[Federal Register Volume 75, Number 237 (Friday, December 10, 2010)]
[Rules and Regulations]
[Pages 77230-77303]
[FR Doc No: 2010-29954]

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Part III

Environmental Protection Agency

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40 CFR Parts 124, 144, 145, et al.

Federal Requirements Under the Underground Injection Control (UIC)
Program for Carbon Dioxide (CO[bdi2]) Geologic Sequestration (GS)
Wells; Final Rule

Federal Register / Vol. 75 , No. 237 / Friday, December 10, 2010 /
Rules and Regulations

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 124, 144, 145, 146, and 147

[EPA-HQ-OW-2008-0390 FRL-9232-7]
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: Final rule.

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SUMMARY: This action finalizes minimum 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 final rule 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 establishes a new class of well, Class
VI, and sets minimum technical criteria for the permitting, geologic
site characterization, area of review (AoR) and corrective action,
financial responsibility, well construction, operation, mechanical
integrity testing (MIT), monitoring, well plugging, post-injection site
care (PISC), and site closure of Class VI wells for the purposes of
protecting underground sources of drinking water (USDWs). The elements
of this rulemaking are based on the existing Underground Injection
Control (UIC) regulatory framework, with modifications to address the
unique nature of CO2 injection for GS. This rule will help
ensure consistency in permitting underground injection of
CO2 at GS operations across the United States and provide
requirements to prevent endangerment of USDWs in anticipation of the
eventual use of GS to reduce CO2 emissions to the atmosphere
and to mitigate climate change.

DATES: This regulation is effective January 10, 2011. For purposes of
judicial review, this final rule is promulgated as of 1 p.m., Eastern
time on December 24, 2010, as provided in 40 CFR 23.7.

ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-HQ-OW-2008-0390. All documents in the docket are listed on the
http://www.regulations.gov Web site. 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, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically through http://www.regulations.gov or in hard copy at the OW Docket, EPA/DC, EPA West,
Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public
Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is<PHONE_NUMBER>, and the telephone number for the OW
Docket is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Mary Rose (Molly) Bayer, 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:<PHONE_NUMBER>; fax number:<PHONE_NUMBER>; e-mail address:
<EMAIL_ADDRESS>For general information, visit the Underground
Injection Control Geologic Sequestration Web site at http://www.epa.gov/safewater/uic/wells_sequestration.html.

SUPPLEMENTARY INFORMATION:

I. General Information

    This regulation affects 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 include, but are not
limited to, the following:

------------------------------------------------------------------------
             Category                  Examples of regulated entities
------------------------------------------------------------------------
Private...........................  Owners or Operators of CO2 injection
                                     wells used for Class VI GS.
Private...........................  Owners or Operators of existing CO2
                                     injection wells transitioning from
                                     Class I, II, or Class V injection
                                     activities to Class VI GS.
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    This table is not intended to be an exhaustive list; rather it
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 at Sec.  146.81 in the rule
section of this action. 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

AoR Area of Review
BLM United States Department of the Interior, Bureau of Land
Management
BOEMRE United States Department of the Interior, Bureau of Ocean
Energy Management, Regulation and Enforcement
CAA Clean Air Act
CBI Confidential Business Information
CCS Carbon Capture and Storage
CERCLA Comprehensive Environmental Response, Compensation, and
Liability Act
CO2 Carbon Dioxide
DOE United States Department of Energy
ECBM Enhanced Coal Bed Methane
EFAB Environmental Financial Advisory Board
EGR Enhanced Gas Recovery
EIS Environmental Impact Statement
EISA Energy Independence and Security Act of 2007
EO Executive Order
EOR Enhanced Oil Recovery
EPA United States Environmental Protection Agency
ER Enhanced Recovery
FPR Federally Permitted Releases
GAO General Accountability Office
GHG Greenhouse Gas
GS Geologic Sequestration
Gt CO2 Gigatons CO2
GWPC Ground Water Protection Council
HHS United States Department of Health and Human Services
ICR Information Collection Request
IOGCC Interstate Oil and Gas Compact Commission
IPCC Intergovernmental Panel on Climate Change
IRS United States Internal Revenue Service
LBNL Lawrence Berkeley National Laboratory
Mg/L Milligrams per liter
MI Mechanical Integrity
MIT Mechanical Integrity Test
MMS United States Department of the Interior, Minerals Management
Service
MPRSA Marine Protection, Research, and Sanctuaries Act of 1972
MRA Miscellaneous Receipts Act
MRR Mandatory Reporting Rule
MRV Monitoring, Reporting, and Verification
NAICS North American Industry Classification System
NASA National Aeronautics and Space Administration
NCER National Center for Environmental Research
NDWAC National Drinking Water Advisory Council
NEPA National Environmental Protection Act
NETL National Energy Technology Laboratory
NGO Non-Governmental Organization
NIWG National Indian Work Group
NOAA National Oceanic and Atmospheric Administration
NODA Notice of Data Availability
NOI Notice of Intent

NTC National Tribal Caucus
NTTAA National Technology Transfer and Advancement Act of 1995
NTWC National Tribal Water Council
O&M Operation and Maintenance
OAR Office of Air and Radiation
OCS Outer Continental Shelf
OCSLA Outer Continental Shelf Lands Act
OMB Office of Management and Budget
ORD Office of Research and Development
PBMS Performance Based Measurement System
Pg Petagram
PISC Post-Injection Site Care
PRA Paperwork Reduction Act
PWSS Public Water System Supervision
QASP Quality Assurance and Surveillance Plan
RA Regulatory Alternative
RCRA Resource Conservation and Recovery Act
RCSP Regional Carbon Sequestration Partnership
RFA Regulatory Flexibility Act
RIC Regional Indian Coordinators
SDWA Safe Drinking Water Act
STAR Science To Achieve Results
STC3 State-Tribal Climate Change Council
SWP Southwest Regional Partnership on Carbon Sequestration
TCLP Toxicity Characteristic Leaching Procedure
TDS Total Dissolved Solids
TNW Tangible Net Worth
UIC Underground Injection Control
UICPG83 Underground Injection Control Program Guidance
 83
UMRA Unfunded Mandates Reform Act
USDW Underground Source of Drinking Water
USGS United States Department of the Interior, United States
Geological Survey
WRI World Resources Institute

Definitions

    Annulus: The space between the well casing and the wall of the bore
hole; the space between concentric strings of casing; the space between
casing and tubing.
    Area of review (AoR): The region surrounding the geologic
sequestration project where USDWs may be endangered by the injection
activity. The area of review is delineated using computational modeling
that accounts for the physical and chemical properties of all phases of
the injected carbon dioxide stream and displaced fluids, and is based
on available site characterization, monitoring, and operational data as
set forth in Sec.  146.84.
    Automatic shut-off device: A valve which closes when a pre-
determined pressure or flow value is exceeded. Shut-off devices in
injection wells can automatically shut down injection activities
preventing an excursion outside of the permitted values.
    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 and is blocked.
    Biosphere: The part of the Earth's crust, waters, and atmosphere
that supports life.
    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 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 outermost 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(s) that
acts as barrier to fluid movement. For Class VI wells operating under
an injection depth waiver, confining zone means a geologic formation,
group of formations, or part of a formation stratigraphically overlying
and underlying the injection zone(s).
    Corrective action: The use of Director-approved methods to ensure
that wells within the area of review do not serve as conduits for the
movement of fluids into 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 or his/her
delegatee; 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 trapped or
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) and/or displaces
extractable oil and gas, which is then available for recovery. This is
also used for secondary or tertiary recovery.
    Flapper valve: A valve consisting of a hinged flapper that seals
the valve orifice. In Class VI wells, flapper valves can engage to shut
off the flow of the CO2 when acceptable operating parameters
are exceeded.
    Formation or geological formation: A layer of rock that is made up
of a certain type of rock or a combination of types.
    Geologic sequestration (GS): The long-term containment of a
gaseous, liquid or supercritical carbon dioxide stream in subsurface
geologic formations. This term does not apply to CO2 capture
or transport.
    Geologic sequestration project: For the purpose of this regulation,
an injection well or wells used to emplace a carbon dioxide stream
beneath the lowermost formation containing a USDW; or, wells used for
geologic sequestration of carbon dioxide that have been granted a
waiver of the injection depth requirements pursuant to requirements

at Sec.  146.95; or, wells used for geologic sequestration of carbon
dioxide that have received an expansion to the areal extent of an
existing Class II EOR/EGR aquifer exemption pursuant to Sec. Sec.
146.4 and 144.7(d). It includes the subsurface three-dimensional extent
of the carbon dioxide plume, associated area of elevated pressure, and
displaced fluids, 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 CO2 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: 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.
    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 that seals the outside of the tubing to
the inside of the long string casing, isolating an annular space.
    Pinch-out: A situation where a formation thins to zero thickness.
    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 ensure 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: Subsurface 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).
    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.
    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. Background
    A. Why is EPA taking this regulatory action?
    1. What is GS?
    2. Why is GS under consideration as a climate change mitigation
technology?
    3. What are the unique risks to USDWs associated with GS?
    B. Under what authority is this rulemaking promulgated?
    C. How does this rulemaking relate to the greenhouse gas (GHG)
reporting program?
    D. How does this rulemaking relate to other federal authorities
and GS and CCS activities?
    E. What steps did EPA take to develop this rulemaking?
    1. Developing Guidance for Experimental GS Projects
    2. Conducting Research
    a. Tracking the Results of CO2 GS Research Projects
    b. Tracking State Regulatory Efforts
    c. Conducting Technical Workshops on Issues Associated with
CO2 GS
    3. Conducting Stakeholder Coordination and Outreach
    4. Proposed Rulemaking
    5. Notice of Data Availability and Request for Comment
    F. How Will EPA's Adaptive Rulemaking Approach Incorporate
Future Information and Research?
    G. How Does This Action Affect UIC Program Implementation?
    H. How Does This Rule Affect Existing Injection Wells Under the
UIC Program?
III. What is EPA's Final Regulatory Approach?
    A. Site Characterization
    B. Area of Review (AoR) and Corrective Action
    1. AoR Requirements
    2. Corrective Action Requirements
    C. Injection Well Construction
    D. Class VI Injection Depth Waivers and Use of Aquifer
Exemptions for GS
    1. Proposed Rule
    2. Notice of Data Availability and Request for Comment
    3. Final Approach
    E. Injection Well Operation
    F. Testing and Monitoring
    1. Testing and Monitoring Plan
    2. CO2 Stream Analysis
    3. Mechanical Integrity Testing (MIT)
    4. Corrosion Monitoring
    5. Ground Water/Geochemical Monitoring
    6. Pressure Fall-Off Testing
    7. CO2 Plume and Pressure Front Monitoring/Tracking

    8. Surface Air/Soil Gas Monitoring
    9. Additional Requirements
    G. Recordkeeping and Reporting
    1. What Information Must Be Provided by the Owner or Operator?
    2. How Must Information Be Submitted?
    3. What are the Recordkeeping Requirements under This Rule?
    H. Well Plugging, Post-Injection Site Care (PISC), and Site
Closure
    1. Injection Well Plugging
    2. Post-Injection Site Care (PISC)
    3. Site Closure
    I. Financial Responsibility
    J. Emergency and Remedial Response
    K. Involving the Public in Permitting Decisions
    L. Duration of a Class VI Permit
IV. Cost Analysis
    A. National Benefits and Costs of the Rule
    1. National Benefits Summary
    a. Relative Risk Framework--Qualitative Analysis
    b. Other Nonquantified Benefits
    2. National Cost Summary
    a. Cost of the Selected RA
    b. Nonquantified Costs and Uncertainties in Cost Estimates
    c. Supplementary Costs and Uncertainties in Cost Estimates
    B. Comparison of Benefits and Costs of RAs Considered
    1. Costs Relative to Benefits; Maximizing Net Social Benefits
    2. Cost Effectiveness and Incremental Net Benefits
    C. Conclusions
V. Statutory and Executive Order Review
VI. References

II. Background

    Today's action finalizes minimum Federal requirements under SDWA
for injection of CO2 for the purpose of GS. The purpose of
the rulemaking is to ensure that GS is conducted in a manner that
protects USDWs from endangerment. GS refers to a suite of technologies
that can be deployed to reduce CO2 emissions to the
atmosphere and help mitigate climate change. Due to the large
CO2 injection volumes anticipated at GS projects, the
relative buoyancy of CO2, its mobility within subsurface
geologic formations, its corrosivity in the presence of water, and the
potential presence of impurities in the captured CO2 stream,
the Agency has determined that tailored requirements, modeled on the
existing UIC regulatory framework, are necessary to manage the unique
nature of CO2 injection for GS. This final rule applies to
owners or operators of wells that will be used to inject CO2
into the subsurface for the purpose of GS.
    To support today's final regulatory action, EPA proposed Federal
Requirements Under the Underground Injection Control (UIC) Program for
Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells (73
FR 43492) on July 25, 2008; and the Agency published a supplemental
publication, Federal Requirements Under the Underground Injection
Control (UIC) Program for Carbon Dioxide (CO2) Geologic
Sequestration (GS) Wells; Notice of Data Availability and Request for
Comment (74 FR 44802) on August 31, 2009. Final Class VI requirements
are informed, in part, by comments and information submitted in
response to these publications.
    Today's rule defines a new class of injection well (Class VI),
along with technical criteria that tailor the existing UIC regulatory
framework to address the unique nature of CO2 injection for
GS. It sets minimum technical criteria for Class VI wells to protect
USDWs from endangerment, including:
     Site characterization that includes an assessment of the
geologic, hydrogeologic, geochemical, and geomechanical properties of
the proposed GS site to ensure that Class VI wells are located in
suitable formations.
     Computational modeling of the AoR for GS projects that
accounts for the physical and chemical properties of the injected
CO2 and is based on available site characterization,
monitoring, and operational data.
     Periodic reevaluation of the AoR to incorporate monitoring
and operational data and verify that the CO2 plume and the
associated area of elevated pressure are moving as predicted within the
subsurface.
     Well construction using materials that can withstand
contact with CO2 over the life of the GS project.
     Robust monitoring of the CO2 stream, injection
pressures, integrity of the injection well, ground water quality and
geochemistry, and monitoring of the CO2 plume and position
of the pressure front throughout injection.
     Comprehensive post-injection monitoring and site care
following cessation of injection to show the position of the
CO2 plume and the associated area of elevated pressure to
demonstrate that neither pose an endangerment to USDWs.
     Financial responsibility requirements to ensure that funds
will be available for all corrective action, injection well plugging,
post-injection site care (PISC), site closure, and emergency and
remedial response.
    Today's rule will help ensure consistency in permitting underground
injection of CO2 at GS operations across the United States
(US) and provide requirements to prevent endangerment of USDWs in
anticipation of the potential role of carbon capture and storage (CCS)
in mitigating climate change. Today's action also briefly discusses the
relationship between today's rule and other Federal and State
activities related to GS and CCS in Sections II.C and D, and E.2.b, and
III.F.2.

A. Why is EPA taking this regulatory action?

1. What is GS?
    GS is the process of injecting CO2 into deep subsurface
rock formations for long-term storage. It is part of the process known
as 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 state (IPCC, 2005; IEA, 2008).
CO2 exists as a supercritical fluid at high pressures, 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, frequently by pipeline, or alternatively using
tanker trucks or ships (WRI, 2007; IEA, 2008).
    At the GS site, the CO2 is injected into deep subsurface
rock formations through one or more wells, using technologies developed
and refined by the oil, gas, and chemical manufacturing industries over
the past several decades. EPA believes that many owners or operators
will inject CO2 in a supercritical state to depths greater
than 800 meters (2,645 feet) for the purpose of maximizing capacity and
storage.
    When injected into an appropriate receiving formation,
CO2 is sequestered by a combination of trapping mechanisms,
including physical and geochemical processes (Benson, 2008). Physical
trapping occurs when the relatively buoyant CO2 rises in the
formation until it reaches a stratigraphic zone with low 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 to 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.
    The effectiveness of physical CO2 trapping is
demonstrated by natural analogs in a range of geologic settings where
CO2 has remained trapped for millions of years (Holloway et
al., 2007). 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 (IPCC, 2005). Other natural
CO2 sources include the following geologic domes: McElmo
Dome, Sheep Mountain, and Bravo Dome in Colorado and New Mexico.
    Many of the injection and monitoring technologies that may be
applicable to GS are commercially available today and will be more
widely demonstrated over the next 10 to 15 years (Dooley et al., 2009).
The oil and natural gas industry in the United States has over 35 years
of experience of injection and monitoring of CO2 in the deep
subsurface for the purposes of enhancing oil and natural gas
production. This experience provides a strong foundation for the
injection and monitoring technologies that will be needed for
commercial-scale CCS. US and international experience with enhanced
recovery (ER) and commercial CCS projects, as well as ongoing research,
demonstration, and deployment programs throughout the world, provide
critical experience and information to inform the safe injection of
CO2. For additional information about these projects, see
section II.E.
    Although CCS is occurring now on a relatively small scale, it could
play a larger role in mitigating greenhouse gas (GHG) emissions from a
wide variety of stationary sources. According to the Inventory of US
Greenhouse Gas Emissions and Sinks: 1990-2007, stationary sources
contributed 67 percent of the total CO2 emissions from
fossil fuel combustion in 2007 (USEPA, 2008a). These sources represent
a wide variety of sectors amenable to CO2 capture: electric
power plants (existing and new), natural gas processing facilities,
petroleum refineries, iron and steel foundries, ethylene plants,
hydrogen production facilities, ammonia refineries, ethanol production
facilities, ethylene oxide plants, and cement kilns. Furthermore, 95
percent of the 500 largest stationary sources are within 50 miles of a
candidate GS reservoir (Dooley et al., 2008). Estimated GS capacity in
the United States is over 3,500 Gigatons CO2 (Gt
CO2) (DOE NETL, 2007), although the actual capacity may be
lower once site-specific technical and economic considerations are
addressed. Even if only a fraction of that geologic capacity is used,
CCS would play a sizeable role in mitigating US GHG emissions.
2. Why is GS under consideration as a climate change mitigation
technology?
    Climate change is happening now, and the effects can be seen on
every continent and in every ocean. While certain effects of climate
change can be beneficial, particularly in the short term, current and
future effects of climate change pose considerable risks to human
health and the environment. There is now clear evidence that the
Earth's climate is warming (USEPA, 2010):
     Global surface temperatures have risen by 1.3 degrees
Fahrenheit ([ordm]F) over the last 100 years.
     Worldwide, the last decade has been the warmest on record.
     The rate of warming across the globe over the last 50
years (0.24[ordm]F per decade) is almost double the rate of warming
over the last 100 years (0.13[ordm]F per decade).
    Most of this recent warming is very likely the result of human
activities. Many human activities release greenhouse gases into the
atmosphere (such as the combustion of fossil fuels). The levels of
these gases are increasing at a faster rate than at any time in
hundreds of thousands of years.
    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
CO2 emissions to the atmosphere. For example, CCS 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. The
development and deployment of clean coal technologies including CCS
will be a key to achieving domestic emissions reductions.
    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. Other options include energy conservation, efficiency
improvements, and the use of alternative fuels and renewable energy
sources. Ensuring that GS is done in a manner that is protective of
USDWs will ensure the safety and efficacy of CO2 injection
for GS.
    While predictions about large-scale availability and the rate of
CCS project deployment are subject to uncertainty, EPA analyses of
Congressional climate change legislative proposals (the American Power
Act of 2010 and the American Clean Energy and Security Act H.R. 2454 of
2009, both in the 111th Congress) indicate that CCS has the potential
to play a significant role in climate change mitigation scenarios. For
example, analysis of the American Power Act indicates that CCS
technology could account for 10 percent of CO2 emission
reductions in 2050 (USEPA, 2010f). These results indicate that CCS
could play an important role in achieving national greenhouse gas
reduction goals.
    Today's final rule provides minimum Federal requirements for the
injection of CO2 to protect USDWs from endangerment as this
key climate mitigation technology is developed and deployed. It
clarifies requirements that apply to CO2 injection for GS,
provides consistency in requirements across the US, and affords
transparency about what requirements apply to owners or operators.
3. What are the unique risks to USDWs associated with GS?
    Large CO2 injection volumes associated with GS, the
buoyant and mobile nature of the injectate, the potential presence of
impurities in the CO2 stream, and its corrosivity in the
presence of water could pose risks to USDWs. The purpose of today's
Class VI requirements for GS is to ensure the protection of USDWs,
recognizing that an improperly managed GS project has the potential to
endanger USDWs. Proper siting, well construction, operation, and
monitoring of GS projects are therefore necessary to reduce the risk of
USDW contamination.
    It is expected that GS projects will inject large volumes of
CO2. These volumes will be much larger than are typically
injected in other well classes regulated through the UIC program, and
could cause significant pressure increases in the subsurface.
Supercritical or gaseous CO2 in the subsurface is buoyant,
and thus would tend to flow upwards if it were to come into contact
with a migration pathway, such as a fault, fracture, or improperly
constructed or plugged well. However, the pressures induced by
injection will also influence CO2 and mobilized fluids to
flow away from the injection well in all directions, including
laterally, upwards and downwards. When CO2 mixes with
formation fluids, a percentage of it will dissolve. The resulting
aqueous mixture of CO2 and water will sink due to a density
differential between the mixture and the surrounding fluids.
CO2 is also highly mobile in the subsurface (i.e., has a
very low viscosity), and, in the presence of water, CO2 can
be corrosive. These properties (of CO2), as well as the
large

volumes that may be injected for GS result in several unique challenges
for protection of USDWs in the vicinity of GS sites from endangerment.
    While CO2 itself is not a drinking water contaminant,
CO2 in the presence of water forms a weak acid, known as
carbonic acid, that, in some instances, could cause leaching and
mobilization of naturally-occurring metals or other contaminants from
geologic formations into ground water (e.g., arsenic, lead, and organic
compounds). Another potential risk to USDWs is the presence of
impurities in the captured CO2 stream, which may include
drinking water contaminants such as hydrogen sulfide or mercury.
Additionally, pressures induced by injection may force native brines
(naturally occurring salty water) into USDWs, causing degradation of
water quality and affecting drinking water treatment processes.
Research studies have shown that the potential migration of injected
CO2 or formation fluids into a USDW could cause impairment
through one or several of these processes (e.g., Birkholzer et al.,
2008a).
    Today's action addresses endangerment to USDWs by establishing new
minimum Federal requirements for the proper management of
CO2 injection and storage in several program areas,
including permitting, site characterization, AoR and corrective action,
well construction, mechanical integrity testing (MIT), financial
responsibility, monitoring, well plugging, PISC, and site closure. EPA
believes that proper GS project management will appropriately mitigate
potential risks of endangerment to USDWs posed by injection activities.

B. Under what authority is this rulemaking promulgated?

    Today's rule is focused on USDW protection under the authority of
Part C of SDWA (SDWA, section 1421 et seq., 42 U.S.C. 300h et seq.).
Part C of the SDWA requires EPA to establish minimum requirements for
State\1\ UIC programs that regulate the subsurface injection of fluids
onshore and offshore under submerged lands within the territorial
jurisdiction of States\2\.
---------------------------------------------------------------------------

    \1\ Reference to ``States'' includes Tribes and Territories
pursuant to 40 CFR 144.3.
    \2\ The Submerged Lands Act and Territorial Submerged Lands Act
define the scope of territorial jurisdiction of States and
Territories respectively.
---------------------------------------------------------------------------

    SDWA is designed to protect the quality of drinking water sources
in the US and prescribes that EPA issue regulations for State UIC
programs that contain ``minimum requirements for effective programs to
prevent underground injection which endangers drinking water sources''
(42 U.S.C. 300h et seq.). 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 (SDWA, section 1421(d)(2)).

    Under this authority, the Agency promulgated a series of UIC
regulations at 40 CFR parts 144 through 148 for federally approved UIC
programs. 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 defined 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 SDWA 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).
    Under the SDWA, the injection of any ``fluid'' must meet the
requirements of the UIC program. A ``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. The types of fluids currently injected into wells subject
to UIC requirements 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.

C. How does this rulemaking relate to the greenhouse gas (GHG)
reporting program?

    Today's rulemaking under SDWA authority complements the
CO2 Injection and GS Reporting rulemaking (subparts RR and
UU) under the Greenhouse Gas Reporting Program's Clean Air Act (CAA)
authority developed by EPA's Office of Air and Radiation (OAR).
    The CAA defines EPA's responsibilities for protecting and improving
the nation's air quality and the stratospheric ozone layer. The GHG
Reporting Program requires reporting of GHG emissions and other
relevant information from certain source categories in the U.S. The GHG
Reporting Program, which became effective on December 29, 2009,
includes reporting requirements for facilities and suppliers in 32
subparts. For more detailed background information on the GHG Reporting
Program, see the preamble to the final rule establishing the GHG
Reporting Program (74 FR 56260, October 30, 2009).
    In a separate action being finalized concurrently with this UIC
Class VI rulemaking, EPA is amending 40 CFR part 98, which provides the
regulatory framework for the GHG Reporting Program, to add reporting
requirements covering facilities that conduct GS (subpart RR) and all
other facilities that inject CO2 underground (subpart UU).
This data will inform Agency policy decisions under CAA sections 111
and 112 related to the use of CCS for mitigating GHG emissions. In
combination with data from other subparts of the GHG Reporting Program,
data from subpart UU and subpart RR will allow EPA to track the flow of
CO2 across the CCS system. EPA will be able to reconcile
subpart RR data on CO2 received with CO2 supply
data in order to understand the quantity of CO2 supply that
is geologically sequestered.
    Owners or operators subject to today's rule are required to report
under subpart RR. Subpart RR establishes reporting requirements for
facilities that inject a CO2 stream for long-term
containment into a subsurface geologic formation, including sub-seabed
offshore formations. These facilities are required to develop and
implement a site-specific

Monitoring, Reporting, and Verification (MRV) plan which, once approved
by EPA (in a process separate from the UIC permitting process), would
be used to verify the amount of CO2 sequestered and to
quantify emissions in the event that injected CO2 leaks to
the surface. For more information on subpart RR, see http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.
    UIC requirements and Subpart RR requirements: EPA designed the
reporting requirements under subpart RR with consideration of the
requirements for Class VI well owners or operators in subpart H of part
146 of today's rule. Subpart RR builds on the Class VI requirements
outlined in today's rule with the additional goals of verifying the
amount of CO2 sequestered and collecting data on any
CO2 surface emissions from GS facilities as identified under
subpart RR of part 98.
    The Agency acknowledges that there are similar data elements that
must be reported pursuant to requirements in this action and those
required to be reported under subpart RR. Specifically, owners or
operators subject to both regulations must report the amount (flow
rate) of injected CO2. The Class VI and subpart RR rules
differ, not only in purpose but in the specific requirements for the
measurement unit and collection/reporting frequency. The UIC program
Class VI rule requires that owners or operators report information on
the CO2 stream to ensure appropriate well siting,
construction, operation, monitoring, post-injection site care, site
closure, and financial responsibility to ensure protection of USDWS.
Under subpart RR, owners or operators must report the amount (flow
rate) of injected CO2 for the mass balance equation that
will be used to quantify the amount of CO2 sequestered by a
facility.

  Table II-1--Comparison of Reporting Requirements Under Subpart RR and
                    Select UIC Class VI Requirements
------------------------------------------------------------------------
    Reporting requirement          Subpart RR           UIC Class VI
------------------------------------------------------------------------
Quantity of CO2 transferred   Yes.................  N/A.
 onsite.
Quantity (flow rate) of CO2   Yes.................  Yes.
 injected.
Fugitive and vented           Yes.................  N/A.
 emissions from surface
 equipment.
Quantity of CO2 produced      Yes.................  N/A.
 with oil or natural gas
 (ER).
Percent of CO2 estimated to   Yes.................  N/A.
 remain with the oil and gas
 (ER).
Quantity of CO2 emitted from  Yes.................  N/A.
 the subsurface.
Quantity of CO2 sequestered   Yes.................  N/A.
 in the subsurface.
Cumulative mass of CO2        Yes.................  N/A.
 sequestered in the
 subsurface.
Monitoring plan for           Yes.................  Yes.\1\
 detecting air emissions.
Monitoring plan for           Yes.................  N/A.
 quantifying air emissions.
------------------------------------------------------------------------
(1) UIC Class VI rule allows for surface air/soil gas monitoring for
  USDW protection at the discretion of the UIC Director.

    EPA requires reporting of other data to satisfy various
programmatic needs. See section III of this preamble and associated
requirements in subpart H of part 146 and the preamble to subpart RR
for additional information on these specific requirements and their
purpose. Table II-1 provides a comparison of the major reporting
requirements in subpart RR and the extent to which there is overlap
with Class VI requirements. For the monitoring plan listed in Table II-
1, EPA will accept a UIC Class VI permit to satisfy certain subpart RR
MRV plan requirements. However, the reporter must include additional
information to outline how monitoring will achieve surface detection
and quantification of CO2. EPA is pursuing ways to better
integrate data management between the UIC and GHG Reporting Programs to
ensure that data needs are harmonized and the burden to regulated
entities is minimized.

D. How does this rulemaking relate to other federal authorities and GS
and CCS activities?

    While the SDWA provides EPA with the authority to develop
regulations to protect USDWs from endangerment, it does not provide
authority to develop regulations for all areas related to GS. EPA
received a number of public comments on the proposal (73 FR 43492, July
25, 2008) indicating that the Agency should further explore
environmental and regulatory issues beyond the scope of the proposed
SDWA requirements for underground injection of CO2 for GS.
    In response to comments and as a result of the presidential memo
``A Comprehensive Strategy on Carbon Capture and Storage'' (http://www.whitehouse.gov/the-press-office/presidential-memorandum-a-comprehensive-Federal-strategy-carbon-capture-and-storage), the Agency
continues to evaluate areas of potential applicability of other Federal
environmental statutes including, but not limited to, the CAA
(discussed in section II.C), the Resource Conservation and Recovery Act
(RCRA; discussed in section III.F.2), the Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA; discussed in section
III.F.2), and the Marine Protection, Research and Sanctuaries Act
(MPRSA; discussed in this section) to various aspects of GS and CCS.
    Additionally, EPA and the US Department of Energy (DOE) co-chaired
the Interagency Task Force on Carbon Capture and Storage to develop a
plan to overcome the barriers to the widespread, cost-effective
deployment of CCS within 10 years, with a goal of bringing five to 10
commercial demonstration projects online by 2016. The Task Force's
report is available at http://www.whitehouse.gov/administration/eop/ceq/initiatives/ccs.
    This section clarifies the distinction between today's rulemaking
and a number of other Federal rulemakings and initiatives.
    National Environmental Protection Act (NEPA): The SDWA UIC program
is exempt from performing an Environmental Impact Statement (EIS) under
section 101(2)(C) and an alternatives analysis under section 101(2)(E)
of NEPA under a functional equivalence analysis. See Western Nebraska
Resources Council v. US EPA, 943 F.2d 867, 871-72 (8th Cir. 1991) and
EPA Associate General Counsel Opinion (August 20, 1979).
    Marine Protection, Research, and Sanctuaries Act (MPRSA) and London
Protocol Implementation: Sub-seabed CO2 injection for GS
may, in certain circumstances, be defined as ocean dumping and subject
to regulation under the MPRSA. Application of the MPRSA would entail
coordination of the permitting processes under the SDWA and MPRSA,
pursuant to MPRSA sections 106(a) and (d). The substantive
environmental protection requirements of both statutes would need to be
satisfied prior to the

commencement of GS. The MPRSA was enacted in 1972 and implements the
London Convention on the Prevention of Marine Pollution by Dumping of
Wastes and Other Matter (the ``London Convention''). In 1996, the
Protocol to the London Convention (the ``London Protocol'') was
established. The Protocol stipulates that sub-seabed GS may be approved
provided that: (1) Disposal is into a sub-seabed geologic formation;
(2) the CO2 stream consists overwhelmingly of
CO2, with only incidental associated substances derived from
the source material and capture and sequestration process used; and,
(3) no wastes or other matter are added for the purpose of disposal.
The US has signed, but has not yet ratified, the Protocol. If the
Protocol is ratified, and implementing legislation is enacted, EPA, in
conjunction with other Federal agencies, will develop any necessary
regulations for implementing the provisions relevant to sub-seabed GS.
    Bureau of Ocean Energy Management, Regulation, and Enforcement
(BOEMRE) Outer Continental Shelf Lands Act (OCSLA): BOEMRE, formerly
the Minerals Management Service (MMS), an agency within the Department
of the Interior, administers the OCSLA. As a result of recent OCSLA
amendments by the Energy Policy Act of 2005, the OCSLA provides for the
grant of leases, easements, or rights-of-way on the outer continental
shelf to the extent that an activity ``supports production,
transportation, or transmission of energy from sources other than oil
and gas'' and complies with the other provisions of OCSLA section 8(p).
Offshore geologic sequestration of CO2 on the outer
continental shelf may be subject to requirements under the OCSLA.
    As indicated in the Report of the Interagency Task Force on Carbon
Capture and Storage (2010), ratification of the London Protocol and
associated amendment of the MPRSA as well as amendment of the Outer
Continental Shelf Lands Act (OCSLA) will ensure a comprehensive
statutory framework for the storage of CO2 on the outer
continental shelf.
    Bureau of Land Management (BLM) Report to Congress: The BLM,
another agency within the Department of Interior, was required by
Section 714 of the Energy Independence and Security Act (EISA) of 2007
(Pub. L. 110-140, HR 6) to prepare a report outlining a regulatory
framework that could be applied to lands managed by the Bureau for
natural resource development, chiefly oil and gas. With assistance from
both EPA and the DOE, BLM submitted a Report to Congress titled
``Framework for Geological Carbon Sequestration on Public Land'' (BLM,
2009). This report affirms BLM's role in appropriately managing Federal
lands where GS injection projects may be sited. Additionally, the
report makes recommendations regarding approaches for effective
regulation of such activities under existing Federal authorities
including the SDWA and UIC program requirements.
    United States Geological Survey (USGS) GS Capacity Methodology:
USGS, another agency within the Department of Interior and the primary
Federal agency responsible for national geological research, has been
an active participant with DOE and EPA at conferences and workshops on
CCS. In 2008, in response to the EISA, USGS initiated development of a
methodology for estimating the capacity to store CO2 in
geologic formations of the U.S. While previous capacity estimates
published by DOE/National Energy Technology Laboratory (NETL) have been
broad in scope (i.e., geologic basin-wide), the USGS is focusing on
small-scale, refined estimates. In 2009, USGS published a proposed,
risk-based methodology for GS capacity estimation. After input from
other agencies and stakeholders, USGS released a final report: A
Probabilistic Assessment Methodology for the Evaluation of Geologic
Carbon Dioxide Storage (USGS, 2010). The report is available at http://pubs.usgs.gov/of/2010/1127/. USGS continues to work on capacity
estimation as required under the EISA.
    Internal Revenue Service (IRS) Guidance for Tax Incentives for GS
Projects: In response to the Energy Improvement and Extension Act of
2008, IRS, in consultation with EPA and DOE, issued guidance 2009-44
IRB (IRS, 2009) for taxpayers seeking to claim tax credits for
capturing and sequestering CO2 from a qualified facility in
the U.S. Under section 45Q of the Internal Revenue Code, a taxpayer who
stores CO2 under the predetermined conditions may qualify
for the tax credit ($10 per metric ton of qualified CO2 at
ER projects; $20 per metric ton of qualified CO2 for non-ER
projects). The taxpayer will be responsible for maintaining records for
inspection by the IRS and tax credit amounts will be adjusted for
inflation for any taxable year beginning after 2009. The Internal
Revenue Service published IRS Notice 2009-83 (available at: http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860) to provide guidance
regarding eligibility for the section 45Q tax credit, computation of
the section 45Q tax credit, reporting requirements for taxpayers
claiming the section 45Q tax credit, and rules regarding adequate
security measures for ``secure geological storage of CO2.''
    Following publication of today's final Class VI requirements, and
as clarified in the guidance, taxpayers claiming the section 45Q tax
credit must follow the appropriate UIC requirements (e.g., Class II or
Class VI). The guidance also clarifies that taxpayers claiming section
45Q tax credit must follow the GS monitoring, reporting, and
verification procedures finalized in the CO2 Injection and
GS Reporting Rule that is part of the GHG Reporting Program.
    General Accountability Office Reports on GS and CCS: The United
States General Accountability Office (GAO) has prepared, or is in the
process of preparing, several reports for Congressional requestors
related to the GS of CO2. In September 2008, GAO (GAO-08-
1080) completed a report related to assessing the application of CCS
technologies entitled: Climate Change--Federal Actions Will Greatly
Affect the Viability of Carbon Capture and Storage as a Key Mitigation
Option (GAO, 2008). In September 2010, GAO released a report entitled:
Climate Change, A Coordinated Strategy Could Focus Federal
Geoengineering Research and Inform Governance Efforts (GAO-10-903)
which describes innovative technologies that may alter climate change,
details current research activities, and clarifies how coordination
could inform subsequent climate science efforts. GAO initiated another
report (GAO-10-675) focused on the methods by which coal-fired power
plants may capture carbon emissions. The draft title of that study is:
Coal Power Plants--Opportunities Exist for DOE to Provide Better
Information on the Maturity of Key Technologies to Reduce Carbon
Emissions (GAO, 2010).
    EPA will continue to coordinate internally and with other Federal
agencies to promote consistency in existing and future GS and CCS
initiatives.

E. What steps did EPA take to develop this rulemaking?

    Today's final rule builds upon longstanding programmatic
requirements for underground injection that have been in place since
the 1980s and that are used to manage over 800,000 injection wells
nationwide. These programmatic requirements are designed to prevent
fluid movement into USDWs by addressing the potential pathways through
which injected fluids can migrate into USDWs and cause endangerment.
    EPA coordinated with Federal and non-Federal entities on GS and CCS
to

determine how best to tailor existing UIC requirements to
CO2 for GS.
    EPA has taken a number of steps in advance of today's action
including: (1) Developing guidance for experimental GS projects; (2)
conducting research; (3) conducting stakeholder coordination and
outreach; (4) issuing a proposed rulemaking and soliciting and
reviewing public comment; and, (5) publishing a Notice of Data
Availability (NODA) and Request for Comment to seek additional input on
the rulemaking.
1. Developing Guidance for Experimental GS Projects
    In 2007, EPA issued technical guidance to assist State and EPA
Regional UIC programs in processing permit applications for pilot and
other small scale experimental GS projects. The guidance was developed
in cooperation with DOE and States, the Ground Water Protection Council
(GWPC), the Interstate Oil and Gas Compact Commission (IOGCC), and
other stakeholders. UIC Program Guidance #83: Using the Class V
Experimental Technology Well Classification for Pilot Carbon GS
Projects (USEPA, 2007) provides recommendations for permit writers
regarding the use of the UIC Class V experimental technology well
classification at demonstration GS projects while ensuring USDW
protection. Program guidance 83 is available at: http://www.epa.gov/safewater/uic/wells_sequestration.html. EPA is preparing
additional guidance for owners or operators and Directors regarding the
use of Class V experimental technology wells for GS following
promulgation of today's rule.
2. Conducting Research
    EPA participated in and supported research to inform today's
rulemaking including: Supporting and tracking the development and
results of national and international CO2 GS field and
research projects; tracking GS-related State regulatory and legislative
efforts; and conducting technical workshops on issues associated with
CO2 GS. EPA described these research activities in detail in
the proposed rule (July 2008) and the NODA and Request for Comment
(August 2009). Additional information pertaining to these activities,
which are summarized below, may be found in the rulemaking docket.
a. Tracking the Results of CO2 GS Research Projects
    To inform today's rulemaking, EPA tracked the progress and results
of national and international GS research projects. DOE leads field
research on GS in the U.S. in conjunction with the Regional Carbon
Sequestration Partnerships (RCSPs). Currently, DOE's NETL is developing
and/or operating GS projects, a number of which have either completed
injection or are in the process of injecting CO2. The seven
RCSPs are conducting pilot and demonstration projects to study site
characterization (including injection and confining formation
information, core data and site selection information); well
construction (well depth, construction materials, and proximity to
USDWs); frequency and types of tests and monitoring conducted (on the
well and on the project site); modeling and monitoring results; and
injection operation (injection rates, pressures, and volumes,
CO2 source and co-injectates). See section II.E.5 for more
information on the status of these projects.
    Lawrence Berkeley National Laboratory (LBNL) research: EPA and DOE
are jointly funding work by the LBNL to study potential impacts of
CO2 injection on ground water aquifers and drinking water
sources. The preliminary results have been used to inform today's
rulemaking and are described in detail in section II.E.5.
    In addition, EPA is funding an analysis by LBNL to integrate
experimental and modeling information. LBNL will characterize ground
water samples and aquifer mineralogies from select sites in the U.S.
and conduct controlled laboratory experiments to assess the potential
mobilization of hazardous constituents by dissolved CO2.
These experiments will provide data that will be used to validate
previous predictive modeling studies (of aquifer vulnerabilities to
potential CO2 leaks) which may be applied to other GS sites
in the future to assess the fate and migration of CO2-
mobilized constituents in ground water.
    EPA's Office of Research and Development (ORD) GS research: EPA's
ORD engages Agency scientists and engineers in targeted research to
provide information to stakeholders and policy makers focused on areas
of national environmental concern, including climate change and GS. In
addition, ORD's National Center for Environmental Research (NCER)
provides extramural research grants for similar investigations through
a competitive solicitation process. In the fall of 2009, NCER awarded
six Science To Achieve Results (STAR) grants to recipients from major
universities and institutions. The awards were granted to projects
focused on Integrated Design, Modeling and Monitoring of GS of
Anthropogenic CO4 to Safeguard Sources of Drinking Water.
Work under the grants began in late 2009 and includes: Evaluating
potential impacts on drinking water aquifers of CO2-rich
dissolved brines (Clemson University); reducing the hydrologic and
geochemical uncertainties associated with CO2 sequestration
in deep, saline reservoirs (University of Illinois-Urbana); assessing
appropriate monitoring approaches at GS sites (University of Texas at
Austin); integrating design, monitoring, and modeling of GS to assist
in developing a practical methodology for characterizing risks to USDWs
(University of Utah); conducting laboratory experiments on shallow
aquifer systems to improve our understanding of geochemical and
microbiological reactions under low pH/high CO2 stress
(Columbia University); and, developing a set of computational tools to
model CO2 and brine movement associated with GS (Princeton
University).
    International projects: EPA is tracking the progress of
international GS efforts. The largest and longest-running commercial,
large-scale projects in operation today include: The Sleipner Project
in the Norwegian North Sea (operating since 1996); the Weyburn enhanced
oil recovery (EOR) project in Saskatchewan, Canada (operating since
2000); the In Salah Gas Project in Algeria (operating since 2004); and
Snohvit, also in offshore Norway in the Barents Sea (operating since
2008). Other projects EPA is tracking include Otway in Australia
(operating since 2008); Ketzin in Germany (operating since 2008); and
Lacq in France (operating since 2009). EPA is also tracking two
projects that are anticipated to begin injection in the near future:
CarbFix in Iceland (anticipated to commence injection in 2010) and
Gorgon in Australia (anticipated to start in 2014). EPA evaluated
available information and experiences gained from these international
projects to inform today's action, as appropriate. Additional
information on how these and other international projects informed the
GS rulemaking is contained in the rulemaking docket (USEPA, 2010a).
b. Tracking State Regulatory Efforts
    EPA has made it a priority to engage States and State organizations
throughout the rulemaking effort. EPA recognizes the complexity and
importance of the States' approaches to managing GS and is aware that
States are in various stages of developing statutory frameworks,
regulations,

technical guidance, and strategies for addressing CCS and GS.
Throughout the regulatory development process for the Class VI
regulation, EPA monitored States' regulatory efforts and approaches and
sought input on State activities related to addressing GS in the
proposed rule and NODA. At present, several States have published GS
regulations, while others are investigating and developing strategies
to address GS issues (e.g., management of multi-purpose injection wells
in oil and gas reservoirs). EPA is tracking regulatory efforts in 18
States: Colorado, Illinois, Kansas, Kentucky, Louisiana, Michigan,
Mississippi, Montana, New Mexico, New York, North Dakota, Oklahoma,
Pennsylvania, Texas, Utah, Washington, West Virginia, and Wyoming. EPA
is considering this information as it develops guidance on the primacy
application and approval process for Class VI wells. Information about
these State activities may be found in the docket for today's
rulemaking.
c. Conducting Technical Workshops on Issues Associated With
CO2 GS
    EPA 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.
The workshops included the following: Measurement, Monitoring, and
Verification (in New Orleans, Louisiana on January 16, 2008);
Geological Setting and AoR Considerations for CO2 GS (in
Washington, DC on July 10-11, 2007); Well Construction and MIT (in
Albuquerque, New Mexico on March 14, 2007); a State Regulators'
Workshop on GS of CO2 (in collaboration with DOE in San
Antonio, Texas on January 24, 2007); an International Symposium on Site
Characterization for CO2 Geological Storage (co-sponsored
with LBNL in Berkeley, California on March 20-22, 2006); Risk
Assessment for Geologic CO2 Storage (co-sponsored with the
Ground Water Protection Council (GWPC) in Portland, Oregon on September
28-29, 2005); and Modeling and Reservoir Simulation for Geologic Carbon
Storage (in Houston, Texas on April 6-7, 2005). Summaries of these
workshops are available on EPA's Web site, at http://www.epa.gov/safewater/uic/wells_sequestration.html.
3. Conducting Stakeholder Coordination and Outreach
    Throughout the rulemaking process, the Agency conducted public
workshops and public hearings and consulted with specific groups. EPA
representatives also attended meetings to explain the GS rulemaking
effort to interested members of the public and stakeholder groups.
Meeting information, notes, and summaries are available in the docket
for this rulemaking.
    Public stakeholder coordination: EPA held public meetings to
discuss EPA's rulemaking approach, and consulted with other stakeholder
groups including non-governmental organizations (NGOs) to gain an
understanding of stakeholder interests and concerns. As part of this
outreach, 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. Workshop summaries are available on EPA's Web
site, at http://www.epa.gov/safewater/uic/wells_sequestration.html.
    EPA also coordinated with GWPC, a State association that focuses on
ensuring safe application of injection well technology and protecting
ground water resources, and IOGCC, a chartered State association
representing oil and gas producing States throughout the rulemaking
process. Members of GWPC and IOGCC have specific expertise regulating
the injection of CO2 for the ER of oil and gas. EPA staff
attended national meetings and calls of these organizations, as well as
those held by technical and trade organizations, NGOs, States, and
Tribal organizations to discuss the rulemaking process and GS-specific
technical issues.
    Consultation with the National Drinking Water Advisory Council
(NDWAC): In November 2008, during the public comment period for the
proposed rule, EPA met with NDWAC to discuss the proposed rule. At the
meeting, EPA presented information about the rulemaking and responded
to NDWAC questions and comments. NDWAC members indicated that they
understood the role of GS as a climate mitigation tool and encouraged
the Agency to continue to ensure the protection of USDWs. Since
proposal publication, EPA has met with NDWAC to discuss the status of
the rule and answer questions from NDWAC members. The notes of these
meetings are in the rulemaking docket.
    Consultations with States, Tribes, and Territories: EPA engaged
States, Tribes, and Territories early and throughout the rulemaking
process to promote open communication and solicit input and feedback on
all aspects of the rule.
    In April of 2008, prior to publication of the proposed rule, the
Agency sent background information about the rulemaking to all
Federally-recognized Indian Tribes and invited participation in a
dedicated GS consultation effort. EPA Regional Indian Coordinators
(RICs), the National Indian Workgroup (NIWG), the National Tribal
Caucus (NTC) and the National Tribal Water Council (NTWC) contacts were
also invited to participate in the consultation. EPA provided
additional rulemaking updates after publication of the proposal with
the above-mentioned groups as well as the National Water Program State-
Tribal Climate Change Council (STC3). The Fort Peck Assiniboine and
Sioux Tribes and the Navajo Nation received UIC program primacy for the
Class II program (under section 1425 of the SDWA) during the proposal
period for this rule (73 FR 65556; 73 FR 63639). Therefore, the Agency
initiated an additional consultation effort with these Tribal co-
regulators post-proposal. Summaries of the Tribal consultation
conference calls are included in the docket for today's rulemaking.
    To ensure that States were consulted, the Agency also sent
background information about the rulemaking to States and State
organizations including the National Governors' Association, National
Conference of State Legislatures, Council of State Governments, and the
National League of Cities, among others, and held a dedicated
conference call on GS for interested State representatives in April
2008. Additionally, the Agency participated in rulemaking updates, as
appropriate, during national meetings and conferences, and gave
presentations to State organizations throughout development of the
rule. A summary of these efforts is included in the docket for today's
rulemaking.
    Consultation with the United States Department of Health and Human
Services (HHS): Pursuant to SDWA section 1421, EPA consulted with the
U.S. Department of Health and Human Services during the rulemaking
process. Prior to proposal publication and rule finalization, the
Agency provided background information to HHS on the purpose and scope
of the rule. In June of 2010, EPA met with HHS to discuss the GS
rulemaking process as well as key elements of the proposed rule, the
Notice of Data Availability and Request for Comment, and the final
rule. During the June 2010 briefing, HHS participants asked about
technical criteria for Class VI wells and monitoring technologies
applicable to GS projects. The Agency addressed questions and comments
and HHS certified that the EPA satisfied consultation obligations under
the SDWA. The memo certifying this consultation is available in the
docket for today's rulemaking.

4. Proposed Rulemaking
    On July 25, 2008, EPA published the proposed Federal Requirements
Under the Underground Injection Control (UIC) Program for Carbon
Dioxide (CO2) Geologic Sequestration (GS) Wells (73 FR 43492). The
Agency proposed a new class of injection well (Class VI), along with
technical criteria for permitting Class VI wells that tailored the
existing UIC regulatory framework to address the unique nature of
CO2 injection for GS, including:
     Site characterization requirements that would apply to
owners or operators of Class VI wells and require submission of
extensive geologic, hydrogeologic, and geomechanical information on the
proposed GS site to ensure that Class VI wells are located in suitable
formations. EPA also proposed that owners or operators identify
additional containment/confining zones, if required by the Director, to
improve USDW protection.
     Enhanced AoR and corrective action requirements (e.g.,
plugging abandoned wells) to delineate the AoR for GS projects using
computational modeling that accounts for the physical and chemical
properties of all phases of the injected CO2 stream. EPA
also proposed that owners or operators periodically reevaluate the AoR
around the injection well to incorporate monitoring and operational
data and verify that the CO2 is moving as predicted within
the subsurface.
     Well construction using materials that are compatible with
and can withstand contact with CO2 over the life of the GS
project.
     Multi-faceted monitoring of the CO2 stream,
injection pressures, the integrity of the injection well, groundwater
quality above the confining zone(s), and the position of the
CO2 plume and the pressure front throughout injection.
     Comprehensive post-injection monitoring and site care
until it can be demonstrated that movement of the plume and pressure
front have ceased and the injectate does not pose a risk to USDWs.
     Financial responsibility requirements to ensure that
financial resources would be available for corrective action, injection
well plugging, post-injection site care, and site closure, and
emergency and remedial response.
    Following publication of the proposed rule, EPA initiated a 120-day
public comment period, which the Agency extended by 30 days to
accommodate requests from interested parties. The public comment period
for the proposed rule closed on December 24, 2008. EPA received
approximately 400 unique submittals from 190 commenters, including late
submissions. Commenters represented States; industry (including the oil
and gas industry, electric utilities, and energy companies);
environmental groups; and associations (including water organizations
and CCS associations).
    During the public comment period, the Agency held public hearings
on the proposed rule in Chicago, IL on September 30, 2008 and in
Denver, CO on October 2, 2008. The two hearings collectively drew
approximately 100 people representing non-governmental organizations,
academia, industry, and other organizations. At the hearings, 29 people
submitted oral comments. Transcripts of the public hearings are in the
rulemaking docket (Docket ID Nos. EPA-HQ-OW-2008-0390-0185 and EPA-HQ-
OW-2008-0390-0256).
5. Notice of Data Availability and Request for Comment
    Based on public comments received on the proposed rule, the Agency
identified several topics on which it needed additional public comment.
EPA published Federal Requirements Under the Underground Injection
Control (UIC) Program for Carbon Dioxide (CO2) Geologic
Sequestration (GS) Wells; Notice of Data Availability and Request for
Comment (74 FR 44802) on August 31, 2009, to describe additional topics
and request comment.
    The NODA and Request for Comment presented new data and information
from three DOE-sponsored RCSP projects including: (1) The Escatawpa,
Mississippi project; (2) the Aneth Field, Paradox Basin project in
Southeast Utah; and, (3) the Pump Canyon Site project in New Mexico.
Additional information on these projects and responses to comments
received on the NODA and Request for Comment are available in the
docket for this rulemaking.
    The NODA and Request for Comment also provided results of two GS-
related modeling studies conducted by the LBNL. The first study
(Birkholzer et al., 2008a) focused on the potential for GS to cause
changes in ground water quality as a result of potential CO2
leakage and subsequent mobilization of trace elements such as arsenic,
barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium.
Results from this model simulation suggest that if CO2 were
to leak into a shallow aquifer, mobilization of lead and arsenic could
occur, causing increases in the concentration of these trace elements
in ground water and potential for drinking water standard exceedances.
    The second study modeled a theoretical scenario of GS in a
sedimentary basin to demonstrate the potential for basin-scale
hydrologic impacts of CO2 storage (Birkholzer et al.,
2008b). Model results indicate that basin-wide pressure influences may
be large and that predicted pressure changes could move saline water
upward into overlying aquifers if localized pathways, such as
conductive faults, are present. This example illustrates the importance
of basin-scale evaluation of reservoir pressures and far-field
pressures resulting from CO2 injection.
    Additional information on LBNL's research and responses to comments
received on the NODA and Request for Comment are available in the
docket for this rulemaking.
    The full publications on the LBNL research are also available on
LBNL's Web site at http://esd.lbl.gov/GCS/projects/CO2/index_CO2.html.
    Lastly, the NODA and Request for Comment presented an alternative
to address public comments and concerns about the proposed injection
depth requirements for Class VI wells. Section III.D of today's action
contains more information on this subject.
    Following publication of the NODA and Request for Comment, EPA
initiated a 45-day public comment period, which closed on October 15,
2009. EPA received 67 unique submittals from 64 commenters, many of
whom commented on the proposed rule. The Agency also held a public
hearing in Chicago, IL on September 17, 2009. Six people, representing
the oil and gas industry, electric utilities, water associations, and
academia attended the hearing. Two attendees submitted oral comments at
the hearing. A transcript of the public hearing is in the rulemaking
docket (EPA-HQ-OW-2008-0390-391).

F. How will EPA's adaptive rulemaking approach incorporate future
information and research?

    In the preamble to the proposed rule (73 FR 43492), EPA explained
the need for and merits of using an adaptive approach to regulating
injection of CO2 for GS at 40 CFR parts 144 through 146. The
Agency indicated that this approach would provide regulatory certainty
to owners or operators, promote consistent permitting approaches, and
ensure that Class VI permitting Agencies are able to meet current and
future demand for Class VI permits. The proposal also clarified that,
as the Agency reviewed public comments, it would continue to evaluate
ongoing research and demonstration projects and gather other

relevant information as needed to make refinements to the rulemaking
process.
    Many commenters strongly supported an adaptive, flexible approach
and suggested that the Agency initially take a conservative approach in
developing the UIC-GS requirements, with a provision for periodic
review of the rule to allow EPA to incorporate operational experience
as it is gained. These commenters also urged EPA not to wait until the
completion of DOE's pilot projects before finalizing the GS rule,
expressing a need for early regulatory certainty.
    Some commenters expressed concerns about an adaptive approach,
stating that it could lead to regulatory uncertainty because
modifications could be made after the initial regulations are
promulgated. One commenter said that GS will not scale-up rapidly,
leaving ample time to study and assess possible regulatory approaches.
    EPA agrees with commenters who supported an adaptive approach to
the UIC rulemaking for GS. Additionally, the Agency believes that there
is a need to have regulations in place during the earliest phases of GS
deployment. Finalizing today's requirements will allow early Class VI
wells to be permitted in a manner that addresses the unique
characteristics of CO2 injection for GS and allow early
projects to demonstrate successful confinement of CO2 in a
manner that is protective of USDWs. EPA also believes that an adaptive
approach enables the Agency to make changes to the program as necessary
to incorporate new research, data, and information about GS and
associated technologies (e.g., modeling and well construction). This
new information may increase protectiveness, streamline implementation,
reduce costs, or otherwise inform the requirements for GS injection of
CO2. The Agency plans, every six years, to review the
rulemaking and data on GS projects to determine whether the appropriate
amount and types of information and appropriate documentation are being
collected, and to determine if modifications to the Class VI UIC
requirements are appropriate or necessary. This time period is
consistent with the periodic review of National Primary Drinking Water
Standards under Section 1412 of SDWA.

G. How does this action affect UIC program implementation?

    Under section 1421(b), the SDWA mandates that EPA develop minimum
Federal requirements for State UIC primary enforcement responsibility,
or primacy, to ensure protection of USDWs. In order to implement the
UIC program, States must apply to EPA for primacy approval. In the
primacy application, States must demonstrate: (1) State jurisdiction
over underground injection projects; (2) that their State regulations
are at least as stringent as those promulgated by EPA (e.g.,
permitting, inspection, operation, monitoring, and recordkeeping
requirements); and (3) that the State has the necessary administrative,
civil, and criminal enforcement penalty remedies pursuant to 40 CFR
145.13 authorities.
    Once an application for primacy is received, the EPA Administrator
must review and approve or disapprove the State's primacy application.
EPA may also choose to approve or disapprove part of the application.
This determination is based on EPA's mandate under the SDWA as
implemented by UIC regulations established in 40 CFR part 144 through
146, and must be made by a rulemaking. Most States were authorized with
full or partial primacy for the UIC program in the early 1980s;
recently, two Tribes received primacy for the Class II program under
section 1425 of the SDWA. EPA directly implements the UIC program in
States that have not applied for primacy and States that have primacy
for part of the UIC program. A complete list of the primacy agencies in
each State is available at http://www.epa.gov/safewater/uic/primacy.html.
    EPA may approve primacy for States as authorized by sections 1422
and 1425 of the SDWA. There are fundamental differences between how
these two statutory provisions are applied. Under section 1422, States
must demonstrate that their proposed UIC program meets the statutory
requirements under section 1421 and that their program contains
requirements that are at least as stringent as the minimum Federal
requirements provided for in the UIC regulations to ensure protection
of USDWs. Alternatively, States seeking primacy under section 1425 have
the option to demonstrate that their Class II program is an
``effective'' program to prevent underground injection that endangers
USDWs. Typically, these States follow the broader elements of a State
program submission established by EPA in 40 CFR part 145, subpart C. In
today's final rule, and in accordance with the SDWA section 1422, all
Class VI State programs must be at least as stringent as the minimum
Federal requirements finalized in today's rule.
    UIC program implementation: Authority to administer a State UIC
program may be granted to one or more State agencies. States may choose
to include in their UIC primacy application a program that is
administered by multiple agencies. Under 40 CFR 145.23, in order for
more than one agency to be responsible for administration of the
program, each agency must have Statewide jurisdiction over the class of
injection activities for which they are responsible. Some States
administer their program for all injection well classes through a
single agency, whereas other States elect to divide the program between
agencies. For example, in most States, the Class II program is run by
an oil and gas agency and other well classes are run by a State
environmental agency (e.g., the Oklahoma Corporation Commission
oversees Class II wells in the State, and the Oklahoma Department of
Environmental Quality oversees other well classes). Additionally,
several States allow their oil and gas agencies to administer their UIC
program for specific well classes or subclasses provided they meet all
minimum Federal requirements (e.g., the Railroad Commission of Texas
oversees Class III brine-mining wells and Class V geothermal wells in
Texas). EPA believes that retaining this flexibility for States to
identify the appropriate agency to oversee Class VI wells will address
commenters' concerns that States should be afforded the opportunity to
determine which agency should oversee Class VI wells, and recognizes
the existing expertise of both State oil and gas agencies and deep well
injection programs, generally overseen by State environmental agencies.
    Proposed approach for Class VI primacy and public comment: In the
proposed rule, EPA emphasized that States, Territories, and Tribes
seeking primacy for Class VI wells would be required to demonstrate
that their regulations are at least as stringent as the proposed
minimum Federal requirements. Recognizing that some States may wish to
obtain primacy for only Class VI wells, the Agency requested comment on
the merits and possible disadvantages of allowing primacy approval for
Class VI wells independent of other well classes.
    Commenters representing States, industry, various trade
associations, and electric utilities supported the concept of allowing
independent primacy for Class VI wells. Commenters asserted that States
have the best knowledge of regional geology and areas in need of
special protection, along with necessary pre-existing relationships
with the regulated community. Commenters also agreed with EPA's
statement in the proposal that independent primacy would encourage
States to develop a

comprehensive regulatory program for all aspects of CCS (noting that
some States have already begun legislative efforts that are wider in
scope than the proposed Federal rule) and facilitate the rapid
deployment of commercial-scale CCS projects. They also asserted that
this approach is acceptable under the UIC program's statutory
authority.
    Independent primacy for Class VI wells: Historically, EPA has not
accepted independent UIC primacy applications from States for
individual well classes under section 1422 of SDWA, as a matter of
policy. For example, if a State wanted primacy for Class I wells, the
State would also need to accept primacy for all other well classes
under section 1422 of SDWA (See section II.H for a description of well
classifications). This policy has been in place since the initiation of
the Federal UIC program and was intended to encourage States to take
full primacy for UIC programs, avoid Federal duplication of efforts,
and provide for administrative efficiencies.
    However, based on comments on the UIC-GS proposed rule and
discussions with States and stakeholders, the Agency will allow
independent primacy for Class VI wells under Sec.  145.1(i) of today's
rule, and will accept applications from States for independent primacy
under section 1422 of the SDWA for managing UIC-GS projects under Class
VI. EPA believes that States are in the best position to implement UIC-
GS programs, and by allowing for independent Class VI primacy, EPA
encourages States to take responsibility for implementation of Class VI
regulations. The Agency's UIC program believes that this may, in turn,
help provide for a more comprehensive approach to managing GS projects
by promoting the integration of GS activities under SDWA into a broader
framework for States managing issues related to CCS that may lie
outside the scope of the UIC program or other EPA programs. This would
harness the unique efficiencies States can offer to promote adoption of
GS technology that incorporates issues in the broader scope of CCS,
while ensuring that USDWs are protected through the UIC regulatory
framework. Allowing States to apply only for Class VI primacy will also
shorten the primacy approval process.
    EPA's willingness to accept independent primacy applications for
Class VI wells applies only to Class VI well primacy and does not apply
to any other well class under SDWA section 1422 (i.e., I, III, IV, and
V). EPA believes that this shift in its longstanding policy of
discouraging ``partial'' or ``independent'' primacy is warranted to
encourage States to seek primacy for Class VI wells and allow States to
address the unique challenges that would otherwise be barriers to
comprehensive and seamless management of GS projects.
    The Agency recognizes that some States are currently addressing
off-facility surface access for corrective action and monitoring, pore
space ownership and trespass issues, and amalgamation of correlative
rights in depleted reservoirs for GS. Additionally, because GS
technologies are an important component of CCS, the Agency considers
the allowance for independent Class VI primacy important and unique to
this well class. This decision is expected to ensure that the Class VI
primacy application process does not serve as a barrier to GS and CCS
deployment. EPA will not consider applications for independent primacy
for any other injection well class under SDWA section 1422 other than
Class VI, nor will the Agency accept the return of portions of existing
1422 programs. EPA will continue to process primacy applications for
Class II injection wells under the authority of section 1425 of the
SDWA.
    Today's final rule includes a new subparagraph Sec.  145.1(i) that
establishes EPA's intention to allow for independent primacy for Class
VI wells. The Agency is developing implementation materials to provide
guidance to States applying for Class VI primacy under section 1422 of
SDWA and to assist UIC Directors evaluating permit applications.
    Effective date of the GS rule and Class VI primacy application and
approval timeframe: Today's rule, at Sec.  145.21(h), establishes a
Federal Class VI primacy program in States that choose not to seek
primacy for the Class VI portion of the UIC program within the approval
timeframe established under section 1422(b)(1)(B) of the SDWA. Under
Sec.  145.21(h), States will have 270 days following final promulgation
of the GS rule September 6, 2011 to submit a complete primacy
application that meets the requirements of Sec. Sec.  145.22 or 145.32.
Pursuant to the SDWA, this 270-day timeframe allows States that seek
primacy for the new Class VI wells a reasonable amount of time to
develop and submit their application to EPA for approval. EPA will
assist States in meeting the 270-day deadline by developing
implementation materials for States and conducting training on the
process of applying for and receiving primacy for Class VI wells under
section 1422 of SDWA. EPA will also assist States as they develop GS
regulations that are the equivalent of minimum Federal requirements and
plans to use an expedited process for approving primacy.
    Although the SDWA allows the Administrator to extend the date for
submission of an application for up to 270 additional days for good
cause, the Agency has determined that it will not provide for an
extension for States applying for Class VI primacy. Instead, EPA
believes that, in light of national priorities for promoting climate
change mitigation strategies and Administration priorities for
developing and deploying CCS projects in the next few years, it is
important to have enforceable Class VI regulations in place nationwide
as soon as possible.
    If a State does not submit a complete application during the 270-
day period, or EPA has not approved a State's Class VI program
submission, then EPA will establish a Federal UIC Class VI program in
that State after the 270-day application period closes. This will
ensure that tailored State- or Federally-enforceable requirements
applicable to GS projects will be in place nationwide as soon as
possible after rule finalization. Further, a clear, nationally-
consistent deadline will avoid potential confusion that may arise if
some States have approved Class VI programs and others do not. EPA will
publish a list of the States where the Federal Class VI requirements
have become applicable in the Federal Register and update 40 CFR part
147. It is important to note that, although the Agency is not accepting
extension requests, a State may, at any time in the future, apply for
primacy for the new GS requirements following establishment of a
Federal Class VI UIC program. If a State receives approval after the
270-day deadline (for a primacy application submitted either before or
after the deadline), EPA will publish a subsequent notice of the
approval as required by the SDWA; at that point, the State, rather than
EPA, will implement the Class VI program.
    The Agency clarifies that States may not issue Class VI UIC permits
until their Class VI UIC programs are approved. During the first 270-
days and prior to EPA approval of a Class VI primacy application,
States without existing SDWA section 1422 primacy programs must direct
all Class VI GS permit applications to the appropriate EPA Region. EPA
Regions will issue permits using existing authorities and well
classifications (e.g., Class I or Class V), as appropriate.
    States with existing UIC primacy for all non-Class VI well classes
under section 1422 that receive Class VI permit applications within the
first 270

days after promulgation of the final rule may consider using existing
authorities (e.g., Class I or Class V), as appropriate, to issue
permits for CO2 injection for GS while EPA is evaluating
their Class VI primacy application. EPA encourages States to issue
permits that meet the requirements for Class VI wells to ensure that
Class V and Class I wells previously used for GS can be re-permitted as
Class VI wells that meet the protective requirements of today's final
rule within one year of promulgation of the Class VI regulation,
pursuant to requirements at Sec.  146.81(c), with minimal additional
effort on the part of the owner or operator or the Director.
    After the 270-day deadline, and until a State has an approved Class
VI program, EPA will establish and implement a Class VI program.
Therefore, all permit applications in States without Class VI programs
must be directed to the appropriate EPA Region in order for a Class VI
permit to be issued. In States where EPA directly implements the Class
VI program, Class I permits for CO2 injection for GS may no
longer be issued and Class V permits may only be issued to projects
eligible for such permits (see discussion of the relationship between
Class V and Class VI permits in Section II.H).
    Streamlining the primacy approval process: In an effort to support
States with the Class VI primacy application process and respond to
comments received during the rulemaking process, today's rule includes
new regulatory language at Sec. Sec.  145.22 and 145.23 to streamline
and clarify the process for submission of Class VI primacy applications
and address the unique aspect of Class VI injection operations. For
example, EPA is allowing the electronic submission of required primacy
application information (e.g., letter from the Governor, program
description, Attorney General's statement, or Memorandum of Agreement).
The Agency is also allowing the use of existing reporting form(s),
e.g., existing UIC program forms or State equivalents, for Class VI
wells, as appropriate.
    EPA will evaluate the efficiency and effectiveness of electronic
submittals as part of the adaptive approach to the GS rulemaking and
determine whether electronic submittal may be applicable to other UIC
primacy applications submitted to EPA for review and approval under
sections 1422 and 1425 of SDWA. Additionally, the Agency is developing
a Class VI Program Primacy Application and Implementation Manual that
describes, for States, the process of applying for and receiving
primacy for Class VI wells under section 1422 of SDWA. The Manual will
also provide tools designed to assist States with the development of
their primacy application and UIC Directors with evaluating permit
application information.
    Unique requirements for Class VI permit applications: To address
the unique nature of Class VI injection operations, today's rule at
Sec.  145.23(f) includes new language describing the requirements for
Class VI State program descriptions. Specifically, Sec.  145.23(f)(1)
requires States to include a schedule for issuing Class VI permits for
wells within the State that require them within two years after
receiving program approval from EPA, and Sec.  145.23(f)(2) requires
States to include their permitting priorities, as well as the number of
permits to be issued during the first two years of program operation.
In addition, today's rule at Sec.  145.23(f)(4) requires the Director
of Class VI programs approved before December 10, 2011, to provide a
description of the process for notifying owners or operators of any
Class I wells previously permitted for the purpose of geologic
sequestration or Class V experimental technology wells no longer being
used for experimental purposes that will continue injection of carbon
dioxide for the purpose of GS that they must apply for a Class VI
permit pursuant to requirements at Sec.  146.81(c) within one year of
December 10, 2011. Sec.  145.23(f)(4) also requires the Director of a
Class VI Program approved after December 10, 2011, to provide a
description of the process for notifying owners or operators of any
Class I wells previously permitted for the purpose of geologic
sequestration or Class V experimental technology wells no longer being
used for experimental purposes that will continue injection of carbon
dioxide for the purpose of GS or Class VI wells permitted by EPA that
they must apply to the State program for a Class VI permit pursuant to
requirements at Sec.  146.81(c) within one year of Class VI program
approval. EPA is committed to working closely with and receiving input
from States during all stages of the GS permitting process,
irrespective of primacy status. Close coordination during program
implementation will minimize effort and burden on States and owners and
operators and streamline the administrative process for transferring
permits or permit applications when primacy is granted. These
requirements are tailored for Class VI wells to ensure that States are
prepared to review Class VI permit applications as soon as possible
following program approval; and, in light of the national priorities to
promote climate change mitigation strategies, such modifications of
Sec.  145.23 may help ensure expeditious implementation of Class VI
requirements across the country.
    Today's rule, at Sec.  145.23(f)(13), requires States to describe
in their primacy application procedures for notifying any States,
Tribes, and Territories of Class VI permit applications where the AoR
is predicted to cross jurisdictional boundaries and for documenting
this consultation. This new requirement addresses comments on the
proposed rule and NODA and Request for Comment that Class VI operations
are likely to have larger AoRs that may cross jurisdictional boundaries
and necessitate trans-boundary coordination. At Sec.  145.23(f)(9), the
final rule also requires States receiving Class VI program approval to
incorporate information related to any EPA approved exemptions
expanding the areal extent of an existing Class II EOR/EGR aquifer
exemption for Class VI injection. This requirement complements aquifer
exemption requirements promulgated under today's rule and ensures that
State programs incorporate information regarding the specific location
(and any associated supporting data) into their program descriptions.
    The Agency plans to review these requirements as part of the
adaptive rulemaking approach to ensure that the tailored requirements
are appropriate to ensure USDW protection from endangerment.

H. How does this rule affect existing injection wells under the UIC
program?

    Today's rulemaking establishes a new class of injection well, Class
VI, for GS projects because CO2 injection for long-term
storage presents several unique challenges that warrant the designation
of a new well type.
    When EPA initially promulgated its UIC regulations in 1980, the
Agency defined five classes of injection wells at 40 CFR 144.6, based
on similarities in the fluids injected, construction, injection depth,
design, injection practices, 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 among the deepest of the injection wells and are
subject to technically sophisticated construction and operation
requirements.
     Class II wells inject fluids (e.g., CO2; brine)
in connection with conventional

oil or natural gas production, enhanced oil and gas production, and the
storage of hydrocarbons that are liquid at standard temperature and
pressure.
     Class III wells inject fluids associated with the
extraction of minerals, including the mining of sulfur and solution
mining of minerals (e.g., uranium).
     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 a Federal or State-approved 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
are used to inject below USDWs. This well class includes Class V
experimental technology wells including those permitted as GS pilot
projects.
    The Agency acknowledges that owners or operators of wells regulated
under existing well classifications may want to change the purpose of
their injection activity. The following sections describe the
applicability of today's rule to owners or operators of existing wells
and considerations for Directors evaluating existing wells that may be
re-permitted as Class VI wells.
    Class I wells: Wells previously permitted as Class I wells for GS,
including wells permitted prior to rule promulgation and wells
permitted during the 270-day period after rule promulgation, must apply
for Class VI permits within one year of promulgation by December 10,
2011, pursuant to requirements at Sec.  146.81(c). The Agency
anticipates that permit applications (e.g., Class I or Class V)
developed for CO2 GS following publication of today's rule
will follow the Class VI requirements and be designed to facilitate
efficient re-permitting as Class VI wells. Such forethought will allow
new Class VI permits to be issued with minimal additional effort on the
part of the owner or operator and the Director. Additional information
on Class V experimental technology wells is discussed in this section.
For additional information on permitting authorities and UIC program
implementation, see section II.G.
    Class II CO2 injection wells designated for enhanced
recovery: Enhanced oil recovery (EOR) and enhanced gas recovery (EGR)
technologies, collectively referred to as enhanced recovery (ER), are
used in oil and gas reservoirs to increase production. Injection of
CO2 is one of several ER techniques that have successfully
been used to boost production efficiency of oil and gas by re-
pressurizing the reservoir, and in the case of oil, by also increasing
mobility. Injection wells used for ER are regulated through the UIC
Class II program.
    CO2 currently injected for ER in the U.S. comes from
both natural and anthropogenic sources, which provide 79 percent and 21
percent, respectively, of CO2 supply (DOE NETL, 2008).
Natural CO2 sources consist of geologic domes in Colorado,
New Mexico, and Mississippi. Anthropogenic sources of CO2
supplied for ER today include natural gas processing, ammonia and
fertilizer production, and coal gasification facilities.
    Historically, CO2 purchases comprise about 33 to 68
percent of the cost of a CO2-ER project (EPRI, 1999). For
this reason, CO2 injection volumes are carefully tracked at
ER sites. CO2 recovered from production wells during ER is
recycled (i.e., separated and re-injected), and at the conclusion of an
ER project as much CO2 as is feasible is recovered and
transported to other ER facilities for re-use. However, a certain
amount of CO2 remains underground. Current Class II ER
requirements do not require tracking and monitoring of the injectate;
therefore, the migration and fate of the unrecovered CO2 is
not documented.
    As of 2008, there were 105 CO2-EOR projects within the
US (Oil and Gas Journal, 2008). The majority (58) of these projects are
located in Texas, and the remaining projects are located in
Mississippi, Wyoming, Michigan, Oklahoma, New Mexico, Utah, Louisiana,
Kansas, and Colorado. CO2-EOR projects recovered 323,000
barrels of oil per day in 2008, 6.5 percent of total domestic oil
production. A total of 6,121 CO2 injection wells among 105
projects were used to inject 51 million metric tons of CO2
(Oil and Gas Journal, 2008; EIA, 2009; DOE NETL, 2008). Compared to
CO2-EOR, CO2-EGR remains largely in the
development stage (e.g., Oldenburg et al., 2001).
    Future deployment of CCS may fundamentally alter CO2-ER
in the U.S. DOE anticipates that many early GS projects will be sited
in depleted or active oil and gas reservoirs because the reservoirs
have been previously characterized for hydrocarbon recovery and may
have suitable infrastructure (e.g., wells, pipelines, etc.) in place.
Additionally, oil and gas fields now considered to be ``depleted'' may
resume operation because of increased availability and decreased cost
of anthropogenic CO2.
    EPA believes that if the business model for ER changes to focus on
maximizing CO2 injection volumes and permanent storage, then
the risk of endangerment to USDWs is likely to increase. This is
because reservoir pressure within the injection zone will increase as
CO2 injection volumes increase. Elevated reservoir pressure
is a significant risk driver at GS sites, as it may cause unintended
fluid movement and leakage into USDWs that may cause endangerment.
Additionally, increasing reservoir pressure within the injection zone
as a result of GS will stress the primary confining zone (i.e.,
geologic caprock) and well plugs to a greater degree than during
traditional ER (e.g., Klusman, 2003). Finally, active and abandoned
well bores are much more numerous in oil and gas fields than other
potential GS sites, and under certain circumstances could serve as
potential leakage pathways. For example, in typical productive oil and
gas fields, a CO2 plume with a radius of about 5 km (3.1
miles) may come into contact with several hundred producing or
abandoned wells (Celia et al., 2004).
    EPA proposed that the Class VI GS requirements would not apply to
Class II ER wells as long as any oil or gas production is occurring,
but would apply only after the oil and gas reservoir is depleted. Under
the proposed approach, Class II wells could be used for the injection
of CO2, as long as oil production is simultaneously
occurring from the same formation. The preamble to the proposal sought
comment on the merits of this approach.
    Some commenters agreed with the proposed approach while others
suggested that the approach did not adequately address risks posed to
USDWs by injection operations transitioning from production to long-
term storage of CO2. A majority of commenters requested that
EPA develop specific criteria for this transition.
    Consistent with these comments, EPA determined that owners or
operators of wells injecting CO2 in oil and gas reservoirs
for GS where there is an increased risk to USDWs compared to
traditional Class II operations using CO2 should be required
to obtain a Class VI permit, with some special consideration for the
fact that they are transitioning from a well not originally designed to
meet Class VI requirements. Additionally, EPA recognizes that further
clarification is needed to sufficiently characterize the factors that
lead to increased risks and warrant conversion from Class II to Class
VI.
    Therefore, today's rule clarifies that Class VI requirements apply
to any CO2 injection project (regardless of formation

type) when there is an increased risk to USDWs as compared to
traditional Class II operations using CO2. Traditional ER
projects are not impacted by this rulemaking and will continue
operating under Class II permitting requirements. EPA recognizes that
there may be some CO2 trapped in the subsurface at these
operations; however, if there is no increased risk to USDWs, then these
operations would continue to be permitted under Class II.
    EPA has developed specific, risk-based factors to be considered by
the Director in making the determination to apply Class VI requirements
to transitioning wells. EPA believes this approach provides the
necessary, site-specific flexibility while providing appropriate
protection of USDWs from endangerment. These risk-based factors for
determining whether Class VI requirements apply are finalized in
today's rule at Sec.  144.19 and include: (1) Increase in reservoir
pressure within the injection zone; (2) increase in CO2
injection rates; (3) decrease in reservoir production rates; (4) the
distance between the injection zone and USDWs; (5) the suitability of
the Class II AoR delineation; (6) the quality of abandoned well plugs
within the AoR; (7) the owner's or operator's plan for recovery of
CO2 at the cessation of injection; (8) the source and
properties of injected CO2; and (9) any additional site-
specific factors as determined by the Director. Any single factor may
not necessarily result in a determination that a Class II owner or
operator must apply for a Class VI permit; rather, all factors must be
evaluated comprehensively to inform a Director's (or owners' or
operators') decision. The Agency is also developing guidance to support
Directors and owners or operators in evaluating these factors and
making the determination on whether to apply Class VI requirements.
    Owners and operators of Class II wells that are injecting carbon
dioxide for the primary purpose of long-term storage into an oil and
gas reservoir must apply for and obtain a Class VI permit where there
is an increased risk to USDWs compared to traditional Class II
operations using CO2. EPA expects that, in most cases, the
ER owners or operators will use these same factors to evaluate whether
there is an increased risk to USDWs. When an increased risk is
identified, the owner or operator must notify the Director of their
intent to seek a Class VI permit. Today's rule clarifies that the
Director has the discretion to make this determination in the absence
of an owner or operator notification and, in doing so, require the
owner or operator to apply for and obtain a Class VI permit in order to
continue injection operations (Sec.  144.19(a)). In the event that an
injection operation makes changes to the ER operation such that the
increased risk to USDWs warrants transition to Class VI and does not
notify the Director, the owner or operator may be subject to specific
enforcement and compliance actions to protect USDWs from endangerment,
including corrective action within the AoR, cessation of injection,
monitoring, and/or PISC under sections 1423 and 1431 of the SDWA.
    The Agency acknowledges that some stakeholders and commenters are
concerned about the burden that a transition may impose on existing
programs. EPA believes that transition to Class VI is necessary to
ensure USDW protection but is allowing the constructed components of
Class II ER wells to be grandfathered into the Class VI permitting
regime at the discretion of the Director and pursuant to requirements
at Sec.  146.81(c), in order to facilitate the transition from Class II
to Class VI wells without undue regulatory burden. As outlined in
section II.G, today's rule clarifies that State oil and gas agencies
that oversee the Class II program in many States may assume regulatory
authority for Class VI by either a memorandum of understanding with the
Class VI primacy agency, or by obtaining primacy for the entire Class
VI program as long as it is identified in the State's program
description under Sec.  145.23. In this way, the same agency may
oversee the Class II and Class VI programs, streamlining the transition
process. State primary enforcement responsibility is discussed further
in section II.G.
    As part of EPA's adaptive rulemaking approach for Class VI wells,
the Agency will collect data on transitioning Class II projects to
determine whether the factors at Sec.  144.19 adequately address risks
to USDWs and whether additional or amended Federal regulations or other
actions are warranted for transitioning wells from ER to long-term
storage of CO2.
    Class V Experimental Technology Wells: Prior to finalization of the
Class VI regulation, a number of CO2 injection projects were
permitted as Class V experimental technology wells for the purpose of
testing GS technology in the U.S. Wells permitted under this
classification are designed for the purpose of testing new technology
that is of an experimental nature. EPA understands that some of the
wells previously permitted as Class V experimental technology wells may
no longer be used for this purpose. GS wells that are not being used
for experimental purposes must be re-permitted as Class VI wells and
will be subject to today's requirements.
    In the preamble to the proposed rule, EPA described UIC Program
Guidance 83 (Using the Class V Experimental Technology Well
Classification for Pilot GS Projects) and the use of the Class V
experimental technology well classification (see section II.E.1 of
today's notice). EPA stated that the guidance will continue to apply to
experimental projects (as long as the projects continue to qualify as
experimental technology wells under the guidelines described in the
guidance) and to future projects that are experimental in nature.
    Several commenters on the proposed rule asked EPA to clarify the
point at which Class V experimental technology wells should be re-
permitted as Class VI wells. Today's rule, at Sec.  146.81(c), requires
owners or operators of Class V experimental technology wells no longer
being used for experimental purposes (e.g., wells that will continue
injection of CO2 for the purpose of GS) to apply for Class
VI permits within one year of rule promulgation and to comply with the
requirements of today's rule. However, EPA is allowing the constructed
components of Class V experimental technology wells to be grandfathered
into the Class VI permitting regime at the discretion of the Director
and pursuant to requirements at Sec.  146.81(c).
    Following promulgation of today's rule, only GS projects of an
experimental nature (i.e., to test GS technologies and collect data)
will continue to be classified, permitted, and regulated as Class V
experimental technology wells; and Class V wells are prohibited from
operating as non-experimental GS operations under Sec.  144.15.
Experimental projects are those whose primary purpose is to test new,
unproven technologies. EPA does not consider it appropriate to permit
CO2 injection wells that are testing the injectivity or
appropriateness of an individual formation (e.g., as a prelude to a
commercial-scale operation) as Class V experimental technology wells.
Such wells should be permitted as Class VI wells.
    Other commenters suggested that owners or operators of wells
injecting CO2 into basalts, coal seams, and salt domes
should be able to seek a Class V experimental permit. EPA agrees that
the Class V experimental technology well classification may be
appropriate for these projects provided they are experimental in
nature. EPA expects that, following today's rule, a limited number of
experimental injection

projects testing GS technology will continue. EPA anticipates that
these projects will be small-scale and involve limited CO2
volumes. However, if these projects become larger scale and are no
longer experimental, they will need to be permitted as Class VI wells.
The construction, operation or maintenance of any non-experimental
Class V GS wells is prohibited (Sec.  144.15).
    The Agency is preparing additional guidance for owners or operators
and Directors regarding the use of the Class V experimental technology
well classification for GS following promulgation of today's rule. The
guidance will assist owners and operators and Directors in determining
what constitutes a Class V experimental technology well for the
purposes of testing GS technology.
    Grandfathering for Class I, Class II and Class V Experimental
Technology Wells: Recognizing that owners or operators of existing
Class I, Class II, and Class V experimental technology wells may seek
to change the purpose of their injection well, EPA proposed to give the
Director discretion to carry over or ``grandfather'' the construction
requirements (e.g., permanent, cemented well components) provided he or
she is able to make a determination that these wells would not endanger
USDWs. EPA sought comment on this approach and how the proposed
grandfathering provisions for existing wells may affect compliance with
Class VI construction requirements.
    Nearly all industry commenters favored grandfathering of Class I,
II, and V well construction requirements for GS, indicating that most
wells are built to appropriate specifications and would have sufficient
mechanical integrity for GS in order to protect USDWs from
endangerment. These commenters cited oil and gas industry experience
with CO2 injection in the UIC Class II program and suggested
that this experience demonstrates that construction requirements for
Class II injection wells are sufficient to protect USDWs. Other
commenters asserted that grandfathering Class II construction will
expedite the transition of Class II ER projects to Class VI GS.
    Several commenters were concerned that the structural modifications
that may be required for some existing Class II wells to comply with
the proposed injection well construction requirements at Sec.  146.86
may actually compromise the integrity of those wells. One commenter
also mentioned that pre-existing wells, including wells approved for
sequestration as Class I and/or Class II wells, have not been
constructed to the same standards. These existing wells penetrating the
injection zone may, therefore, become potential threats to USDWs.
    In response, EPA recognizes that the oil and gas industry has
decades of experience injecting CO2 for ER and that many
Class V experimental technology wells, including those used in the
RCSP's projects, are specifically designed for injection of
CO2 and are being constructed to Class I non-hazardous waste
well specifications. In today's final rule, at Sec.  146.81(c), owners
or operators seeking to grandfather existing Class I, II, or V wells
for GS must demonstrate to the Director that the grandfathered wells
were engineered and constructed to meet the requirements at Sec.
146.86(a) and ensure protection of USDWs from endangerment in lieu of
requirements at Sec.  146.86(b) and Sec.  146.87(a). Based on the owner
or operator's demonstration, the Director will determine if a well is
appropriately constructed for GS. If the Director determines that the
construction is appropriate for GS, the well will be re-permitted as a
Class VI well and must meet the operational, testing and monitoring,
reporting, injection well plugging, and PISC and site closure
requirements in subpart H of part 146. If an owner or operator seeking
to grandfather an existing Class I, II, or V well to a Class VI well
cannot make this demonstration, then grandfathering of the constructed
well and re-permitting as a Class VI well is prohibited.

III. What is EPA's final regulatory approach?

    Today's rule creates a new class of injection well (Class VI) under
the existing UIC program with new minimum Federal requirements that
protect USDWs from endangerment during underground injection of
CO2 for the purpose of GS. Today's action includes
requirements for the permitting, siting, construction, operation,
financial responsibility, testing and monitoring, PISC, and site
closure of Class VI injection wells that address the pathways through
which USDWs may be endangered. These requirements are tailored from
existing UIC program components to ensure that they are appropriate for
the unique nature of injecting large volumes of CO2 for GS
into a variety of geological formations to ensure that USDWs are not
endangered.
    Today's rule retains many of the requirements for Class VI wells
that EPA proposed on July 25, 2008. However, based on a review of
public comments on the proposed rule and the NODA and Request for
Comment, EPA made several changes to the GS rule. These changes are
highlighted as follows and are described in today's publication.
     Additional description of the adaptive rulemaking
approach. To ensure USDW protection and meet the potentially fast pace
of GS deployment, EPA plans to continue its adaptive rulemaking
approach for GS to incorporate new research, data, and information
about GS and associated technologies. See section II.F.
     Elaboration on the rationale for allowing States to gain
Class VI primacy independent of other well classes. To encourage States
to take responsibility for implementation of Class VI regulations and
foster a more comprehensive approach to managing GS projects within a
broader framework for managing CCS issues, Sec.  145.21 of today's rule
allows States to gain primacy for Class VI wells independent of other
well classes. See section II.G.
     Explanation of the considerations for permitting wells
that are transitioning from Class II to Class VI. To clarify the point
at which the purpose of CO2 injection transitions from ER
(i.e., a Class II well) to long-term storage (i.e., Class VI) and the
risk posed to USDWs increases and is greater than traditional ER
projects injecting CO2, today's rule at Sec.  144.19
contains specific, risk-based factors to be considered by owners or
operators and by Directors in making this determination. See section
II.H.
     Incorporation of a process to allow Class VI well owners
or operators to seek a waiver from the injection depth requirements. To
provide flexibility to address concerns about geologic storage capacity
limitations, address injection depth on a site-specific basis, and
accommodate injection into different formation types. Today's rule, at
Sec.  146.95, allows owners or operators to seek a waiver of the Class
VI injection depth requirements provided they can demonstrate USDW
protection. Today's final rule also limits the use of aquifer
exemptions for Class VI well injection activities (Sec.  144.7(d)). See
section III.D.
     Clarification of the requirements for submitting materials
to support Class VI permit applications. Today's rule specifies
separate requirements for information to be submitted with the permit
application (Sec.  146.82(a)) and information that must be submitted
before well operation is authorized (Sec.  146.82(c)). This
modification addresses comments that not all of the information to
support the proposed Class VI permit application requirements will be
available at the

time the operator develops their initial permit application, See
section III.A.
     Addition of requirements for updating project-specific
plans. To ensure that management of GS projects reflect up-to-date
information, today's rule requires periodic reviews of the AoR and
corrective action, testing and monitoring, and emergency and remedial
response plans (Sec.  146.84(e), Sec.  146.90(j), and Sec.  146.94(d)).
Any significant changes to the plans require a permit modification
(under Sec.  144.39(a)(5)). See Sections III.F and III.K.