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

Federal RegisterDec 10, 2010

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ENVIRONMENTAL PROTECTION AGENCY

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

[EPA-HQ-OW-2008-0390 FRL-9232-7]

RIN 2040-AE98

Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO

) Geologic Sequestration (GS) Wells

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Final rule.

SUMMARY:

This action finalizes minimum Federal requirements under the Safe Drinking Water Act (SDWA) for underground injection of carbon dioxide (CO

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

emissions to the atmosphere and help to mitigate climate change. This final rule applies to owners or operators of wells that will be used to inject CO

into the subsurface for the purpose of long-term storage. It establishes a new class of well, Class VI, and sets minimum technical criteria for the permitting, geologic site characterization, area of review (AoR) and corrective action, financial responsibility, well construction, operation, mechanical integrity testing (MIT), monitoring, well plugging, post-injection site care (PISC), and site closure of Class VI wells for the purposes of protecting underground sources of drinking water (USDWs). The elements of this rulemaking are based on the existing Underground Injection Control (UIC) regulatory framework, with modifications to address the unique nature of CO

injection for GS. This rule will help ensure consistency in permitting underground injection of CO

at GS operations across the United States and provide requirements to prevent endangerment of USDWs in anticipation of the eventual use of GS to reduce CO

emissions to the atmosphere and to mitigate climate change.

DATES:

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

ADDRESSES:

EPA has established a docket for this action under Docket ID No. EPA-HQ-OW-2008-0390. All documents in the docket are listed on the

http://www.regulations.gov

Web site. Although listed in the index, some information is not publicly available,

e.g.,

CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through

http://www.regulations.gov

or in hard copy at the OW Docket, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the OW Docket is (202) 566-2426.

FOR FURTHER INFORMATION CONTACT:

Mary Rose (Molly) Bayer, Underground Injection Control Program, Drinking Water Protection Division, Office of Ground Water and Drinking Water (MC-4606M), Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone number: (202) 564-1981; fax number: (202) 564-3756; e-mail address:

bayer.maryrose@epa.gov.

For general information, visit the Underground Injection Control Geologic Sequestration Web site at

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

SUPPLEMENTARY INFORMATION:

I. General Information

This regulation affects owners or operators of injection wells that will be used to inject CO

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

Category

Examples of regulated entities

Private

Owners or Operators of CO

injection wells used for Class VI GS.

Private

Owners or Operators of existing CO

injection wells transitioning from Class I, II, or Class V injection activities to Class VI GS.

This table is not intended to be an exhaustive list; rather it provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is now aware could potentially be regulated by this action. Other types of entities not listed in the table could also be regulated. To determine whether your facility is regulated by this action, you should carefully examine the applicability criteria found at § 146.81 in the rule section of this action. If you have questions regarding the applicability of this action to a particular entity, consult the person listed in the preceding

FOR FURTHER INFORMATION CONTACT

section.

Abbreviations and Acronyms

AoR Area of Review

BLM United States Department of the Interior, Bureau of Land Management

BOEMRE United States Department of the Interior, Bureau of Ocean Energy Management, Regulation and Enforcement

CAA Clean Air Act

CBI Confidential Business Information

CCS Carbon Capture and Storage

CERCLA Comprehensive Environmental Response, Compensation, and Liability Act

Carbon Dioxide

DOE United States Department of Energy

ECBM Enhanced Coal Bed Methane

EFAB Environmental Financial Advisory Board

EGR Enhanced Gas Recovery

EIS Environmental Impact Statement

EISA Energy Independence and Security Act of 2007

EO Executive Order

EOR Enhanced Oil Recovery

EPA United States Environmental Protection Agency

ER Enhanced Recovery

FPR Federally Permitted Releases

GAO General Accountability Office

GHG Greenhouse Gas

GS Geologic Sequestration

Gt CO

Gigatons CO

GWPC Ground Water Protection Council

HHS United States Department of Health and Human Services

ICR Information Collection Request

IOGCC Interstate Oil and Gas Compact Commission

IPCC Intergovernmental Panel on Climate Change

IRS United States Internal Revenue Service

LBNL Lawrence Berkeley National Laboratory

Mg/L Milligrams per liter

MI Mechanical Integrity

MIT Mechanical Integrity Test

MMS United States Department of the Interior, Minerals Management Service

MPRSA Marine Protection, Research, and Sanctuaries Act of 1972

MRA Miscellaneous Receipts Act

MRR Mandatory Reporting Rule

MRV Monitoring, Reporting, and Verification

NAICS North American Industry Classification System

NASA National Aeronautics and Space Administration

NCER National Center for Environmental Research

NDWAC National Drinking Water Advisory Council

NEPA National Environmental Protection Act

NETL National Energy Technology Laboratory

NGO Non-Governmental Organization

NIWG National Indian Work Group

NOAA National Oceanic and Atmospheric Administration

NODA Notice of Data Availability

NOI Notice of Intent

NTC National Tribal Caucus

NTTAA National Technology Transfer and Advancement Act of 1995

NTWC National Tribal Water Council

O&M Operation and Maintenance

OAR Office of Air and Radiation

OCS Outer Continental Shelf

OCSLA Outer Continental Shelf Lands Act

OMB Office of Management and Budget

ORD Office of Research and Development

PBMS Performance Based Measurement System

Pg Petagram

PISC Post-Injection Site Care

PRA Paperwork Reduction Act

PWSS Public Water System Supervision

QASP Quality Assurance and Surveillance Plan

RA Regulatory Alternative

RCRA Resource Conservation and Recovery Act

RCSP Regional Carbon Sequestration Partnership

RFA Regulatory Flexibility Act

RIC Regional Indian Coordinators

SDWA Safe Drinking Water Act

STAR Science To Achieve Results

STC3 State-Tribal Climate Change Council

SWP Southwest Regional Partnership on Carbon Sequestration

TCLP Toxicity Characteristic Leaching Procedure

TDS Total Dissolved Solids

TNW Tangible Net Worth

UIC Underground Injection Control

UICPG#83 Underground Injection Control Program Guidance # 83

UMRA Unfunded Mandates Reform Act

USDW Underground Source of Drinking Water

USGS United States Department of the Interior, United States Geological Survey

WRI World Resources Institute

Definitions

Annulus:

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

Area of review (AoR):

The region surrounding the geologic sequestration project where USDWs may be endangered by the injection activity. The area of review is delineated using computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream and displaced fluids, and is based on available site characterization, monitoring, and operational data as set forth in § 146.84.

Automatic shut-off device:

A valve which closes when a pre-determined pressure or flow value is exceeded. Shut-off devices in injection wells can automatically shut down injection activities preventing an excursion outside of the permitted values.

Ball valve:

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

Biosphere:

The part of the Earth's crust, waters, and atmosphere that supports life.

Buoyancy:

Upward force on one phase (

e.g.,

a fluid) produced by the surrounding fluid (

e.g.,

a liquid or a gas) in which it is fully or partially immersed, caused by differences in pressure or density.

Capillary force:

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

Caprock:

See confining zone.

Carbon dioxide plume:

The extent underground, in three dimensions, of an injected carbon dioxide stream.

Carbon dioxide (CO

)

stream:

Carbon dioxide that has been captured from an emission source (

e.g.,

a power plant), plus incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. This subpart does not apply to any carbon dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261.

Casing:

The pipe material placed inside a drilled hole to prevent the hole from collapsing. The two types of casing in most injection wells are (1) surface casing, the outermost casing that extends from the surface to the base of the lowermost USDW and (2) long-string casing, which extends from the surface to or through the injection zone.

Cement:

Material used to support and seal the well casing to the rock formations exposed in the borehole. Cement also protects the casing from corrosion and prevents movement of injectate up the borehole. The composition of the cement may vary based on the well type and purpose; cement may contain latex, mineral blends, or epoxy.

Confining zone:

A geologic formation, group of formations, or part of a formation stratigraphically overlying the injection zone(s) that acts as barrier to fluid movement. For Class VI wells operating under an injection depth waiver, confining zone means a geologic formation, group of formations, or part of a formation stratigraphically overlying and underlying the injection zone(s).

Corrective action:

The use of Director-approved methods to ensure that wells within the area of review do not serve as conduits for the movement of fluids into USDWs.

Corrosive:

Having the ability to wear away a material by chemical action. Carbon dioxide mixed with water forms carbonic acid, which can corrode well materials.

Dip:

The angle between a planar feature, such as a sedimentary bed or a fault, and the horizontal plane. The dip of subsurface rock layers can provide clues as to whether injected fluids may be contained.

Director:

The person responsible for permitting, implementation, and compliance of the UIC program. For UIC programs administered by EPA, the Director is the EPA Regional Administrator or his/her delegatee; for UIC programs in Primacy States, the Director is the person responsible for permitting, implementation, and compliance of the State, Territorial, or Tribal UIC program.

Ductility:

The ability of a material to sustain stress until it fractures.

Enhanced Coal Bed Methane (ECBM) recovery:

The process of injecting a gas (

e.g.,

) 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

is injected, it adsorbs to the surface of the coal, where it remains trapped or sequestered.

Enhanced Oil or Gas Recovery (EOR/EGR):

Typically, the process of injecting a fluid (

e.g.,

water, brine, or CO

) into an oil or gas bearing formation to recover residual oil or natural gas. The injected fluid thins (decreases the viscosity) and/or displaces extractable oil and gas, which is then available for recovery. This is also used for secondary or tertiary recovery.

Flapper valve:

A valve consisting of a hinged flapper that seals the valve orifice. In Class VI wells, flapper valves can engage to shut off the flow of the CO

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 CO

capture or transport.

Geologic sequestration project:

For the purpose of this regulation, an injection well or wells used to emplace a carbon dioxide stream beneath the lowermost formation containing a USDW; or, wells used for geologic sequestration of carbon dioxide that have been granted a waiver of the injection depth requirements pursuant to requirements

at § 146.95; or, wells used for geologic sequestration of carbon dioxide that have received an expansion to the areal extent of an existing Class II EOR/EGR aquifer exemption pursuant to §§ 146.4 and 144.7(d). It includes the subsurface three-dimensional extent of the carbon dioxide plume, associated area of elevated pressure, and displaced fluids, as well as the surface area above that delineated region.

Geophysical surveys:

The use of geophysical techniques (

e.g.,

seismic, electrical, gravity, or electromagnetic surveys) to characterize subsurface rock formations.

Injectate:

The fluids injected. For the purposes of this rule, this is also known as the CO

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 CO

through a well or wells associated with a geologic sequestration project.

Lithology:

The description of rocks, based on color, mineral composition and grain size.

Mechanical integrity (MI):

The absence of significant leakage within the injection tubing, casing, or packer (known as internal mechanical integrity), or outside of the casing (known as external mechanical integrity).

Mechanical Integrity Test:

A test performed on a well to confirm that a well maintains internal and external mechanical integrity. MITs are a means of measuring the adequacy of the construction of an injection well and a way to detect problems within the well system.

Model:

A representation or simulation of a phenomenon or process that is difficult to observe directly or that occurs over long time frames. Models that support GS can predict the flow of CO

within the subsurface, accounting for the properties and fluid content of the subsurface formations and the effects of injection parameters.

Packer:

A mechanical device that seals the outside of the tubing to the inside of the long string casing, isolating an annular space.

Pinch-out:

A situation where a formation thins to zero thickness.

Pore space:

Open spaces in rock or soil. These are filled with water or other fluids such as brine (

i.e.,

salty fluid). CO

injected into the subsurface can displace pre-existing fluids to occupy some of the pore spaces of the rocks in the injection zone.

Post-injection site care:

Appropriate monitoring and other actions (including corrective action) needed following cessation of injection to ensure that USDWs are not endangered, as required under § 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

plume refers to the zone where there is a pressure differential sufficient to cause the movement of injected fluids or formation fluids into a USDW.

Saline formations:

Subsurface geographically extensive sedimentary rock layers saturated with waters or brines that have a high total dissolved solids (TDS) content (

i.e.,

over 10,000 mg/L TDS).

Site closure:

The point/time, as determined by the Director following the requirements under § 146.93, at which the owner or operator of a GS site is released from post-injection site care responsibilities.

Sorption (absorption, adsorption):

Absorption refers to gases or liquids being incorporated into a material of a different state; adsorption is the adhering of a molecule or molecules to the surface of a different molecule.

Stratigraphic zone (unit):

A layer of rock (or stratum) that is recognized as a unit based on lithology, fossil content, age or other properties.

Supercritical fluid:

A fluid above its critical temperature (31.1°C for CO

) and critical pressure (73.8 bar for CO

). 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

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

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

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

is less viscous than water and brine.

Table of Contents

I. General Information

II. Background

A. Why is EPA taking this regulatory action?

1. What is GS?

2. Why is GS under consideration as a climate change mitigation technology?

3. What are the unique risks to USDWs associated with GS?

B. Under what authority is this rulemaking promulgated?

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

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

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

1. Developing Guidance for Experimental GS Projects

2. Conducting Research

a. Tracking the Results of CO

GS Research Projects

b. Tracking State Regulatory Efforts

c. Conducting Technical Workshops on Issues Associated with CO

3. Conducting Stakeholder Coordination and Outreach

4. Proposed Rulemaking

5. Notice of Data Availability and Request for Comment

F. How Will EPA's Adaptive Rulemaking Approach Incorporate Future Information and Research?

G. How Does This Action Affect UIC Program Implementation?

H. How Does This Rule Affect Existing Injection Wells Under the UIC Program?

III. What is EPA's Final Regulatory Approach?

A. Site Characterization

B. Area of Review (AoR) and Corrective Action

1. AoR Requirements

2. Corrective Action Requirements

C. Injection Well Construction

D. Class VI Injection Depth Waivers and Use of Aquifer Exemptions for GS

1. Proposed Rule

2. Notice of Data Availability and Request for Comment

3. Final Approach

E. Injection Well Operation

F. Testing and Monitoring

1. Testing and Monitoring Plan

2. CO

Stream Analysis

3. Mechanical Integrity Testing (MIT)

4. Corrosion Monitoring

5. Ground Water/Geochemical Monitoring

6. Pressure Fall-Off Testing

7. CO

Plume and Pressure Front Monitoring/Tracking

8. Surface Air/Soil Gas Monitoring

9. Additional Requirements

G. Recordkeeping and Reporting

1. What Information Must Be Provided by the Owner or Operator?

2. How Must Information Be Submitted?

3. What are the Recordkeeping Requirements under This Rule?

H. Well Plugging, Post-Injection Site Care (PISC), and Site Closure

1. Injection Well Plugging

2. Post-Injection Site Care (PISC)

3. Site Closure

I. Financial Responsibility

J. Emergency and Remedial Response

K. Involving the Public in Permitting Decisions

L. Duration of a Class VI Permit

IV. Cost Analysis

A. National Benefits and Costs of the Rule

1. National Benefits Summary

a. Relative Risk Framework—Qualitative Analysis

b. Other Nonquantified Benefits

2. National Cost Summary

a. Cost of the Selected RA

b. Nonquantified Costs and Uncertainties in Cost Estimates

c. Supplementary Costs and Uncertainties in Cost Estimates

B. Comparison of Benefits and Costs of RAs Considered

1. Costs Relative to Benefits; Maximizing Net Social Benefits

2. Cost Effectiveness and Incremental Net Benefits

C. Conclusions

V. Statutory and Executive Order Review

VI. References

II. Background

Today's action finalizes minimum Federal requirements under SDWA for injection of CO

for the purpose of GS. The purpose of the rulemaking is to ensure that GS is conducted in a manner that protects USDWs from endangerment. GS refers to a suite of technologies that can be deployed to reduce CO

emissions to the atmosphere and help mitigate climate change. Due to the large CO

injection volumes anticipated at GS projects, the relative buoyancy of CO

, its mobility within subsurface geologic formations, its corrosivity in the presence of water, and the potential presence of impurities in the captured CO

stream, the Agency has determined that tailored requirements, modeled on the existing UIC regulatory framework, are necessary to manage the unique nature of CO

injection for GS. This final rule applies to owners or operators of wells that will be used to inject CO

into the subsurface for the purpose of GS.

To support today's final regulatory action, EPA proposed

Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO

)

Geologic Sequestration (GS) Wells

(73 FR 43492) on July 25, 2008; and the Agency published a supplemental publication,

Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO

)

Geologic Sequestration (GS) Wells; Notice of Data Availability and Request for Comment

(74 FR 44802) on August 31, 2009. Final Class VI requirements are informed, in part, by comments and information submitted in response to these publications.

Today's rule defines a new class of injection well (Class VI), along with technical criteria that tailor the existing UIC regulatory framework to address the unique nature of CO

injection for GS. It sets minimum technical criteria for Class VI wells to protect USDWs from endangerment, including:

• Site characterization that includes an assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS site to ensure that Class VI wells are located in suitable formations.

• Computational modeling of the AoR for GS projects that accounts for the physical and chemical properties of the injected CO

and is based on available site characterization, monitoring, and operational data.

• Periodic reevaluation of the AoR to incorporate monitoring and operational data and verify that the CO

plume and the associated area of elevated pressure are moving as predicted within the subsurface.

• Well construction using materials that can withstand contact with CO

over the life of the GS project.

• Robust monitoring of the CO

stream, injection pressures, integrity of the injection well, ground water quality and geochemistry, and monitoring of the CO

plume and position of the pressure front throughout injection.

• Comprehensive post-injection monitoring and site care following cessation of injection to show the position of the CO

plume and the associated area of elevated pressure to demonstrate that neither pose an endangerment to USDWs.

• Financial responsibility requirements to ensure that funds will be available for all corrective action, injection well plugging, post-injection site care (PISC), site closure, and emergency and remedial response.

Today's rule will help ensure consistency in permitting underground injection of CO

at GS operations across the United States (US) and provide requirements to prevent endangerment of USDWs in anticipation of the potential role of carbon capture and storage (CCS) in mitigating climate change. Today's action also briefly discusses the relationship between today's rule and other Federal and State activities related to GS and CCS in Sections II.C and D, and E.2.b, and III.F.2.

A. Why is EPA taking this regulatory action?

1. What is GS?

GS is the process of injecting CO

into deep subsurface rock formations for long-term storage. It is part of the process known as CCS.

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

for GS, operators typically compress CO

to convert it from a gaseous state to a supercritical state (IPCC, 2005; IEA, 2008). CO

exists as a supercritical fluid at high pressures, and in this state it exhibits properties of both a liquid and a gas. After capture and compression, the CO

is delivered to the sequestration site, frequently by pipeline, or alternatively using tanker trucks or ships (WRI, 2007; IEA, 2008).

At the GS site, the CO

is injected into deep subsurface rock formations through one or more wells, using technologies developed and refined by the oil, gas, and chemical manufacturing industries over the past several decades. EPA believes that many owners or operators will inject CO

in a supercritical state to depths greater than 800 meters (2,645 feet) for the purpose of maximizing capacity and storage.

When injected into an appropriate receiving formation, CO

is sequestered by a combination of trapping mechanisms, including physical and geochemical processes (Benson, 2008). Physical trapping occurs when the relatively buoyant CO

rises in the formation until it reaches a stratigraphic zone with low permeability (

i.e.,

geologic confining system) that inhibits further upward migration. Physical trapping can also occur as residual CO

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

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

molecules attach to the surfaces of coal and certain organic-rich shales, displacing other molecules such as methane. Geochemical trapping occurs when chemical reactions between the dissolved CO

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

will be trapped by these mechanisms depends on properties of

the receiving formation and the injected CO

stream.

The effectiveness of physical CO

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

has remained trapped for millions of years (Holloway

et al.,

2007). For example, CO

has been trapped for more than 65 million years under the Pisgah Anticline, northeast of the Jackson Dome in Mississippi and Louisiana (IPCC, 2005). Other natural CO

sources include the following geologic domes: McElmo Dome, Sheep Mountain, and Bravo Dome in Colorado and New Mexico.

Many of the injection and monitoring technologies that may be applicable to GS are commercially available today and will be more widely demonstrated over the next 10 to 15 years (Dooley

et al.,

2009). The oil and natural gas industry in the United States has over 35 years of experience of injection and monitoring of CO

in the deep subsurface for the purposes of enhancing oil and natural gas production. This experience provides a strong foundation for the injection and monitoring technologies that will be needed for commercial-scale CCS. US and international experience with enhanced recovery (ER) and commercial CCS projects, as well as ongoing research, demonstration, and deployment programs throughout the world, provide critical experience and information to inform the safe injection of CO

. For additional information about these projects, see section II.E.

Although CCS is occurring now on a relatively small scale, it could play a larger role in mitigating greenhouse gas (GHG) emissions from a wide variety of stationary sources. According to the Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2007, stationary sources contributed 67 percent of the total CO

emissions from fossil fuel combustion in 2007 (USEPA, 2008a). These sources represent a wide variety of sectors amenable to CO

capture: electric power plants (existing and new), natural gas processing facilities, petroleum refineries, iron and steel foundries, ethylene plants, hydrogen production facilities, ammonia refineries, ethanol production facilities, ethylene oxide plants, and cement kilns. Furthermore, 95 percent of the 500 largest stationary sources are within 50 miles of a candidate GS reservoir (Dooley

et al.,

2008). Estimated GS capacity in the United States is over 3,500 Gigatons CO

(Gt CO

) (DOE NETL, 2007), although the actual capacity may be lower once site-specific technical and economic considerations are addressed. Even if only a fraction of that geologic capacity is used, CCS would play a sizeable role in mitigating US GHG emissions.

2. Why is GS under consideration as a climate change mitigation technology?

Climate change is happening now, and the effects can be seen on every continent and in every ocean. While certain effects of climate change can be beneficial, particularly in the short term, current and future effects of climate change pose considerable risks to human health and the environment. There is now clear evidence that the Earth's climate is warming (USEPA, 2010):

• Global surface temperatures have risen by 1.3 degrees Fahrenheit (ºF) over the last 100 years.

• Worldwide, the last decade has been the warmest on record.

• The rate of warming across the globe over the last 50 years (0.24ºF per decade) is almost double the rate of warming over the last 100 years (0.13ºF per decade).

Most of this recent warming is very likely the result of human activities. Many human activities release greenhouse gases into the atmosphere (such as the combustion of fossil fuels). The levels of these gases are increasing at a faster rate than at any time in hundreds of thousands of years.

Fossil fuels are expected to remain the mainstay of energy production well into the 21st century, and increased concentrations of CO

are expected unless energy producers reduce CO

emissions to the atmosphere. For example, CCS would enable the continued use of coal in a manner that greatly reduces the associated CO

emissions while other safe and affordable alternative energy sources are developed in the coming decades. The development and deployment of clean coal technologies including CCS will be a key to achieving domestic emissions reductions.

GS is one of a portfolio of options that could be deployed to reduce CO

emissions to the atmosphere and help to mitigate climate change. Other options include energy conservation, efficiency improvements, and the use of alternative fuels and renewable energy sources. Ensuring that GS is done in a manner that is protective of USDWs will ensure the safety and efficacy of CO

injection for GS.

While predictions about large-scale availability and the rate of CCS project deployment are subject to uncertainty, EPA analyses of Congressional climate change legislative proposals (the American Power Act of 2010 and the American Clean Energy and Security Act H.R. 2454 of 2009, both in the 111th Congress) indicate that CCS has the potential to play a significant role in climate change mitigation scenarios. For example, analysis of the American Power Act indicates that CCS technology could account for 10 percent of CO

emission reductions in 2050 (USEPA, 2010f). These results indicate that CCS could play an important role in achieving national greenhouse gas reduction goals.

Today's final rule provides minimum Federal requirements for the injection of CO

to protect USDWs from endangerment as this key climate mitigation technology is developed and deployed. It clarifies requirements that apply to CO

injection for GS, provides consistency in requirements across the US, and affords transparency about what requirements apply to owners or operators.

3. What are the unique risks to USDWs associated with GS?

Large CO

injection volumes associated with GS, the buoyant and mobile nature of the injectate, the potential presence of impurities in the CO

stream, and its corrosivity in the presence of water could pose risks to USDWs. The purpose of today's Class VI requirements for GS is to ensure the protection of USDWs, recognizing that an improperly managed GS project has the potential to endanger USDWs. Proper siting, well construction, operation, and monitoring of GS projects are therefore necessary to reduce the risk of USDW contamination.

It is expected that GS projects will inject large volumes of CO

. These volumes will be much larger than are typically injected in other well classes regulated through the UIC program, and could cause significant pressure increases in the subsurface. Supercritical or gaseous CO

in the subsurface is buoyant, and thus would tend to flow upwards if it were to come into contact with a migration pathway, such as a fault, fracture, or improperly constructed or plugged well. However, the pressures induced by injection will also influence CO

and mobilized fluids to flow away from the injection well in all directions, including laterally, upwards and downwards. When CO

mixes with formation fluids, a percentage of it will dissolve. The resulting aqueous mixture of CO

and water will sink due to a density differential between the mixture and the surrounding fluids. CO

is also highly mobile in the subsurface (

i.e.,

has a very low viscosity), and, in the presence of water, CO

can be corrosive. These properties (of CO

), as well as the large

volumes that may be injected for GS result in several unique challenges for protection of USDWs in the vicinity of GS sites from endangerment.

While CO

itself is not a drinking water contaminant, CO

in the presence of water forms a weak acid, known as carbonic acid, that, in some instances, could cause leaching and mobilization of naturally-occurring metals or other contaminants from geologic formations into ground water (

e.g.,

arsenic, lead, and organic compounds). Another potential risk to USDWs is the presence of impurities in the captured CO

stream, which may include drinking water contaminants such as hydrogen sulfide or mercury. Additionally, pressures induced by injection may force native brines (naturally occurring salty water) into USDWs, causing degradation of water quality and affecting drinking water treatment processes. Research studies have shown that the potential migration of injected CO

or formation fluids into a USDW could cause impairment through one or several of these processes (

e.g.,

Birkholzer

et al.,

2008a).

Today's action addresses endangerment to USDWs by establishing new minimum Federal requirements for the proper management of CO

injection and storage in several program areas, including permitting, site characterization, AoR and corrective action, well construction, mechanical integrity testing (MIT), financial responsibility, monitoring, well plugging, PISC, and site closure. EPA believes that proper GS project management will appropriately mitigate potential risks of endangerment to USDWs posed by injection activities.

B. Under what authority is this rulemaking promulgated?

Today's rule is focused on USDW protection under the authority of Part C of SDWA (SDWA, section 1421

et seq.,

42 U.S.C. 300h

et seq.

). Part C of the SDWA requires EPA to establish minimum requirements for State

UIC programs that regulate the subsurface injection of fluids onshore and offshore under submerged lands within the territorial jurisdiction of States

Reference to “States” includes Tribes and Territories pursuant to 40 CFR 144.3.

The Submerged Lands Act and Territorial Submerged Lands Act define the scope of territorial jurisdiction of States and Territories respectively.

SDWA is designed to protect the quality of drinking water sources in the US and prescribes that EPA issue regulations for State UIC programs that contain “minimum requirements for effective programs to prevent underground injection which endangers drinking water sources” (42 U.S.C. 300h

et seq.

). Congress further defined endangerment as follows:

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

Under this authority, the Agency promulgated a series of UIC regulations at 40 CFR parts 144 through 148 for federally approved UIC programs. The chief goal of any Federally approved UIC program (whether administered by a State, Territory, Tribe or EPA) is the protection of USDWs. This includes not only those formations that are presently being used for drinking water, but also those that can reasonably be expected to be used in the future. EPA has defined through its UIC regulations that USDWs are underground aquifers with less than 10,000 milligrams per liter (mg/L) total dissolved solids (TDS) and which contain a sufficient quantity of ground water to supply a public water system (40 CFR 144.3). Section 1421(b)(3)(A) of the SDWA also provides that EPA's UIC regulations shall “permit or provide for consideration of varying geologic, hydrological, or historical conditions in different States and in different areas within a State.”

EPA promulgated administrative and permitting regulations, now codified in 40 CFR parts 144 and 146, on May 19, 1980 (45 FR 33290), and technical requirements, in 40 CFR part 146, on June 24, 1980 (45 FR 42472). The regulations were subsequently amended on August 27, 1981 (46 FR 43156), February 3, 1982 (47 FR 4992), January 21, 1983 (48 FR 2938), April 1, 1983 (48 FR 14146), May 11, 1984 (49 FR 20138), July 26, 1988 (53 FR 28118), December 3, 1993 (58 FR 63890), June 10, 1994 (59 FR 29958), December 14, 1994 (59 FR 64339), June 29, 1995 (60 FR 33926), December 7, 1999 (64 FR 68546), May 15, 2000 (65 FR 30886), June 7, 2002 (67 FR 39583), and November 22, 2005 (70 FR 70513).

Under the SDWA, the injection of any “fluid” must meet the requirements of the UIC program. A “fluid” is defined under 40 CFR 144.3 as any material or substance which flows or moves whether in a semisolid, liquid, sludge, gas or other form or state, and includes the injection of liquids, gases, and semisolids (

i.e.,

slurries) into the subsurface. The types of fluids currently injected into wells subject to UIC requirements include: CO

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

injected for the purpose of GS is subject to the SDWA.

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

Today's rulemaking under SDWA authority complements the CO

Injection and GS Reporting rulemaking (subparts RR and UU) under the Greenhouse Gas Reporting Program's Clean Air Act (CAA) authority developed by EPA's Office of Air and Radiation (OAR).

The CAA defines EPA's responsibilities for protecting and improving the nation's air quality and the stratospheric ozone layer. The GHG Reporting Program requires reporting of GHG emissions and other relevant information from certain source categories in the U.S. The GHG Reporting Program, which became effective on December 29, 2009, includes reporting requirements for facilities and suppliers in 32 subparts. For more detailed background information on the GHG Reporting Program, see the preamble to the final rule establishing the GHG Reporting Program (74 FR 56260, October 30, 2009).

In a separate action being finalized concurrently with this UIC Class VI rulemaking, EPA is amending 40 CFR part 98, which provides the regulatory framework for the GHG Reporting Program, to add reporting requirements covering facilities that conduct GS (subpart RR) and all other facilities that inject CO

underground (subpart UU). This data will inform Agency policy decisions under CAA sections 111 and 112 related to the use of CCS for mitigating GHG emissions. In combination with data from other subparts of the GHG Reporting Program, data from subpart UU and subpart RR will allow EPA to track the flow of CO

across the CCS system. EPA will be able to reconcile subpart RR data on CO

received with CO

supply data in order to understand the quantity of CO

supply that is geologically sequestered.

Owners or operators subject to today's rule are required to report under subpart RR. Subpart RR establishes reporting requirements for facilities that inject a CO

stream for long-term containment into a subsurface geologic formation, including sub-seabed offshore formations. These facilities are required to develop and implement a site-specific

Monitoring, Reporting, and Verification (MRV) plan which, once approved by EPA (in a process separate from the UIC permitting process), would be used to verify the amount of CO

sequestered and to quantify emissions in the event that injected CO

leaks to the surface. For more information on subpart RR, see

http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.

UIC requirements and Subpart RR requirements:

EPA designed the reporting requirements under subpart RR with consideration of the requirements for Class VI well owners or operators in subpart H of part 146 of today's rule. Subpart RR builds on the Class VI requirements outlined in today's rule with the additional goals of verifying the amount of CO

sequestered and collecting data on any CO

surface emissions from GS facilities as identified under subpart RR of part 98.

The Agency acknowledges that there are similar data elements that must be reported pursuant to requirements in this action and those required to be reported under subpart RR. Specifically, owners or operators subject to both regulations must report the amount (flow rate) of injected CO

The Class VI and subpart RR rules differ, not only in purpose but in the specific requirements for the measurement unit and collection/reporting frequency. The UIC program Class VI rule requires that owners or operators report information on the CO

stream to ensure appropriate well siting, construction, operation, monitoring, post-injection site care, site closure, and financial responsibility to ensure protection of USDWS. Under subpart RR, owners or operators must report the amount (flow rate) of injected CO

for the mass balance equation that will be used to quantify the amount of CO

sequestered by a facility.

Table II-1—Comparison of Reporting Requirements Under Subpart RR and Select UIC Class VI Requirements

Reporting requirement

Subpart RR

UIC Class VI

Quantity of CO

transferred onsite

Yes

N/A.

Quantity (flow rate) of CO

injected

Yes

Yes.

Fugitive and vented emissions from surface equipment

Yes

N/A.

Quantity of CO

produced with oil or natural gas (ER)

Yes

N/A.

Percent of CO

estimated to remain with the oil and gas (ER)

Yes

N/A.

Quantity of CO

emitted from the subsurface

Yes

N/A.

Quantity of CO

sequestered in the subsurface

Yes

N/A.

Cumulative mass of CO

sequestered in the subsurface

Yes

N/A.

Monitoring plan for detecting air emissions

Yes

Yes.

Monitoring plan for quantifying air emissions

Yes

N/A.

(1) UIC Class VI rule allows for surface air/soil gas monitoring for USDW protection at the discretion of the UIC Director.

EPA requires reporting of other data to satisfy various programmatic needs. See section III of this preamble and associated requirements in subpart H of part 146 and the preamble to subpart RR for additional information on these specific requirements and their purpose. Table II-1 provides a comparison of the major reporting requirements in subpart RR and the extent to which there is overlap with Class VI requirements. For the monitoring plan listed in Table II-1, EPA will accept a UIC Class VI permit to satisfy certain subpart RR MRV plan requirements. However, the reporter must include additional information to outline how monitoring will achieve surface detection and quantification of CO

. EPA is pursuing ways to better integrate data management between the UIC and GHG Reporting Programs to ensure that data needs are harmonized and the burden to regulated entities is minimized.

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

While the SDWA provides EPA with the authority to develop regulations to protect USDWs from endangerment, it does not provide authority to develop regulations for all areas related to GS. EPA received a number of public comments on the proposal (73 FR 43492, July 25, 2008) indicating that the Agency should further explore environmental and regulatory issues beyond the scope of the proposed SDWA requirements for underground injection of CO

for GS.

In response to comments and as a result of the presidential memo “A Comprehensive Strategy on Carbon Capture and Storage” (

http://www.whitehouse.gov/the-press-office/presidential-memorandum-a-comprehensive-Federal-strategy-carbon-capture-and-storage

), the Agency continues to evaluate areas of potential applicability of other Federal environmental statutes including, but not limited to, the CAA (discussed in section II.C), the Resource Conservation and Recovery Act (RCRA; discussed in section III.F.2), the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA; discussed in section III.F.2), and the Marine Protection, Research and Sanctuaries Act (MPRSA; discussed in this section) to various aspects of GS and CCS.

Additionally, EPA and the US Department of Energy (DOE) co-chaired the Interagency Task Force on Carbon Capture and Storage to develop a plan to overcome the barriers to the widespread, cost-effective deployment of CCS within 10 years, with a goal of bringing five to 10 commercial demonstration projects online by 2016. The Task Force's report is available at

http://www.whitehouse.gov/administration/eop/ceq/initiatives/ccs.

This section clarifies the distinction between today's rulemaking and a number of other Federal rulemakings and initiatives.

National Environmental Protection Act (NEPA):

The SDWA UIC program is exempt from performing an Environmental Impact Statement (EIS) under section 101(2)(C) and an alternatives analysis under section 101(2)(E) of NEPA under a functional equivalence analysis. See

Western Nebraska Resources Council

US EPA,

943 F.2d 867, 871-72 (8th Cir. 1991) and EPA Associate General Counsel Opinion (August 20, 1979).

Marine Protection, Research, and Sanctuaries Act (MPRSA) and London Protocol Implementation:

Sub-seabed CO

injection for GS may, in certain circumstances, be defined as ocean dumping and subject to regulation under the MPRSA. Application of the MPRSA would entail coordination of the permitting processes under the SDWA and MPRSA, pursuant to MPRSA sections 106(a) and (d). The substantive environmental protection requirements of both statutes would need to be satisfied prior to the

commencement of GS. The MPRSA was enacted in 1972 and implements the London Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter (the “London Convention”). In 1996, the Protocol to the London Convention (the “London Protocol”) was established. The Protocol stipulates that sub-seabed GS may be approved provided that: (1) Disposal is into a sub-seabed geologic formation; (2) the CO

stream consists overwhelmingly of CO

, with only incidental associated substances derived from the source material and capture and sequestration process used; and, (3) no wastes or other matter are added for the purpose of disposal. The US has signed, but has not yet ratified, the Protocol. If the Protocol is ratified, and implementing legislation is enacted, EPA, in conjunction with other Federal agencies, will develop any necessary regulations for implementing the provisions relevant to sub-seabed GS.

Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) Outer Continental Shelf Lands Act (OCSLA):

BOEMRE, formerly the Minerals Management Service (MMS), an agency within the Department of the Interior, administers the OCSLA. As a result of recent OCSLA amendments by the Energy Policy Act of 2005, the OCSLA provides for the grant of leases, easements, or rights-of-way on the outer continental shelf to the extent that an activity “supports production, transportation, or transmission of energy from sources other than oil and gas” and complies with the other provisions of OCSLA section 8(p). Offshore geologic sequestration of CO

on the outer continental shelf may be subject to requirements under the OCSLA.

As indicated in the Report of the Interagency Task Force on Carbon Capture and Storage (2010), ratification of the London Protocol and associated amendment of the MPRSA as well as amendment of the Outer Continental Shelf Lands Act (OCSLA) will ensure a comprehensive statutory framework for the storage of CO

on the outer continental shelf.

Bureau of Land Management (BLM) Report to Congress:

The BLM, another agency within the Department of Interior, was required by Section 714 of the Energy Independence and Security Act (EISA) of 2007 (Pub. L. 110-140, HR 6) to prepare a report outlining a regulatory framework that could be applied to lands managed by the Bureau for natural resource development, chiefly oil and gas. With assistance from both EPA and the DOE, BLM submitted a Report to Congress titled “Framework for Geological Carbon Sequestration on Public Land” (BLM, 2009). This report affirms BLM's role in appropriately managing Federal lands where GS injection projects may be sited. Additionally, the report makes recommendations regarding approaches for effective regulation of such activities under existing Federal authorities including the SDWA and UIC program requirements.

United States Geological Survey (USGS) GS Capacity Methodology:

USGS, another agency within the Department of Interior and the primary Federal agency responsible for national geological research, has been an active participant with DOE and EPA at conferences and workshops on CCS. In 2008, in response to the EISA, USGS initiated development of a methodology for estimating the capacity to store CO

in geologic formations of the U.S. While previous capacity estimates published by DOE/National Energy Technology Laboratory (NETL) have been broad in scope (

i.e.,

geologic basin-wide), the USGS is focusing on small-scale, refined estimates. In 2009, USGS published a proposed, risk-based methodology for GS capacity estimation. After input from other agencies and stakeholders, USGS released a final report:

A Probabilistic Assessment Methodology for the Evaluation of Geologic Carbon Dioxide Storage

(USGS, 2010). The report is available at

http://pubs.usgs.gov/of/2010/1127/.

USGS continues to work on capacity estimation as required under the EISA.

Internal Revenue Service (IRS) Guidance for Tax Incentives for GS Projects:

In response to the Energy Improvement and Extension Act of 2008, IRS, in consultation with EPA and DOE, issued guidance 2009-44 IRB (IRS, 2009) for taxpayers seeking to claim tax credits for capturing and sequestering CO

from a qualified facility in the U.S. Under section 45Q of the Internal Revenue Code, a taxpayer who stores CO

under the predetermined conditions may qualify for the tax credit ($10 per metric ton of qualified CO

at ER projects; $20 per metric ton of qualified CO

for non-ER projects). The taxpayer will be responsible for maintaining records for inspection by the IRS and tax credit amounts will be adjusted for inflation for any taxable year beginning after 2009. The Internal Revenue Service published IRS Notice 2009-83 (available at:

http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860

) to provide guidance regarding eligibility for the section 45Q tax credit, computation of the section 45Q tax credit, reporting requirements for taxpayers claiming the section 45Q tax credit, and rules regarding adequate security measures for “secure geological storage of CO

”

Following publication of today's final Class VI requirements, and as clarified in the guidance, taxpayers claiming the section 45Q tax credit must follow the appropriate UIC requirements (

e.g.,

Class II or Class VI). The guidance also clarifies that taxpayers claiming section 45Q tax credit must follow the GS monitoring, reporting, and verification procedures finalized in the CO

Injection and GS Reporting Rule that is part of the GHG Reporting Program.

General Accountability Office Reports on GS and CCS:

The United States General Accountability Office (GAO) has prepared, or is in the process of preparing, several reports for Congressional requestors related to the GS of CO

. In September 2008, GAO (GAO-08-1080) completed a report related to assessing the application of CCS technologies entitled:

Climate Change—Federal Actions Will Greatly Affect the Viability of Carbon Capture and Storage as a Key Mitigation Option

(GAO, 2008). In September 2010, GAO released a report entitled:

Climate Change, A Coordinated Strategy Could Focus Federal Geoengineering Research and Inform Governance Efforts

(GAO-10-903) which describes innovative technologies that may alter climate change, details current research activities, and clarifies how coordination could inform subsequent climate science efforts. GAO initiated another report (GAO-10-675) focused on the methods by which coal-fired power plants may capture carbon emissions. The draft title of that study is:

Coal Power Plants—Opportunities Exist for DOE to Provide Better Information on the Maturity of Key Technologies to Reduce Carbon Emissions

(GAO, 2010).

EPA will continue to coordinate internally and with other Federal agencies to promote consistency in existing and future GS and CCS initiatives.

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

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

EPA coordinated with Federal and non-Federal entities on GS and CCS to

determine how best to tailor existing UIC requirements to CO

for GS.

EPA has taken a number of steps in advance of today's action including: (1) Developing guidance for experimental GS projects; (2) conducting research; (3) conducting stakeholder coordination and outreach; (4) issuing a proposed rulemaking and soliciting and reviewing public comment; and, (5) publishing a Notice of Data Availability (NODA) and Request for Comment to seek additional input on the rulemaking.

1. Developing Guidance for Experimental GS Projects

In 2007, EPA issued technical guidance to assist State and EPA Regional UIC programs in processing permit applications for pilot and other small scale experimental GS projects. The guidance was developed in cooperation with DOE and States, the Ground Water Protection Council (GWPC), the Interstate Oil and Gas Compact Commission (IOGCC), and other stakeholders.

UIC Program Guidance #83: Using the Class V Experimental Technology Well Classification for Pilot Carbon GS Projects

(USEPA, 2007) provides recommendations for permit writers regarding the use of the UIC Class V experimental technology well classification at demonstration GS projects while ensuring USDW protection. Program guidance #83 is available at:

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

EPA is preparing additional guidance for owners or operators and Directors regarding the use of Class V experimental technology wells for GS following promulgation of today's rule.

2. Conducting Research

EPA participated in and supported research to inform today's rulemaking including: Supporting and tracking the development and results of national and international CO

GS field and research projects; tracking GS-related State regulatory and legislative efforts; and conducting technical workshops on issues associated with CO

GS. EPA described these research activities in detail in the proposed rule (July 2008) and the NODA and Request for Comment (August 2009). Additional information pertaining to these activities, which are summarized below, may be found in the rulemaking docket.

a. Tracking the Results of CO

GS Research Projects

To inform today's rulemaking, EPA tracked the progress and results of national and international GS research projects. DOE leads field research on GS in the U.S. in conjunction with the Regional Carbon Sequestration Partnerships (RCSPs). Currently, DOE's NETL is developing and/or operating GS projects, a number of which have either completed injection or are in the process of injecting CO

. The seven RCSPs are conducting pilot and demonstration projects to study site characterization (including injection and confining formation information, core data and site selection information); well construction (well depth, construction materials, and proximity to USDWs); frequency and types of tests and monitoring conducted (on the well and on the project site); modeling and monitoring results; and injection operation (injection rates, pressures, and volumes, CO

source and co-injectates). See section II.E.5 for more information on the status of these projects.

Lawrence Berkeley National Laboratory (LBNL) research:

EPA and DOE are jointly funding work by the LBNL to study potential impacts of CO

injection on ground water aquifers and drinking water sources. The preliminary results have been used to inform today's rulemaking and are described in detail in section II.E.5.

In addition, EPA is funding an analysis by LBNL to integrate experimental and modeling information. LBNL will characterize ground water samples and aquifer mineralogies from select sites in the U.S. and conduct controlled laboratory experiments to assess the potential mobilization of hazardous constituents by dissolved CO

. These experiments will provide data that will be used to validate previous predictive modeling studies (of aquifer vulnerabilities to potential CO

leaks) which may be applied to other GS sites in the future to assess the fate and migration of CO

-mobilized constituents in ground water.

EPA's Office of Research and Development (ORD) GS research:

EPA's ORD engages Agency scientists and engineers in targeted research to provide information to stakeholders and policy makers focused on areas of national environmental concern, including climate change and GS. In addition, ORD's National Center for Environmental Research (NCER) provides extramural research grants for similar investigations through a competitive solicitation process. In the fall of 2009, NCER awarded six Science To Achieve Results (STAR) grants to recipients from major universities and institutions. The awards were granted to projects focused on

Integrated Design, Modeling and Monitoring of GS of Anthropogenic CO

to Safeguard Sources of Drinking Water.

Work under the grants began in late 2009 and includes: Evaluating potential impacts on drinking water aquifers of CO

-rich dissolved brines (Clemson University); reducing the hydrologic and geochemical uncertainties associated with CO

sequestration in deep, saline reservoirs (University of Illinois-Urbana); assessing appropriate monitoring approaches at GS sites (University of Texas at Austin); integrating design, monitoring, and modeling of GS to assist in developing a practical methodology for characterizing risks to USDWs (University of Utah); conducting laboratory experiments on shallow aquifer systems to improve our understanding of geochemical and microbiological reactions under low pH/high CO

stress (Columbia University); and, developing a set of computational tools to model CO

and brine movement associated with GS (Princeton University).

International projects:

EPA is tracking the progress of international GS efforts. The largest and longest-running commercial, large-scale projects in operation today include: The Sleipner Project in the Norwegian North Sea (operating since 1996); the Weyburn enhanced oil recovery (EOR) project in Saskatchewan, Canada (operating since 2000); the In Salah Gas Project in Algeria (operating since 2004); and Snohvit, also in offshore Norway in the Barents Sea (operating since 2008). Other projects EPA is tracking include Otway in Australia (operating since 2008); Ketzin in Germany (operating since 2008); and Lacq in France (operating since 2009). EPA is also tracking two projects that are anticipated to begin injection in the near future: CarbFix in Iceland (anticipated to commence injection in 2010) and Gorgon in Australia (anticipated to start in 2014). EPA evaluated available information and experiences gained from these international projects to inform today's action, as appropriate. Additional information on how these and other international projects informed the GS rulemaking is contained in the rulemaking docket (USEPA, 2010a).

b. Tracking State Regulatory Efforts

EPA has made it a priority to engage States and State organizations throughout the rulemaking effort. EPA recognizes the complexity and importance of the States' approaches to managing GS and is aware that States are in various stages of developing statutory frameworks, regulations,

technical guidance, and strategies for addressing CCS and GS. Throughout the regulatory development process for the Class VI regulation, EPA monitored States' regulatory efforts and approaches and sought input on State activities related to addressing GS in the proposed rule and NODA. At present, several States have published GS regulations, while others are investigating and developing strategies to address GS issues (

e.g.,

management of multi-purpose injection wells in oil and gas reservoirs). EPA is tracking regulatory efforts in 18 States: Colorado, Illinois, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Montana, New Mexico, New York, North Dakota, Oklahoma, Pennsylvania, Texas, Utah, Washington, West Virginia, and Wyoming. EPA is considering this information as it develops guidance on the primacy application and approval process for Class VI wells. Information about these State activities may be found in the docket for today's rulemaking.

c. Conducting Technical Workshops on Issues Associated With CO

EPA conducted a series of technical workshops with regulators, industry, utilities, and technical experts to identify and discuss questions relevant to the effective management of CO

GS. The workshops included the following: Measurement, Monitoring, and Verification (in New Orleans, Louisiana on January 16, 2008); Geological Setting and AoR Considerations for CO

GS (in Washington, DC on July 10-11, 2007); Well Construction and MIT (in Albuquerque, New Mexico on March 14, 2007); a State Regulators' Workshop on GS of CO

(in collaboration with DOE in San Antonio, Texas on January 24, 2007); an International Symposium on Site Characterization for CO

Geological Storage (co-sponsored with LBNL in Berkeley, California on March 20-22, 2006); Risk Assessment for Geologic CO

Storage (co-sponsored with the Ground Water Protection Council (GWPC) in Portland, Oregon on September 28-29, 2005); and Modeling and Reservoir Simulation for Geologic Carbon Storage (in Houston, Texas on April 6-7, 2005). Summaries of these workshops are available on EPA's Web site, at

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

3. Conducting Stakeholder Coordination and Outreach

Throughout the rulemaking process, the Agency conducted public workshops and public hearings and consulted with specific groups. EPA representatives also attended meetings to explain the GS rulemaking effort to interested members of the public and stakeholder groups. Meeting information, notes, and summaries are available in the docket for this rulemaking.

Public stakeholder coordination:

EPA held public meetings to discuss EPA's rulemaking approach, and consulted with other stakeholder groups including non-governmental organizations (NGOs) to gain an understanding of stakeholder interests and concerns. As part of this outreach, EPA conducted two public stakeholder workshops with participants from industry, environmental groups, utilities, academia, States, and the general public. These workshops were held in December 2007 and February 2008. Workshop summaries are available on EPA's Web site, at

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

EPA also coordinated with GWPC, a State association that focuses on ensuring safe application of injection well technology and protecting ground water resources, and IOGCC, a chartered State association representing oil and gas producing States throughout the rulemaking process. Members of GWPC and IOGCC have specific expertise regulating the injection of CO

for the ER of oil and gas. EPA staff attended national meetings and calls of these organizations, as well as those held by technical and trade organizations, NGOs, States, and Tribal organizations to discuss the rulemaking process and GS-specific technical issues.

Consultation with the National Drinking Water Advisory Council (NDWAC):

In November 2008, during the public comment period for the proposed rule, EPA met with NDWAC to discuss the proposed rule. At the meeting, EPA presented information about the rulemaking and responded to NDWAC questions and comments. NDWAC members indicated that they understood the role of GS as a climate mitigation tool and encouraged the Agency to continue to ensure the protection of USDWs. Since proposal publication, EPA has met with NDWAC to discuss the status of the rule and answer questions from NDWAC members. The notes of these meetings are in the rulemaking docket.

Consultations with States, Tribes, and Territories:

EPA engaged States, Tribes, and Territories early and throughout the rulemaking process to promote open communication and solicit input and feedback on all aspects of the rule.

In April of 2008, prior to publication of the proposed rule, the Agency sent background information about the rulemaking to all Federally-recognized Indian Tribes and invited participation in a dedicated GS consultation effort. EPA Regional Indian Coordinators (RICs), the National Indian Workgroup (NIWG), the National Tribal Caucus (NTC) and the National Tribal Water Council (NTWC) contacts were also invited to participate in the consultation. EPA provided additional rulemaking updates after publication of the proposal with the above-mentioned groups as well as the National Water Program State-Tribal Climate Change Council (STC3). The Fort Peck Assiniboine and Sioux Tribes and the Navajo Nation received UIC program primacy for the Class II program (under section 1425 of the SDWA) during the proposal period for this rule (73 FR 65556; 73 FR 63639). Therefore, the Agency initiated an additional consultation effort with these Tribal co-regulators post-proposal. Summaries of the Tribal consultation conference calls are included in the docket for today's rulemaking.

To ensure that States were consulted, the Agency also sent background information about the rulemaking to States and State organizations including the National Governors' Association, National Conference of State Legislatures, Council of State Governments, and the National League of Cities, among others, and held a dedicated conference call on GS for interested State representatives in April 2008. Additionally, the Agency participated in rulemaking updates, as appropriate, during national meetings and conferences, and gave presentations to State organizations throughout development of the rule. A summary of these efforts is included in the docket for today's rulemaking.

Consultation with the United States Department of Health and Human Services (HHS):

Pursuant to SDWA section 1421, EPA consulted with the U.S. Department of Health and Human Services during the rulemaking process. Prior to proposal publication and rule finalization, the Agency provided background information to HHS on the purpose and scope of the rule. In June of 2010, EPA met with HHS to discuss the GS rulemaking process as well as key elements of the proposed rule, the Notice of Data Availability and Request for Comment, and the final rule. During the June 2010 briefing, HHS participants asked about technical criteria for Class VI wells and monitoring technologies applicable to GS projects. The Agency addressed questions and comments and HHS certified that the EPA satisfied consultation obligations under the SDWA. The memo certifying this consultation is available in the docket for today's rulemaking.

4. Proposed Rulemaking

On July 25, 2008, EPA published the proposed

Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO

) Geologic Sequestration (GS) Wells

(73 FR 43492). The Agency proposed a new class of injection well (Class VI), along with technical criteria for permitting Class VI wells that tailored the existing UIC regulatory framework to address the unique nature of CO

injection for GS, including:

• Site characterization requirements that would apply to owners or operators of Class VI wells and require submission of extensive geologic, hydrogeologic, and geomechanical information on the proposed GS site to ensure that Class VI wells are located in suitable formations. EPA also proposed that owners or operators identify additional containment/confining zones, if required by the Director, to improve USDW protection.

• Enhanced AoR and corrective action requirements (

e.g.,

plugging abandoned wells) to delineate the AoR for GS projects using computational modeling that accounts for the physical and chemical properties of all phases of the injected CO

stream. EPA also proposed that owners or operators periodically reevaluate the AoR around the injection well to incorporate monitoring and operational data and verify that the CO

is moving as predicted within the subsurface.

• Well construction using materials that are compatible with and can withstand contact with CO

over the life of the GS project.

• Multi-faceted monitoring of the CO

stream, injection pressures, the integrity of the injection well, groundwater quality above the confining zone(s), and the position of the CO

plume and the pressure front throughout injection.

• Comprehensive post-injection monitoring and site care until it can be demonstrated that movement of the plume and pressure front have ceased and the injectate does not pose a risk to USDWs.

• Financial responsibility requirements to ensure that financial resources would be available for corrective action, injection well plugging, post-injection site care, and site closure, and emergency and remedial response.

Following publication of the proposed rule, EPA initiated a 120-day public comment period, which the Agency extended by 30 days to accommodate requests from interested parties. The public comment period for the proposed rule closed on December 24, 2008. EPA received approximately 400 unique submittals from 190 commenters, including late submissions. Commenters represented States; industry (including the oil and gas industry, electric utilities, and energy companies); environmental groups; and associations (including water organizations and CCS associations).

During the public comment period, the Agency held public hearings on the proposed rule in Chicago, IL on September 30, 2008 and in Denver, CO on October 2, 2008. The two hearings collectively drew approximately 100 people representing non-governmental organizations, academia, industry, and other organizations. At the hearings, 29 people submitted oral comments. Transcripts of the public hearings are in the rulemaking docket (Docket ID Nos. EPA-HQ-OW-2008-0390-0185 and EPA-HQ-OW-2008-0390-0256).

5. Notice of Data Availability and Request for Comment

Based on public comments received on the proposed rule, the Agency identified several topics on which it needed additional public comment. EPA published

Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO

)

Geologic Sequestration (GS) Wells; Notice of Data Availability and Request for Comment

(74 FR 44802) on August 31, 2009, to describe additional topics and request comment.

The NODA and Request for Comment presented new data and information from three DOE-sponsored RCSP projects including: (1) The Escatawpa, Mississippi project; (2) the Aneth Field, Paradox Basin project in Southeast Utah; and, (3) the Pump Canyon Site project in New Mexico. Additional information on these projects and responses to comments received on the NODA and Request for Comment are available in the docket for this rulemaking.

The NODA and Request for Comment also provided results of two GS-related modeling studies conducted by the LBNL. The first study (Birkholzer

et al.,

2008a) focused on the potential for GS to cause changes in ground water quality as a result of potential CO

leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium. Results from this model simulation suggest that if CO

were to leak into a shallow aquifer, mobilization of lead and arsenic could occur, causing increases in the concentration of these trace elements in ground water and potential for drinking water standard exceedances.

The second study modeled a theoretical scenario of GS in a sedimentary basin to demonstrate the potential for basin-scale hydrologic impacts of CO

storage (Birkholzer

et al.,

2008b). Model results indicate that basin-wide pressure influences may be large and that predicted pressure changes could move saline water upward into overlying aquifers if localized pathways, such as conductive faults, are present. This example illustrates the importance of basin-scale evaluation of reservoir pressures and far-field pressures resulting from CO

injection.

Additional information on LBNL's research and responses to comments received on the NODA and Request for Comment are available in the docket for this rulemaking.

The full publications on the LBNL research are also available on LBNL's Web site at

http://esd.lbl.gov/GCS/projects/CO2/index_CO2.html.

Lastly, the NODA and Request for Comment presented an alternative to address public comments and concerns about the proposed injection depth requirements for Class VI wells. Section III.D of today's action contains more information on this subject.

Following publication of the NODA and Request for Comment, EPA initiated a 45-day public comment period, which closed on October 15, 2009. EPA received 67 unique submittals from 64 commenters, many of whom commented on the proposed rule. The Agency also held a public hearing in Chicago, IL on September 17, 2009. Six people, representing the oil and gas industry, electric utilities, water associations, and academia attended the hearing. Two attendees submitted oral comments at the hearing. A transcript of the public hearing is in the rulemaking docket (EPA-HQ-OW-2008-0390-391).

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

In the preamble to the proposed rule (73 FR 43492), EPA explained the need for and merits of using an adaptive approach to regulating injection of CO

for GS at 40 CFR parts 144 through 146. The Agency indicated that this approach would provide regulatory certainty to owners or operators, promote consistent permitting approaches, and ensure that Class VI permitting Agencies are able to meet current and future demand for Class VI permits. The proposal also clarified that, as the Agency reviewed public comments, it would continue to evaluate ongoing research and demonstration projects and gather other

relevant information as needed to make refinements to the rulemaking process.

Many commenters strongly supported an adaptive, flexible approach and suggested that the Agency initially take a conservative approach in developing the UIC-GS requirements, with a provision for periodic review of the rule to allow EPA to incorporate operational experience as it is gained. These commenters also urged EPA not to wait until the completion of DOE's pilot projects before finalizing the GS rule, expressing a need for early regulatory certainty.

Some commenters expressed concerns about an adaptive approach, stating that it could lead to regulatory uncertainty because modifications could be made after the initial regulations are promulgated. One commenter said that GS will not scale-up rapidly, leaving ample time to study and assess possible regulatory approaches.

EPA agrees with commenters who supported an adaptive approach to the UIC rulemaking for GS. Additionally, the Agency believes that there is a need to have regulations in place during the earliest phases of GS deployment. Finalizing today's requirements will allow early Class VI wells to be permitted in a manner that addresses the unique characteristics of CO

injection for GS and allow early projects to demonstrate successful confinement of CO

in a manner that is protective of USDWs. EPA also believes that an adaptive approach enables the Agency to make changes to the program as necessary to incorporate new research, data, and information about GS and associated technologies (

e.g.,

modeling and well construction). This new information may increase protectiveness, streamline implementation, reduce costs, or otherwise inform the requirements for GS injection of CO

. The Agency plans, every six years, to review the rulemaking and data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the Class VI UIC requirements are appropriate or necessary. This time period is consistent with the periodic review of National Primary Drinking Water Standards under Section 1412 of SDWA.

G. How does this action affect UIC program implementation?

Under section 1421(b), the SDWA mandates that EPA develop minimum Federal requirements for State UIC primary enforcement responsibility, or primacy, to ensure protection of USDWs. In order to implement the UIC program, States must apply to EPA for primacy approval. In the primacy application, States must demonstrate: (1) State jurisdiction over underground injection projects; (2) that their State regulations are at least as stringent as those promulgated by EPA (

e.g.,

permitting, inspection, operation, monitoring, and recordkeeping requirements); and (3) that the State has the necessary administrative, civil, and criminal enforcement penalty remedies pursuant to 40 CFR 145.13 authorities.

Once an application for primacy is received, the EPA Administrator must review and approve or disapprove the State's primacy application. EPA may also choose to approve or disapprove part of the application. This determination is based on EPA's mandate under the SDWA as implemented by UIC regulations established in 40 CFR part 144 through 146, and must be made by a rulemaking. Most States were authorized with full or partial primacy for the UIC program in the early 1980s; recently, two Tribes received primacy for the Class II program under section 1425 of the SDWA. EPA directly implements the UIC program in States that have not applied for primacy and States that have primacy for part of the UIC program. A complete list of the primacy agencies in each State is available at

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

EPA may approve primacy for States as authorized by sections 1422 and 1425 of the SDWA. There are fundamental differences between how these two statutory provisions are applied. Under section 1422, States must demonstrate that their proposed UIC program meets the statutory requirements under section 1421 and that their program contains requirements that are at least as stringent as the minimum Federal requirements provided for in the UIC regulations to ensure protection of USDWs. Alternatively, States seeking primacy under section 1425 have the option to demonstrate that their Class II program is an “effective” program to prevent underground injection that endangers USDWs. Typically, these States follow the broader elements of a State program submission established by EPA in 40 CFR part 145, subpart C. In today's final rule, and in accordance with the SDWA section 1422, all Class VI State programs must be at least as stringent as the minimum Federal requirements finalized in today's rule.

UIC program implementation:

Authority to administer a State UIC program may be granted to one or more State agencies. States may choose to include in their UIC primacy application a program that is administered by multiple agencies. Under 40 CFR 145.23, in order for more than one agency to be responsible for administration of the program, each agency must have Statewide jurisdiction over the class of injection activities for which they are responsible. Some States administer their program for all injection well classes through a single agency, whereas other States elect to divide the program between agencies. For example, in most States, the Class II program is run by an oil and gas agency and other well classes are run by a State environmental agency (

e.g.,

the Oklahoma Corporation Commission oversees Class II wells in the State, and the Oklahoma Department of Environmental Quality oversees other well classes). Additionally, several States allow their oil and gas agencies to administer their UIC program for specific well classes or subclasses provided they meet all minimum Federal requirements (

e.g.,

the Railroad Commission of Texas oversees Class III brine-mining wells and Class V geothermal wells in Texas). EPA believes that retaining this flexibility for States to identify the appropriate agency to oversee Class VI wells will address commenters' concerns that States should be afforded the opportunity to determine which agency should oversee Class VI wells, and recognizes the existing expertise of both State oil and gas agencies and deep well injection programs, generally overseen by State environmental agencies.

Proposed approach for Class VI primacy and public comment:

In the proposed rule, EPA emphasized that States, Territories, and Tribes seeking primacy for Class VI wells would be required to demonstrate that their regulations are at least as stringent as the proposed minimum Federal requirements. Recognizing that some States may wish to obtain primacy for only Class VI wells, the Agency requested comment on the merits and possible disadvantages of allowing primacy approval for Class VI wells independent of other well classes.

Commenters representing States, industry, various trade associations, and electric utilities supported the concept of allowing independent primacy for Class VI wells. Commenters asserted that States have the best knowledge of regional geology and areas in need of special protection, along with necessary pre-existing relationships with the regulated community. Commenters also agreed with EPA's statement in the proposal that independent primacy would encourage States to develop a

comprehensive regulatory program for all aspects of CCS (noting that some States have already begun legislative efforts that are wider in scope than the proposed Federal rule) and facilitate the rapid deployment of commercial-scale CCS projects. They also asserted that this approach is acceptable under the UIC program's statutory authority.

Independent primacy for Class VI wells:

Historically, EPA has not accepted independent UIC primacy applications from States for individual well classes under section 1422 of SDWA, as a matter of policy. For example, if a State wanted primacy for Class I wells, the State would also need to accept primacy for all other well classes under section 1422 of SDWA (See section II.H for a description of well classifications). This policy has been in place since the initiation of the Federal UIC program and was intended to encourage States to take full primacy for UIC programs, avoid Federal duplication of efforts, and provide for administrative efficiencies.

However, based on comments on the UIC-GS proposed rule and discussions with States and stakeholders, the Agency will allow independent primacy for Class VI wells under § 145.1(i) of today's rule, and will accept applications from States for independent primacy under section 1422 of the SDWA for managing UIC-GS projects under Class VI. EPA believes that States are in the best position to implement UIC-GS programs, and by allowing for independent Class VI primacy, EPA encourages States to take responsibility for implementation of Class VI regulations. The Agency's UIC program believes that this may, in turn, help provide for a more comprehensive approach to managing GS projects by promoting the integration of GS activities under SDWA into a broader framework for States managing issues related to CCS that may lie outside the scope of the UIC program or other EPA programs. This would harness the unique efficiencies States can offer to promote adoption of GS technology that incorporates issues in the broader scope of CCS, while ensuring that USDWs are protected through the UIC regulatory framework. Allowing States to apply only for Class VI primacy will also shorten the primacy approval process.

EPA's willingness to accept independent primacy applications for Class VI wells applies only to Class VI well primacy and does not apply to any other well class under SDWA section 1422 (

i.e.,

I, III, IV, and V). EPA believes that this shift in its longstanding policy of discouraging “partial” or “independent” primacy is warranted to encourage States to seek primacy for Class VI wells and allow States to address the unique challenges that would otherwise be barriers to comprehensive and seamless management of GS projects.

The Agency recognizes that some States are currently addressing off-facility surface access for corrective action and monitoring, pore space ownership and trespass issues, and amalgamation of correlative rights in depleted reservoirs for GS. Additionally, because GS technologies are an important component of CCS, the Agency considers the allowance for independent Class VI primacy important and unique to this well class. This decision is expected to ensure that the Class VI primacy application process does not serve as a barrier to GS and CCS deployment. EPA will not consider applications for independent primacy for any other injection well class under SDWA section 1422 other than Class VI, nor will the Agency accept the return of portions of existing 1422 programs. EPA will continue to process primacy applications for Class II injection wells under the authority of section 1425 of the SDWA.

Today's final rule includes a new subparagraph § 145.1(i) that establishes EPA's intention to allow for independent primacy for Class VI wells. The Agency is developing implementation materials to provide guidance to States applying for Class VI primacy under section 1422 of SDWA and to assist UIC Directors evaluating permit applications.

Effective date of the GS rule and Class VI primacy application and approval timeframe:

Today's rule, at § 145.21(h), establishes a Federal Class VI primacy program in States that choose not to seek primacy for the Class VI portion of the UIC program within the approval timeframe established under section 1422(b)(1)(B) of the SDWA. Under § 145.21(h), States will have 270 days following final promulgation of the GS rule September 6, 2011 to submit a complete primacy application that meets the requirements of §§ 145.22 or 145.32. Pursuant to the SDWA, this 270-day timeframe allows States that seek primacy for the new Class VI wells a reasonable amount of time to develop and submit their application to EPA for approval. EPA will assist States in meeting the 270-day deadline by developing implementation materials for States and conducting training on the process of applying for and receiving primacy for Class VI wells under section 1422 of SDWA. EPA will also assist States as they develop GS regulations that are the equivalent of minimum Federal requirements and plans to use an expedited process for approving primacy.

Although the SDWA allows the Administrator to extend the date for submission of an application for up to 270 additional days for good cause, the Agency has determined that it will not provide for an extension for States applying for Class VI primacy. Instead, EPA believes that, in light of national priorities for promoting climate change mitigation strategies and Administration priorities for developing and deploying CCS projects in the next few years, it is important to have enforceable Class VI regulations in place nationwide as soon as possible.

If a State does not submit a complete application during the 270-day period, or EPA has not approved a State's Class VI program submission, then EPA will establish a Federal UIC Class VI program in that State after the 270-day application period closes. This will ensure that tailored State- or Federally-enforceable requirements applicable to GS projects will be in place nationwide as soon as possible after rule finalization. Further, a clear, nationally-consistent deadline will avoid potential confusion that may arise if some States have approved Class VI programs and others do not. EPA will publish a list of the States where the Federal Class VI requirements have become applicable in the

Federal Register

and update 40 CFR part 147. It is important to note that, although the Agency is not accepting extension requests, a State may, at any time in the future, apply for primacy for the new GS requirements following establishment of a Federal Class VI UIC program. If a State receives approval after the 270-day deadline (for a primacy application submitted either before or after the deadline), EPA will publish a subsequent notice of the approval as required by the SDWA; at that point, the State, rather than EPA, will implement the Class VI program.

The Agency clarifies that States may not issue Class VI UIC permits until their Class VI UIC programs are approved. During the first 270-days and prior to EPA approval of a Class VI primacy application, States without existing SDWA section 1422 primacy programs must direct all Class VI GS permit applications to the appropriate EPA Region. EPA Regions will issue permits using existing authorities and well classifications (

e.g.,

Class I or Class V), as appropriate.

States with existing UIC primacy for all non-Class VI well classes under section 1422 that receive Class VI permit applications within the first 270

days after promulgation of the final rule may consider using existing authorities (

e.g.,

Class I or Class V), as appropriate, to issue permits for CO

injection for GS while EPA is evaluating their Class VI primacy application. EPA encourages States to issue permits that meet the requirements for Class VI wells to ensure that Class V and Class I wells previously used for GS can be re-permitted as Class VI wells that meet the protective requirements of today's final rule within one year of promulgation of the Class VI regulation, pursuant to requirements at § 146.81(c), with minimal additional effort on the part of the owner or operator or the Director.

After the 270-day deadline, and until a State has an approved Class VI program, EPA will establish and implement a Class VI program. Therefore, all permit applications in States without Class VI programs must be directed to the appropriate EPA Region in order for a Class VI permit to be issued. In States where EPA directly implements the Class VI program, Class I permits for CO

injection for GS may no longer be issued and Class V permits may only be issued to projects eligible for such permits (see discussion of the relationship between Class V and Class VI permits in Section II.H).

Streamlining the primacy approval process:

In an effort to support States with the Class VI primacy application process and respond to comments received during the rulemaking process, today's rule includes new regulatory language at §§ 145.22 and 145.23 to streamline and clarify the process for submission of Class VI primacy applications and address the unique aspect of Class VI injection operations. For example, EPA is allowing the electronic submission of required primacy application information (

e.g.,

letter from the Governor, program description, Attorney General's statement, or Memorandum of Agreement). The Agency is also allowing the use of existing reporting form(s),

e.g.,

existing UIC program forms or State equivalents, for Class VI wells, as appropriate.

EPA will evaluate the efficiency and effectiveness of electronic submittals as part of the adaptive approach to the GS rulemaking and determine whether electronic submittal may be applicable to other UIC primacy applications submitted to EPA for review and approval under sections 1422 and 1425 of SDWA. Additionally, the Agency is developing a Class VI Program Primacy Application and Implementation Manual that describes, for States, the process of applying for and receiving primacy for Class VI wells under section 1422 of SDWA. The Manual will also provide tools designed to assist States with the development of their primacy application and UIC Directors with evaluating permit application information.

Unique requirements for Class VI permit applications:

To address the unique nature of Class VI injection operations, today's rule at § 145.23(f) includes new language describing the requirements for Class VI State program descriptions. Specifically, § 145.23(f)(1) requires States to include a schedule for issuing Class VI permits for wells within the State that require them within two years after receiving program approval from EPA, and § 145.23(f)(2) requires States to include their permitting priorities, as well as the number of permits to be issued during the first two years of program operation. In addition, today's rule at § 145.23(f)(4) requires the Director of Class VI programs approved before December 10, 2011, to provide a description of the process for notifying owners or operators of any Class I wells previously permitted for the purpose of geologic sequestration or Class V experimental technology wells no longer being used for experimental purposes that will continue injection of carbon dioxide for the purpose of GS that they must apply for a Class VI permit pursuant to requirements at § 146.81(c) within one year of December 10, 2011. § 145.23(f)(4) also requires the Director of a Class VI Program approved after December 10, 2011, to provide a description of the process for notifying owners or operators of any Class I wells previously permitted for the purpose of geologic sequestration or Class V experimental technology wells no longer being used for experimental purposes that will continue injection of carbon dioxide for the purpose of GS or Class VI wells permitted by EPA that they must apply to the State program for a Class VI permit pursuant to requirements at § 146.81(c) within one year of Class VI program approval. EPA is committed to working closely with and receiving input from States during all stages of the GS permitting process, irrespective of primacy status. Close coordination during program implementation will minimize effort and burden on States and owners and operators and streamline the administrative process for transferring permits or permit applications when primacy is granted. These requirements are tailored for Class VI wells to ensure that States are prepared to review Class VI permit applications as soon as possible following program approval; and, in light of the national priorities to promote climate change mitigation strategies, such modifications of § 145.23 may help ensure expeditious implementation of Class VI requirements across the country.

Today's rule, at § 145.23(f)(13), requires States to describe in their primacy application procedures for notifying any States, Tribes, and Territories of Class VI permit applications where the AoR is predicted to cross jurisdictional boundaries and for documenting this consultation. This new requirement addresses comments on the proposed rule and NODA and Request for Comment that Class VI operations are likely to have larger AoRs that may cross jurisdictional boundaries and necessitate trans-boundary coordination. At § 145.23(f)(9), the final rule also requires States receiving Class VI program approval to incorporate information related to any EPA approved exemptions expanding the areal extent of an existing Class II EOR/EGR aquifer exemption for Class VI injection. This requirement complements aquifer exemption requirements promulgated under today's rule and ensures that State programs incorporate information regarding the specific location (and any associated supporting data) into their program descriptions.

The Agency plans to review these requirements as part of the adaptive rulemaking approach to ensure that the tailored requirements are appropriate to ensure USDW protection from endangerment.

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

Today's rulemaking establishes a new class of injection well, Class VI, for GS projects because CO

injection for long-term storage presents several unique challenges that warrant the designation of a new well type.

When EPA initially promulgated its UIC regulations in 1980, the Agency defined five classes of injection wells at 40 CFR 144.6, based on similarities in the fluids injected, construction, injection depth, design, injection practices, and operating techniques. These five well classes are still in use today and are described below.

• Class I wells inject industrial non-hazardous liquids, municipal wastewaters, or hazardous wastes beneath the lowermost USDW. These wells are among the deepest of the injection wells and are subject to technically sophisticated construction and operation requirements.

• Class II wells inject fluids (

e.g.,

; brine) in connection with conventional

oil or natural gas production, enhanced oil and gas production, and the storage of hydrocarbons that are liquid at standard temperature and pressure.

• Class III wells inject fluids associated with the extraction of minerals, including the mining of sulfur and solution mining of minerals (

e.g.,

uranium).

• Class IV wells inject hazardous or radioactive wastes into or above USDWs. Few Class IV wells are in use today. These wells are banned unless authorized under a Federal or State-approved ground water remediation project.

• Class V includes all injection wells that are not included in Classes I-IV. In general, Class V wells inject non-hazardous fluids into or above USDWs; however, there are some deep Class V wells that are used to inject below USDWs. This well class includes Class V experimental technology wells including those permitted as GS pilot projects.

The Agency acknowledges that owners or operators of wells regulated under existing well classifications may want to change the purpose of their injection activity. The following sections describe the applicability of today's rule to owners or operators of existing wells and considerations for Directors evaluating existing wells that may be re-permitted as Class VI wells.

Class I wells:

Wells previously permitted as Class I wells for GS, including wells permitted prior to rule promulgation and wells permitted during the 270-day period after rule promulgation, must apply for Class VI permits within one year of promulgation by December 10, 2011, pursuant to requirements at § 146.81(c). The Agency anticipates that permit applications (

e.g.,

Class I or Class V) developed for CO

GS following publication of today's rule will follow the Class VI requirements and be designed to facilitate efficient re-permitting as Class VI wells. Such forethought will allow new Class VI permits to be issued with minimal additional effort on the part of the owner or operator and the Director. Additional information on Class V experimental technology wells is discussed in this section. For additional information on permitting authorities and UIC program implementation, see section II.G.

Class II CO

injection wells designated for enhanced recovery:

Enhanced oil recovery (EOR) and enhanced gas recovery (EGR) technologies, collectively referred to as enhanced recovery (ER), are used in oil and gas reservoirs to increase production. Injection of CO

is one of several ER techniques that have successfully been used to boost production efficiency of oil and gas by re-pressurizing the reservoir, and in the case of oil, by also increasing mobility. Injection wells used for ER are regulated through the UIC Class II program.

currently injected for ER in the U.S. comes from both natural and anthropogenic sources, which provide 79 percent and 21 percent, respectively, of CO

supply (DOE NETL, 2008). Natural CO

sources consist of geologic domes in Colorado, New Mexico, and Mississippi. Anthropogenic sources of CO

supplied for ER today include natural gas processing, ammonia and fertilizer production, and coal gasification facilities.

Historically, CO

purchases comprise about 33 to 68 percent of the cost of a CO

-ER project (EPRI, 1999). For this reason, CO

injection volumes are carefully tracked at ER sites. CO

recovered from production wells during ER is recycled (

i.e.,

separated and re-injected), and at the conclusion of an ER project as much CO

as is feasible is recovered and transported to other ER facilities for re-use. However, a certain amount of CO

remains underground. Current Class II ER requirements do not require tracking and monitoring of the injectate; therefore, the migration and fate of the unrecovered CO

is not documented.

As of 2008, there were 105 CO

-EOR projects within the US (Oil and Gas Journal, 2008). The majority (58) of these projects are located in Texas, and the remaining projects are located in Mississippi, Wyoming, Michigan, Oklahoma, New Mexico, Utah, Louisiana, Kansas, and Colorado. CO

-EOR projects recovered 323,000 barrels of oil per day in 2008, 6.5 percent of total domestic oil production. A total of 6,121 CO

injection wells among 105 projects were used to inject 51 million metric tons of CO

(Oil and Gas Journal, 2008; EIA, 2009; DOE NETL, 2008). Compared to CO

-EOR, CO

-EGR remains largely in the development stage (

e.g.,

Oldenburg

et al.,

2001).

Future deployment of CCS may fundamentally alter CO

-ER in the U.S. DOE anticipates that many early GS projects will be sited in depleted or active oil and gas reservoirs because the reservoirs have been previously characterized for hydrocarbon recovery and may have suitable infrastructure (

e.g.,

wells, pipelines, etc.) in place. Additionally, oil and gas fields now considered to be “depleted” may resume operation because of increased availability and decreased cost of anthropogenic CO

EPA believes that if the business model for ER changes to focus on maximizing CO

injection volumes and permanent storage, then the risk of endangerment to USDWs is likely to increase. This is because reservoir pressure within the injection zone will increase as CO

injection volumes increase. Elevated reservoir pressure is a significant risk driver at GS sites, as it may cause unintended fluid movement and leakage into USDWs that may cause endangerment. Additionally, increasing reservoir pressure within the injection zone as a result of GS will stress the primary confining zone (

i.e.,

geologic caprock) and well plugs to a greater degree than during traditional ER (

e.g.,

Klusman, 2003). Finally, active and abandoned well bores are much more numerous in oil and gas fields than other potential GS sites, and under certain circumstances could serve as potential leakage pathways. For example, in typical productive oil and gas fields, a CO

plume with a radius of about 5 km (3.1 miles) may come into contact with several hundred producing or abandoned wells (Celia

et al.,

2004).

EPA proposed that the Class VI GS requirements would not apply to Class II ER wells as long as any oil or gas production is occurring, but would apply only after the oil and gas reservoir is depleted. Under the proposed approach, Class II wells could be used for the injection of CO

, as long as oil production is simultaneously occurring from the same formation. The preamble to the proposal sought comment on the merits of this approach.

Some commenters agreed with the proposed approach while others suggested that the approach did not adequately address risks posed to USDWs by injection operations transitioning from production to long-term storage of CO

. A majority of commenters requested that EPA develop specific criteria for this transition.

Consistent with these comments, EPA determined that owners or operators of wells injecting CO

in oil and gas reservoirs for GS where there is an increased risk to USDWs compared to traditional Class II operations using CO

should be required to obtain a Class VI permit, with some special consideration for the fact that they are transitioning from a well not originally designed to meet Class VI requirements. Additionally, EPA recognizes that further clarification is needed to sufficiently characterize the factors that lead to increased risks and warrant conversion from Class II to Class VI.

Therefore, today's rule clarifies that Class VI requirements apply to any CO

injection project (regardless of formation

type) when there is an increased risk to USDWs as compared to traditional Class II operations using CO

. Traditional ER projects are not impacted by this rulemaking and will continue operating under Class II permitting requirements. EPA recognizes that there may be some CO

trapped in the subsurface at these operations; however, if there is no increased risk to USDWs, then these operations would continue to be permitted under Class II.

EPA has developed specific, risk-based factors to be considered by the Director in making the determination to apply Class VI requirements to transitioning wells. EPA believes this approach provides the necessary, site-specific flexibility while providing appropriate protection of USDWs from endangerment. These risk-based factors for determining whether Class VI requirements apply are finalized in today's rule at § 144.19 and include: (1) Increase in reservoir pressure within the injection zone; (2) increase in CO

injection rates; (3) decrease in reservoir production rates; (4) the distance between the injection zone and USDWs; (5) the suitability of the Class II AoR delineation; (6) the quality of abandoned well plugs within the AoR; (7) the owner's or operator's plan for recovery of CO

at the cessation of injection; (8) the source and properties of injected CO

; and (9) any additional site-specific factors as determined by the Director. Any single factor may not necessarily result in a determination that a Class II owner or operator must apply for a Class VI permit; rather, all factors must be evaluated comprehensively to inform a Director's (or owners' or operators') decision. The Agency is also developing guidance to support Directors and owners or operators in evaluating these factors and making the determination on whether to apply Class VI requirements.

Owners and operators of Class II wells that are injecting carbon dioxide for the primary purpose of long-term storage into an oil and gas reservoir must apply for and obtain a Class VI permit where there is an increased risk to USDWs compared to traditional Class II operations using CO

. EPA expects that, in most cases, the ER owners or operators will use these same factors to evaluate whether there is an increased risk to USDWs. When an increased risk is identified, the owner or operator must notify the Director of their intent to seek a Class VI permit. Today's rule clarifies that the Director has the discretion to make this determination in the absence of an owner or operator notification and, in doing so, require the owner or operator to apply for and obtain a Class VI permit in order to continue injection operations (§ 144.19(a)). In the event that an injection operation makes changes to the ER operation such that the increased risk to USDWs warrants transition to Class VI and does not notify the Director, the owner or operator may be subject to specific enforcement and compliance actions to protect USDWs from endangerment, including corrective action within the AoR, cessation of injection, monitoring, and/or PISC under sections 1423 and 1431 of the SDWA.

The Agency acknowledges that some stakeholders and commenters are concerned about the burden that a transition may impose on existing programs. EPA believes that transition to Class VI is necessary to ensure USDW protection but is allowing the constructed components of Class II ER wells to be grandfathered into the Class VI permitting regime at the discretion of the Director and pursuant to requirements at § 146.81(c), in order to facilitate the transition from Class II to Class VI wells without undue regulatory burden. As outlined in section II.G, today's rule clarifies that State oil and gas agencies that oversee the Class II program in many States may assume regulatory authority for Class VI by either a memorandum of understanding with the Class VI primacy agency, or by obtaining primacy for the entire Class VI program as long as it is identified in the State's program description under § 145.23. In this way, the same agency may oversee the Class II and Class VI programs, streamlining the transition process. State primary enforcement responsibility is discussed further in section II.G.

As part of EPA's adaptive rulemaking approach for Class VI wells, the Agency will collect data on transitioning Class II projects to determine whether the factors at § 144.19 adequately address risks to USDWs and whether additional or amended Federal regulations or other actions are warranted for transitioning wells from ER to long-term storage of CO

Class V Experimental Technology Wells:

Prior to finalization of the Class VI regulation, a number of CO

injection projects were permitted as Class V experimental technology wells for the purpose of testing GS technology in the U.S. Wells permitted under this classification are designed for the purpose of testing new technology that is of an experimental nature. EPA understands that some of the wells previously permitted as Class V experimental technology wells may no longer be used for this purpose. GS wells that are not being used for experimental purposes must be re-permitted as Class VI wells and will be subject to today's requirements.

In the preamble to the proposed rule, EPA described UIC Program Guidance #83

(Using the Class V Experimental Technology Well Classification for Pilot GS Projects)

and the use of the Class V experimental technology well classification (see section II.E.1 of today's notice). EPA stated that the guidance will continue to apply to experimental projects (as long as the projects continue to qualify as experimental technology wells under the guidelines described in the guidance) and to future projects that are experimental in nature.

Several commenters on the proposed rule asked EPA to clarify the point at which Class V experimental technology wells should be re-permitted as Class VI wells. Today's rule, at § 146.81(c), requires owners or operators of Class V experimental technology wells no longer being used for experimental purposes (

e.g.,

wells that will continue injection of CO

for the purpose of GS) to apply for Class VI permits within one year of rule promulgation and to comply with the requirements of today's rule. However, EPA is allowing the constructed components of Class V experimental technology wells to be grandfathered into the Class VI permitting regime at the discretion of the Director and pursuant to requirements at § 146.81(c).

Following promulgation of today's rule, only GS projects of an experimental nature (

i.e.,

to test GS technologies and collect data) will continue to be classified, permitted, and regulated as Class V experimental technology wells; and Class V wells are prohibited from operating as non-experimental GS operations under § 144.15. Experimental projects are those whose primary purpose is to test new, unproven technologies. EPA does not consider it appropriate to permit CO

injection wells that are testing the injectivity or appropriateness of an individual formation (

e.g.,

as a prelude to a commercial-scale operation) as Class V experimental technology wells. Such wells should be permitted as Class VI wells.

Other commenters suggested that owners or operators of wells injecting CO

into basalts, coal seams, and salt domes should be able to seek a Class V experimental permit. EPA agrees that the Class V experimental technology well classification may be appropriate for these projects provided they are experimental in nature. EPA expects that, following today's rule, a limited number of experimental injection

projects testing GS technology will continue. EPA anticipates that these projects will be small-scale and involve limited CO

volumes. However, if these projects become larger scale and are no longer experimental, they will need to be permitted as Class VI wells. The construction, operation or maintenance of any non-experimental Class V GS wells is prohibited (§ 144.15).

The Agency is preparing additional guidance for owners or operators and Directors regarding the use of the Class V experimental technology well classification for GS following promulgation of today's rule. The guidance will assist owners and operators and Directors in determining what constitutes a Class V experimental technology well for the purposes of testing GS technology.

Grandfathering for Class I, Class II and Class V Experimental Technology Wells:

Recognizing that owners or operators of existing Class I, Class II, and Class V experimental technology wells may seek to change the purpose of their injection well, EPA proposed to give the Director discretion to carry over or “grandfather” the construction requirements (

e.g.,

permanent, cemented well components) provided he or she is able to make a determination that these wells would not endanger USDWs. EPA sought comment on this approach and how the proposed grandfathering provisions for existing wells may affect compliance with Class VI construction requirements.

Nearly all industry commenters favored grandfathering of Class I, II, and V well construction requirements for GS, indicating that most wells are built to appropriate specifications and would have sufficient mechanical integrity for GS in order to protect USDWs from endangerment. These commenters cited oil and gas industry experience with CO

injection in the UIC Class II program and suggested that this experience demonstrates that construction requirements for Class II injection wells are sufficient to protect USDWs. Other commenters asserted that grandfathering Class II construction will expedite the transition of Class II ER projects to Class VI GS.

Several commenters were concerned that the structural modifications that may be required for some existing Class II wells to comply with the proposed injection well construction requirements at § 146.86 may actually compromise the integrity of those wells. One commenter also mentioned that pre-existing wells, including wells approved for sequestration as Class I and/or Class II wells, have not been constructed to the same standards. These existing wells penetrating the injection zone may, therefore, become potential threats to USDWs.

In response, EPA recognizes that the oil and gas industry has decades of experience injecting CO

for ER and that many Class V experimental technology wells, including those used in the RCSP's projects, are specifically designed for injection of CO

and are being constructed to Class I non-hazardous waste well specifications. In today's final rule, at § 146.81(c), owners or operators seeking to grandfather existing Class I, II, or V wells for GS must demonstrate to the Director that the grandfathered wells were engineered and constructed to meet the requirements at § 146.86(a) and ensure protection of USDWs from endangerment in lieu of requirements at § 146.86(b) and § 146.87(a). Based on the owner or operator's demonstration, the Director will determine if a well is appropriately constructed for GS. If the Director determines that the construction is appropriate for GS, the well will be re-permitted as a Class VI well and must meet the operational, testing and monitoring, reporting, injection well plugging, and PISC and site closure requirements in subpart H of part 146. If an owner or operator seeking to grandfather an existing Class I, II, or V well to a Class VI well cannot make this demonstration, then grandfathering of the constructed well and re-permitting as a Class VI well is prohibited.

III. What is EPA's final regulatory approach?

Today's rule creates a new class of injection well (Class VI) under the existing UIC program with new minimum Federal requirements that protect USDWs from endangerment during underground injection of CO

for the purpose of GS. Today's action includes requirements for the permitting, siting, construction, operation, financial responsibility, testing and monitoring, PISC, and site closure of Class VI injection wells that address the pathways through which USDWs may be endangered. These requirements are tailored from existing UIC program components to ensure that they are appropriate for the unique nature of injecting large volumes of CO

for GS into a variety of geological formations to ensure that USDWs are not endangered.

Today's rule retains many of the requirements for Class VI wells that EPA proposed on July 25, 2008. However, based on a review of public comments on the proposed rule and the NODA and Request for Comment, EPA made several changes to the GS rule. These changes are highlighted as follows and are described in today's publication.

• Additional description of the adaptive rulemaking approach. To ensure USDW protection and meet the potentially fast pace of GS deployment, EPA plans to continue its adaptive rulemaking approach for GS to incorporate new research, data, and information about GS and associated technologies. See section II.F.

• Elaboration on the rationale for allowing States to gain Class VI primacy independent of other well classes. To encourage States to take responsibility for implementation of Class VI regulations and foster a more comprehensive approach to managing GS projects within a broader framework for managing CCS issues, § 145.21 of today's rule allows States to gain primacy for Class VI wells independent of other well classes. See section II.G.

• Explanation of the considerations for permitting wells that are transitioning from Class II to Class VI. To clarify the point at which the purpose of CO

injection transitions from ER (

i.e.,

a Class II well) to long-term storage (

i.e.,

Class VI) and the risk posed to USDWs increases and is greater than traditional ER projects injecting CO

, today's rule at § 144.19 contains specific, risk-based factors to be considered by owners or operators and by Directors in making this determination. See section II.H.

• Incorporation of a process to allow Class VI well owners or operators to seek a waiver from the injection depth requirements. To provide flexibility to address concerns about geologic storage capacity limitations, address injection depth on a site-specific basis, and accommodate injection into different formation types. Today's rule, at § 146.95, allows owners or operators to seek a waiver of the Class VI injection depth requirements provided they can demonstrate USDW protection. Today's final rule also limits the use of aquifer exemptions for Class VI well injection activities (§ 144.7(d)). See section III.D.

• Clarification of the requirements for submitting materials to support Class VI permit applications. Today's rule specifies separate requirements for information to be submitted with the permit application (§ 146.82(a)) and information that must be submitted before well operation is authorized (§ 146.82(c)). This modification addresses comments that not all of the information to support the proposed Class VI permit application requirements will be available at the

time the operator develops their initial permit application, See section III.A.

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

• Increasing the frequency of AoR reevaluations. To address concerns about the inherent uncertainties in modeling CO

movement, the emerging nature of GS technology, and the importance of targeting monitoring activities where risk to USDWs is greatest, today's rule at § 146.84(e) requires that the AoR for GS projects be reevaluated at a fixed frequency, not to exceed five years as specified in the AoR and corrective action plan, or when monitoring and operational conditions warrant. See section III.B.

• Clarification and expansion of financial responsibility requirements for Class VI well owners or operators. To ensure that financial resources are available to protect USDWs from endangerment, today's rule (at § 146.85) identifies qualifying financial instruments, the time frames over which financial responsibility must be maintained, procedures for estimating the costs of activities covered by the financial instruments, procedures for notifying the Director of adverse financial conditions, and requirements for adjusting cost estimates to reflect changes to the project plans. See section III.I.

• Revisions to the GS site monitoring and plume tracking requirements to ensure that the most appropriate methods are used to identify potential risks to USDWs posed by injection activities, verify predictions of CO

plume movement, provide inputs for modeling, identify needed corrective actions, and target other monitoring activities. Today's rule, at § 146.90(g), requires Class VI well owners or operators to use direct methods to monitor for pressure changes in the injection zone and to supplement these direct methods with indirect, geophysical techniques unless the Director determines, based on site-specific geology, that such methods are not appropriate. See section III.F.

EPA believes that these changes will result in a clearer, more protective approach to permitting GS projects across the U.S. while still allowing for consideration of site specific variability.

In addition to protecting USDWs, today's 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.

Today's final GS rule contains tailored requirements for geologic siting; AoR and corrective action; construction; operation; monitoring and MIT; recordkeeping and reporting; well plugging, PISC, and site closure; financial responsibility; emergency and remedial response; public involvement; and permit duration of Class VI wells.

To develop today's final regulatory approach, EPA considered public comments submitted in response to the proposed rule and the NODA and Request for Comment. Sections III.A through L focus on the aspects of the GS regulation that are tailored to the unique nature of GS and highlight the changes between the proposed and final GS rule. Additional background information is available in the preamble, NODA and Request for Comment, and docket for this rulemaking.

A. Site Characterization

Today's final action requires owners or operators of Class VI wells to perform a detailed assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS site to ensure that GS wells are sited in appropriate locations and inject into suitable formations. Class VI well owners or operators must also identify additional confining zones, if required by the Director, to increase USDW protection.

Site characterization is a fundamental component of the UIC program. Owners or operators must identify the presence of suitable geologic characteristics at a site to ensure the protection of USDWs from endangerment associated with injection activities. Existing UIC regulations for siting injection wells include requirements to identify geologic formations suitable to receive injected fluids and confine those fluids such that they are isolated in order to ensure protection of USDWs from endangerment. Today's rule similarly requires the owner or operator to perform a detailed assessment to evaluate the presence and adequacy of the various geologic features necessary to receive and confine large volumes of injected CO

so that the injection activities will not endanger USDWs. Today's requirements for Class VI wells are based extensively on the long-standing site characterization requirements of the UIC program, and are tailored to address the unique nature of GS. Specifically, § 146.83 of today's rule sets forth the criteria for a GS site that is geologically suitable to receive and confine the injected CO

, while § 146.82 identifies the specific information an owner or operator must submit to the Director in order to demonstrate that the site meets the minimum siting criteria at § 146.83.

Today's rule at § 146.83 retains the minimum criteria for siting as proposed. Owners or operators of Class VI wells must provide extensive geologic data to demonstrate to the Director that wells will be sited in areas with a suitable geologic system comprised of a sufficient injection zone and a confining zone free of transmissive faults or fractures to ensure USDW protection. In addition, the Agency proposed that owners or operators must, at the Director's discretion, identify and characterize additional (secondary) confinement zones that will impede vertical fluid movement. EPA sought comment on the merits of identifying these additional zones, and received many comments on this topic.

The majority of commenters who commented on the requirement to identify additional zones at the Director's discretion disagreed with the proposed approach, saying that the requirement is unnecessary if the injection zone and confining zones were competent, and believing it would reduce the number of GS storage site opportunities. EPA disagrees with the commenters' assertion that secondary confinement and containment zones should not be required under the final rule and received no data or information to support commenters' assertion that characterizing secondary confining zones is technically infeasible. Therefore, EPA is retaining the requirement that owners or operators must, at the Director's discretion, identify and characterize additional confining zones. In certain geologic settings, these zones may be appropriate to ensure USDW protection, impede vertical fluid movement, allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation and remediation (§ 146.83(b)).

Today's rule at § 146.82 establishes the detailed information that owners or operators must submit to the Director to demonstrate that the site is suitable for GS. As part of the site characterization and permit application process, owners or operators of Class VI wells are required to submit maps and cross sections describing subsurface geologic formations and the general vertical and

lateral limits of all USDWs within the AoR. The Agency anticipates that owners or operators will use existing wells within the AoR or construct stratigraphic test wells for purposes of data collection; such wells may be subsequently converted to monitoring wells. Site characterization identifies potential risks and eliminates unacceptable sites,

e.g.,

sites with potential seismic risk or sites that contain transmissive faults or fractures. Data and information collected during site characterization also inform the development of construction and operating plans, provide inputs for AoR delineation models, and establish baseline information to which geochemical, geophysical, and hydrogeologic site monitoring data collected over the life of the injection project can be compared.

Today's rule also requires owners or operators to submit, with their permit applications, a series of comprehensive site-specific plans: An AoR and corrective action plan, a monitoring and testing plan, an injection well plugging plan, a PISC and site closure plan, and an emergency and remedial response plan. This requirement for a comprehensive series of site-specific plans is new to the UIC program. The Director will evaluate all of the plans in the context of the geologic data, proposed construction information, and proposed operating data submitted as part of the site characterization process, to ensure that planned activities at the facility are appropriate to the site-specific circumstances and address all risks of endangerment to USDWs.

EPA sought comment on the proposed submissions required for permit applications, and received many comments indicating that not all of the information listed in the proposed rule at § 146.82 will be available at the time the operator develops their initial permit application. In response to comments, EPA revised § 146.82 so that the final regulation specifies separate requirements for information to be submitted with the permit application (§ 146.82(a)) and information that must be submitted before well operation is authorized (§ 146.82(c)).

Today's final rule includes requirements at § 146.82(a)(2) that the owner or operator identify all State, Tribal, and Territorial boundaries within the AoR. Based on the information provided to the Director during the initiation of the permit application, the Director, pursuant to requirements at § 146.82(b), must provide written notification to all States, Tribes, and Territories in the AoR to inform them of the permit application and to afford them an opportunity to be involved in any relevant activities (

e.g.,

development of the emergency and remedial response plan (§ 146.94)). These requirements respond to comments received regarding the anticipated large AoRs and injection volumes for GS and the importance of ensuring trans-boundary coordination across the U.S. The Agency encourages transparency in the permitting process and anticipates that State-State/State-Tribal communication on GS permitting will facilitate information sharing and encourage safe, protective projects.

The final GS permitting requirements provided in today's rule in conjunction with the minimum siting requirements at § 146.83 enable flexibility and the discretion of the permitting authority when appropriate, while ensuring USDW protection. This flexibility and permitting authority discretion serves to maximize efficiencies for owners or operators and permitting agencies. The rule enables owners or operators to choose from the variety of technologies and methods appropriate to their site-specific conditions. At the same time, the rule provides the foundation for national consistency in permitting of GS projects. To promote national consistency, the Agency is developing guidance to support comprehensive site characterization required under today's rule.

B. Area of Review (AoR) and Corrective Action

Today's rule at § 146.84 enhances the existing UIC requirements for AoR and corrective action to require computational modeling of the AoR for GS projects that accounts for the physical and chemical properties of the injected CO

and is based on available site characterization, monitoring, and operational data. Owners or operators must periodically reevaluate the AoR to incorporate monitoring and operational data and verify that the CO

is moving as predicted within the subsurface.

AoR modeling and reevaluation are important components of the overall proposed strategy to track the CO

plume and pressure front through an iterative process of site characterization, modeling, and monitoring at GS sites. This approach addresses the unique and complex movement of CO

at GS sites.

1. AoR Requirements

Under the UIC program, EPA established an evaluative process to determine that there are no features near an injection well (such as faults, fractures or artificial penetrations) where injected fluid could move into a USDW or displace native fluids into USDWs resulting in endangerment to USDWs. Existing UIC regulations require that the owners or operators define the AoR, within which they must identify artificial penetrations (regardless of property ownership) and determine whether they have been properly completed or plugged. The AoR determination is integral to assessing geologic site suitability because it requires the delineation of the expected extent of the carbon dioxide plume and associated pressure front and identification and evaluation of any penetrations that could result in the endangerment of USDWs. For existing injection well classes (I through V), the AoR is defined either by a fixed radius around the injection well or by a simple radial calculation (40 CFR 146.6).

AoR and corrective action plan:

EPA proposed that owners or operators of Class VI wells prepare, maintain, and comply with a plan to delineate the AoR for a proposed GS project, periodically reevaluate the delineation, and perform corrective action that meets the requirements of this section and is acceptable to the Director. Commenters supported the proposed requirement for an AoR and corrective action plan, particularly advocating updates that ensure that facilities are being properly managed to address changing circumstances (

e.g.,

addition of monitoring wells or operational changes). The Agency is developing guidance that describes the content of project plans required in the GS rule, including the AoR and corrective action plan.

Today's final rule retains the requirement for owners or operators to develop and implement an AoR and corrective action plan; the approved plan will be incorporated into the Class VI permit and will be considered permit conditions; failure to follow the plan will result in a permit violation under SDWA section 1423. Owners or operators must also review the AoR and corrective action plan following the most recent AoR reevaluation and submit an amended plan, or demonstrate to the Director that no amendment to the AoR and corrective action plan is needed (§ 146.84(e)(4)). The iterative process by which this and other required plans are reviewed throughout the life of a project will promote an ongoing dialogue between owners or operators and the Director. Tying the plan reviews to the AoR reevaluation frequency is appropriate to ensure that reviews of the plans are conducted on a defined schedule, if there is a change in the AoR, or if other circumstances change, while adding little burden if the AoR reevaluation

confirms that the plan is appropriate as written. The plan review process also supports development and review of effective testing and monitoring programs. Additional information on updates to the AoR and corrective action plan is discussed in subsequent sections.

AoR definition:

In the proposed rule, EPA defined the AoR for a GS project as “the region surrounding the GS project that may be impacted by the injection activity,” and stated that “the AoR is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected CO

stream.” Several commenters stated that the proposed AoR definition for Class VI wells was vague and open to broad interpretation, which could lead to overly large or small AoRs. Other commenters believed that specific CO

phases and areas of quantitative measures of elevated pressure should be included in the definition.

EPA evaluated all comments on the AoR definition, and determined that a performance-based definition provides sufficient instruction regarding the region that should be included within the AoR. However, to provide additional clarity, EPA modified the Class VI AoR definition for today's final rulemaking. The AoR is defined in the final rule as, “the region surrounding the geologic sequestration project where USDWs may be endangered by the injection activity. The AoR is delineated using computational modeling that accounts for the physical and chemical properties of all phases of the injected CO

stream and displaced fluids and is based on available site characterization, monitoring, and operational data as set forth in § 146.84.” The Agency is developing guidance on AoR and corrective action to support AoR delineation (

i.e.,

including regions of the CO

plume and pressure front).

Use and applicability of computational models:

EPA proposed that the AoR for Class VI wells be determined using sophisticated computational modeling that accounts for multiphase flow and the buoyancy of CO

, and is informed by site characterization data. EPA proposed that any computational model that meets minimum Federal requirements and is acceptable to the Director may be used, including proprietary models. EPA sought comment on the use and applicability of computational modeling and allowing the use of proprietary models for GS AoR delineation.

Many commenters agreed with EPA that computational multiphase modeling is the most accurate method of delineating the AoR of GS sites. Several commenters also provided detailed technical suggestions regarding how modeling should be conducted. Some commenters opposed the use of computational models, stating that they are overly complicated to use and interpret and are not warranted for protection of USDWs.

EPA agrees with commenters who support the use of computational modeling, and retains the requirement in today's rule at § 146.84(a). The Agency is developing guidance on AoR and corrective action to support the use of computational modeling for AoR delineation. Available data from pilot projects and research studies (

e.g.,

Schnaar and Digiulio, 2009) support today's final approach of requiring the use of computational models to delineate the AoR for GS sites.

Comments were submitted both in support of and against allowing the use of proprietary models. Several commenters who supported allowing the use of proprietary models said that allowing the use of these models will save costs and increase efficiency, as many existing CO

injection projects currently rely on proprietary models. However, commenters suggested that the Director be given access to the model in order to fully evaluate results and modeling assumptions. Commenters that opposed the use of proprietary models did not believe that such models are sufficiently transparent, and believed that the Director would not be able to replicate the results.

EPA's final approach allows the use of proprietary models at the discretion of the Director. EPA does not agree with commenters who believe that the use of proprietary models will prohibit full evaluation of model results and assumptions. Several available proprietary models meet minimum Federal requirements for use in AoR delineation and their use has been documented in peer-reviewed research studies. Class VI well owners or operators, including those using proprietary AoR delineation models, are required to disclose the code assumptions, relevant equations, and scientific basis to the satisfaction of the Director. To ensure that all predictive models used for AoR delineation are meeting the Agency's intent, EPA will collect and review project data on models used in early GS projects as part of its adaptive rulemaking approach. See section II.F.

AoR reevaluation:

EPA proposed that the AoR delineation be reevaluated periodically over the life of the project in order to incorporate CO

monitoring data into models to ensure protection of USDWs from endangerment. Under the proposed approach, AoR reevaluation would occur at a minimum of every 10 years during CO

injection, or when monitoring data and modeling predictions differ significantly. EPA sought comment on the requirement for reevaluation every 10 years and what conditions would merit reevaluation of the AoR.

The majority of commenters agreed that AoR reevaluations are necessary, citing the large volumes of CO

that may be injected, the uncertainty of CO

movement in the subsurface, the need to incorporate monitoring data, and the lack of experience in tracking large volumes of CO

. EPA agrees with commenters who supported the proposed approach for periodic AoR reevaluation. EPA believes that in order to sufficiently protect USDWs from endangerment, the CO

plume and pressure front should be tracked over the lifetime of the project using an iterative approach of site characterization, modeling, and monitoring. Periodic AoR reevaluation, as required in today's final action, is an integral component of this approach. EPA believes that the AoR reevaluation is an efficient use of resources and notes that if the CO

plume and pressure front are moving as predicted, the burden of the AoR reevaluation requirement will be minimal. In cases where the observed monitoring data agree with model predictions, an AoR reevaluation may simply consist of a demonstration to the Director that monitoring data validate modeled predictions.

Several commenters supported the proposed reevaluation timeframe of a minimum of 10 years or when monitoring and modeling data differ. However, many commenters believed that 10 years was too infrequent and suggested more frequent reevaluations or basing the reevaluation timeframe on a performance standard, given the potential risks posed by these projects to USDWs and the general uncertainty related to CO

movement at GS projects. Based on consideration of public comments, EPA agrees that reevaluations of the AoR every 10 years may not be sufficient, and today's final approach requires an AoR reevaluation at a minimum of once every five years, or when monitoring data and modeling predictions differ significantly. EPA believes that this revised frequency addresses commenters' concerns about the inherent uncertainties in modeling CO

movement, the emerging nature of GS technology, and the importance of targeting monitoring activities where

risk of endangerment to USDWs is greatest.

2. Corrective Action Requirements

EPA proposed that owners or operators of Class VI wells identify and evaluate all artificial penetrations within the AoR. Based on this review, owners or operators, in consultation with the Director, would identify the wells that need corrective action to prevent the movement of CO

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. This inventory and review process is similar to what is required of Class I and Class II injection well owners or operators. The proposal did not prescribe any specific methods or cements that should be used for corrective action, but stated that the methods used must be appropriate for CO

injection and compatible with all fluids.

Phased corrective action:

Due to the anticipated large size of the AoR for Class VI wells, EPA proposed allowing owners or operators to conduct corrective action on a phased basis during the lifetime of the project, at the discretion of the Director. In these cases, corrective action would not need to be conducted throughout the entire AoR prior to injection. Corrective action would only be necessary in areas near the injection well with a high certainty of CO

exposure during the first years of injection as informed by site-characterization data and model predictions. Artificial penetrations in areas farther from the injection well would be addressed after injection has commenced, but prior to CO

plume and pressure front movement into that area. The proposal sought comment on allowing for phased corrective action at the discretion of the Director.

The majority of commenters agreed with EPA's proposed approach of allowing phased corrective action at the Director's discretion. Most commenters believed that phased corrective action is a practical and cost effective approach. However, some commenters argued that phased corrective action should be allowed at all sites and not left to Director's discretion. Others argued that specific timeframes (

e.g.,

two to five years) for corrective action should be mandated to ensure that wells are addressed prior to plume movement into that area. Several State commenters disagreed with EPA's proposal to allow phased corrective action and believed that all corrective action should be completed prior to injection.

EPA agrees with commenters who supported allowing for phased corrective action at the discretion of the Director, and retains this provision in today's final regulation at § 146.84(d). Phased corrective action may provide many benefits to a project including spreading corrective action costs throughout the life of a GS project, avoiding delays in project start-up, allowing for use of future, improved corrective action techniques, and addressing unanticipated changes in the movement of the CO

plume or pressure front. Given the wide range of conditions and site-specific considerations unique to GS sites, Director's discretion is appropriate as Directors are in the best position to make decisions about the appropriateness of phased corrective action.

EPA agrees with commenters that corrective action on wells should be completed in advance of the anticipated arrival of the CO

plume or pressure front. However, it is not appropriate to set a specific timeframe for completing corrective action because CO

plume movement will be site-specific and may change over the life of a GS project. Instead, decisions regarding the timing of corrective action will be incorporated into the approved AoR and corrective action plan for each project based on project-specific information. The Agency is developing guidance on AoR and corrective action for GS sites, which addresses the types of issues these commenters raise.

C. Injection Well Construction

Today's rule finalizes requirements (at § 146.86) for the design and construction of Class VI wells using materials that can withstand contact with CO

over the life of the GS project in order to prevent movement of fluids into USDWs.

Proper construction of injection wells provides multiple layers of protection to ensure the prevention of fluid movement into USDWs. Today's final approach is based on existing construction requirements for surface casing, long-string casing, and tubing and packer for Class I hazardous waste injection wells, with modifications to address the unique physical characteristics of CO

, including its buoyancy relative to other fluids in the subsurface and the potential presence of impurities in captured CO

. In addition to protecting USDWs, today's comprehensive construction requirements respond to concerns about GS project safety and potential impacts on USDWs.

Surface and long-string casing requirements:

EPA proposed that surface casing for a Class VI well be set through the base of the lowermost USDW and cemented to the surface; and, that the long-string casing be cemented in place along its entire length from the injection zone to the surface. This is consistent with existing requirements for Class I hazardous waste injection wells.

EPA proposed the enhanced casing requirements for Class VI wells to maintain additional barriers to CO

leakage outside of the injection zone, and solicited comment on the proposed construction requirements related to the depth of the surface casing. Commenters objecting to the proposed requirements argued that the surface casing and long-string casing requirements may preclude GS in areas with very deep USDWs. They commented that, under certain circumstances, it would be too burdensome or technologically infeasible to construct the casings to the required depth. Commenters also argued that these requirements would adversely impact acceptance of GS and would slow down large-scale deployment of this climate change mitigation technology. These commenters recommended that the rule allow more flexibility regarding surface and long-string casing depths to accommodate varied conditions where Class VI wells may be constructed throughout the U.S. Other commenters agreed with the Agency's proposed long-string casing requirements for Class VI wells, stating that the requirements prevent undesirable migration of fluids behind the casing and provide maximum zonal isolation.

The Agency disagrees that the surface and long-string casing requirements are not flexible enough to address the varied geological formations and aquifer characteristics across the United States. EPA adds that cementing of deep wells has been performed successfully by owners or operators of Class I wells at depths up to 12,000 feet (USEPA, 2001). Protection of USDWs from endangerment, regardless of their depth or stratigraphic location, is the primary mission of the UIC program and the purpose of all requirements for injection wells.

However, in order to address concerns about lack of flexibility while ensuring USDW protection, EPA modified the surface casing requirements at § 146.86(b) to provide owners or operators flexibility regarding how to complete the surface casing in situations where the cement cannot be re-circulated to the surface. The regulation does not specify how the cementing

must be accomplished (

e.g.,

single or staged circulation); instead, it allows flexibility for owners or operators to propose alternative cementing methods that provide a sufficient cement seal and prevent fluid movement through any channels adjacent to the well bore under all circumstances in order to protect USDWs from endangerment. The Agency is retaining the requirements as proposed for long-string casing construction for Class VI wells. To further address comments on deep injection wells, today's final rule includes requirements at § 146.95 for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells operating under injection depth waivers must comply with additional construction requirements to ensure that wells used to inject above or between USDWs are protective and will not endanger USDWs. See section III.D for a detailed discussion of the waiver approach.

Cement and well materials requirements:

EPA proposed that all materials used in the construction of Class VI wells must be compatible with fluids with which the materials may be expected to come into contact, and that cement and cement additives must be compatible with the CO

stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the project. The Agency requested comment on cementing of the long-string casing, including the use of degradation-resistant well construction materials, such as acid-resistant cements and corrosion-resistant casing for Class VI wells.

Commenters who disagreed with EPA's proposed requirements for well materials and cement argued that the specific use of acid-resistant/corrosion-resistant cement is excessive. They expressed concerns that the proposed rule did not reflect actual field experience or recent laboratory research and they encouraged the Agency to defer imposing these additional requirements until further field experience and research are conducted. These commenters suggested that the Agency allow Director's discretion in determining the standards for casing and cementing on a case-by-case basis.

Commenters who supported the use of acid-resistant/degradation-resistant cement and materials asserted that their use is essential to reduce the risk of leaks associated with compromised mechanical integrity and to protect USDWs from endangerment, at a modest cost relative to the long-term benefit of well integrity.

Some commenters supported the use of Class II well construction standards for Class VI wells. These commenters indicated that the oil and gas industry has several decades of CO

injection experience, which, they believe demonstrates that Class II construction standards are sufficient to protect human health and the environment. EPA recognizes that the oil and gas industry has experience injecting CO

and that many of the wells used for ER may be suitable for GS. However, GS is sufficiently different from Class II ER operations to warrant today's tailored construction requirements for Class VI wells at § 146.86. For example, the volume of CO

anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Additionally, formation pressures are expected to be higher as a result of Class VI injection when compared to formation pressures associated with Class II ER projects. Today's final rule does provide for grandfathering of construction for wells transitioning to GS provided the owner or operator can demonstrate to the Director (during the re-permitting process) that wells were constructed and cemented with materials compatible with GS activities; see section II.H.

EPA agrees with commenters that cement additives and degradation resistant materials are crucial to proper construction of Class VI wells. Because of the numerous approaches developed for cement design and due to continually evolving well materials and construction technology (as evidenced by oil and gas industry experience demonstrating the effectiveness of existing cementing materials and procedures), EPA believes it would not be prudent or feasible to specify design standards for cement or cementing procedures, such as wellbore conditioning. Instead, the final rule specifies a performance standard at § 146.86(b)(1) that all casing and cementing or other materials used in the construction of each well have sufficient structural strength, be designed for the life of the GS project, be compatible with the injected fluids, and prevent fluid movement into or between USDWs.

Tubing and packer requirements:

EPA proposed that all Class VI wells be constructed with tubing and a packer that is set opposite a cemented interval at a location approved by the Director, and sought comment on this approach. Several commenters agreed with the proposed approach for tubing and packer of Class VI wells, saying that tubing

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