2, today's proposed
rule would increase the costs of complying with UIC regulations for
these wells from approximately a baseline of $32.3 million to $47.3
million using a 3 percent discount rate, which is an increase of 46%.
EPA believes these increased costs are needed to address the unique
issues associated with CO₂ geological sequestration. The
costs of the other regulatory alternatives considered are detailed in
the Cost Analysis, along with a discussion of how EPA derived these
estimates.

               Table VII-2.--Incremental Costs of Preferred Regulatory Alternative for 22 Projects
                                                [2007$, $million]
----------------------------------------------------------------------------------------------------------------
                                                                   One-time     Capital
                     Regulatory alternative                          costs       costs     O&M costs     Total
----------------------------------------------------------------------------------------------------------------
                                                                              3 Percent Discount Rate
                                                                 -----------------------------------------------
Baseline........................................................        $2.5       $10.6       $19.2       $32.3
Alternative 3...................................................         3.8        15.5        28.1        47.3
Alt 3--Incremental..............................................         1.3         4.9         8.8        15.0
                                                                 -----------------------------------------------
                                                                              7 Percent Discount Rate
                                                                 -----------------------------------------------
Baseline........................................................        $2.9       $12.7       $18.0       $33.6
Alternative 3...................................................         4.2        18.6        26.4        49.2
Alt 3--Incremental..............................................         1.3         5.9         8.4        15.6
----------------------------------------------------------------------------------------------------------------

    Table VII-3 presents a breakout of the incremental costs of the
Preferred Alternative by rule component.
     Monitoring activities account for 60 percent of the
incremental regulatory costs. Most of this cost is for the
construction, operation, and maintenance of corrosion-resistant
monitoring wells. This cost also includes tracking of the plume and
pressure front as well as the cost of incorporating monitoring results
into fluid flow models that are used to reevaluate the AoR. These
activities are a key component of decreasing risk associated with GS
because they facilitate early detection of unacceptable movement of
CO₂ or formation fluids.
     The next largest cost component of the Preferred
Alternative is injection well operation, accounting for 22 percent of
the total incremental cost. This component ensures that the wells
operate within safety parameters and the injection does not cause
unacceptable fluid movement.
     Well plugging and post-injection site care activities,
which ensure that the injection well is properly closed in a way that
addresses the corrosive

[[Page 43526]]

nature of the CO₂ and does not allow it to serve as a
conduit for fluid movement, account for 5 percent of the total
incremental cost of RA 3.
     Mechanical Integrity Testing, including continuous
pressure monitoring, which can provide timely warning that
CO₂ may have compromised the well, accounts for an
additional 4 percent of the cost.
     Construction of GS wells using the corrosion resistant
design and materials necessary to withstand exposure to CO₂
accounts for 4 percent of the incremental cost of the Preferred
Alternative.

                                           Table VII-3.--Incremental Rule Costs of Preferred Regulatory Alternative for 22 Projects by Rule Component
                                                                                        [2007$, $million]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                           Rule component
                                                                  ------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                                   Well
                     Regulatory  alternative                                                       Injection                                     plugging     Financial    Permitting
                                                                     Geologic site   Monitoring      well       Area of      Well       MIT     and post-  responsibility   authority    Total
                                                                   characterization              construction    review   operation             injection        \1\          admin
                                                                                                                                                site care
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                      3 Percent Discount Rate
                                                                  ------------------------------------------------------------------------------------------------------------------------------
Baseline.........................................................           $0.7           $1.8        $10.4        $0.6      $18.5       $0.1       $0.1          $0.0          $0.1      $32.3
Alternative 3....................................................            1.2           10.9         11.0         0.7       21.8        0.7        0.9           0.0           0.1       47.3
Alt 3 Incremental................................................            0.4            9.1          0.6         0.1        3.3        0.6        0.8           0.0           0.0       15.0
Incremental--% of Total..........................................             3%            60%           4%          1%        22%         4%         5%            0%            0%       100%
                                                                  ------------------------------------------------------------------------------------------------------------------------------
                                                                                                                      7 Percent Discount Rate
                                                                  ------------------------------------------------------------------------------------------------------------------------------
Baseline.........................................................           $0.9           $2.1        $12.5        $0.6      $17.3       $0.1       $0.1          $0.0          $0.1      $33.6
Alternative 3....................................................            1.4           12.0         13.3         0.8       20.3        0.7        0.7           0.0           0.1       49.2
Alt 3 Incremental................................................            0.5            9.9          0.8         0.2        3.0        0.6        0.6           0.0           0.0       15.6
Incremental--% of Total..........................................             3%            63%           5%          1%        19%         4%         4%            0%            0%       100%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Costs related to demonstration of Financial Responsibility are less than $100,000 in annualized terms.

b. Nonquantified Costs and Uncertainties in Cost Estimates
    The purpose of the GS proposed rule is to mitigate any risk
introduced by CO₂ GS activity to the quality, and indirectly
the quantity, of current and potential future USDWs. Furthermore, the
rule proposes requirements that are intended to provide redundant
safeguards. In the rare case where the rule, if finalized, is non-
implementable or not readily comprehensible, contamination could occur
to a USDW. In that case, the cost of cleaning up the USDW or finding an
alternative source of drinking water could be attributable to the rule.
Based on data from States regarding implementation of the UIC program
and current research, EPA considers the likelihood of this occurring
very small, and has not quantified this risk.
    Should the final GS rule somehow impede CO₂ GS from
happening, then the opportunity costs of not capturing the benefits
associated with GS of CO₂ could be attributed to the
regulations; however, the Agency has tried to develop a proposed rule
that balances risk with practicability and economic considerations, and
believes the probability of such impedance is very low. If finalized,
the GS rule would ensure protection of USDWs from GS activities while
also providing regulatory certainty to industry and permitting
authorities and an increased understanding of GS through public
participation and outreach. Thus, EPA believes the proposed rule will
not impede CO₂ GS from happening and has not quantified such
risk.
    Uncertainties in the analysis are included in some of the basic
assumptions as well as some detailed cost items. Uncertainties related
to economic trends, the future rate of CCS deployment, and GS
implementation choices may affect three basic assumptions on which the
analysis is based: (1) The estimated number of projects that will be
affected by the GS proposed rule; (2) the labor rates applied; and (3)
the estimated number of monitoring wells to be constructed per
injection well to adequately monitor in a given geologic setting.
    First, the number of projects that will deploy from 2012 through
2036 may be significantly underestimated in this analysis given the
uncertainty in future deployment of this technology. The current
baseline assumption is that 22 projects will deploy during the 25-year
period, as described in Chapter 3 of the proposed rule Cost Analysis
and explained in detail in the Geologic CO₂ Sequestration
Activity Baseline (USEPA, 2008f) document.
    Second, the labor rate adopted for each of the labor categories
described in Section 5.2.1 of the Cost Analysis (Geoscientist,
Geological Engineer, State Geologist, and Agency Geologist) may be
underestimated. The practice of CO₂ injection represents an
activity that, although already practiced widely in some contexts
(i.e., EOR), is expected to expand rapidly in the coming years. This
expansion may be exponential under certain climate legislative
scenarios, which may lead to shortages in labor and equipment in the
short term, resulting in rapid cost escalation for many of the cost
components discussed in this chapter. (Anecdotal evidence based on
discussions with industry representatives suggests that there may
already be labor shortages developing in some critical disciplines.)
Because the cost analyses presented in this chapter are based on
current industry costs, the level and pace of price responses as the
level of CO₂ GS increases represent a highly uncertain
component in the cost estimates presented in this chapter.
    Third, the Agency assumes three monitoring wells per injection well
for the purpose of estimating national costs; however, the Agency
recognizes that

[[Page 43527]]

operators and primacy agency Directors may choose more or fewer
monitoring wells depending on project site characteristics. Because the
monitoring wells and associated costs represent a significant component
of the Cost Analysis, the Agency acknowledges that this factor may be
significant in the overall uncertainty of the Cost Analysis. EPA
requests comment on whether three monitoring wells per injection well
is an appropriate costing assumption.
    Additional uncertainties correspond more directly to specific
assumptions made in constructing the cost model. If the assumptions for
such items are incorrect, there may be significant cost implications
outside of the general price level uncertainties discussed above. These
cost items are described in section 5.9.2 of the GS proposed rule Cost
Analysis.
c. Supplementary Cost Information
    To better establish the context in which to evaluate the Cost
Analysis for this proposal, we consider three types of costs that are
not accounted for explicitly for this proposed rule: (1) Costs that are
incurred beyond the 25-year timeframe of the Cost Analysis, (2) costs
that could arise due to a higher rate of deployment of CCS in the
future, and (3) the proportion of overall CCS costs attributable to the
proposed requirements. Because geologic sequestration of CO₂
is in the early phase of development, and given the significant
interest in research, development, and eventual commercialization of
CCS, EPA provides a preliminary discussion of the impact of these costs
below.
    The Cost Analysis for this proposed rule explores costs that might
be incurred during a 25-year timeframe.\2\ When analyzing costs for a
commercial size sequestration project that begins in year one of the
Cost Analysis, EPA assumes that the first year is a construction
period, followed by 20 years of injection, followed by 50 years of
post-injection site care as indicated in the proposal. The 20-year
injection period reflects the assumption that a source such as a coal-
fired power plant, with a potential operational lifetime of 40 to 60
years, would plan for the sequestration of only half of its emissions
at a time, rather than incur those costs all at once. EPA requests
comment on this assumption. Given the 25-year timeframe of the
analysis, only the first four years of post-injection care period would
be captured in the Cost Analysis for a project beginning in year 1, and
fewer or no years of post-injection care for a project beginning later
in the 25-year analytical time frame. Based on estimates of the first
four years of the post-injection care period, EPA estimates that the
average costs for one large deep saline project incurred beyond the 25-
year timeframe of the Cost Analysis are approximately $0.30/t
CO₂ for the remaining 46 years of post-injection site care.
The full amount of the 46 years of post-injection site care is
incremental to the baseline. The incremental sequestration costs above
the baseline, over the full lifetime of the sequestration project, are
estimated to be $1.20/t CO₂. Thus the 25-year timeframe
captures approximately 75% of the lifetime incremental costs associated
with implementing this rule. It should be noted that the longer the
time horizon over which costs are estimated, the greater the
uncertainty surrounding those estimates.
---------------------------------------------------------------------------

    \2\ A detailed discussion of timeframe over which the proposed
requirements were estimated can be found in the Cost Analysis.
---------------------------------------------------------------------------

    The Cost Analysis assumes that 22 projects will inject 350 Mt
CO₂ cumulatively over the next 25 years.\3\ The start years
of these projects, for both pilot and large sizes, are staggered over
the 25 years.\4\ Based on the assumed deployment schedule, the analysis
captures the full injection periods for three large-scale projects
(with an injection period of 20 years), 12 pilot projects (with an
injection period of seven years), and partial injection periods for the
remaining seven projects. While the baseline injection amount
represents a significant step towards demonstrating the feasibility of
CCS, it represents a small amount of current CO₂ emissions
in the U.S.
---------------------------------------------------------------------------

    \3\ A more detailed discussion of these projects can be found in
the Cost Analysis.
    \4\ A detailed table of the scheduled deployment of projects
assumed in the baseline over the 25-year timeframe can be found in
Exhibit 3.1 of the Cost Analysis.
---------------------------------------------------------------------------

    The U.S. fleet of 1,493 coal-fired generators emits 1,932 Mt
CO₂ per year. The technical or economic viability of
retrofitting these or other industrial facilities with CCS is not the
subject of this proposed rulemaking. However, if some percentage of
these facilities undertook CCS, they (or the owner or operator of the
CO₂ injection wells) would be subject to the UIC
requirements. For example, if 25% of these facilities undertook CCS
(assuming a 90% capture rate and the incremental proposed rule
sequestration costs outlined in Table VII-4) the incremental
sequestration costs associated with meeting the proposed Class VI
requirements, assuming they are finalized, would be on the order of
$500 million. Similarly, if 100% of these plants undertook CCS, the
incremental costs would be on the order of $2 billion, although it is
unlikely that all coal plants would deploy CCS simultaneously. These
preliminary cost estimates represent the annualized incremental cost of
meeting the additional sequestration requirements in the proposed rule
that would be incurred over the lifetime of the sequestration projects,
assuming that all sequestration projects begin in the same year. These
cost estimates were not generated from a full economic analysis or
included in the Cost Analysis for this proposal, due to the uncertainty
of what percentage, if any, of such facilities will deploy CCS in the
future. These estimates represent a snapshot of potential costs
assuming 25% or 100% of all plants undertake CCS beginning in the same
year, and do not take into consideration CCS deployment rates and
project-specific costs. Actual annualized costs incurred as CCS deploys
in the future could be higher or lower, depending on a number of
factors including deployment rates, capital and labor cost trends, and
the shape of the learning curve.
    Based on current literature, sequestration costs are expected to be
a small component of total CCS project costs. Table VII-4 shows example
total CCS project costs broken down by capture, transportation, and
sequestration components. The largest component of total CCS project
costs is the cost of capturing CO₂ ($42/t CO₂ for
capture from an Integrated Gasification Combined Cycle power plant
\5\). Transportation costs vary widely depending on the distance from
emission source to sequestration site, but we can use a long-term
average estimate of $3/t CO₂.\6\ We estimate total
sequestration costs for a commercial size deep saline project to be
approximately $3.40/t CO₂, of which approximately $1.20/t
CO₂ is attributable to complying with requirements of this
proposed rule (including the full 50 years of post-injection site
care). Based on the project costs outlined in Table VII-4, the proposed
requirements amount to approximately 3% of the total CCS project costs.
---------------------------------------------------------------------------

    \5\ Cost and Performance Baseline for Fossil Energy Plants, Vol.
1, DOE/NETL-2007/1281, May 2007.
    \6\ On the Long-Term Average Cost of CO₂ Transport
and Storage, JJ Dooley, RT Dahowski, CL Davidson, Pacific Northwest
National Laboratory Operated for the U.S. Department of Energy by
Battelle Memorial Institute, PNNL-17389, March 2008.

[[Page 43528]]



              Table VII-4.--Example Total CCS Project Costs
------------------------------------------------------------------------
  Example Total CCS project costs  (including capture at an IGCC plant,
      transportation, and deep saline reservoir at commercial scale
                             sequestration)
-------------------------------------------------------------------------
                                             Cost over     Percentage of
                                            lifetime of      total CCS
                                           project  ($/    project cost
                                               tCO2)            (%)
------------------------------------------------------------------------
Capture (IGCC plant)....................          $42.00              87
Transportation Estimate.................            3.00               6
Baseline Sequestration..................            2.20               4
Incremental Proposed Rule Sequestration             1.20               3
 Requirements...........................
                                         -------------------------------
    Total CCS Project Cost..............           48.40  ..............
------------------------------------------------------------------------

B. Comparison of Benefits and Costs of Regulatory Alternatives of the
Proposed Rule

a. Costs Relative to Benefits; Maximizing Net Social Benefits
    Because EPA lacks the data to perform a quantified analysis of
benefits, a direct numerical comparison of costs to benefits cannot be
done. Costs can only be compared to qualitative relative risks as
discussed in section VII-1.
    Compared to the baseline, RA3 provides greater protection to USDWs
because it is specifically tailored to the injection of CO₂.
The current regulatory requirements do not specifically consider the
injection of a buoyant corrosive fluid. In particular, RA3 includes
increased monitoring requirements that provide the amount of protection
the Agency estimates is necessary for USDWs. As described in the prior
section (A. National Benefits and Costs of the Proposed Rule),
monitoring requirements account for 60 percent of the incremental
regulatory costs, of which 70 percent is incurred for the construction,
operation, and maintenance of monitoring wells, and the other 30
percent for tracking of the plume and pressure front through complex
modeling at a minimum of every 10 years for all operators (the cost
model assumes every 5 years) and monitoring for CO₂ leakage.
Public awareness of these protective measures would be expected to
enhance public acceptance of CO₂ GS.
    RA1 and RA2 do not provide the specific safeguards against
CO₂ migration that RA3 does because of a significantly
greater amount of discretion allowed to Directors and operators for
interpreting requirements, and less stringent requirements for some
compliance activities. (Only RA3 and RA4 require the periodic complex
modeling exercise for tracking the plume, for example.) RA4 provides
greater safeguards against CO₂ migration, but at a much
higher cost.
b. Cost Effectiveness and Incremental Net Benefits
    RA1 and RA2 provide lower costs than RA3 but at increased levels of
risk to USDWs. Although RA4 has more stringent requirements, EPA does
not believe that the increased requirements and the increased costs are
necessary to provide protection to USDWs. Therefore EPA believes that
RA3 is the best alternative.

C. Conclusions

    RA3 provides a high level of protection to USDWs overlying
injection zones of CO₂. It does so at lower costs than the
more stringent RA4 while providing significantly more protection than
RA1 or RA2. Therefore EPA believes RA3 is the preferred regulatory
alternative. The Agency seeks comment on cost assumptions in today's
proposal.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993),
this action is a ``significant regulatory action.'' Accordingly, EPA
submitted this action to the Office of Management and Budget (OMB) for
review under EO 12866 and any changes made in response to OMB
recommendations have been documented in the docket for this action.

B. Paperwork Reduction Act (PRA)

    The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) document prepared by EPA has been
assigned EPA ICR number 2309.01.
    The information collected as a result of this proposed rule will
allow EPA and State permitting authorities to review geologic
information about a proposed GS site to evaluate its suitability for
safe and effective GS. It also allows the Agency to verify throughout
the life of the injection project that UIC protective requirements are
in place and that USDWs are protected. The Paperwork Reduction Act
requires EPA to estimate the burden on owners or operators of
CO₂ GS wells, and States, Territories, and Tribes with
primacy. Burden is defined at 5 CFR 1320.3(b).
    For GS well operators applying for permits, this burden includes
the time, effort, and financial resources needed to collect information
to furnish EPA with the following information:

--UIC permit applications and information to support the site
characterization, such as maps and cross sections, information on the
geologic structure, hydrogeologic properties, and baseline geochemical
data on the proposed site.
--AoR and corrective action plan.
--Testing and monitoring plan.
--Well plugging and post-injection site care plans.
--Emergency and remedial response plans.
--Reports of well logs and tests performed during well construction.
--Periodic updates to the AoR models and corrective action status.
--Demonstration of financial responsibility and periodic updates.
--Periodic reports of monitoring and testing.
--Reports of post-injection monitoring.
--Non-endangerment demonstrations and the conclusion of all post-
injection site care.

    For the first 3 years after publication of the final rule in the
Federal Register, the major information requirements apply to operators
of GS wells that are submitting an application for the construction of
a CO₂ GS well (or seeking a Class VI permit for an existing
well) or monitoring and MIT data during the operation of the GS
project.

[[Page 43529]]

    States and Tribes with primacy will incur burden associated with
the following activities:

--Applying for primacy.
--Reviewing permit applications and associated data submitted by
operators (including the testing and monitoring plan, AoR and
corrective action plan, injection well plugging plan, post-injection
site care and closure plan, and emergency and remedial response plan).
--Making decisions on whether to grant or deny permits and writing
permits.
--Reviewing testing and monitoring data submitted by operators, e.g.,
continuous monitoring and MIT results.

    For the first 3 years after publication of the final rule in the
Federal Register, preparing primacy applications will account for the
majority of primacy agency burden. This is a one-time burden to each
State or Tribe that seeks primacy and, in subsequent ICRs, primacy
agency burden is expected to decrease by approximately 90 percent.
    The collection requirements are mandatory under the SDWA (42 U.S.C.
300h et seq.). Calculation of the information collection burden and
costs associated with today's proposal can be found in the Information
Collection Request for the Federal Requirements Under the Underground
Injection Control Program for Carbon Dioxide Geologic Sequestration
Wells (USEPA, 2008g), available through http://www.regulation.gov under
Docket ID EPA-HQ-OW-2008-0390.
    As shown in Table VIII-1, the total burden associated with the
proposed rule over the 3 years following promulgation is 62,117 hours,
or an average of 20,706 hours per year. The total cost over this period
is $7.3 million, or an average of $2.4 million per year. The average
burden per response for each activity that requires a collection of
information is 164 hours; the average cost per response is $19,310.
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information request unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR Part 9.
    To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, EPA has established a public docket for
this proposed rule under Docket ID number EPA-HQ-OW-2008-0390. Submit
any comments related to the ICR to EPA and OMB. See ADDRESSES section
at the beginning of this notice for where to submit comments to EPA.
Send comments to OMB at the Office of Information and Regulatory
Affairs, Office of Management and Budget, 725 17th Street, NW.,
Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is
required to make a decision concerning the ICR between 30 and 60 days
after July 25, 2008, a comment to OMB is best assured of having its
full effect if OMB receives it by August 25, 2008. The final rule will
respond to any OMB or public comments on the information collection
requirements contained in this proposal.

    Table VIII-1.--Annual, Total, and Annual Average Burden Hours and Costs for the Proposed Rule Information
                                    Collection Request 3-Year Approval Period
----------------------------------------------------------------------------------------------------------------
                                                                                                      Annual
                                      Year 1          Year 2          Year 3           Total          average
----------------------------------------------------------------------------------------------------------------
                   Total (Owners/Operators, Primay Agencies, and DI Programs/EPA Headquarters)
----------------------------------------------------------------------------------------------------------------
Burden (in hours)...............        21,934.2        18,293.7        18,435.2        62,117.0        20,705.7
Respondents.....................            24.3            28.2            29.9            47.0            27.5
Responses.......................           131.0           113.0           129.0           378.0           126.0
Costs ($).......................      $3,412,795      $2,428,168      $2,702,335      $7,299,064      $2,433,021
    Labor ($)...................      $1,132,302        $877,087        $887,616      $3,145,843      $1,048,614
    Non-Labor ($)...............      $2,280,493      $1,551,081      $1,814,719      $4,119,644      $1,373,215
Burden per Response.............           167.4           161.9           142.9           164.3           164.3
Cost per Response...............         $26,052         $21,488         $20,948         $19,310         $19,310
Burden per Respondent...........           901.4           648.4           615.9         1,321.6           753.1
Cost per Respondent.............        $140,252         $86,065         $90,278        $155,299         $88,495
----------------------------------------------------------------------------------------------------------------
                                                Operators/Owners
----------------------------------------------------------------------------------------------------------------
Burden (in hours)...............         5,359.5         2,118.0         2,228.5        13,160.0         4,386.7
Respondents.....................             3.0             4.0             5.0             5.0             4.0
Responses.......................            63.0            54.0            65.0           187.0            62.3
Costs ($).......................      $2,678,179      $1,711,130      $1,983,931      $5,129,006      $1,709,669
    Labor ($)...................        $397,687        $160,049        $169,212        $975,786        $325,262
    Non-Labor ($)...............      $2,280,493      $1,551,081      $1,814,719      $4,119,644      $1,373,215
Avg. Burden per Response........            85.1            39.2            34.3            70.4            70.4
Avg. Cost per Response..........         $42,511         $31,688         $30,522         $27,428         $27,428
Burden per Respondent...........         1,786.5           529.5           445.7           2,632         1,096.7
Cost per Respondent.............        $892,726        $427,783        $396,786      $1,025,801        $427,417
----------------------------------------------------------------------------------------------------------------
                                                Primacy Agencies
----------------------------------------------------------------------------------------------------------------
Burden (in hours)...............        11,278.8        10,990.7        11,013.1        33,281.8        11,093.9
Respondents.....................            10.3            13.2            13.9            31.0            12.5
Responses.......................            36.3            29.8            33.4            99.4            33.1
Costs ($).......................        $475,547        $463,433        $464,374      $1,403,354        $467,785
    Labor ($)...................        $475,547        $463,433        $464,374      $1,403,354        $467,785
    Non-Labor ($)...............  ..............  ..............  ..............  ..............  ..............
Burden per Response.............           311.1           369.1           330.0         1,010.2           336.7
Cost per Response...............         $13,117         $15,565         $13,915         $42,597         $14,199
Burden per Respondent...........         1,091.4           831.8           790.4         2,713.6           904.5

[[Page 43530]]


Cost per Respondent.............         $46,021         $35,073         $33,328        $114,422         $38,141
----------------------------------------------------------------------------------------------------------------
                                          DI Programs/EPA Headquarters
----------------------------------------------------------------------------------------------------------------
Burden (in hours)...............         5,296.6         5,184.9         5,193.6        15,675.2         5,225.1
Respondents.....................            11.0            11.0            11.0            11.0            11.0
Responses.......................            31.7            29.2            30.6            91.6            30.5
Costs ($).......................        $259,069        $253,605        $254,029        $766,703        $255,568
    Labor ($)...................        $259,069        $253,605        $254,029        $766,703        $255,568
    Non-Labor ($)...............  ..............  ..............  ..............  ..............  ..............
Burden per Response.............           166.8           177.4           169.6           171.1           171.1
Cost per Response...............          $8,161          $8,677          $8,294          $8,370          $8,370
Burden per Respondent...........           481.5           471.4           472.1         1,425.0           475.0
Cost per Respondent.............         $23,552         $23,055         $23,094         $69,700         $23,233
----------------------------------------------------------------------------------------------------------------
Note: Numbers may not appear to add due to rounding.

C. Regulatory Flexibility Act (RFA)

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions. For purposes
of assessing the impacts of today's proposed rule on small entities,
small entity is defined as: (1) A small business as defined by the
Small Business Administration's (SBA) regulations at 13 CFR 121.201;
(2) a small governmental jurisdiction that is a government of a city,
county, town, school district or special district with a population of
less than 50,000; and (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not
dominant in its field.
    After considering the economic impacts of today's proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. This
proposed rule will not impose any requirements on small entities.
Sequestering CO₂ via injection wells is a voluntary action
that would only be undertaken by a small entity if it were in its
interest compared to other alternatives it may have. GS of
CO₂ is still a scientifically complex activity, the cost of
which is anticipated to be prohibitive to small entities. Therefore it
is anticipated small entities would not elect to sequester
CO₂ via injection wells. We continue to be interested in the
potential impacts of the proposed rule on small entities and welcome
comments on issues related to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA regulation for which a written
statement is needed, section 205 of UMRA generally requires EPA to
identify and consider a reasonable number of regulatory alternatives
and adopt the least costly, most cost-effective or least burdensome
alternative that achieves the objectives of the rule. The provisions of
section 205 do not apply when they are inconsistent with applicable
law. Moreover, section 205 allows EPA to adopt an alternative other
than the least costly, most cost-effective or least burdensome
alternative if the Administrator publishes with the final rule an
explanation why that alternative was not adopted. Before EPA
establishes any regulatory requirements that may significantly or
uniquely affect small governments, including tribal governments, it
must have developed under section 203 of UMRA a small government agency
plan. The plan must provide for notifying potentially affected small
governments, enabling officials of affected small governments to have
meaningful and timely input in the development of EPA regulatory
proposals with significant Federal intergovernmental mandates, and
informing, educating, and advising small governments on compliance with
the regulatory requirements.
    Based on the analysis of 22 pilot projects, EPA has determined that
this proposed rule does not contain a Federal mandate that may result
in expenditures of $100 million or more for State, local, and tribal
governments, in the aggregate, or the private sector in any one year.
Expenditures associated with compliance for these projects, defined as
the incremental costs beyond the existing regulations under which a
CO₂ GS well could be permitted and deployed, will not
surpass $100 million in the aggregate in any year. Thus, today's
proposed rule is not subject to the requirements of sections 202 and
205 of UMRA. However, EPA recognizes that if CCS is used more widely,
the incremental costs of the requirements associated with this rule
could exceed $100 million in the aggregate in some years. EPA will
determine the applicability of UMRA for the final rule and provide any
necessary analysis.
    EPA has determined that this proposed rule contains no regulatory
requirements that might significantly or uniquely affect small
governments. Most regulated entities are anticipated to be private
entities, not governments.

E. Executive Order 13132: Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have Federalism

[[Page 43531]]

implications.'' ``Policies that have Federalism implications'' is
defined in the Executive Order to include regulations that have
``substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government.''
    This proposed rule does not have Federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. Currently, States may gain the
authority to regulate a full or partial UIC program in their State by
applying for primacy. States with primacy must develop a program
incorporating all new Federal requirements for Class VI wells if they
wish to regulate CO₂ GS, and all programs will be subject to
EPA approval. Since application for primacy is a voluntary process, the
addition of this proposed regulation to the UIC regulations should not
significantly impact States or their right to primacy for other classes
of wells. If States do not develop a program for Class VI wells, EPA
will oversee CO₂ GS in those States. Thus, Executive Order
13132 does not apply to this proposal.
    Although section 6 of Executive Order 13132 does not apply to this
rule, EPA did consult with State and local officials early in the
process of developing this proposed rule to permit them to have
meaningful and timely input in its development. EPA sent letters with
background about the rulemaking and an invitation for consultation to
the National Governors' Association, the National Conference of State
Legislatures, the Council of State Governments, the National League of
Cities, the U.S. Conference of Mayors, the National Association of
Counties, the International City/County Management Association, the
National Association of Towns and Townships, and the County Executives
of America. EPA held a meeting with interested parties from these
organizations in April 2008.
    In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed rule
from State and local officials. A summary of the concerns raised during
that consultation and EPA's response to those concerns will be provided
in the preamble to the final rule.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    Executive Order 13175, entitled ``Consultation and Coordination
With Indian Tribal Governments'' (59 FR 22951, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' This proposed rule does not
have tribal implications as specified in Executive Order 13175.
Currently, no Indian Tribes have primacy. However, Indian Tribes may
acquire authority to regulate a partial or full UIC program in lands
under their jurisdiction by applying for and gaining primacy from the
Agency. Tribes seeking primacy must develop requirements at least as
stringent as the new proposed Federal requirements for Class VI wells
if they wish to regulate CO₂ GS, and all programs will be
subject to EPA approval. If Tribes do not develop a program for Class
VI wells, EPA is responsible for regulating the GS of CO₂ on
tribal lands. The application for primacy is a voluntary process.
Furthermore, this proposal clarifies regulatory ambiguity rather than
placing new requirements on tribal or other governmental entities.
Therefore, this proposed rule should not change the Tribal-Federal
relationship and should not significantly impact Tribes. Thus,
Executive Order 13175 does not apply to this proposed rule.
    Although Executive Order 13175 does not apply to this proposed
rule, EPA consulted with tribal officials in developing this proposed
rule. EPA sent letters with background about the rulemaking and an
invitation for consultation to all of the federally recognized Indian
Tribes. EPA held a meeting with interested parties from Tribal
governments in April 2008.
    EPA specifically solicits additional comment on this proposed rule
from tribal officials.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    This action is not subject to EO 13045 (62 FR 19885, April 23,
1997) because it is not economically significant as defined in EO
12866, and because the Agency does not believe the environmental health
or safety risks addressed by this action present a disproportionate
risk to children. Moreover, this proposed rule will not require that
CO₂ GS be undertaken; but does require that if it is
undertaken, operators will conduct the activity in such a way as to
protect USDWs from endangerment caused by CO₂. This action's
health and risk assessments are contained in Risk and Occurrence
Document for Geologic Sequestration Proposed Rulemaking (USEPA, 2008e).
    The public is invited to submit comments or identify peer-reviewed
studies and data that assess the effects of early life exposure to
changes in drinking water quality that may be caused by geologic
sequestration of carbon dioxide.

H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use

    EPA has tentatively determined that this rule is not a
``significant energy action'' as defined in Executive Order 13211,
``Actions Concerning Regulations That Significantly Affect Energy
Supply, Distribution, or Use'' (66 FR 28355, May 22, 2001) because
application of these requirements to the 22 pilot projects is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. EPA will consider the potential effects
of more widespread application of the rule requirements and make a
final determination regarding EO 13211 applicability for the final rule
(see UMRA discussion above).
    The higher degree of regulatory certainty and clarity in the
permitting process may, in fact, have a positive effect on the energy
sector. Specifically, if climate change legislation that imposes caps
or taxes on CO₂ emissions is passed in the future, energy
generation firms and other CO₂ producing industries will
have an economic incentive to reduce emissions, and this rule will
provide regulatory certainty in determining how to maximize operations
(for example, by increasing production while staying within the
emissions cap or avoiding some carbon taxes). The proposed rule may
allow some firms to extend the life of their existing capital
investment in plant machinery or plant processes.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards

[[Page 43532]]

bodies. NTTAA directs EPA to provide Congress, through OMB,
explanations when the Agency decides not to use available and
applicable voluntary consensus standards.
    The proposed rulemaking involves technical standards. Therefore,
the Agency conducted a search to identify potentially applicable
voluntary consensus standards. However, we identified no such
standards, and none were brought to our attention. Thus the Agency
decided to convene numerous workshops (discussed further in Chapter 2
of the Cost Analysis for the GS proposed rule) to develop standards
based on current information available from experts in industry,
government, and non-governmental organizations. EPA proposes to use a
combination of technologies and standard practices that it estimates
will provide the necessary protection to USDWs with regard to site
characterization, construction, operation, monitoring, closure, and
post-closure requirements for CO₂ GS wells, without placing
undue burden on well operators. These methods are listed in Chapter 2
of the Cost Analysis for the GS proposed rule and described in further
detail in the Geologic CO2 Sequestration Technology & Cost Analysis
(USEPA, 2008h) developed in support of this proposed rule.
    EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially
applicable voluntary consensus standards and to explain why such
standards should be used in this regulation.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, any disproportionately
high and adverse human health or environmental effects of their
programs, policies, and activities on minority populations and low-
income populations in the United States.
    EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it increases the
level of environmental protection for all affected populations without
having any disproportionately high and adverse human health or
environmental effects on any population, including any minority or low-
income population.
    Existing electric power generation plants that burn fossil fuels
may be more prevalent in areas with higher percentages of people who
are minorities or have lower incomes on average, but it is hard to
predict where new plants with CCS will be built. This proposed rule
would not require that CO₂ GS be undertaken; but does
require that if it is undertaken, operators will conduct the activity
in such a way as to protect USDWs from endangerment caused by
CO₂. Additionally, this proposed rule if finalized will
ensure that all areas of the United States are subject to the same
minimum Federal requirements for protection of USDWs from endangerment
from GS. Additional detail regarding the potential risk of the proposed
rule is presented in the Risk and Occurrence Document for Geologic
Sequestration Proposed Rulemaking (USEPA, 2008e).
    EPA believes that UIC permit writers should consider the impact of
GS on any communities in the geographic areas of GS sites. Permit
writers can ask specific questions to specifically address any
potentially different impacts on minority and/or low-income
communities. Examples include: In reviewing the application or Notice
of Intent (NOI) for a GS permit, is there any indication that a
minority and/or low-income community would be adversely affected? Are
there measures that should be undertaken to understand minority and/or
low-income community concerns during the permit drafting and
development phase, including the development of permit conditions? If
an environmental justice issue is identified, does the program solicit
input and participation from minority and/or low-income populations?
    EPA seeks comment on environmental justice considerations for GS
permit writers.

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USEPA 2008g. Information Collection Request for the Federal
Requirements

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Under the Underground Injection Control Program for Carbon Dioxide
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Washington, DC.

List of Subjects

40 CFR Part 144

    Environmental protection, Administrative practice and procedure,
Confidential business information, Hazardous waste, Indians--lands,
Reporting and recordkeeping requirements, Surety bonds, Water supply.

40 CFR Part 146

    Environmental protection, Hazardous waste, Indian lands, Reporting
and recordkeeping requirements, Water supply.

    Dated: July 15, 2008.
Stephen L. Johnson,
Administrator.
    For the reasons set forth in the preamble, title 40 chapter I of
the Code of Federal Regulations is proposed to be amended as follows:

PART 144--UNDERGROUND INJECTION CONTROL PROGRAM

    1. The authority citation for part 144 continues to read as
follows:

    Authority: 42 U.S.C. 300f et seq.; Resource Conservation and
Recovery Act, 42 U.S.C. 6901 et seq.

Subpart A--General Provisions

    2. Section 144.1 is amended as follows:
    a. Adding new paragraph (f)(1)(viii); and
    b. Revising the first two sentences in paragraph (g) introductory
text.


Sec.  144.1  Purpose and scope of part 144.

* * * * *
    (f) * * *
    (1) * * *
    (viii) Subpart H of this part sets forth requirements for owners or
operators of Class VI injection wells.
* * * * *
    (g) Scope of the permit or rule requirement. The UIC Permit Program
regulates underground injections by six classes of wells (see
definition of ``well injection,'' Sec.  144.3). The six classes of
wells are set forth in Sec.  144.6. All owners or operators of these
injection wells must be authorized either by permit or rule by the
Director. * * *
* * * * *
    3. Section 144.6 is amended as follows:
    a. Revising paragraph (e); and
    b. Adding new paragraph (f).


Sec.  144.6  Classification of wells.

* * * * *
    (e) Class V. Injection wells not included in Class I, II, III, IV,
or VI. Specific types of Class V injection wells are described in Sec. 
144.81.
    (f) Class VI. Wells used for geologic sequestration of carbon
dioxide beneath the lowermost formation containing a USDW.

Subpart B--General Program Requirements

    4. Adding Sec.  144.15 to read as follows.


Sec.  144.15  Prohibition of non-experimental Class V wells for
geologic sequestration.

    The construction, operation or maintenance of any non-experimental
Class V geologic sequestration well is prohibited.
    5. Adding Sec.  144.18 to read as follows.


Sec.  144.18  Requirements for Class VI wells.

    Owners or operators of Class VI wells must obtain a permit. Class
VI wells are not authorized by rule to inject.

Subpart D--Authorization by Permit

    6. Section 144.36 is amended by revising the first two sentences in
paragraph (a) to read as follows:


Sec.  144.36  Duration of permits.

    (a) Permits for Class I and V wells shall be effective for a fixed
term not to exceed 10 years. UIC Permits for Class II, III and VI wells
shall be issued for a period up to the operating life of the facility.
* * *
* * * * *
    7. Section 144.39 is amended by revising the second sentence in
paragraph (a) introductory text and by revising the second sentence in
paragraph (a)(3) introductory text to read as follows:


Sec.  144.39  Modification or revocation and reissuance of permits.

* * * * *
    (a) * * * For Class I hazardous waste injection wells, Class II,
Class III or Class VI wells the following may be causes for revocation
and reissuance as well as modification; and for all other wells the
following may be cause for revocation or reissuance as well as
modification when the permittee requests or agrees. * * *
* * * * *
    (3) * * * Permits other than for Class I hazardous waste injection
wells, Class II, Class III or Class VI wells may be modified during
their terms for this cause only as follows: * * *
* * * * *

Subpart E--Permit Conditions

    8. Section 144.51 is amended by revising the first sentence in
paragraph (q)(1) and the first sentence in paragraph (q)(2) to read as
follows:


Sec.  144.51  Conditions applicable to all permits.

* * * * *
    (q) * * *
    (1) The owner or operator of a Class I, II, III or VI well
permitted under this part shall establish mechanical integrity prior to
commencing injection or on a schedule determined by the Director.
Thereafter the owner or operator of Class I, II, and III wells must
maintain mechanical integrity as defined in Sec.  146.8 and the owner
or operator of Class VI wells must maintain mechanical integrity as
defined in Sec.  146.89 of this chapter. * * *
    (2) When the Director determines that a Class I, II, III or VI well
lacks mechanical integrity pursuant to Sec.  146.8 or Sec.  146.89 for
Class VI of this chapter, he/she shall give written notice of his/her
determination to the owner or operator. * * *
* * * * *
    9. Section 144.52 is amended by revising paragraph (a)(8) to read
as follows:


Sec.  144.52  Establishing permit conditions.

    (a) * * *
    (8) Mechanical integrity. A permit for any Class I, II, III or VI
well or injection project which lacks mechanical integrity shall
include, and for any Class V well may include, a condition prohibiting
injection operations until the permittee shows to the satisfaction of
the Director under Sec.  146.08 or Sec.  146.89 for Class VI that the
well has mechanical integrity.
* * * * *

[[Page 43535]]

    10. Section 144.55 is amended by revising the first sentence in
paragraph (a) to read as follows:


Sec.  144.55  Corrective action.

    (a) Coverage. Applicants for Class I, II, (other than existing),
III or VI injection well permits shall identify the location of all
known wells within the injection well's area of review which penetrate
the injection zone, or in the case of Class II wells operating over the
fracture pressure of the injection formation, all known wells within
the area of review penetrating formations affected by the increase in
pressure. Applicants for Class VI shall perform corrective action as
specified in Sec.  146.84.* * *
* * * * *

Subpart G--Requirements for Owners and Operators of Class V
Injection Wells

    11. Section 144.80 is amended by revising the first sentence in
paragraph (e) and by adding paragraph (f) to read as follows:


Sec.  144.80  What is a Class V injection well?

* * * * *
    (e) Class V. Injection wells not included in Class I, II, III, IV
or VI. * * *
    (f) Class VI. Wells used for geologic sequestration of carbon
dioxide.

PART 146--UNDERGROUND INJECTION CONTROL PROGRAM: CRITERIA AND
STANDARDS

    12. The authority citation for part 146 continues to read as
follows:

    Authority: Safe Drinking Water Act 42, U.S.C. 300f et seq.;
Resource Conservation and Recovery Act, 42 U.S.C. 6901 et seq.

    13. Section 146.5 is amended as follows:
    a. Revising the first sentence in paragraph (e) introductory text;
and
    b. Adding paragraph (f).


Sec.  146.5  Classification of injection wells.

* * * * *
    (e) Class V. Injection wells not included in Class I, II, III, IV
or VI. * * *
* * * * *
    (f) Class VI. Wells used for geologic sequestration of carbon
dioxide beneath the lowermost formation containing an underground
source of drinking water (USDW).
    14. Subpart H is added to read as follows:
Subpart H--Criteria and Standards Applicable to Class VI Wells
Sec.
146.81 Applicability.
146.82 Required Class VI permit information.
146.83 Minimum criteria for siting.
146.84 Area of review and corrective action.
146.85 Financial responsibility.
146.86 Injection well construction requirements.
146.87 Logging, sampling, and testing prior to injection well
operation.
146.88 Injection well operating requirements.
146.89 Mechanical integrity.
146.90 Testing and monitoring requirements.
146.91 Reporting requirements.
146.92 Injection well plugging.
146.93 Post-injection site care and site closure.
146.94 Emergency and remedial response.

Subpart H--Criteria and Standards Applicable to Class VI Wells


Sec.  146.81  Applicability.

    (a) This subpart establishes criteria and standards for underground
injection control programs to regulate Class VI carbon dioxide geologic
sequestration injection wells.
    (b) This subpart applies to wells used to inject carbon dioxide
specifically for the purpose of geologic sequestration, i.e., the long-
term containment of a gaseous, liquid or supercritical carbon dioxide
stream in subsurface geologic formations.
    (c) This subpart applies to owners and operators of permit or rule-
authorized Class I industrial, Class II, or Class V experimental carbon
dioxide injection projects who seek to apply for a Class VI geologic
sequestration permit for their well or wells. If the Director
determines that USDWs will not be endangered, such wells are exempt, at
the Director's discretion, from the casing and cementing requirements
at Sec. Sec.  146.86(b) and 146.87(a)(1) through (3).
    (d) Definitions. The following definitions apply to this subpart.
To the extent that these definitions conflict with those in Sec.  146.3
these definitions govern:
    Area of review means 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.
    Carbon dioxide plume means the underground extent, in three
dimensions, of an injected carbon dioxide stream.
    Carbon dioxide stream means 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.
    Confining zone means 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 means 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
(USDW).
    Geologic sequestration means 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 means an injection well or wells
used to emplace a carbon dioxide 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.
    Injection zone means 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.
    Post-injection site care means 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 means the zone of elevated pressure that is created
by the injection of carbon dioxide into the subsurface. For the
purposes of this subpart, the pressure front of a carbon dioxide plume
refers to a zone where there is a pressure differential sufficient to
cause the movement of injected fluids or formation fluids into a USDW.
    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 is released from post-injection site care
responsibilities.
    Transmissive fault or fracture means a fault or fracture that has
sufficient permeability and vertical extent to allow fluids to move
between formations.

[[Page 43536]]

Sec.  146.82  Required Class VI permit information.

    This section sets forth the information which the owner or operator
must submit to the Director in order to be permitted as a Class VI
well. The application for a permit for construction and operation of a
Class VI well must include the following:
    (a) Information required in 40 CFR 144.31(e)(1) through (6);
    (b) A map showing the injection well(s) for which a permit is
sought and the applicable area of review. Within the area of review,
the map must show the number, or name and location of all injection
wells, producing wells, abandoned wells, plugged wells or dry holes,
deep stratigraphic boreholes, State or EPA approved subsurface cleanup
sites, surface bodies of water, springs, mines (surface and
subsurface), quarries, water wells and other pertinent surface features
including structures intended for human occupancy and roads. The map
should also show faults, if known or suspected. Only information of
public record is required to be included on this map;
    (c) The area of review based on modeling, using data obtained
during logging and testing of the well and the formation as required by
paragraphs (l), (r), and (s) of this section;
    (d) Information on the geologic structure and hydrogeologic
properties of the proposed storage site and overlying formations,
including:
    (1) Maps and cross sections of the area of review;
    (2) Location, orientation, and properties of known or suspected
faults and fractures that may transect the confining zone(s) in the
area of review and a determination that they would not interfere with
containment;
    (3) Information on seismic history including the presence and depth
of seismic sources and a determination that the seismicity would not
interfere with containment;
    (4) Data on the depth, areal extent, thickness, mineralogy,
porosity, permeability and capillary pressure of the injection and
confining zone(s); including geology/facies changes based on field data
which may include geologic cores, outcrop data, seismic surveys, well
logs, and names and lithologic descriptions;
    (5) Geomechanical information on fractures, stress, ductility, rock
strength, and in situ fluid pressures within the confining zone; and
    (6) Geologic and topographic maps and cross sections illustrating
regional geology, hydrogeology, and the geologic structure of the local
area.
    (e) A tabulation of all wells within the area of review which
penetrate the injection or confining zone(s). Such data must include a
description of each well's type, construction, date drilled, location,
depth, record of plugging and/or completion, and any additional
information the Director may require;
    (f) Maps and stratigraphic cross sections indicating the general
vertical and lateral limits of all USDWs, water wells and springs
within the area of review, their positions relative to the injection
zone(s) and the direction of water movement, where known;
    (g) Baseline geochemical data on subsurface formations, including
all USDWs in the area of review;
    (h) Proposed operating data:
    (1) Average and maximum daily rate and volume of the carbon dioxide
stream;
    (2) Average and maximum injection pressure;
    (3) The source of the carbon dioxide stream; and
    (4) An analysis of the chemical and physical characteristics of the
carbon dioxide stream;
    (i) The compatibility of the carbon dioxide stream with fluids in
the injection zone and minerals in both the injection and the confining
zone(s), based on the results of the formation testing program, and
with the materials used to construct the well;
    (j) Proposed formation testing program to obtain an analysis of the
chemical and physical characteristics of the injection zone and
confining zone;
    (k) Proposed stimulation program and a determination that
stimulation will not interfere with containment;
    (l) The results of the formation testing program as required in
paragraph (j) of this section;
    (m) Proposed procedure to outline steps necessary to conduct
injection operation;
    (n) Schematic or other appropriate drawings of the surface and
subsurface construction details of the well;
    (o) Injection well construction procedures that meet the
requirements of Sec.  146.86;
    (p) Proposed area of review and corrective action plan that meets
the requirements under Sec.  146.84;
    (q) The status of corrective action on wells in the area of review;
    (r) All available logging and testing program data on the well
required by Sec.  146.87;
    (s) A demonstration of mechanical integrity pursuant to Sec. 
146.89;
    (t) A demonstration, satisfactory to the Director, that the
applicant has met the financial responsibility requirements under Sec. 
146.85;
    (u) Proposed testing and monitoring plan required by Sec.  146.90;
    (v) Proposed injection well plugging plan required by Sec. 
146.92(b);
    (w) Proposed post-injection site care and site closure plan
required by Sec.  146.93(a);
    (x) Proposed emergency and remedial response plan required by Sec. 
146.94; and
    (y) Any other information requested by the Director.


Sec.  146.83  Minimum criteria for siting.

    (a) Owners or operators of Class VI wells must demonstrate to the
satisfaction of the Director that the wells will be sited in areas with
a suitable geologic system. The geologic system must be comprised of:
    (1) An injection zone of sufficient areal extent, thickness,
porosity, and permeability to receive the total anticipated volume of
the carbon dioxide stream;
    (2) A confining zone(s) that is free of transmissive faults or
fractures and of sufficient areal extent and integrity to contain the
injected carbon dioxide stream and displaced formation fluids and allow
injection at proposed maximum pressures and volumes without initiating
or propagating fractures in the confining zone(s); and
    (b) At the Director's discretion, owners or operators of Class VI
wells must identify and characterize additional zones that will impede
vertical fluid movement, are free of faults and fractures that may
interfere with containment, allow for pressure dissipation, and provide
additional opportunities for monitoring, mitigation and remediation.


Sec.  146.84  Area of review and corrective action.

    (a) The area of review is 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.
    (b) The owner or operator of a Class VI well must prepare,
maintain, and comply with a plan to delineate the area of review for a
proposed geologic sequestration project, periodically reevaluate the
delineation, and perform corrective action that meets the requirements
of this section and is acceptable to the Director. As a part of the
permit application for approval by the Director, the owner or operator
must submit an area of review and corrective action plan that includes
the following information:
    (1) The method for delineating the area of review that meets the

[[Page 43537]]

requirements of paragraph (c) of this section, including the model to
be used, assumptions that will be made, and the site characterization
data on which the model will be based;
    (2) A description of:
    (i) The minimum fixed frequency, not to exceed 10 years, the owner
or operator proposes to reevaluate the area of review;
    (ii) The monitoring and operational conditions that would warrant a
reevaluation of the area of review prior to the next scheduled
reevaluation as determined by the minimum fixed frequency established
in paragraph (b)(2)(i) of this section.
    (iii) How monitoring and operational data (e.g., injection rate and
pressure) will be used to inform an area of review reevaluation; and
    (iv) How corrective action will be conducted to meet the
requirements of paragraph (d) of this section, including what
corrective action will be performed prior to injection and what, if
any, portions of the area of review will have corrective action
addressed on a phased basis and how the phasing will be determined; how
corrective action will be adjusted if there are changes in the area of
review; and how site access will be guaranteed for future corrective
action.
    (c) Owners or operators of Class VI wells must perform the
following actions to delineate the area of review, identify all wells
that require corrective action, and perform corrective action on those
wells:
    (1) Predict, using computational modeling, the projected lateral
and vertical migration of the carbon dioxide plume and formation fluids
in the subsurface from the commencement of injection activities until
the plume movement ceases, pressure differentials sufficient to cause
the movement of injected fluids or formation fluids into a USDW are no
longer present, or after a fixed time period as determined by the
Director. The model must:
    (i) Be based on detailed geologic data collected to characterize
the injection zone, confining zone and any additional zones; and
anticipated operating data, including injection pressures, rates and
total volumes over the proposed life of the geological sequestration
project;
    (ii) Take into account any geologic heterogeneities, data quality,
and their possible impact on model predictions; and
    (iii) Consider potential migration through faults, fractures, and
artificial penetrations.
    (2) Using methods approved by the Director, identify all
penetrations, including active and abandoned wells and underground
mines, in the area of review that may penetrate the confining zone.
Provide a description of each well's type, construction, date drilled,
location, depth, record of plugging and/or completion, and any
additional information the Director may require; and
    (3) Determine which abandoned wells in the area of review have been
plugged (as required by Sec.  146.92) in a manner that prevents the
movement of carbon dioxide or associated fluids that may endanger
USDWs.
    (d) Owners or operators of Class VI wells must perform corrective
action on all wells in the area of review that are determined to need
corrective action using methods necessary to prevent the movement of
fluid into or between USDWs including use of corrosion resistant
materials, where appropriate.
    (e) If monitoring data indicate an endangerment to USDWs, the owner
or operator must notify the Director and cease operations as required
by Sec.  146.94.
    (f) At the minimum fixed frequency, not to exceed 10 years, as
specified in the area of review and corrective action plan, or when
monitoring and operational conditions warrant, owners or operators must:
    (1) Reevaluate the area of review in the same manner specified in
paragraph (c)(1) of this section;
    (2) Identify all wells in the reevaluated area of review that
require corrective action in the same manner specified in paragraph
(c)(2) of this section;
    (3) Perform corrective action on wells requiring corrective action
in the reevaluated area of review in the same manner specified in
paragraph (c)(3) of this section; and
    (4) Submit an amended area of review and corrective action plan or
demonstrate to the Director through monitoring data and modeling
results that no amendment to the area of review and corrective action
plan is needed.
    (g) The emergency and remedial response plan (as required by Sec. 
146.94) and a demonstration of financial responsibility (as described
by Sec.  146.85) must account for the entire area of review, regardless
of whether or not corrective action in the area of review is phased.

Sec.  146.85  Financial responsibility.

    (a) The owner or operator must demonstrate and maintain financial
responsibility and resources for corrective action (that meets the
requirements of Sec.  146.84), injection well plugging (that meets the
requirements of Sec.  146.92), post-injection site care and site
closure (that meets the requirements of Sec.  146.93), and emergency
and remedial response (that meets the requirements of Sec.  146.94) in
a manner prescribed by the Director until:
    (1) The Director receives and approves the completed post-injection
site care and site closure plan; and
    (2) The Director determines that the site has reached the end of
the post-injection site care period.
    (b) The owner or operator must provide to the Director, at a
frequency determined by the Director, written updates of adjustments to
the cost estimate to account for any amendments to the area of review
and corrective action plan (Sec.  146.84), the injection well plugging
plan (Sec.  146.92), and the post-injection site care and site closure
plan (Sec.  146.93).
    (c) The owner or operator must notify the Director of adverse
financial conditions such as bankruptcy, that may affect the ability to
carry out injection well plugging and post-injection site care and site
closure.
    (d) The operator must provide an adjustment of the cost estimate to
the Director if the Director has reason to believe that the original
demonstration is no longer adequate to cover the cost of injection well
plugging (as required by Sec.  146.92) and post-injection site care and
site closure (as required by Sec.  146.93).

Sec.  146.86  Injection well construction requirements.

    (a) General. The owner or operator must ensure that all Class VI
wells are constructed and completed to:
    (1) Prevent the movement of fluids into or between USDWs or into
any unauthorized zones;
    (2) Permit the use of appropriate testing devices and workover
tools; and
    (3) Permit continuous monitoring of the annulus space between the
injection tubing and long string casing.
    (b) Casing and Cementing of Class VI Wells.
    (1) Casing and cement or other materials used in the construction
of each Class VI well must have sufficient structural strength and be
designed for the life of the geologic sequestration project. All well
materials must be compatible with fluids with which the materials may
be expected to come into contact and meet or exceed standards developed
for such materials by the American Petroleum Institute, ASTM
International, or comparable standards acceptable to the Director. The
casing and cementing program must be designed to prevent the movement
of fluids into or between USDWs. In order to allow the Director to
determine and specify casing and cementing

[[Page 43538]]

requirements, the owner or operator must provide the following
information:
    (i) Depth to the injection zone;
    (ii) Injection pressure, external pressure, internal pressure and
axial loading;
    (iii) Hole size;
    (iv) Size and grade of all casing strings (wall thickness, external
diameter, nominal weight, length, joint specification and construction
material);
    (v) Corrosiveness of the carbon dioxide stream, and formation
fluids;
    (vi) Down-hole temperatures;
    (vii) Lithology of injection and confining zones;
    (viii) Type or grade of cement; and
    (ix) Quantity, chemical composition, and temperature of the carbon
dioxide stream.
    (2) Surface casing must extend through the base of the lowermost
USDW and be cemented to the surface.
    (3) At least one long string casing, using a sufficient number of
centralizers, must extend to the injection zone and must be cemented by
circulating cement to the surface in one or more stages.
    (4) Circulation of cement may be accomplished by staging. The
Director may approve an alternative method of cementing in cases where
the cement cannot be recirculated to the surface, provided the owner or
operator can demonstrate by using logs that the cement does not allow
fluid movement behind the well bore.
    (5) Cement and cement additives must be compatible with the carbon
dioxide stream and formation fluids and of sufficient quality and
quantity to maintain integrity over the design life of the geologic
sequestration project. The integrity and location of the cement shall
be verified using technology capable of evaluating cement quality
radially and identifying the location of channels to ensure that USDWs
are not endangered.
    (c) Tubing and packer.
    (1) All owner and operators of Class VI wells must inject fluids
through tubing with a packer set at a depth opposite a cemented
interval at the location approved by the Director.
    (2) In order for the Director to determine and specify requirements
for tubing and packer, the owner or operator must submit the following
information:
    (i) Depth of setting;
    (ii) Characteristics of the carbon dioxide stream (chemical
content, corrosiveness, temperature, and density);
    (iii) Injection pressure;
    (iv) Annular pressure;
    (v) Injection rate (intermittent or continuous) and volume of the
carbon dioxide stream;
    (vi) Size of casing; and
    (vii) Tubing tensile, burst, and collapse strengths.

Sec.  146.87  Logging, sampling, and testing prior to injection well
operation.

    (a) During the drilling and construction of a Class VI injection
well, the owner or operator must run appropriate logs, surveys and
tests to determine or verify the depth, thickness, porosity,
permeability, and lithology of, and the salinity of any formation
fluids in, all relevant geologic formations to assure conformance with
the injection well construction requirements under Sec.  146.86, and to
establish accurate baseline data against which future measurements may
be compared. The owner or operator must submit to the Director a
descriptive report prepared by a knowledgeable log analyst that
includes an interpretation of the results of such logs and tests. At a
minimum, such logs and tests must include:
    (1) Deviation checks during drilling on all holes constructed by
drilling a pilot hole which are enlarged by reaming or another method.
Such checks must be at sufficiently frequent intervals to determine the
location of the borehole and to assure that vertical avenues for fluid
movement in the form of diverging holes are not created during
drilling; and
    (2) Before and upon installation of the surface casing:
    (i) Resistivity, spontaneous potential, and caliper logs before the
casing is installed; and
    (ii) A cement bond and variable density log, and a temperature log
after the casing is set and cemented.
    (3) Before and upon installation of the long string casing:
    (i) Resistivity, spontaneous potential, porosity, caliper, gamma
ray, fracture finder logs, and any other logs the Director requires for
the given geology before the casing is installed; and
    (ii) A cement bond and variable density log, and a temperature log
after the casing is set and cemented.
    (4) A series of tests designed to demonstrate the internal and
external mechanical integrity of injection wells, which may include:
    (i) A pressure test with liquid or gas;
    (ii) A tracer survey such as oxygen-activation logging;
    (iii) A temperature or noise log;
    (iv) A casing inspection log, if required by the Director; and
    (5) Any alternative methods that provide equivalent or better
information and that are required of and/or approved of by the
Director.
    (b) The owner or operator must take and submit to the Director
whole cores or sidewall cores of the injection zone and confining
system and formation fluid samples from the injection zone(s). The
Director may accept cores from nearby wells if the owner or operator
can demonstrate that core retrieval is not possible and that such cores
are representative of conditions at the well. The Director may require
the owner or operator to core other formations in the borehole.
    (c) The owner or operator must record the fluid temperature, pH,
conductivity, reservoir pressure and the static fluid level of the
injection zone(s).
    (d) At a minimum, the owner or operator must determine or calculate
the following information concerning the injection and confining
zone(s):
    (1) Fracture pressure;
    (2) Other physical and chemical characteristics of the injection
and confining zones; and
    (3) Physical and chemical characteristics of the formation fluids
in the injection zone.
    (e) Upon completion, but prior to operation, the owner or operator
must conduct the following tests to verify hydrogeologic
characteristics of the injection zone:
    (1) A pump test; or
    (2) Injectivity tests.
    (f) The owner or operator must provide the Director with the
opportunity to witness all logging and testing by this subpart. The
owner or operator must submit a schedule of such activities to the
Director 30 days prior to conducting the first test and submit any
changes to the schedule 30 days prior to the next scheduled test.

Sec.  146.88  Injection well operating requirements.

    (a) Except during stimulation, the owner or operator must ensure
that injection pressure does not exceed 90 percent of the fracture
pressure of the injection zone so as to assure that the injection does
not initiate new fractures or propagate existing fractures in the
injection zone. In no case may injection pressure initiate fractures in
the confining zone(s) or cause the movement of injection or formation
fluids that endangers a USDW.
    (b) Injection between the outermost casing protecting USDWs and the
well bore is prohibited.
    (c) The owner or operator must fill the annulus between the tubing
and the long string casing with a non-corrosive fluid approved by the
Director. The owner or operator must maintain on the annulus a pressure
that exceeds the operating injection pressure, unless the

[[Page 43539]]

Director determines that such requirement might harm the integrity of
the well.
    (d) Other than during periods of well workover (maintenance)
approved by the Director in which the sealed tubing-casing annulus is
of necessity disassembled for maintenance or corrective procedures, the
owner or operator must maintain mechanical integrity of the injection
well at all times.
    (e) The owner or operator must install and use continuous recording
devices to monitor: The injection pressure; the rate, volume, and
temperature of the carbon dioxide stream; and the pressure on the
annulus between the tubing and the long string casing and annulus fluid
volume; and must install and use alarms and automatic down-hole shut-
off systems, designed to alert the operator and shut-in the well when
operating parameters such as annulus pressure, injection rate or other
parameters approved by the Director diverge beyond permitted ranges
and/or gradients specified in the permit;
    (f) If a down-hole automatic shutdown is triggered or a loss of
mechanical integrity is discovered, the owner or operator must
immediately investigate and identify as expeditiously as possible the
cause of the shutoff. If, upon such investigation, the well appears to
be lacking mechanical integrity, or if monitoring required under
paragraph (e) of this section otherwise indicates that the well may be
lacking mechanical integrity, the owner or operator must:
    (1) Immediately cease injection;
    (2) Take all steps reasonably necessary to determine whether there
may have been a release of the injected carbon dioxide stream into any
unauthorized zone;
    (3) Notify the Director within 24 hours;
    (4) Restore and demonstrate mechanical integrity to the
satisfaction of the Director prior to resuming injection; and
    (5) Notify the Director when injection can be expected to resume.


Sec.  146.89  Mechanical integrity.

    (a) A Class VI well has mechanical integrity if:
    (1) There is no significant leak in the casing, tubing or packer;
and
    (2) There is no significant fluid movement into a USDW through
channels adjacent to the injection well bore.
    (b) To evaluate the absence of significant leaks under paragraph
(a)(1) of this section, owners or operators must, following an initial
annulus pressure test, continuously monitor injection pressure, rate,
injected volumes, and pressure on the annulus between tubing and long
stem casing and annulus fluid volume as specified in Sec.  146.88(e);
    (c) At least once per year, the owner or operator must use one of
the following methods to determine the absence of significant fluid
movement under paragraph (a)(2) of this section:
    (1) A tracer survey such as oxygen-activation logging;
    (2) A temperature or noise log; or
    (3) A casing inspection log, if required by the Director.
    (d) The Director may require any other test to evaluate mechanical
integrity under paragraph (a)(1) or (a)(2) of this section. Also, the
Director may allow the use of a test to demonstrate mechanical
integrity other than those listed above with the written approval of
the Administrator. To obtain approval, the Director must submit a
written request to the Administrator, which must set forth the proposed
test and all technical data supporting its use. The Administrator must
approve the request if it will reliably demonstrate the mechanical
integrity of wells for which its use is proposed. Any alternate method
approved by the Administrator will be published in the Federal Register
and may be used in all States in accordance with applicable State law
unless its use is restricted at the time of approval by the
Administrator.
    (e) In conducting and evaluating the tests enumerated in this
section or others to be allowed by the Director, the owner or operator
and the Director must apply methods and standards generally accepted in
the industry. When the owner or operator reports the results of
mechanical integrity tests to the Director, he/she shall include a
description of the test(s) and the method(s) used. In making his/her
evaluation, the Director must review monitoring and other test data
submitted since the previous evaluation.
    (f) The Director may require additional or alternative tests if the
results presented by the owner or operator under paragraph (d) of this
section are not satisfactory to the Director to demonstrate that there
is no significant leak in the casing, tubing or packer or significant
movement of fluid into or between USDWs resulting from the injection
activity as stated in paragraphs (a)(1) and (2) of this section.


Sec.  146.90  Testing and monitoring requirements.

    The owner or operator of a Class VI well must prepare, maintain,
and comply with a testing and monitoring plan to verify that the
geologic sequestration project is operating as permitted and is not
endangering USDWs. The testing and monitoring plan must be submitted
with the permit application, for Director approval, and must include a
description of how the owner or operator will meet the requirements of
this section. Testing and monitoring associated with geologic
sequestration projects must, at a minimum, include:
    (a) Analysis of the carbon dioxide stream with sufficient frequency
to yield data representative of its chemical and physical
characteristics;
    (b) Installation and use, except during well workovers as defined
in Sec.  146.86(d), of continuous recording devices to monitor
injection pressure, rate and volume; the pressure on the annulus
between the tubing and the long string casing; and the annulus fluid
volume;
    (c) Corrosion monitoring of the well materials for loss of mass,
thickness, cracking, pitting and other signs of corrosion must be
performed on a quarterly basis to ensure that the well components meet
the minimum standards for material strength and performance set forth
in Sec.  146.86(b) by:
    (1) Placing coupons of the well construction materials in contact
with the carbon dioxide stream; or
    (2) Routing the carbon dioxide stream through a loop constructed
with the material used in the well; or
    (3) Using an alternative method approved by the Director;
    (d) Periodic monitoring of the ground water quality and geochemical
changes above the confining zone(s) that may be a result of carbon
dioxide movement through the confining zone or additional identified
zones:
    (1) The location and number of monitoring wells must be based on
specific information about the geologic sequestration project,
including injection rate and volume, geology, the presence of
artificial penetrations and other factors;
    (2) The monitoring frequency and spatial distribution of monitoring
wells must be based on baseline geochemical data that has been
collected under Sec.  146.82(a)(6) and any modeling results in the area
of review evaluation required by Sec.  146.84(b);
    (e) A demonstration of external mechanical integrity pursuant to
Sec.  146.89(c) at least once per year throughout the duration of the
geologic sequestration project;
    (f) A pressure fall-off test at least once every five years unless
more frequent testing is required by the Director based on site
specific information;

[[Page 43540]]

    (g) Testing and monitoring to track the extent of the carbon
dioxide plume and the position of the pressure front by either
monitoring for pressure changes in the first formation overlying the
confining zone or using indirect, geophysical techniques (e.g.,
seismic, electrical, gravity, or electromagnetic surveys and/or down-
hole carbon dioxide detection tools);
    (h) At the Director's discretion, surface air monitoring and/or
soil gas monitoring to detect movement of carbon dioxide that could
endanger a USDW.
    (1) The testing and monitoring plan must be based on potential
vulnerabilities within the area of review;
    (2) The monitoring frequency and spatial distribution of surface
air monitoring and/or soil gas monitoring must reflect baseline data
and the monitoring plan must include how the proposed monitoring will
yield useful information on the area of review delineation and/or
compliance with standards under 40 CFR 144.12;
    (i) Any additional monitoring, as required by the Director,
necessary to support, upgrade, and improve computational modeling of
the area of review evaluation required under Sec.  146.84(b) and to
determine compliance with standards under 40 CFR 144.12; and
    (j) A quality assurance and surveillance plan for all testing and
monitoring requirements.

Sec.  146.91  Reporting requirements.

    The owner or operator must, at a minimum, provide the following
reports to the Director, for each permitted Class VI well:
    (a) Semi-annual reports containing:
    (1) Any changes to the physical, chemical and other relevant
characteristics of the carbon dioxide stream from the proposed
operating data;
    (2) Monthly average, maximum and minimum values for injection
pressure, flow rate and volume, and annular pressure;
    (3) A description of any event that exceeds operating parameters
for annulus pressure or injection pressure as specified in the permit;
    (4) A description of any event which triggers a shutdown device
required pursuant to Sec.  146.88(e) and the response taken;
    (5) The monthly volume of the carbon dioxide stream injected over
the reporting period and project cumulatively;
    (6) Monthly annulus fluid volume added; and
    (7) The results of monitoring prescribed under Sec.  146.90.
    (b) Report, within 30 days the results of:
    (1) Periodic tests of mechanical integrity;
    (2) Any other test of the injection well conducted by the permittee
if required by the Director; and
    (3) Any well workover.
    (c) Owners or operators must submit reports in an electronic format
acceptable to the Director. At the discretion of the Director, other
formats may be accepted.

Sec.  146.92  Injection well plugging.

    (a) Prior to the well plugging, the owner or operator must flush
each Class VI injection well with a buffer fluid, determine bottomhole
reservoir pressure, and perform a final mechanical integrity test.
    (b) Well Plugging Plan. The owner or operator of a Class VI well
must prepare, maintain, and comply with a plan that is acceptable to
the Director. The requirement to maintain and implement an approved
plan is directly enforceable regardless of whether the requirement is a
condition of the permit. The well plugging plan must be submitted as
part of the permit application and must include the following
information:
    (1) Appropriate test or measure to determine bottomhole reservoir
pressure;
    (2) Appropriate testing methods to ensure mechanical integrity as
specified in Sec.  146.89;
    (3) The type and number of plugs to be used;
    (4) The placement of each plug including the elevation of the top
and bottom of each plug;
    (5) The type and grade and quantity of material to be used in
plugging. The material must be compatible with the carbon dioxide
stream; and
    (6) The method of placement of the plugs.
    (c) Notice of intent to plug. The owner or operator must notify the
Director at least 60 days before plugging of a well. At this time, if
any changes have been made to the original well plugging plan, the
owner or operator must also provide the revised well plugging plan. At
the discretion of the Director, a shorter notice period may be allowed.
    (d) Plugging report. Within 60 days after plugging or at the time
of the next semi-annual report (whichever occurs earlier) the owner or
operator must submit a plugging report to the Director. If the semi-
annual report is due less than 15 days after completion of plugging,
then the report must be submitted within 60 days after plugging. The
report must be certified as accurate by the owner or operator and by
the person who performed the plugging operation (if other than the
owner or operator.)


Sec.  146.93  Post-injection site care and site closure.

    (a) The owner or operator of a Class VI well must prepare,
maintain, and comply with a plan for post-injection site care and site
closure that meets the requirements of paragraph (a)(2) of this section
and is acceptable to the Director.
    (1) The owner or operator must submit the post-injection site care
and site closure plan as a part of the permit application to be
approved by the Director.
    (2) The post-injection site care and site closure plan must include
the following information:
    (i) The pressure differential between pre-injection and predicted
post-injection pressures in the injection zone;
    (ii) The predicted position of the carbon dioxide plume and
associated pressure front at site closure as demonstrated in the area
of review evaluation required under Sec.  146.84(b);
    (iii) A description of post-injection monitoring location, methods,
and proposed frequency; and
    (iv) A proposed schedule for submitting post-injection site care
monitoring results to the Director.
    (3) Upon cessation of injection, owners or operators of Class VI
wells must either submit an amended post-injection site care and site
closure plan or demonstrate to the Director through monitoring data and
modeling results that no amendment to the plan is needed.
    (4) The owner or operator may modify and resubmit the post-
injection site care and site closure plan for the Director's approval
within 30 days of such change.
    (b) The owner or operator shall monitor the site following the
cessation of injection to show the position of the carbon dioxide plume
and pressure front and demonstrate that USDWs are not being endangered.
    (1) The owner or operator shall continue to conduct monitoring as
specified in the Director-approved post-injection site care and site
closure plan for at least 50 years following the cessation of
injection. At the Director's discretion, the monitoring will continue
until the geologic sequestration project no longer poses an
endangerment to USDWs.
    (2) If the owner or operator can demonstrate to the satisfaction of
the Director before 50 years, based on monitoring and other site-
specific data, that the geologic sequestration project

[[Page 43541]]

no longer poses an endangerment to USDWs, the Director may approve an
amendment to the post-injection site care and site closure plan to
reduce the frequency of monitoring or may authorize site closure before
the end of the 50-year period.
    (3) Prior to authorization for site closure, the owner or operator
must submit to the Director a demonstration, based on monitoring and
other site-specific data, that the carbon dioxide plume and pressure
front have stabilized and that no additional monitoring is needed to
assure that the geologic sequestration project does not pose an
endangerment to USDWs.
    (4) If such a demonstration cannot be made (i.e., if the carbon
dioxide plume and pressure front have not stabilized) after the 50-year
period, the owner or operator must submit to the Director a plan to
continue post-injection site care.
    (c) Notice of intent for site closure. The owner or operator must
notify the Director at least 120 days before site closure. At this
time, if any changes have been made to the original post-injection site
care and site closure plan, the owner or operator must also provide the
revised plan. At the discretion of the Director, a shorter notice
period may be allowed.
    (d) After the Director has authorized site closure, the owner or
operator must plug all monitoring wells in a manner which will not
allow movement of injection or formation fluids that endangers a USDW.
    (e) Once the Director has authorized site closure, the owner or
operator must submit a site closure report within 90 days that must
thereafter be retained at a location designated by the Director. The
report must include:
    (1) Documentation of appropriate injection and monitoring well
plugging as specified in Sec.  146.92 and paragraph (c) of this
section. The owner or operator must provide a copy of a survey plat
which has been submitted to the local zoning authority designated by
the Director. The plat must indicate the location of the injection well
relative to permanently surveyed benchmarks. The owner or operator must
also submit a copy of the plat to the Regional Administrator of the
appropriate EPA Regional Office;
    (2) Documentation of appropriate notification and information to
such State, local and tribal authorities as have authority over
drilling activities to enable such State and local authorities to
impose appropriate conditions on subsequent drilling activities that
may penetrate the injection and confining zone(s); and
    (3) Records reflecting the nature, composition and volume of the
carbon dioxide stream.
    (f) Each owner or operator of a Class VI injection well must record
a notation on the deed to the facility property or any other document
that is normally examined during title search that will in perpetuity
provide any potential purchaser of the property the following
information:
    (1) The fact that land has been used to sequester carbon dioxide;
    (2) The name of the State agency, local authority, and/or tribe
with which the survey plat was filed, as well as the address of the
Regional Environmental Protection Agency Office to which it was
submitted; and
    (3) The volume of fluid injected, the injection zone or zones into
which it was injected, and the period over which injection occurred.
    (g) The owner or operator must retain for three years following
site closure, records collected during the post-injection site care
period. The owner or operator must deliver the records to the Director
at the conclusion of the retention period, and the records must
thereafter be retained at a location designated by the Director for
that purpose.

Sec.  146.94  Emergency and remedial response.

    (a) As part of the permit application, the owner or operator must
provide the Director with an emergency and remedial response plan that
describes actions to be taken to address movement of the injection or
formation fluids that may cause an endangerment to a USDW during
construction, operation, closure and post-closure periods.
    (b) If the owner or operator obtains evidence that the injected
carbon dioxide stream and associated pressure front may cause an
endangerment to a USDW, the owner or operator must:
    (1) Immediately cease injection;
    (2) Take all steps reasonably necessary to identify and
characterize any release;
    (3) Notify the Director within 24 hours; and
    (4) Implement the emergency and remedial response plan approved by
the Director.
    (c) The Director may allow the operator to resume injection prior
to remediation if the owner or operator demonstrates that the injection
operation will not endanger USDWs.
    (d) The owner or operator must notify the Director and obtain his
approval prior to conducting any well workover.

[FR Doc. E8-16626 Filed 7-24-08; 8:45 am]
BILLING CODE 6560-50-P
Notices For
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Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells

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