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


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Part II





Environmental Protection Agency





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40 CFR Parts 144 and 146



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


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 144 and 146

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

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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

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

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

    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

[[Page 43497]]

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

C. Who Implements the UIC Program?

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

D. What Are the Risks Associated With CO2 GS?

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

[[Page 43498]]

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

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

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

[[Page 43499]]

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

[[Page 43500]]

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

[[Page 43501]]

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

[[Page 43502]]

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

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

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

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

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

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

[[Page 43503]]

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

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

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

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

    The Comprehensive Environmental Response, Compensation, and 
Liability

[[Page 43504]]

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

III. Proposed Regulatory Alternatives

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

A. Proposed Alternative

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

[[Page 43505]]

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

[[Page 43506]]

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

[[Page 43507]]

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

[[Page 43508]]

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

[[Page 43509]]

a smaller diameter pipe, usually designated as the long-string casing, 
is run into the hole. Similar to the surface casing, the long-string 
casing is cemented in place to the borehole by circulating cement from 
the bottom back up to the surface casing, filling the gap between the 
outside of the long-string casing and the wellbore. This cementing 
process again ensures that rock formations are isolated and no fluid 
movement occurs between formations.
    Depending on the depth to the injection formation, additional 
strings of casing may be necessary, but in each case, these casings are 
engineered and designed to withstand internal and external pressures at 
depth. The final result is multiple barriers of cement and casing 
between formations above the injection zone and the fluids being 
injected. Typically a portion of the wellbore in the injection zone is 
left open or the casing is perforated to allow injected fluid to enter 
into the injection zone.
    Inside the long string casing, injection tubing is run from the 
surface to a depth within the injection zone. This tubing may be 
engineered of steel, an alloy, fiberglass, or a composite material most 
suitable for the injectate's composition. The tubing extends from the 
wellhead down to the storage zone where it is sealed by a mechanical 
device known as a packer. The area between the tubing and long string 
casing is isolated and the fluid injected into the well can only enter 
the geologic formation for which it is targeted. With this type of well 
construction, the fluid within the well tubing has minimal contact with 
the components of the well that protect USDWs.
    The space between the injection tubing and the long string casing 
and above the packer is called the annulus. The annulus between the 
wellhead and the packer is a water-tight space filled with a non-
corrosive fluid that helps to protect the inside of the casing and 
outside of the tubing from damage due to chemical reactions. In 
addition, monitoring the pressure of the annulus using standard 
pressure devices can easily detect any leaks in the tubing, long string 
casing, or packer.
    Due to the buoyancy of CO2, today's proposal includes 
enhancements to typical deep well construction procedures to provide 
additional barriers to CO2 leakage outside of the injection 
zone. The proposal would require that surface casing for GS wells be 
set through the base of the lowermost USDW and cemented to the surface. 
The long-string casing would be cemented in place along its entire 
length. GS wells would also be constructed with a packer that is set 
opposite a cemented interval, at a location approved by the Director. 
EPA seeks comment on the proposed GS well requirements for depth of 
surface casing, the cementing of long-string casing, and construction 
with a packer set opposite a cemented interval. EPA also seeks comment 
on how the proposed grandfathering provisions for existing wells 
(construction requirements) may affect compliance with the above, 
proposed construction requirements.
    More information on well drilling may be found by consulting 
various sources including the Department of Energy, the American 
Petroleum Institute (API), and the Society of Petroleum Engineers 
(SPE). Please consult information or links on EPA's Web site: http://
www.epa.gov/safewater/uic.html, or similar sources.
    Horizontal Well Construction: While horizontal well construction is 
not typical in deep injection wells in the UIC program, there are 
examples of horizontal well completions being used with success to 
improve the production of EOR and ECBM operations (e.g., Westermark et 
al., 2004; Sams et al., 2005). EPA understands that the In Salah 
project in Algeria is using horizontal well construction for GS 
purposes. Horizontal wells are constructed by use of a directional 
drilling system, which generally consists of both a curve and lateral 
drilling assembly. After the vertical portion of the well is 
constructed, the curve drilling assembly is used to drill a curve of 
prescribed radius to change the path from vertical to horizontal. The 
lateral drilling assembly is then used to construct the horizontal 
section, which can be lined or remain as an open hole. Importantly, 
several horizontal sections can be completed stemming from a single 
vertical completion.
    The use of horizontal wells for a GS project could provide several 
benefits over vertical wells. Horizontal wells provide enhanced 
connectivity with permeable sections of the formation, increasing 
injectivity. The use of horizontal wells increases the sweep, or 
formation contact area, of the injected CO2 plume, as 
vertical channeling through high permeability regions is reduced. 
Increasing the sweep results in enhanced residual-phase CO2 
trapping and dissolution favorable for the purposes of permanent 
storage. Horizontal wells also reduce the pressures needed to inject 
any given volume of fluid. In addition, fewer vertical completions are 
required with the use of horizontal wells, which reduces the number of 
artificial penetrations in the formation through which fluid could 
migrate, as well as reducing overall costs.
    EPA seeks comment on the merits of horizontal well drilling 
techniques for GS wells and the applicability of well construction 
requirements discussed in this proposal.
    Well Component Degradation: The potentially corrosive nature of the 
injectate must be taken into consideration in the design and 
construction of CO2 GS wells. The quality of the well 
materials, proper well construction, composition and placement of 
appropriate cement along the wellbore, and appropriate maintenance are 
crucial, because a leaking annulus would be a significant route of 
escape for CO2 (IPCC, 2005).
    CO2 mixed with water or impurities (NOX, 
SOX and H2S) can be corrosive to well materials 
and cements. Conventional cement formulations (e.g., Portland cement) 
are potentially vulnerable to acid attack. Acid attack on the calcium 
carbonate in cement can lead to altered permeability and mechanical 
instability. Defects in the well cement, such as channels, cracks, and 
microannuli (i.e., small spaces between the casing and cement) can 
provide pathways for acid to migrate and accelerate degradation.
    Experience with CO2 injection for EOR includes the use 
of acid-resistant cements. Cements with a reduced Portland content are 
more resistant to acid because they contain less calcium carbonate 
(CaCO3). Acid resistant cements can be formulated by adding 
fly ash, silica fume (microsilica), latex, epoxy, or other substances. 
Calcium phosphate cement is a blend of high-alumina cement, phosphate, 
and fly ash that can retain integrity under conditions where other 
cements lose a substantial portion of their weight, according to one 
manufacturer (http://www.eandpnet.com/area/exp/153.htm).
    EPA examined available information to determine the rate at which 
cement degrades in acidic environments. Laboratory studies provide 
evidence of deterioration of cement and other well components due to 
exposure to acid. For example, Duguid et al., (2004) performed a 
laboratory study in which Portland cement experienced significant 
damage within seven days. Similar experiments by Kutchko et al., (2007) 
showed less cement alteration. Differences between these studies may be 
due to different experimental conditions, such as temperature and 
pressure.
    Limited results of field studies show clear evidence of reactions 
between CO2 and well cement, but do not show such severe 
corrosion. Cement samples from

[[Page 43510]]

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

[[Page 43511]]

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

[[Page 43512]]

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

[[Page 43513]]

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

[[Page 43514]]

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

[[Page 43515]]

proposal would also require owners or operators to monitor ground water 
quality and geochemical changes above the confining system. The results 
of this monitoring would be compared to baseline geochemical data to 
identify changes that may indicate unacceptable movement of 
CO2 or formation fluids.
    In order to provide guidance related to monitoring of GS sites, EPA 
invited expert advice and reviewed technical documentation. EPA held a 
technical workshop on measurement, monitoring, and verification focused 
on the availability and utility of various subsurface and near-surface 
monitoring techniques that may be applicable to GS projects. This 
workshop, co-sponsored by the Ground Water Protection Council (GWPC), 
took place in New Orleans, LA, on January 16, 2008.
    Monitoring within the confining zone for pressure, pH, salinity, or 
the presence of dissolved minerals, heavy metals, or organic 
contaminants requires direct access to the subsurface via monitoring 
wells. Wells installed for this purpose would be strategically placed 
in areas predicted to overlie the eventual CO2 plume and 
area of elevated pressure. Well number and placement would be based on 
project specific information such as injection rate and volume, site 
specific geology, baseline geochemical data, and the presence of 
artificial penetrations. Predictive models of the extent and direction 
of plume movement can support decisions about monitoring well 
placement. This has the dual benefit of targeting resources associated 
with what is an expensive monitoring activity and minimizing the number 
of artificial penetrations near the injection well, which could 
potentially become conduits for fluid movement into USDWs.
    Today's proposal would require that owners or operators perform a 
pressure fall-off test at least once every five years. Pressure fall-
off tests are designed to ensure that reservoir injection pressures are 
tracking to predicted pressures and modeling input. They may be used in 
project siting and AoR calculations. Results of pressure fall-off tests 
may indicate mischaracterization of the site specific geology and 
potentially unidentified leakage pathways. EPA seeks comment on the use 
and frequency of pressure fall-off testing for GS wells.
    Pressure monitoring, both at the surface and in the formation, is a 
routine part of CO2 injection projects that serves several 
purposes. For instance, monitoring pressure in injection wells allows 
for use of shut-off valves in the event that injection pressure exceeds 
the formation fracture pressure, or pressure drop-offs indicate a 
subsurface leak (IPCC, 2005). Pressure monitoring in monitoring wells 
provides an indication of whether there is potential for brine 
intrusion into USDWs and CO2 leakage. When combined with 
information on temperature, pressure data provide an indication of the 
phase (e.g., gas, supercritical) and amount of the injected 
CO2.
    Various pressure sensors are available, and monitoring can be 
conducted continuously. Conventional sensor types include piezo-
electric transducers, strain gauges, diaphragms, and capacitance gauges 
(Burton et al., 2007). Fiber optic pressure and temperature sensors are 
also now commercially available and can be installed down-hole and 
connected to the surface through fiber optic cables. According to 
Burton et al. (2007), current monitoring technologies are more than 
adequate for monitoring pressure in a GS project.
    Direct geochemical monitoring is an important part of a monitoring 
program. Temperature, salinity, and pH should be monitored, as these 
parameters provide basic information for understanding water and gas 
geochemistry. Additionally, obtaining ground water samples via 
monitoring wells allows direct measurement of aqueous and pure-phase 
CO2. By studying the interactions between brine and 
CO2, it can be determined whether precipitation and/or 
dissolution of minerals is occurring (Nicot and Hovorka, 2008). These 
analyses will also indicate the rate of CO2 trapping 
mechanisms, and whether mineral dissolution may be causing permeability 
changes in the formation or impacting USDWs. Geochemical monitoring may 
also be conducted for heavy metals and organic contaminants that may 
potentially be mobilized in the formation due to injection.
    Information and discussions from EPA technical and public workshops 
indicate that the collection of adequate baseline (pre-injection) data 
is critical for planning monitoring and for detecting CO2 
movement and leakage during and after injection.
    While the use of tracers is not a specific monitoring requirement 
in today's proposal (per III.A.4), some Directors may require owners or 
operators to use them. EPA has considered the merits of tracers for 
CO2 monitoring and recognizes that they may also be 
voluntarily employed by owners or operators. Tracers can also be 
measured through direct geochemical sampling to indicate the speed and 
direction of movement of CO2 after injection. Naturally 
occurring tracers include stable isotopes (atoms of a particular 
element with different numbers of neutrons) of carbon and oxygen. 
Analyses of the amounts of carbon-13 and oxygen-18 isotopes in water 
are commonly used to track movement through the environment and to 
elucidate geochemical processes. It is also possible to include 
tracers, such as perfluorocarbons or noble gases, with the injected 
CO2 (Nimz and Hudson, 2005). Loss of tracers between the 
injection well and monitoring well may indicate diffusion into low-
permeability materials, sorption, partitioning into non-aqueous phase 
liquids, partitioning into trapped gas phases, or leakage of 
CO2 (Nicot and Hovorka, 2008). Tracers were more fully 
discussed in the well construction and operation section of the 
preamble.
    There are several technical challenges associated with in-situ 
monitoring of formation fluids via wells. In the course of sample 
retrieval, there will be pressure changes, causing changes in 
CO2 solubility and pH. To address this, LBNL developed a 
``U-tube'' sampling apparatus to enable collection of fluid and gas 
samples at in-situ pressure conditions. Also, samples collected from 
monitoring wells are point measurements that may not fully represent 
the entire reservoir, especially if there are extensive physical 
heterogeneities.
    Geophysical Methods for Plume Tracking: Various non-invasive deep 
subsurface monitoring techniques are available to track the movement of 
the CO2 plume. Many of these methods have been developed for 
use in the oil and gas industry, and some may also support certain 
aspects of baseline geologic characterization. Seismic and electrical 
techniques have been used to gather data related to rock composition, 
porosity, fluid content, and in-situ stress state.
    In seismic surveying, a controlled source of seismic energy is used 
to send vibrations through the ground. The time it takes for the 
seismic waves to reflect off of a subsurface feature and reach a 
receiver at the surface provides information about the depth of the 
feature. By using an array of receivers, possible plume and leakage 
flowpaths may be discerned. Seismic surveys may also be useful for 
monitoring how rock properties change with time during injection and 
for mapping of the CO2 plume. This method has been used to 
study the subsurface in the area near the injection well for the 
CO2-SINK project in Germany (Juhlin et al., 2006) and at the 
Sleipner and In Salah sites. Seismic

[[Page 43516]]

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

[[Page 43517]]

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

[[Page 43518]]

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

[[Page 43519]]

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

[[Page 43520]]

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

[[Page 43521]]

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

[[Page 43522]]

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

B. Adaptive Approach

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

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

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

[[Page 43523]]

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

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

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

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

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

[[Page 43524]]

VII. Cost Analysis

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

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

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

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

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

[[Page 43525]]


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

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

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

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

[[Page 43526]]

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

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

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

[[Page 43527]]

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

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

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

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

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

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

[[Page 43528]]



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

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

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

C. Conclusions

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

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

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

B. Paperwork Reduction Act (PRA)

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

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

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

[[Page 43529]]

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

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

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

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

[[Page 43530]]


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

C. Regulatory Flexibility Act (RFA)

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

D. Unfunded Mandates Reform Act (UMRA)

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

E. Executive Order 13132: Federalism

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

[[Page 43531]]

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

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

    Executive Order 13175, entitled ``Consultation and Coordination 
With Indian Tribal Governments'' (65 FR 67249, November 9, 2000), 
requires EPA to develop an accountable process to ensure ``meaningful 
and timely input by tribal officials in the development of regulatory 
policies that have tribal implications.'' This proposed rule does not 
have tribal implications as specified in Executive Order 13175. 
Currently, no Indian Tribes have primacy. However, Indian Tribes may 
acquire authority to regulate a partial or full UIC program in lands 
under their jurisdiction by applying for and gaining primacy from the 
Agency. Tribes seeking primacy must develop requirements at least as 
stringent as the new proposed Federal requirements for Class VI wells 
if they wish to regulate CO2 GS, and all programs will be 
subject to EPA approval. If Tribes do not develop a program for Class 
VI wells, EPA is responsible for regulating the GS of CO2 on 
tribal lands. The application for primacy is a voluntary process. 
Furthermore, this proposal clarifies regulatory ambiguity rather than 
placing new requirements on tribal or other governmental entities. 
Therefore, this proposed rule should not change the Tribal-Federal 
relationship and should not significantly impact Tribes. Thus, 
Executive Order 13175 does not apply to this proposed rule.
    Although Executive Order 13175 does not apply to this proposed 
rule, EPA consulted with tribal officials in developing this proposed 
rule. EPA sent letters with background about the rulemaking and an 
invitation for consultation to all of the federally recognized Indian 
Tribes. EPA held a meeting with interested parties from Tribal 
governments in April 2008.
    EPA specifically solicits additional comment on this proposed rule 
from tribal officials.

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

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

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

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

I. National Technology Transfer and Advancement Act

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

[[Page 43532]]

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

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

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

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Duguid, A., M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. 
Celia. 2004. The Effect of CO2 Sequestration on Oil Well 
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Flett, M., R. Gurton, and G. Weir. 2007. Heterogeneous Saline 
Formations for Carbon Dioxide Disposal: Impact of Varying 
Heterogeneity on Containment and Trapping.
Fivelstad, S., R., Waagbo, F.Z. Solveig, A.C.D. Hosfeld, A.B. Olsen, 
and S. Stefansson. 2003. A Major Water Quality Problem in Smolt 
Farms: Combined Effects of Carbon Dioxide, Reduced pH, and Aluminum 
on Atlantic Salmon (Salmo salar L.) Smolts: Physiology and Growth. 
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Garner J., K. Martin, D. McCalvin, and D. McDaniel. 2002. At the 
Ready: Subsurface Safety Valves. Oilfield Review, 14(4), 52-64. 
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BestPract_Rev1-1.pdf.
Harris, J.M. and R.T. Langan. 2001. Crosswell Seismic Profiling: 
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Kazemeini, B. Norden, and K. Zinck-J[oslash]rgensen. 2006. Baseline 
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Kirkendall, B. and J. Roberts. 2001. Electromagnetic Imaging of 
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Thaulow. 2007. Degradation of Well Cement by CO2 Under 
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Requirements

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

List of Subjects

40 CFR Part 144

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

40 CFR Part 146

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

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

PART 144--UNDERGROUND INJECTION CONTROL PROGRAM

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

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

Subpart A--General Provisions

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


Sec.  144.1  Purpose and scope of part 144.

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


Sec.  144.6  Classification of wells.

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

Subpart B--General Program Requirements

    4. Adding Sec.  144.15 to read as follows.


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

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


Sec.  144.18  Requirements for Class VI wells.

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

Subpart D--Authorization by Permit

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


Sec.  144.36  Duration of permits.

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


Sec.  144.39  Modification or revocation and reissuance of permits.

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

Subpart E--Permit Conditions

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


Sec.  144.51  Conditions applicable to all permits.

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


Sec.  144.52  Establishing permit conditions.

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

[[Page 43535]]

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


Sec.  144.55  Corrective action.

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

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

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


Sec.  144.80  What is a Class V injection well?

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

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

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

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

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


Sec.  146.5  Classification of injection wells.

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

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


Sec.  146.81  Applicability.

    (a) This subpart establishes criteria and standards for underground 
injection control programs to regulate Class VI carbon dioxide geologic 
sequestration injection wells.
    (b) This subpart applies to wells used to inject carbon dioxide 
specifically for the purpose of geologic sequestration, i.e., the long-
term containment of a gaseous, liquid or supercritical carbon dioxide 
stream in subsurface geologic formations.
    (c) This subpart applies to owners and operators of permit or rule-
authorized Class I industrial, Class II, or Class V experimental carbon 
dioxide injection projects who seek to apply for a Class VI geologic 
sequestration permit for their well or wells. If the Director 
determines that USDWs will not be endangered, such wells are exempt, at 
the Director's discretion, from the casing and cementing requirements 
at Sec. Sec.  146.86(b) and 146.87(a)(1) through (3).
    (d) Definitions. The following definitions apply to this subpart. 
To the extent that these definitions conflict with those in Sec.  146.3 
these definitions govern:
    Area of review means the region surrounding the geologic 
sequestration project that may be impacted by the injection activity. 
The area of review is based on computational modeling that accounts for 
the physical and chemical properties of all phases of the injected 
carbon dioxide stream.
    Carbon dioxide plume means the underground extent, in three 
dimensions, of an injected carbon dioxide stream.
    Carbon dioxide stream means carbon dioxide that has been captured 
from an emission source (e.g., a power plant), plus incidental 
associated substances derived from the source materials and the capture 
process, and any substances added to the stream to enable or improve 
the injection process. This subpart does not apply to any carbon 
dioxide stream that meets the definition of a hazardous waste under 40 
CFR part 261.
    Confining zone means a geologic formation, group of formations, or 
part of a formation stratigraphically overlying the injection zone that 
acts as a barrier to fluid movement.
    Corrective action means the use of Director approved methods to 
assure that wells within the area of review do not serve as conduits 
for the movement of fluids into underground sources of drinking water 
(USDW).
    Geologic sequestration means the long-term containment of a 
gaseous, liquid or supercritical carbon dioxide stream in subsurface 
geologic formations. This term does not apply to its capture or 
transport.
    Geologic sequestration project means an injection well or wells 
used to emplace a carbon dioxide stream beneath the lowermost formation 
containing a USDW. It includes the subsurface three-dimensional extent 
of the carbon dioxide plume, associated pressure front, and displaced 
brine, as well as the surface area above that delineated region.
    Injection zone means a geologic formation, group of formations, or 
part of a formation that is of sufficient areal extent, thickness, 
porosity, and permeability to receive carbon dioxide through a well or 
wells associated with a geologic sequestration project.
    Post-injection site care means appropriate monitoring and other 
actions (including corrective action) needed following cessation of 
injection to assure that USDWs are not endangered as required under 
Sec.  146.93.
    Pressure front means the zone of elevated pressure that is created 
by the injection of carbon dioxide into the subsurface. For the 
purposes of this subpart, the pressure front of a carbon dioxide plume 
refers to a zone where there is a pressure differential sufficient to 
cause the movement of injected fluids or formation fluids into a USDW.
    Site closure the point/time, as determined by the Director 
following the requirements under Sec.  146.93, at which the owner or 
operator of a GS site is released from post-injection site care 
responsibilities.
    Transmissive fault or fracture means a fault or fracture that has 
sufficient permeability and vertical extent to allow fluids to move 
between formations.

[[Page 43536]]

Sec.  146.82  Required Class VI permit information.

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


Sec.  146.83  Minimum criteria for siting.

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


Sec.  146.84  Area of review and corrective action.

    (a) The area of review is the region surrounding the geologic 
sequestration project that may be impacted by the injection activity. 
The area of review is based on computational modeling that accounts for 
the physical and chemical properties of all phases of the injected 
carbon dioxide stream.
    (b) The owner or operator of a Class VI well must prepare, 
maintain, and comply with a plan to delineate the area of review for a 
proposed geologic sequestration project, periodically reevaluate the 
delineation, and perform corrective action that meets the requirements 
of this section and is acceptable to the Director. As a part of the 
permit application for approval by the Director, the owner or operator 
must submit an area of review and corrective action plan that includes 
the following information:
    (1) The method for delineating the area of review that meets the

[[Page 43537]]

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


Sec.  146.85  Financial responsibility.

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


Sec.  146.86  Injection well construction requirements.

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

[[Page 43538]]

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


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

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


Sec.  146.88  Injection well operating requirements.

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

[[Page 43539]]

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


Sec.  146.89  Mechanical integrity.

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


Sec.  146.90  Testing and monitoring requirements.

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

[[Page 43540]]

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


Sec.  146.91  Reporting requirements.

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


Sec.  146.92  Injection well plugging.

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


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

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

[[Page 43541]]

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


Sec.  146.94  Emergency and remedial response.

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

 [FR Doc. E8-16626 Filed 7-24-08; 8:45 am]

BILLING CODE 6560-50-P
