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

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 (CO

2

) Geologic Sequestration (GS) Wells

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

EPA is proposing Federal requirements under the Safe Drinking Water Act (SDWA) for underground injection of carbon dioxide (CO

2

) for the purpose of geologic sequestration (GS). GS is one of a portfolio of options that could be deployed to reduce CO

2

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 CO

2

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 CO

2

injection for GS. If finalized, this proposal would help ensure consistency in permitting underground injection of CO

2

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 CO

2

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 CO

2

into the subsurface for the purposes of GS. Regulated categories and entities would include, but are not limited to, the following:

Category

Examples of regulated entities

Private

Operators of CO

2

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

CaCO

3

Calcium Carbonate

CAA Clean Air Act

CCS Carbon Capture and Storage

CERCLA Comprehensive Environmental Response, Compensation, and Liability Act

CO

2

Carbon Dioxide

CSLF Carbon Sequestration Leadership Forum

DOE Department of Energy

ECBM Enhanced Coal Bed Methane

EFAB Environmental Finance Advisory Board

EGR Enhanced Gas Recovery

EM Electromagnetic

EOR Enhanced Oil Recovery

EPA Environmental Protection Agency

ERT Electrical Resistance Tomography

FACA Federal Advisory Committee Act

GHGs Greenhouse Gases

GS Geologic Sequestration

GWPC Ground Water Protection Council

H

2

S Hydrogen Sulfide

ICR Information Collection Request

IEA International Energy Agency

IOGCC Interstate Oil and Gas Compact Commission

IPCC Intergovernmental Panel on Climate Change

LBNL Lawrence Berkeley National Laboratory

LIDAR Light Detection and Ranging

MI Mechanical Integrity

MIT Mechanical Integrity Test

MMT Million Metric Tons

MMV Monitoring, Measurement, and Verification

MPRSA Marine Protection, Research, and Sanctuaries Act

NDWAC National Drinking Water Advisory Council

NETL National Energy Technology Laboratory

NGOs Non-Governmental Organizations

NODA Notice of Data Availability

NPDWR National Primary Drinking Water Regulations

NTTAA National Technology Transfer and Advancement Act

OIRA Office of Information and Regulatory Affairs

OMB Office of Management and Budget

O&M Operation and Maintenance

ORD Office of Research and Development

NO

X

Nitrogen Oxides

PFC Perfluorocarbon

PNNL Pacific Northwest National Laboratory

PRA Paperwork Reduction Act

PVT Pressure-Volume-Temperature

PWS Public Water Supply

RA Regulatory Alternative

RCRA Resource Conservation and Recovery Act

RCSP Regional Carbon Sequestration Partnerships

RFA Regulatory Flexibility Act

SACROC Scurry Area Canyon Reef Operators Committee

SBREFA Small Business Regulatory Enforcement Fairness Act

SDWA Safe Drinking Water Act

SO

X

Sulfur Oxides

TDS Total Dissolved Solids

UIC Underground Injection Control

UICPG#83 Underground Injection Control Program Guidance # 83

UMRA Unfunded Mandates Reform Act

USDW Underground Source of Drinking Water

VEF Vulnerability Evaluation Framework

Definitions

Annulus:

The space between the well casing and the wall of the bore hole; the space between concentric strings of casing; space between casing and tubing.

Area of review (AoR):

The region surrounding the geologic sequestration project that may be impacted by the injection activity. The area of review is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream.

Ball valve:

A valve consisting of a hole drilled through a ball placed in between two seals. The valve is closed when the ball is rotated in the seals so the flow path no longer aligns with the well casing.

Buoyancy:

Upward force on one phase (e.g., a fluid) produced by the surrounding fluid (e.g., a liquid or a gas) in which it is fully or partially immersed, caused by differences in pressure or density.

Capillary force:

Adhesive force that holds a fluid in a capillary or a pore space. Capillary force is a function of the properties of the fluid, and surface and dimensions of the space. If the attraction between the fluid and surface is greater than the interaction of fluid molecules, the fluid will be held in place.

Caprock:

See

confining zone.

Carbon Capture and Storage (CCS):

The process of capturing CO

2

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

(CO

2

)

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., CO

2

) 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 CO

2

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 CO

2

) 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 CO

2

when acceptable operating parameters are exceeded.

Formation or geological formation:

A layer of rock that is made up of a certain type of rock or a combination of types.

Geologic sequestration (GS):

The long-term containment of a gaseous, liquid or supercritical carbon dioxide stream in

subsurface geologic formations. This term does not apply to its capture or transport.

Geologic sequestration project:

An injection well or wells used to emplace a CO

2

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 CO

2

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 CO

2

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). CO

2

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 § 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 CO

2

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 CO

2

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 § 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 °C for CO

2

) and critical pressure (73.8 bar for CO

2

). 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 CO

2

is sequestered in the subsurface. Physical trapping occurs when buoyant CO

2

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 CO

2

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, CO

2

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 CO

2

?

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

2

?

C. Who Implements the UIC Program?

D. What Are the Risks Associated With CO

2

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 CO

2

?

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

H. What Are the Target Geologic Formations for GS of CO

2

?

I. Is Injected CO

2

Considered a Hazardous Waste Under RCRA?

J. Is Injected CO

2

Considered a Hazardous Substance Under CERCLA?

III. Proposed Regulatory Alternative

A. Proposed Alternative

1. Proposed Geologic Siting Requirements

2. Proposed Area of Review and Corrective Action Requirements

3. Proposed Injection Well Construction Requirements

4. Proposed Injection Well Operating Requirements

5. Proposed Mechanical Integrity Testing Requirements

6. Proposed Plume and Pressure Front Monitoring Requirements

7. Proposed Recordkeeping and Reporting Requirements

8. Proposed Well Plugging, Post-Injection Site Care, and Site Closure Requirements

9. Proposed Financial Responsibility and Long-term Care Requirements

B. Adaptive Approach

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

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

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

VII. Cost Analysis

A. National Benefits and Costs of the Proposed Rule

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

C. Conclusions

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

B. Paperwork Reduction Act (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act (UMRA)

E. Executive Order 13132: Federalism

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

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

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

I. National Technology Transfer and Advancement Act

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

IX. References

II. What Is EPA Proposing?

EPA is proposing to create a new category of injection well under its existing Underground Injection Control (UIC) Program with new Federal requirements to allow for permitting of the injection of CO

2

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 CO

2

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 CO

2

; rather, this proposal focuses on underground injection of CO

2

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 CO

2

; 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 CO

2

under the Clean Air Act (CAA) in this proposed rulemaking.

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

2

?

1. What Is Geologic Sequestration (GS)?

GS is the process of injecting CO

2

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.

CO

2

is first captured from fossil-fueled power plants or other emission sources. To transport captured CO

2

for GS, operators typically compress CO

2

to convert it from a gaseous state to a supercritical fluid (IPCC, 2005). CO

2

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 CO

2

is delivered to the sequestration site, typically by pipeline, or alternatively using tanker trucks or ships (WRI, 2007).

The CO

2

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 CO

2

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 CO

2

in a supercritical state.

When injected in an appropriate receiving formation, CO

2

is sequestered by a combination of trapping mechanisms, including physical and geochemical processes. Physical trapping occurs when the relatively buoyant CO

2

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 CO

2

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 CO

2

will dissolve from the pure fluid phase into native ground water and hydrocarbons. Preferential sorption occurs when CO

2

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 CO

2

and minerals in the formation lead to the precipitation of solid carbonate minerals (IPCC, 2005). The timeframe over which CO

2

will be trapped by these mechanisms depends on properties of the receiving formation and the injected CO

2

stream. Current research is focused on better understanding these mechanisms and the time required to trap CO

2

under various conditions.

The effectiveness of physical CO

2

trapping is demonstrated by natural analogs worldwide in a range of geologic settings, where CO

2

has remained trapped for millions of years. For example, CO

2

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 °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 CO

2

are expected unless energy producers reduce the CO

2

emissions to the atmosphere. The

capture and storage of CO

2

would enable the continued use of coal in a manner that greatly reduces the associated CO

2

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 CO

2

. Theoretically, this capacity could be large enough to store a thousand years of CO

2

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 CO

2

for hundreds, if not thousands of years. CCS technologies could potentially represent a significant percentage of the cumulative effort for reducing CO

2

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 CO

2

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 CO

2

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 CO

2

?

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 CO

2

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. CO

2

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 CO

2

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 CO

2

. 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 CO

2

can be found in the docket.

Other authorities:

Today's proposal applies to injection wells in the U.S. including those in State territorial

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

C. Who Implements the UIC Program?

Section 1422 of the SDWA provides that States, Territories and federally recognized Tribes may apply to EPA for primary enforcement responsibility to administer the UIC program; those governments receiving such authority are referred to as “Primacy States.” Section 1422 requires Primacy States to meet EPA's minimum Federal requirements for UIC programs, including construction, operating, monitoring and testing, reporting, and closure requirements for well owners or operators. Where States, Territories, and Tribes do not seek this responsibility or fail to demonstrate that they meet EPA's minimum requirements, EPA is required to implement a UIC program for them by regulation.

Additionally, section 1425 allows States, Territories, and Tribes seeking primacy for Class II wells to demonstrate that their existing standards are effective in preventing endangerment of USDWs. These programs must include requirements for permitting, enforcement, inspection, monitoring, recordkeeping, and reporting that demonstrate the effectiveness of their requirements.

Thirty-three States and three Territories currently have primacy to implement the UIC program. EPA shares implementation responsibility with seven States and directly implements the UIC Program for all well classes in 10 states, two Territories, the District of Columbia, and all Tribes. At the time of this proposal, no Tribes have been approved for primacy for the UIC Program. However, at the time of this published notice, Fort Peck Assiniboine and Sioux Tribes in EPA Region 8 and the Navajo Nation in EPA Region 9 have pending primacy applications.

Although EPA believes that the most effective approach for the comprehensive management of CO

2

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 CO

2

. 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 CO

2

and how these efforts might be used to better inform a final Federal rulemaking.

D. What Are the Risks Associated With CO

2

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 CO

2

injection and storage. Risks to USDWs from improperly managed GS projects can include CO

2

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 CO

2

to USDWs in today's proposal will likely also prevent the migration of CO

2

to the surface. However, regulating such surface/atmospheric releases of CO

2

are outside the scope of this proposal and SDWA authority. A more detailed discussion follows.

Potential USDW Impacts

Injected CO

2

is likely to come in contact with water in the formation fluids of the geologic formations into which it is injected. When CO

2

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). CO

2

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 CO

2

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 CO

2

that could be injected, there may be a risk that co-contaminants in the CO

2

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 CO

2

at high pressure could induce fracturing or could open existing fractures, thereby increasing movement through the caprock and enabling CO

2

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 CO

2

to the atmosphere, resulting in the potential to impact human health and surrounding ecosystems under certain circumstances. While CO

2

is present normally in the atmosphere, at very high concentrations and with prolonged exposure, CO

2

can be an asphyxiant. In addition, direct exposure to elevated levels of CO

2

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 CO

2

release.

EPA considers that risk of asphyxiation and other chronic and

acute health effects from airborne exposure resulting from CO

2

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 CO

2

.

EPA collected information on the use of CO

2

injection in the oil and gas industry which has decades of experience in drilling through highly pressurized formations and injecting CO

2

for the purpose of enhanced recovery. Internationally, CO

2

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 CO

2

such that asphyxiation would have been possible.

However, some CO

2

releases from injection activity have been documented. An example of a significant CO

2

leak occurred at Crystal Geyser, Utah. CO

2

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 CO

2

annually. Studies indicated that within a few meters of the well, CO

2

concentrations were below levels that could adversely affect human health (Lewicki

et al.

, 2006).

EPA also evaluated the occurrence of natural discharges of CO

2

to determine whether such releases could be caused by CO

2

injection or whether injection could result in release of similar magnitudes. Although natural underground CO

2

reservoirs exist throughout the world in volcanically active areas, there are very few instances of rapid discharge of large amounts of CO

2

to the surface (Lewicki

et al.

, 2006). Unusually large and rapid releases of CO

2

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 CO

2

to slowly accumulate at the bottom of the lakes over many years. Large volumes of CO

2

escaped during an abrupt lake turnover, possibly prompted by volcanic activity.

While lake turnover can bring CO

2

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 CO

2

beneath many layers of rock with a well-defined geologic confining system. Even if a geologic confining system were compromised, any migration of CO

2

towards the surface would not be analogous to a limnic eruption. Pathways for CO

2

leakage from geologic storage reservoirs are generally conductive faults or fractures. In some cases CO

2

may spread diffusely through overlying rocks and soils (Lewicki

et al.

, 2006). None of these conditions is a likely conduit for release of CO

2

on the scale of the releases at Lakes Nyos and Monoun.

Ecosystem:

Improperly operated CO

2

injection activities resulting in a release of CO

2

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 CO

2

exposure levels. Surface-dwelling animals, including mammals and birds, could be affected similarly to humans when directly exposed to elevated levels of CO

2

. 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 CO

2

for photosynthesis, could also be adversely affected by elevated CO

2

levels in the soil because the CO

2

will inhibit respiration (Vodnik

et al.

, 2006). Soil acidity changes resulting from increased CO

2

concentrations may adversely impact both plant (McGee and Gerlach, 1998) and soil dwelling organisms (Benson

et al.

, 2002). Elevated CO

2

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 CO

2

injection activities is minimal.

Seismic events:

Improperly operated injection of CO

2

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 CO

2

injection is addressed before the commencement of full-scale GS projects. While preventing releases of CO

2

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 CO

2

remains in the confining formations. The measures outlined in today's proposed rulemaking to prevent endangerment of USDWs may also prevent migration of CO

2

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 CO

2

Injection

EPA's UIC regulations prohibit injection wells from causing “the movement of fluid containing any contaminant into an underground source of drinking water, if the presence of that contaminant may cause a violation of any primary drinking water regulation * * * or may otherwise adversely affect the health of persons” (40 CFR 144.12(a)). The federal UIC Program has been implemented since 1980 and has responsibility for managing over 800,000 injection wells. The programmatic components of the UIC Program are designed to prevent fluid movement into USDWs by addressing the potential pathways through which injected fluids can migrate into USDWs. These programmatic components are described in general below:

•

Siting:

EPA requires injection wells to be sited to inject into a zone capable

of storing the fluid, and to inject below a confining system that is free of known open faults or fractures that could allow upward fluid movement that endangers USDWs.

•

Area of Review (AoR) and Corrective Action:

The Agency requires examination of both the vertical and horizontal extent of the area that will potentially be influenced by injection and storage activities and identification of all artificial penetrations in the area that may act as conduits for fluid movement into USDWs (e.g., active and abandoned wells) and, as needed, perform corrective action to these open wells (i.e., artificial penetrations).

•

Well Construction:

EPA requires injection wells to be constructed using well materials and cements that can withstand injection of fluids over the anticipated life span of the project.

•

Operation:

Injection pressures must be monitored so that fractures that could serve as fluid movement conduits are neither propagated into the layers in which fluids are injected or initiated in the confining systems above.

•

Mechanical Integrity Testing (MIT):

The integrity of the injection well system must be monitored at an appropriate frequency to provide assurance that the injection well is operating as intended and is free of significant leaks and fluid movement in the well bore.

•

Monitoring:

Owners or operators must monitor the injection activity using available technologies to verify the location of the injected fluid, the pressure front, and demonstrate that injected fluids are confined to intended storage zones (and, therefore, injection activities are protective of USDWs).

•

Well Plugging and Post-Injection Site Care:

At the end of the injection project, EPA requires injection wells to be plugged in a manner that ensures that these wells will not serve as conduits for future fluid movement into USDWs. Additionally, owners or operators must monitor injection wells to ensure fluids in the storage zone do not pose an endangerment to USDWs.

Today's proposal builds upon these longstanding UIC programmatic components and tailors them based on the current state of knowledge about the injection of CO

2

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 CO

2

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 CO

2

injection to USDWs to determine how best to tailor the existing UIC regulations to address the buoyant and viscous properties of CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

in geologic formations.

3. Tracking the Results of CO

2

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 CO

2

emissions, 97 percent of industrial CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

, and the Massachusetts Institute of Technology, which has a CCS program emphasizing safe and effective future use of coal as a prime energy source.

EPA is also monitoring the progress of international GS efforts. Three projects of note are underway in the North Sea,

Algeria, and Canada, whose results are being used to inform today's proposal.

The Sleipner Project, located off the Norwegian coast in the North Sea, is the first commercial scale GS project into a saline formation. Approximately 1 Million tones (Mt) CO

2

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 CO

2

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 CO

2

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 CO

2

storage project in a gas reservoir. CO

2

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 CO

2

have been injected annually since April 2004 and it is estimated that 17 Mt CO

2

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 CO

2

produced at a coal gasification plant in Beulah, ND is piped to Weyburn in southeastern Saskatchewan for EOR. Approximately 1.5 Mt CO

2

are injected annually via a combination of vertical and horizontal injection wells. It is expected that 20 Mt CO

2

will be stored in the field over the 20 to 25 year life of the CO

2

-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 CO

2

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)/CO

2

sequestration project; the CO

2

SINK project in Ketzin, Germany (a sandstone saline formation); and testing of CO

2

GS in the Deccan Trap basalts of India.

4. Identifying Technical and Regulatory Issues Associated With CO

2

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 CO

2

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 CO

2

-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 CO

2

to discuss and formulate the questions related to CO

2

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 CO

2

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 CO

2

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 CO

2

Storage, participants discussed the development of a risk assessment framework to identify potential risks related to GS of CO

2

and to consider relevant field experience that could be applicable to injection and long-term storage of CO

2

. 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 CO

2

storage reservoir; a discussion of areas of new research and data needs to improve the application of modeling and reservoir simulation for carbon storage.

Summaries of the workshops described above are available on EPA's Web site, at

http://www.epa.gov/safewater/uic/wells_sequestration.html.

5. Stakeholder Coordination and Outreach

Stakeholder participation is an important component of today's proposed rulemaking. EPA held public meetings to discuss EPA's rulemaking approach, met with State and Tribal representatives, and consulted with other stakeholder groups including non-governmental organizations (NGOs), to gain an understanding of stakeholder concerns.

Public Meetings:

EPA conducted two public stakeholder workshops with participants from industry, environmental groups, utilities, academia, States, and the general public. These workshops were held in December 2007 and February 2008. The December 2007 workshop provided EPA with an opportunity to hear stakeholders' perspectives and concerns. EPA and stakeholders discussed issues including the rulemaking process, existing regulations and regulatory components, statutory authority, GS technology, and technical issues associated with GS. During the February 2008 workshop, EPA provided a comprehensive review of how current UIC program elements could be tailored for the purposes of CO

2

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 CO

2

.

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 CO

2

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 CO

2

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 CO

2

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 CO

2

injection for GS and the operational, technical, and administrative considerations for the advancement and appropriate permitting of this technology. This information will support EPA's final decision on how to regulate GS activities.

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

2

?

EPA is proposing to establish a new class of injection well for GS projects because CO

2

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?

CO

2

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 CO

2

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 CO

2

. 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 CO

2

, provided he/she is able to make a determination that these wells would not endanger USDWs. Although CO

2

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 CO

2

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 CO

2

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 CO

2

. 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 CO

2

?

A range of geologic formations is being assessed as potential target formations for receiving and sequestering CO

2

. 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 CO

2

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 CO

2

. 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 CO

2

storage capacity in the U.S. and Canada. Because many of these reservoirs have trapped liquid and gaseous hydrocarbon resources for

millions of years, EPA believes that they can also be used to sequester CO

2

. 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 CO

2

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 CO

2

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 CO

2

injection will differ from those of traditional EOR/EGR operations. The American Petroleum Institute (API) estimates that over 0.6 gigatons (Gt) of CO

2

have been injected for EOR/EGR operations to date and a large percentage of this CO

2

is recovered through production (causing a pressure decrease in the reservoir) (Meyer, 2007). However, DOE estimates that over 90 Gt CO

2

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 CO

2

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 CO

2

, 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 CO

2

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 CO

2

relative to the methane that is naturally found on the surfaces of coal. When CO

2

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 CO

2

molecules are adsorbed. This process effectively “locks” the CO

2

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 CO

2

adsorption to coal has not been proven and the chemical reactions of supercritical CO

2

within coal formations are not well understood. In addition, coals swell as CO

2

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 CO

2

ECBM projects, and ECBM with simultaneous CO

2

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 CO

2

remaining in a gaseous state, which can limit the amount of CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

storage options (IPCC, 2005). CO

2

storage in organic-rich shales, to which CO

2

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 CO

2

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 CO

2

stream a hazardous waste. The composition of the captured CO

2

stream will depend on the source, the flue gas scrubbing technology for removing pollutants, additives, and the CO

2

capture technology. In most cases, the captured CO

2

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 CO

2

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 CO

2

is hazardous under RCRA. Owners or operators will need to characterize their CO

2

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 CO

2

, 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 CO

2

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 CO

2

stream.

J. Is Injected CO

2

Considered a Hazardous Substance Under CERCLA?

The Comprehensive Environmental Response, Compensation, and Liability

Act (CERCLA), also more commonly known as Superfund, is the law that provides broad federal authority to clean up releases or threatened releases of hazardous substances that may endanger human health or the environment. CERCLA references four other environmental laws to designate more than 800 substances as hazardous and to identify many more as potentially hazardous due to their characteristics and the circumstances of their release. It allows EPA to clean up sites contaminated with hazardous substances and seek compensation from responsible parties, or compel responsible parties to perform cleanups themselves. A responsible party may be able to avoid liability through several enumerated defenses, including that the release constituted a “federally permitted release” as defined in CERCLA, 42 U.S.C. 9601(10).

While CO

2

itself is not listed as a hazardous substance under CERCLA, the CO

2

stream may contain other substances such as mercury that are hazardous substances or the constituents of the CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

. 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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

storage. While this option includes flexibility for permit authorities to add requirements, EPA cannot be certain that the necessary adjustments would be made.

Alternative 4 (Highly Specific Requirements Approach) lacks the flexibility for incorporating and adapting to evolving GS technologies and provides no clear additional

benefits beyond alternative 3 for USDW protection, therefore, EPA did not select this alternative.

1. Proposed Geologic Siting Requirements

Existing UIC requirements for siting injection wells include identification of geologic formations suitable to receive the injected fluids and confine them such that they are isolated below the lowermost USDWs, minimizing the potential for endangerment. While initial assessments indicate there are many geologic formations in the U.S. that can potentially receive injected CO

2

, not all can serve as adequate CO

2

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 CO

2

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 CO

2

without fracturing and extensive enough to receive the anticipated total volumes of injected CO

2

. 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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

injection. Estimates of maximum sustainable fluid pressures in CO

2

storage sites are primarily based on predicted changes of effective stresses in rocks during CO

2

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. CO

2

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 CO

2

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 CO

2

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 CO

2

plume).

Today's proposal would provide the Director the discretion to require the owner or operator to identify and characterize additional confining and containment zones above the primary

(i.e., lowermost) confining zone that could further impede vertical fluid movement and allow for pressure dissipation. These layers could provide additional sites for monitoring, mitigation, and remediation. Today's proposal would not require that these additional zones be identified for all GS sites because their absence does not necessarily indicate inappropriateness of a GS site. However, if such zones are present, information about their characteristics can provide inputs for predictive models, identify appropriate monitoring locations, and improve public confidence in and acceptance of a proposed GS site. EPA specifically seeks comment on the merits of identifying these additional zones.

2. Proposed Area of Review and Corrective Action Requirements

Delineating the Area of Review:

Under the UIC program, EPA established an evaluative process to determine that there are no features near the well such as faults, fractures or artificial penetrations, where significant amounts of injected fluid could move into a USDW or displace native fluids into USDWs. Current UIC regulations require that the owner or operator define the Area of Review (AoR), within which the owner or operator must identify all penetrations (regardless of property ownership) in the confining zone and the injection zone and determine whether they have been properly completed or plugged. The AoR determination is integral to the determination of geologic site suitability because it requires the delineation of the storage operation and an identification and evaluation of any penetrations that could result in the endangerment of USDWs (40 CFR 146.6).

For Class I, II, and III injection wells, Federal UIC regulations require that the AoR be defined as either a fixed radius of

1/4

mile surrounding the well (or wells, for an area permit) or an area above the injected fluid and pressure front determined by a computational model. For Class I hazardous waste injection wells, the AoR is defined as a radius of two (2) miles around the well or an area defined based on the calculated cone of pressure influence, whichever is larger.

It is generally agreed that over time, the CO

2

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 CO

2

behavior in the subsurface may produce a non-circular AoR. It is also possible that multiple owners or operators will be injecting CO

2

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 CO

2

, 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 CO

2

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 CO

2

Movement and Reservoir Pressure:

Computational models used to delineate the AoR consider the buoyant nature and specific properties of separate phases of the injected CO

2

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 CO

2

, co-injectates, and compounds mobilized due to injection. In order to provide guidance related to computational modeling of CO

2

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 CO

2

injection (USEPA, 2008d).

Model results provide predictions of CO

2

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 CO

2

leakage and other impacts to USDWs, and to design remediation strategies. Importantly, models can be used to predict CO

2

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, CO

2

in the subsurface. The existing computational codes used to create multiphase models vary substantially in complexity. For example, available codes differ in what processes (e.g., changes of state, chemical reactions) may be included in simulations. As model complexity increases, so does the computational power necessary to use the model, as well as the amount and type of data needed to properly instruct model development. However, more complex models, when properly used, have the potential to provide a more accurate representation of the storage project.

Multiphase models are developed based on a specified set of conditions, such as the formation's geological structure and injection scenario, and inputs describing these conditions are included in an appropriate computational code. Properties of the formation (e.g., permeability, porosity, reservoir entry pressure) and fluids present (e.g., solubility, mass-transfer coefficients), are described by model parameters, the independent variables in the model governing equations that may be constant throughout the domain or vary in space and time. Model predictions depend largely on the

values of key parameters. Often these parameter values are estimated or averaged from several data sources.

Models used for GS sites should be based on accepted science and should be validated. In some cases, owners or operators may choose to use proprietary models (i.e., not available for free to the general public). EPA is aware that the use of proprietary codes may prevent full evaluation of model results (e.g., NRC, 2007). Several popular codes in the petroleum-reservoir engineering discipline are proprietary and owners or operators of particular sites may prefer to use these codes as they have previous experience with them, and they have been used in peer-reviewed studies to model CO

2

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 CO

2

. 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 CO

2

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 CO

2

injection. At the Technical Workshop on Geological Considerations and AoR Studies, participants generally concluded that the reaction of the CO

2

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 CO

2

in the subsurface, particularly the ultimate extent of a CO

2

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 CO

2

plume and area of elevated pressure; however, the near-term predictions (e.g., over the subsequent 10 years) would have the highest degree of certainty and could be the basis of corrective action. Re-running the models would allow refinement to the AoR delineation based on real-world conditions and monitoring results, and thus increase confidence in the modeled predictions. The revised model predictions would also be used to identify monitoring sites so that monitoring would occur in any areas subject to the greatest potential risk.

EPA seeks comment on requiring the reevaluation of the site AoR on a periodic basis, under what conditions the AoR should be reevaluated, and the appropriateness of a 10 year minimum fixed frequency for AoR reevaluation.

Phased Corrective Action:

In the UIC program, corrective action is typically

performed on all wells in the AoR in advance of the injection project. Today's proposal recognizes that this may not always be appropriate for GS projects. The AoR for a GS site may be quite large, requiring considerable time and resources to perform corrective action on all wells that may eventually be affected by the GS project over the course of decades of injection. In addition, if the periodic reevaluations of the AoR indicate that the AoR has grown or shifted to areas not originally included, additional wells may need to be identified for potential corrective action.

Today's proposal would give the Director the discretion to allow owners or operators to perform corrective action on an iterative, phased basis over the operational life of a GS project. Prior to injection, the owner or operator would identify all wells penetrating the confining or injection zone within the site AoR. However, the owner or operator may limit pre-injection corrective action to those wells in the portion of the AoR that would be intersected by the CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

injection wells are based on existing knowledge and practices from the oil and gas industry.

A typical well is constructed by placing multiple strings of high strength steel alloy or fiberglass concentric pipe and tubing into a drilled wellbore. Typically, the first step in well construction is the drilling of a large borehole (e.g., 10″ to 30″) through the base of the lowermost USDW. A large diameter pipe, termed surface casing, is then placed in the wellbore to protect shallow aquifers or underground sources of drinking water during the drilling and injection phases. This casing is usually cemented by circulating cement between the outside of the surface casing and the side of the borehole to ensure that the wellbore is stabilized, that the casing is completely sealed to the rock of the wellbore, and that the geologic formations are isolated from each other and the surface.

Next, a smaller diameter wellbore (e.g., 7″ to 15″) is drilled further downwards, into the injection zone, and

a smaller diameter pipe, usually designated as the long-string casing, is run into the hole. Similar to the surface casing, the long-string casing is cemented in place to the borehole by circulating cement from the bottom back up to the surface casing, filling the gap between the outside of the long-string casing and the wellbore. This cementing process again ensures that rock formations are isolated and no fluid movement occurs between formations.

Depending on the depth to the injection formation, additional strings of casing may be necessary, but in each case, these casings are engineered and designed to withstand internal and external pressures at depth. The final result is multiple barriers of cement and casing 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 CO

2

, today's proposal includes enhancements to typical deep well construction procedures to provide additional barriers to CO

2

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 CO

2

plume, as vertical channeling through high permeability regions is reduced. Increasing the sweep results in enhanced residual-phase CO

2

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 CO

2

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 CO

2

(IPCC, 2005).

CO

2

mixed with water or impurities (NO

X

, SO

X

and H

2

S) 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 CO

2

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 (CaCO

3

). 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 CO

2

and well cement, but do not show such severe corrosion. Cement samples from

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 CO

2

production well in a natural CO

2

reservoir in Colorado exposed to a CO

2

-water environment for 30 years (Crow

et al.,

2008). The study found considerable reactions between the CO

2

and cement, and CO

2

migration up the wellbore along the cement-formation interface. However, the cement alteration was not significant enough to enable CO

2

migration through the cement itself and the distance of CO

2

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 CO

2

-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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

may adsorb and to extract methane. These hydraulic fracturing operations are used to

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 CO

2

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 CO

2

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 CO

2

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.

CO

2

reacts with water to become acidic, potentially accelerating corrosion of well materials. The CO

2

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 CO

2

in a supercritical, liquid state after it is injected, as some well operators may choose to inject the CO

2

as a gas. If the trapping mechanism is sufficiently protective, the injected CO

2

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 CO

2

. The geothermal gradient and weight of the fluid and rock layers above this target depth would maintain CO

2

at a sufficiently high pressure to keep it in a supercritical, liquid state. Storing CO

2

at supercritical pressure would allow storage of greater volumes and thereby increase available underground storage capacity. Additionally, storing CO

2

in a supercritical, liquid state may prevent the frequency of well mechanical integrity failure. When supercritical CO

2

is injected into shallow formations where pressures are not high enough to

maintain its supercritical state, it will revert to a gas. The expansion of gaseous CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

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 CO

2

and the large volumes that are expected to be injected may warrant improved leak detection for GS wells. Detection of leakage of injected CO

2

at the surface would indicate potential endangerment to USDWs. Additionally, if tracers are

used for CO

2

GS projects, they may also help owners or operators to infer geochemical processes caused by CO

2

(e.g., dissolution or precipitation of calcium carbonate) that may pose risks.

Gaseous CO

2

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 CO

2

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 CO

2

(e.g., anthropogenic or biological). Panelists also addressed the potential utility of perfluorocarbon (PFC) and other inert tracers in detecting CO

2

leakage. According to some researchers, PFCs are conservative and will remain with the CO

2

. 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 CO

2

injections, making it feasible to detect if a leak is transient versus long-term in nature.

There may be potential benefits of tracers for CO

2

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 CO

2

, 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 CO

2

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 CO

2

, 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 owner

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