Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2, 43492-43541 [E8-16626]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 73, Number 144 (Friday, July 25, 2008)]
[Proposed Rules]
[Pages 43492-43541]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E8-16626]



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Part II





Environmental Protection Agency





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40 CFR Parts 144 and 146



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

Federal Register / Vol. 73, No. 144 / Friday, July 25, 2008 / 
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 144 and 146

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


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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

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

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OW-
2008-0390, by one of the following methods:
     www.regulations.gov: Follow the on-line instructions for 
submitting comments.
     Mail: Water Docket, Environmental Protection Agency, 
Mailcode: 2822T, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
     Hand Delivery: Water Docket, EPA Docket Center (EPA/DC) 
EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. Such 
deliveries are only accepted during the Docket's normal hours of 
operation, and special arrangements should be made for deliveries of 
boxed information.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OW-2008-
0390. EPA's policy is that all comments received will be included in 
the public docket without change and may be made available online at 
https://www.regulations.gov, including any personal information 
provided, unless the comment includes information claimed to be 
Confidential Business Information (CBI) or other information whose 
disclosure is restricted by statute. Do not submit information that you 
consider to be CBI or otherwise protected, through https://
www.regulations.gov or e-mail. The https://www.regulations.gov Web site 
is an ``anonymous access'' system, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an e-mail comment directly to EPA without 
going through www.regulations.gov your e-mail address will be 
automatically captured and included as part of the comment that is 
placed in the public docket and made available on the Internet. If you 
submit an electronic comment, EPA recommends that you include your name 
and other contact information in the body of your comment and with any 
disk or CD-ROM you submit. If EPA cannot read your comment due to 
technical difficulties and cannot contact you for clarification, EPA 
may not be able to consider your comment. Electronic files should avoid 
the use of special characters, any form of encryption, and be free of 
any defects or viruses.
    Docket: All documents in the docket are listed in the https://
www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
in www.regulations.gov or in hard copy at the Water Docket, EPA/DC, EPA 
West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The 
Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through 
Friday, excluding legal holidays. The telephone number for the Public 
Reading Room is (202) 566-1744, and the telephone number for the EPA 
Docket Center is (202) 566-2426.

FOR FURTHER INFORMATION CONTACT: Lee Whitehurst, Underground Injection 
Control Program, Drinking Water Protection Division, Office of Ground 
Water and Drinking Water (MC-4606M), Environmental Protection Agency, 
1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone number: 
(202) 564-3896; fax number: (202) 564-3756; e-mail address: 
whitehurst.lee@epa.gov. For general information, contact the Safe 
Drinking Water Hotline, telephone number: (800) 426-4791. The Safe 
Drinking Water Hotline is open Monday through Friday, excluding legal 
holidays, from 10 a.m. to 4 p.m. Eastern time.

SUPPLEMENTARY INFORMATION:

I. General Information

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

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                Category                  Examples of regulated entities
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Private................................  Operators of CO2 injection
                                          wells used for GS.
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    This table is not intended to be an exhaustive list, but rather 
provides a guide for readers regarding entities likely to be regulated 
by this action. This table lists the types of entities that EPA is now 
aware could potentially be regulated by this action. Other types of 
entities not listed in the table could also be regulated. To determine 
whether your facility is regulated by this action, you should carefully 
examine the applicability criteria found in 146.81 of this proposed 
rule. If you have questions regarding the applicability of this action 
to a particular entity, consult the person listed in the preceding FOR 
FURTHER INFORMATION CONTACT section.

Abbreviations and Acronyms

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

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

Definitions

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

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

Table of Contents

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

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

II. What Is EPA Proposing?

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

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

1. What Is Geologic Sequestration (GS)?
    GS is the process of injecting CO2 captured from an 
emission source (e.g., a power plant or industrial facility) into deep 
subsurface rock formations for long-term storage. It is part of a 
process known as ``carbon capture and storage'' or CCS.
    CO2 is first captured from fossil-fueled power plants or 
other emission sources. To transport captured CO2 for GS, 
operators typically compress CO2 to convert it from a 
gaseous state to a supercritical fluid (IPCC, 2005). CO2 
exists as a supercritical fluid at high pressures and temperatures, and 
in this state it exhibits properties of both a liquid and a gas. After 
capture and compression, the CO2 is delivered to the 
sequestration site, typically by pipeline, or alternatively using 
tanker trucks or ships (WRI, 2007).
    The CO2 is then injected into deep subsurface rock 
formations via one or more wells, using technologies that have been 
developed and refined by the oil and gas and chemical manufacturing 
industries over the past several decades. To store the CO2 
as a supercritical fluid, it would likely be injected at a depth 
(greater than approximately 800 meters, or 2,625 feet), such that a 
sufficiently high pressure and temperature would be maintained to keep 
the CO2 in a supercritical state.
    When injected in an appropriate receiving formation, CO2 
is sequestered by a combination of trapping mechanisms, including 
physical and geochemical processes. Physical trapping occurs when the 
relatively buoyant CO2 rises in the formation until it 
reaches a stratigraphic zone with low fluid permeability (i.e., 
geologic confining system) that inhibits further upward migration. 
Physical trapping can also occur as residual CO2 is 
immobilized in formation pore spaces as disconnected droplets or 
bubbles at the trailing edge of the plume due to capillary forces. A 
portion of the CO2 will dissolve from the pure fluid phase 
into native ground water and hydrocarbons. Preferential sorption occurs 
when CO2 molecules attach onto the surfaces of coal and 
certain organic-rich shales, displacing other molecules such as 
methane. Geochemical trapping occurs when chemical reactions between 
the dissolved CO2 and minerals in the formation lead to the 
precipitation of solid carbonate minerals (IPCC, 2005). The timeframe 
over which CO2 will be trapped by these mechanisms depends 
on properties of the receiving formation and the injected 
CO2 stream. Current research is focused on better 
understanding these mechanisms and the time required to trap 
CO2 under various conditions.
    The effectiveness of physical CO2 trapping is 
demonstrated by natural analogs worldwide in a range of geologic 
settings, where CO2 has remained trapped for millions of 
years. For example, CO2 has been trapped for more than 65 
million years under the Pisgah Anticline, northeast of the Jackson Dome 
in Mississippi and Louisiana, with no evidence of leakage from the 
confining formation (IPCC, 2005).
2. Why Is Geologic Sequestration Under Consideration as a Climate 
Change Mitigation Technology?
    Greenhouse gases (GHGs) perform the necessary function of keeping 
the planet's surface warm enough for human habitation. But, the 
concentrations of GHGs continue to increase in the atmosphere, and 
according to data from the National Oceanic and Atmospheric 
Administration (NOAA) and National Aeronautics and Space Administration 
(NASA), the Earth's average surface temperature has increased by about 
1.2 to 1.4 [deg]F in the last 100 years. Eleven of the last twelve 
years rank among the twelve warmest years on record (since 1850), with 
the two warmest years being 1998 and 2005. The Intergovernmental Panel 
on Climate Change (IPCC) has concluded that much of the warming in 
recent decades is very likely the result of human activities (IPCC, 
2007). The burning of fossil fuels (e.g., from coal-fired electric 
plants and other sources in the electricity and industrial sectors) is 
a major contributor to human-induced greenhouse gas emissions.
    Fossil fuels are expected to remain the mainstay of energy 
production well into the 21st century, and increased concentrations of 
CO2 are expected unless energy producers reduce the 
CO2 emissions to the atmosphere. The

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capture and storage of CO2 would enable the continued use of 
coal in a manner that greatly reduces the associated CO2 
emissions while other safe and affordable alternative energy sources 
are developed in the coming decades. Given the United States' abundant 
coal resources and reliance on coal for power generation, CCS could be 
a key mitigation technology for achieving domestic emissions 
reductions.
    Estimates based on DOE and IEA studies indicate that areas of the 
U.S. with appropriate geology could theoretically provide storage 
potential for over 3,000 gigatons (or 3,000,000 megatons; Mt) of 
geologically sequestered CO2. Theoretically, this capacity 
could be large enough to store a thousand years of CO2 
emissions from nearly 1,000 coal-fired power plants. Worldwide, there 
appears to be significant capacity in subsurface formations both on 
land and under the seafloor to sequester CO2 for hundreds, 
if not thousands of years. CCS technologies could potentially represent 
a significant percentage of the cumulative effort for reducing 
CO2 emissions worldwide.
    While predictions about large-scale availability and the rate of 
CCS project deployment are subject to considerable uncertainty, EPA 
analyses of Congressional climate change legislative proposals (the 
McCain-Lieberman bill S. 280, the Bingaman-Specter bill S. 1766, and 
the Lieberman-Warner bill S. 2191) indicate that CCS has the potential 
to play a significant role in climate change mitigation scenarios. For 
example, analysis of S. 2191 indicates that CCS technology could 
account for 30 percent of CO2 emission reductions in 2050 
(USEPA, 2008a). It is important to note that GS is only one of a 
portfolio of options that could be deployed to reduce CO2 
emissions. Other options could include efficiency improvements and the 
use of alternative fuels and renewable energy sources. Today's proposal 
provides a regulatory framework to protect USDWs as this key climate 
mitigation technology is developed and deployed. This proposal provides 
certainty to industry and the public about requirements that would 
apply to injection, by providing consistency in requirements across the 
U.S., and transparency about what requirements apply to owners or 
operators.
    Establishing a supporting regulatory framework for the future 
development and deployment of CCS technology can provide the regulatory 
certainty needed to foster industry adoption of CCS, which is crucial 
to supporting the goals of any proposed climate change legislation. 
This proposed rule is consistent with and supports a strategy to 
address climate change through: (1) Slowing the growth of emissions; 
(2) strengthening science, technology and institutions; and (3) 
enhancing international cooperation. EPA plays a significant role in 
implementing this strategy through encouraging voluntary GHG emission 
reductions, and working with other agencies, including DOE, to 
establish programs that promote climate technology and science.

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

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

    Underground injection endangers drinking water sources if such 
injection may result in the presence in underground water which 
supplies or can reasonably be expected to supply any public water 
system of any contaminant, and if the presence of such contaminant 
may result in such system's not complying with any national primary 
drinking water regulation or may otherwise adversely affect the 
health of persons (Section 1421(d)(2) of the SDWA, 42 U.S.C. 
300h(d)(2)).

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

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

C. Who Implements the UIC Program?

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

D. What Are the Risks Associated With CO2 GS?

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

[[Page 43498]]

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

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

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

[[Page 43499]]

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

[[Page 43500]]

Algeria, and Canada, whose results are being used to inform today's 
proposal.
    The Sleipner Project, located off the Norwegian coast in the North 
Sea, is the first commercial scale GS project into a saline formation. 
Approximately 1 Million tones (Mt) CO2 is removed annually 
from the natural gas produced in the Sleipner West Gas Field and 
injected approximately 800 m (2,625 ft) below the seabed. Injection 
began in August 1996, and operators expect to store 20 Mt 
CO2 over the expected 25-year life of the project. 
Activities include baseline data gathering and evaluation, reservoir 
characterization and simulation, assessment of the need and cost for 
monitoring wells, and geophysical modeling. Seismic time-lapse surveys 
have been used to monitor movement of the CO2 plume and 
demonstrate effectiveness of the cap rock (IPCC, 2005).
    The In Salah Gas Project, in the central Saharan region of Algeria, 
is the world's first large-scale CO2 storage project in a 
gas reservoir. CO2 is stripped from natural gas produced 
from the Krechba Field and re-injected via three horizontal injection 
wells into a 1,800 meter-deep (5,906 ft) sandstone reservoir. 
Approximately 1.2 Mt CO2 have been injected annually since 
April 2004 and it is estimated that 17 Mt CO2 will be stored 
over the life of the project. To characterize the site, 3-D seismic 
surveys and well data have been used to map the field, identify deep 
faults, establish a baseline, and conduct a risk assessment of storage 
integrity. Monitoring at the site includes use of noble gas tracers, 
pressure surveys, tomography, gravity baseline studies, microbiological 
studies, four-dimensional seismic surveys, and geomechanical monitoring 
(IPCC, 2005).
    Weyburn is an EOR project where the CO2 produced at a 
coal gasification plant in Beulah, ND is piped to Weyburn in 
southeastern Saskatchewan for EOR. Approximately 1.5 Mt CO2 
are injected annually via a combination of vertical and horizontal 
injection wells. It is expected that 20 Mt CO2 will be 
stored in the field over the 20 to 25 year life of the CO2-
EOR project. The monitoring regime at the site includes high-resolution 
seismic surveys and surface monitoring to determine any potential 
leakage (IPCC, 2005). The conclusions of Phase I of the project are 
that depleted oil and gas reservoirs from EOR operations are a 
promising CO2 storage option and that 4-D seismic monitoring 
is a valuable tool for plume tracking (IEA, 2005).
    Other ongoing GS projects include the Gorgon Gas Development 
project, a deep saline formation project in Barrow Island, Western 
Australia; the Otway (Australia) Project, where GS is taking place in a 
saline formation within a depleted natural gas reservoir; the South 
Quinshu Basin, China Enhanced Coalbed Methane (ECBM)/CO2 
sequestration project; the CO2 SINK project in Ketzin, 
Germany (a sandstone saline formation); and testing of CO2 
GS in the Deccan Trap basalts of India.
4. Identifying Technical and Regulatory Issues Associated With 
CO2 GS
    EPA has conducted a series of technical workshops with regulators, 
industry, ut