U.S. Environmental Protection Agency 

Documentation of OMB Review Under Executive Order 12866 

Title of Action: 

Docket#: FRL#: RIN:

This action was submitted to the Office of Management and Budget (OMB) for review under Executive Order (E.O.) 

12866, titled Regulatory Planning and Review (58 FR 51735, October 4, 1993). Whenever EPA makes publicly available 

a regulatory action that was reviewed under E.O. 12866, section 6(a)(3)(E) of the E.O. directs the Agency to also: 

(1) Make available to the public a copy of the information that was provided to OMB’s Office of Information and 

Regulatory Affairs (OIRA) for review under the E.O., i.e., the text of the draft regulatory action and, if applicable, 

an assessment of the potential costs and benefits, as well as additional information for those actions that are 

determined to be economically significant under the E.O. (Information requirements are described in sections 

6(a)(3)(B) and (C)). 

(2) Identify for the public any substantive changes between the draft submitted to OIRA and the action that was 

subsequently issued, using a method that is complete, clear, and simple. 

(3) Identify for the public those substantive changes made at the suggestion or recommendation of OIRA.

For this regulatory action, were substantive changes made to information reviewed under E.O. 

12866? [Please check the appropriate answer.]

No. [In the docket, include the information identified in item (1) below.]

Yes. [In the docket, include the information identified in items (1) – (3) below.]

Accordingly, the Agency has included this form and the following information in the public 

docket for this regulatory action: [Please check the appropriate information.]

(1) A copy of the information that was provided to OIRA for review under the E.O. 

(2) Documentation of any substantive changes made to the draft regulatory text that was 

submitted to OIRA when compared with what was subsequently made publicly available.

The documentation is provided on the pages following this form. Changes made at the 

suggestion or recommendation of OIRA, if any, are clearly identified through attribution to 

OIRA. EPA has used one or more of the following methods to note changes: [Select the 

appropriate option(s).]

(a) Redline-Strikeout – A copy of the draft regulatory action submitted, using redlinestrikeout to show the substantive changes that were made.

(b) Hand Markup – A copy of the draft regulatory action submitted, using handwritten notes 

to show the substantive changes that were made.

(c) Note to the file - A document that identifies the substantive changes that were made, 

with page and paragraph references to the draft regulatory action that was submitted.

If you have any questions about this regulatory action or this documentation, please call the 

contact:

Name: Email: Phone: 

Revised 05/05/2010 

Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2)

Geologic Sequestration (GS) Wells - Final Rule

EPA-HQ-OW-2008-0390 2040-AE98

Stephanie Flaharty flaharty.stephanie@epa.gov (202) 564-5072
The following documents are attached as documentation of OMB review and subsequent 

changes under Executive Order 12866: 

• The draft Federal Register notice submitted to OMB to initiate Interagency review. 

• A track changed version of the Federal Register notice following finalization of 

OMB/Interagency review. 

To review the unmarked final preamble and rule, please see the Federal Register

publication. A link to the final rule is available at: 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.
Page 1 of 259

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 124, 144, 145, and 146

[EPA-HQ-OW-2008-0390 FRL-XXXX-X]

RIN 2040-AE98

Federal Requirements Under the Underground Injection Control (UIC) Program 

for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

SUMMARY: This action finalizes minimum Federal requirements under the Safe 

Drinking Water Act (SDWA) for underground injection of carbon dioxide (CO2) for the 

purpose of geologic sequestration (GS). GS is one of a portfolio of options that could be 

deployed to reduce CO2 emissions to the atmosphere and help to mitigate climate change. 

This final rule applies to owners or operators of wells that will be used to inject CO2 into 

the subsurface for the purpose of long-term storage. It establishes a new class of well, 

Class VI, and sets minimum technical criteria for the permitting, geologic site 

characterization, area of review (AoR) and corrective action, financial responsibility, well 

construction, operation, mechanical integrity testing (MIT), monitoring, well plugging, 

post-injection site care (PISC), and site closure of Class VI wells for the purposes of 

protecting underground sources of drinking water (USDWs). The elements of this 

rulemaking are based on the existing Underground Injection Control (UIC) regulatory 

framework, with modifications to address the unique nature of CO2 injection for GS. This 

rule will help ensure consistency in permitting underground injection of CO2 at GS 

operations across the United States and provide requirements to prevent endangerment of 

USDWs in anticipation of the eventual use of GS to reduce CO2 emissions to the 

atmosphere and to mitigate climate change. 

DATES: This regulation is effective [INSERT DATE 60 DAYS AFTER 

PUBLICATION OF THE RULE IN THE FEDERAL REGISTER]. For purposes of 

judicial review, this final rule is promulgated as of 1 p.m., Eastern time on [INSERT 

DATE XX DAYS AFTER THE DATE OF PUBLICATION OF THE RULE IN THE 
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FEDERAL REGISTER], as provided in 40 CFR 23.7.

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

CO2 into the subsurface for the purposes of GS. Regulated categories and entities include, 

but are not limited to, the following:

------------------------------------------------------------------------

 Examples of regulated

 Category entities

------------------------------------------------------------------------
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Private................................... Owners or Operators of CO2 injection wells used 

for Class VI GS.

------------------------------------------------------------------------

Private................................... Owners or Operators of existing CO2 injection wells 

transitioning from Class I, II, or Class V injection 

activities to Class VI GS.

------------------------------------------------------------------------

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

CO2 Carbon Dioxide
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DOE United States Department of Energy

ECBM Enhanced Coal Bed Methane

EFAB Environmental Financial Advisory Board

EGR Enhanced Gas Recovery

EIS Environmental Impact Statement

EISA Energy Independence and Security Act of 2007

EO Executive Order

EOR Enhanced Oil Recovery

EPA United States Environmental Protection Agency

ER Enhanced Recovery

FPR Federally Permitted Releases

GAO General Accountability Office

GHG Greenhouse Gas

GS Geologic Sequestration

Gt CO2 Gigatons CO2

GWPC Ground Water Protection Council

HHS United States Department of Health and Human Services

ICR Information Collection Request

IOGCC Interstate Oil and Gas Compact Commission

IPCC Intergovernmental Panel on Climate Change 

IRS United States Internal Revenue Service

LBNL Lawrence Berkeley National Laboratory

Mg/L Milligrams per liter
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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
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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
Page 7 of 259

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 
Page 8 of 259

differences in pressure or density.

Capillary force: adhesive force that holds a fluid in a capillary or a pore space. 

Capillary force is a function of the properties of the fluid, and surface and dimensions of 

the space. If the attraction between the fluid and surface is greater than the interaction of 

fluid molecules, the fluid will be held in place.

Caprock: see confining zone.

Carbon dioxide plume: the extent underground, in three dimensions, of an injected 

carbon dioxide stream.

Carbon dioxide (CO2) stream: carbon dioxide that has been captured from an 

emission source (e.g., a power plant), plus incidental associated substances derived from 

the source materials and the capture process, and any substances added to the stream to 

enable or improve the injection process. This subpart does not apply to any carbon 

dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261.

Casing: the pipe material placed inside a drilled hole to prevent the hole from 

collapsing. The two types of casing in most injection wells are 1) surface casing, the 

outer most casing that extends from the surface to the base of the lowermost USDW and 

2) long-string casing, which extends from the surface to or through the injection zone.

Cement: material used to support and seal the well casing to the rock formations 

exposed in the borehole. Cement also protects the casing from corrosion and prevents 

movement of injectate up the borehole. The composition of the cement may vary based 

on the well type and purpose; cement may contain latex, mineral blends, or epoxy.

Confining zone: a geologic formation, group of formations, or part of a formation 

stratigraphically overlying the injection zone(s) that acts as barrier to fluid movement. 

For Class VI wells operating under an injection depth waiver, confining zone means a 
Page 9 of 259

geologic formation, group of formations, or part of a formation stratigraphically 

overlying and underlying the injection zone(s).

Corrective action: the use of Director-approved methods to ensure that wells within 

the area of review do not serve as conduits for the movement of fluids into USDWs.

Corrosive: having the ability to wear away a material by chemical action. Carbon 

dioxide mixed with water forms carbonic acid, which can corrode well materials.

Dip: the angle between a planar feature, such as a sedimentary bed or a fault, and the 

horizontal plane. The dip of subsurface rock layers can provide clues as to whether 

injected fluids may be contained. 

Director: the person responsible for permitting, implementation, and compliance of 

the UIC program. For UIC programs administered by EPA, the Director is the EPA 

Regional Administrator or his/her delegatee; for UIC programs in Primacy States, the 

Director is the person responsible for permitting, implementation, and compliance of the 

State, Territorial, or Tribal UIC program.

Ductility: the ability of a material to sustain stress until it fractures. 

Enhanced Coal Bed Methane (ECBM) recovery: the process of injecting a gas (e.g., 

CO2) into coal, where it is adsorbed to the coal surface and methane is released. The 

methane can be captured and produced for economic purposes; when CO2 is injected, it 

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

Enhanced Oil or Gas Recovery (EOR/EGR): typically, the process of injecting a fluid 

(e.g., water, brine, or CO2) into an oil or gas bearing formation to recover residual oil or 

natural gas. The injected fluid thins (decreases the viscosity) and/or displaces small 

amounts of extractable oil and gas, which is then available for recovery. This is also 

known as secondary or tertiary recovery.
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Flapper valve: a valve consisting of a hinged flapper that seals the valve orifice. In 

Class VI wells, flapper valves can engage to shut off the flow of the CO2 when 

acceptable operating parameters are exceeded.

Formation or geological formation: a layer of rock that is made up of a certain type of 

rock or a combination of types. 

Geologic sequestration (GS): the long-term containment of a gaseous, liquid or 

supercritical carbon dioxide stream in subsurface geologic formations. This term does not 

apply to CO2 capture or transport.

Geologic sequestration project: for the purpose of this regulation, an injection well or 

wells used to emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW; or, wells used for geologic sequestration of carbon dioxide that have 

been granted a waiver of the injection depth requirements pursuant to requirements at 

§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 

CO2 stream.

Injection zone: a geologic formation, group of formations, or part of a formation that 

is of sufficient areal extent, thickness, porosity, and permeability to receive CO2 through 

a well or wells associated with a geologic sequestration project.
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Lithology: the description of rocks, based on color, mineral composition and grain 

size.

Mechanical integrity (MI): The absence of significant leakage within the injection 

tubing, casing, or packer (known as internal mechanical integrity), or outside of the 

casing (known as external mechanical integrity). 

Mechanical Integrity Test: a test performed on a well to confirm that a well maintains 

internal and external mechanical integrity. MITs are a means of measuring the adequacy 

of the construction of an injection well and a way to detect problems within the well 

system.

Model: a representation or simulation of a phenomenon or process that is difficult to 

observe directly or that occurs over long time frames. Models that support GS can predict 

the flow of CO2 within the subsurface, accounting for the properties and fluid content of 

the subsurface formations and the effects of injection parameters.

Packer: a mechanical device that seals the outside of the tubing to the inside of the 

long string casing, isolating an annular space. 

Pinch-out: a situation where a formation thins to zero thickness.

Pore space: open spaces in rock or soil. These are filled with water or other fluids 

such as brine (i.e., salty fluid). CO2 injected into the subsurface can displace pre-existing 

fluids to occupy some of the pore spaces of the rocks in the injection zone.

Post-injection site care: appropriate monitoring and other actions (including 

corrective action) needed following cessation of injection to ensure that USDWs are not 

endangered, as required under §146.93.
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Pressure front: the zone of elevated pressure that is created by the injection of carbon 

dioxide into the subsurface. For GS projects, the pressure front of a CO2 plume refers to 

the zone where there is a pressure differential sufficient to cause the movement of 

injected fluids or formation fluids into a USDW.

Saline formations: subsurface geographically extensive sedimentary rock layers 

saturated with waters or brines that have a high total dissolved solids (TDS) content (i.e., 

over 10,000 mg/L TDS). 

Site closure: the point/time, as determined by the Director following the requirements 

under §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 (31.1o

C for CO2) and critical 

pressure (73.8 bar for CO2). Supercritical fluids have physical properties intermediate to 

those of gases and liquids. 

Total Dissolved Solids (TDS): the measurement, usually in mg/L, for the amount of 

all inorganic and organic substances suspended in liquid as molecules, ions, or granules. 

For injection operations, TDS typically refers to the saline (i.e., salt) content of watersaturated underground formations.

Transmissive fault or fracture: a fault or fracture that has sufficient permeability and 

vertical extent to allow fluids to move between formations.
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Trapping: the physical and geochemical processes by which injected CO2 is 

sequestered in the subsurface. Physical trapping occurs when buoyant CO2 rises in the 

formation until it reaches a layer that inhibits further upward migration or is immobilized 

in pore spaces due to capillary forces. Geochemical trapping occurs when chemical 

reactions between dissolved CO2 and minerals in the formation lead to the precipitation 

of solid carbonate minerals.

Underground Source of Drinking Water (USDW): an aquifer or portion of an aquifer 

that supplies any public water system or that contains a sufficient quantity of ground 

water to supply a public water system, and currently supplies drinking water for human 

consumption, or that contains fewer than 10,000 mg/l total dissolved solids and is not an 

exempted aquifer.

Viscosity: the property of a fluid or semi-fluid that offers resistance to flow. As a 

supercritical fluid, CO2 is less viscous than water and brine. 

Table of Contents

I. General Information

II. Background

A. Why is EPA Taking This Regulatory Action?

1. What is GS? 

2. Why is GS Under Consideration as a Climate Change Mitigation

Technology? 

3. What are the Unique Risks to USDWs Associated with GS? 

B. Under What Authority is This Rulemaking Promulgated? 

C. How Does This Rulemaking Relate to the Greenhouse Gas (GHG) Reporting 

Program?
Page 14 of 259

D. How Does This Rulemaking Relate to Other Federal Authorities and GS and 

CCS Activities?

E. What Steps Did EPA Take to Develop This Rulemaking? 

1. Developing Guidance for Experimental GS Projects

2. Conducting Research

a. Tracking the Results of CO2 GS Research Projects

b. Tracking State Regulatory Efforts

c. Conducting Technical Workshops on Issues Associated with 

CO2 GS

3. Conducting Stakeholder Coordination and Outreach

4. Proposed Rulemaking

5. Notice of Data Availability and Request for Comment

F. How Will EPA’s Adaptive Rulemaking Approach Incorporate Future 

Information and Research?

G. How Does This Action Affect UIC Program Implementation? 

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

III. What is EPA’s Final Regulatory Approach?

A. Site Characterization

B. Area of Review (AoR) and Corrective Action

1. AoR Requirements

2. Corrective Action Requirements

C. Injection Well Construction

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

2. Notice of Data Availability and Request for Comment

3. Final Approach

E. Injection Well Operation

F. Testing and Monitoring

1. Testing and Monitoring Plan

2. CO2 Stream Analysis

3. Mechanical Integrity Testing (MIT)

4. Corrosion Monitoring

5. Ground Water/Geochemical Monitoring

6. Pressure Fall-Off Testing

7. CO2 Plume and Pressure Front Monitoring/Tracking

8. Surface Air/Soil Gas Monitoring

9. Additional Requirements

G. Recordkeeping and Reporting

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

2. How Must Information Be Submitted?

3. What are the Recordkeeping Requirements under This Rule?

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

1. Injection Well Plugging

2. Post-Injection Site Care (PISC)

3. Site Closure

I. Financial Responsibility
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J. Emergency and Remedial Response

K. Involving the Public in Permitting Decisions

L. Duration of a Class VI Permit

IV. Cost Analysis

A. National Benefits and Costs of the Rule

1. National Benefits Summary

a. Relative Risk Framework – Qualitative Analysis

b. Other Nonquantified Benefits

2. National Cost Summary

a. Cost of the Selected RA

b. Nonquantified Costs and Uncertainties in Cost Estimates

c. Supplementary Costs and Uncertainties in Cost Estimates

B. Comparison of Benefits and Costs of RAs Considered

1. Costs Relative to Benefits; Maximizing Net Social Benefits

2. Cost Effectiveness and Incremental Net Benefits

C. Conclusions

V. Statutory and Executive Order Review

VI. References

II. Background 

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

CO2 for the purpose of GS. The purpose of the rulemaking is to ensure that GS is 

conducted in a manner that protects USDWs from endangerment. GS refers to a suite of 

technologies that can be deployed to reduce CO2 emissions to the atmosphere and help 

mitigate climate change. Due to the large CO2 injection volumes anticipated at GS 
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projects, the relative buoyancy of CO2, its mobility within subsurface geologic 

formations, its corrosivity in the presence of water, and the potential presence of 

impurities in the captured CO2 stream, the Agency has determined that tailored 

requirements, modeled on the existing UIC regulatory framework, are necessary to 

manage the unique nature of CO2 injection for GS. This final rule applies to owners or 

operators of wells that will be used to inject CO2 into the subsurface for the purpose of 

GS. 

To support today’s final regulatory action, EPA proposed Federal Requirements Under 

the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic 

Sequestration (GS) Wells (73 FR 43492) on July 25, 2008; and the Agency published a 

supplemental publication, Federal Requirements Under the Underground Injection 

Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells; 

Notice of Data Availability and Request for Comment (74 FR 44802) on August 31, 2009. 

Final Class VI requirements are informed, in part, by comments and information 

submitted in response to these publications. 

Today’s rule defines a new class of injection well (Class VI), along with technical criteria 

that tailor the existing UIC regulatory framework to address the unique nature of CO2

injection for GS. It sets minimum technical criteria for Class VI wells to protect USDWs

from endangerment, including: 

• Site characterization that includes an assessment of the geologic, hydrogeologic, 

geochemical, and geomechanical properties of the proposed GS site to ensure that 

Class VI wells are located in suitable formations. 

• Computational modeling of the AoR for GS projects that accounts for the physical 

and chemical properties of the injected CO2 and is based on available site 

characterization, monitoring, and operational data. 

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

verify that the CO2 plume and the associated area of elevated pressure are moving as 

predicted within the subsurface.
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• Well construction using materials that can withstand contact with CO2 over the life of 

the GS project. 

• Robust monitoring of the CO2 stream, injection pressures, integrity of the injection 

well, ground water quality and geochemistry, and monitoring of the CO2 plume and 

position of the pressure front throughout injection.

• Comprehensive post-injection monitoring and site care following cessation of 

injection to show the position of the CO2 plume and the associated area of elevated 

pressure to demonstrate that neither pose an endangerment to USDWs.

• Financial responsibility requirements to ensure that funds will be available for all 

corrective action, injection well plugging, post-injection site care (PISC), site closure, 

and emergency and remedial response.

Today’s rule will help ensure consistency in permitting underground injection of CO2 at 

GS operations across the United States (US) and provide requirements to prevent 

endangerment of USDWs in anticipation of the potential role of carbon capture and 

storage (CCS) in mitigating climate change. Today’s action also briefly discusses the 

relationship between today’s rule and other Federal and State activities related to GS and 

CCS in Sections II.C and D, and E.2.b, and III.F.2.

A. Why is EPA Taking This Regulatory Action?

1. What is GS? 

GS is the process of injecting CO2 into deep subsurface rock formations for long-term 

storage. It is part of the process known as CCS. 

CO2 is first captured from fossil-fueled power plants or other emission sources. To 

transport captured CO2 for GS, operators typically compress CO2 to convert it from a 

gaseous state to a supercritical state (IPCC, 2005; IEA, 2008). CO2 exists as a 

supercritical fluid at high pressures, and in this state it exhibits properties of both a liquid 

and a gas. After capture and compression, the CO2 is delivered to the sequestration site, 

frequently by pipeline, or alternatively using tanker trucks or ships (WRI, 2007; IEA, 

2008).
Page 19 of 259

At the GS site, the CO2 is injected into deep subsurface rock formations through one or 

more wells, using technologies developed and refined by the oil, gas, and chemical 

manufacturing industries over the past several decades. It is expected that the CO2 will be 

injected at a depth greater than 800 meters (2,625 feet) such that a sufficiently high 

pressure and temperature will be maintained to keep the CO2 in a supercritical state. 

When injected into an appropriate receiving formation, CO2 is sequestered by a 

combination of trapping mechanisms, including physical and geochemical processes

(Benson, 2008). Physical trapping occurs when the relatively buoyant CO2 rises in the 

formation until it reaches a stratigraphic zone with low permeability (i.e., geologic 

confining system) that inhibits further upward migration. Physical trapping can also occur 

as residual CO2 is immobilized in formation pore spaces as disconnected droplets or 

bubbles at the trailing edge of the plume due to capillary forces. A portion of the CO2 will 

dissolve from the pure fluid phase into native ground water and hydrocarbons. 

Preferential sorption occurs when CO2 molecules attach to the surfaces of coal and 

certain organic-rich shales, displacing other molecules such as methane. Geochemical 

trapping occurs when chemical reactions between the dissolved CO2 and minerals in the 

formation lead to the precipitation of solid carbonate minerals (IPCC, 2005). The 

timeframe over which CO2 will be trapped by these mechanisms depends on properties of 

the receiving formation and the injected CO2 stream. 

The effectiveness of physical CO2 trapping is demonstrated by natural analogs in a range 

of geologic settings where CO2 has remained trapped for millions of years (Holloway et 

al., 2007). For example, CO2 has been trapped for more than 65 million years under the 

Pisgah Anticline, northeast of the Jackson Dome in Mississippi and Louisiana (IPCC, 

2005). Other natural CO2 sources include the following geologic domes: McElmo Dome, 

Sheep Mountain, and Bravo Dome in Colorado and New Mexico. 

Many of the injection and monitoring technologies that may be applicable to GS are 

commercially available today and will be more widely demonstrated over the next 10 to 
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15 years (Dooley et al, 2009). The oil and natural gas industry in the United States has 

over 35 years of experience of injection and monitoring of CO2 in the deep subsurface for 

the purposes of enhancing oil and natural gas production. This experience provides a 

strong foundation for the injection and monitoring technologies that will be needed for 

commercial-scale CCS. US and international experience with enhanced recovery (ER)

and commercial CCS projects, as well as ongoing research, demonstration, and 

deployment programs throughout the world, provide critical experience and information 

to inform the safe injection of CO2. For additional information about these projects, see 

section II.E.

Although CCS is occurring now on a relatively small scale, it could play a larger role in 

mitigating greenhouse gas (GHG) emissions from a wide variety of stationary sources. 

According to the Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2007, 

stationary sources contributed 67 percent of the total CO2 emissions from fossil fuel 

combustion in 2007 (USEPA, 2008a). These sources represent a wide variety of sectors 

amenable to CO2 capture: electric power plants (existing and new), natural gas processing 

facilities, petroleum refineries, iron and steel foundries, ethylene plants, hydrogen 

production facilities, ammonia refineries, ethanol production facilities, ethylene oxide 

plants, and cement kilns. Furthermore, 95 percent of the 500 largest stationary sources are 

within 50 miles of a candidate GS reservoir (Dooley et al., 2008). Estimated GS capacity 

in the United States is over 3,500 Gigatons CO2 (Gt CO2) (DOE, 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 is poised to 

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):
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• 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 CO2 are expected unless energy producers 

reduce CO2 emissions to the atmosphere. For example, CCS would enable the continued 

use of coal in a manner that greatly reduces the associated CO2 emissions while other 

safe and affordable alternative energy sources are developed in the coming decades. The 

development and deployment of clean coal technologies including CCS will be a key to

achieving domestic emissions reductions.

GS is one of a portfolio of options that could be deployed to reduce CO2 emissions to the 

atmosphere and help to mitigate climate change. Other options include energy 

conservation, efficiency improvements, and the use of alternative fuels and renewable 

energy sources. Ensuring that GS is done in a manner that is protective of USDWs will 

ensure the safety and efficacy of CO2 injection for GS.

While predictions about large-scale availability and the rate of CCS project deployment 

are subject to uncertainty, EPA analyses of Congressional climate change legislative 

proposals (the American Power Act of 2010 in the 111th Congress and the American 

Clean Energy and Security Act H.R. 2454) indicate that CCS has the potential to play a 

significant role in climate change mitigation scenarios. For example, analysis of the 
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American Power Act indicates that CCS technology could account for 10 percent of CO2

emission reductions in 2050 (reference: EPA's June 2010 American Power Act analysis: 

http://www.epa.gov/climatechange/economics/economicanalyses.html#apa2010). These 

results indicate that CCS could play an important role in achieving national greenhouse 

gas reduction goals. 

Today’s final rule provides minimum Federal requirements for the injection of CO2 to 

protect USDWs from endangerment as this key climate mitigation technology is 

developed and deployed. It clarifies requirements that apply to CO2 injection for GS, 

provides consistency in requirements across the US, and affords transparency about what 

requirements apply to owners or operators. 

3. What are the Unique Risks to USDWs Associated with GS? 

Large CO2 injection volumes associated with GS, the buoyant and mobile nature of the 

injectate, the potential presence of impurities in the CO2 stream, and its corrosivity in the 

presence of water could pose risks to USDWs. The purpose of today’s Class VI 

requirements for GS is to ensure the protection of USDWs, recognizing that an 

improperly managed GS project has the potential to endanger USDWs. Proper siting, 

well construction, operation, and monitoring of GS projects are therefore necessary to 

reduce the risk of USDW contamination. 

It is expected that GS projects will inject large volumes of CO2. These volumes will be 

much larger than are typically injected in other well classes regulated through the UIC 

program, and could cause significant pressure increases in the subsurface. Supercritical or 

gaseous CO2 in the subsurface is buoyant, and thus would tend to flow upwards if it were 

to come into contact with a migration pathway, such as a fault, fracture, or improperly 

constructed or plugged well. However, the pressures induced by injection will also 

influence CO2 and mobilized fluids to flow away from the injection well in all directions, 

including laterally, upwards and downwards. When CO2 mixes with formation fluids, a 

percentage of it will dissolve. The resulting aqueous mixture of CO2 and water will sink 

due to a density differential between the mixture and the surrounding fluids. CO2 is also 
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highly mobile in the subsurface (i.e., has a very low viscosity), and, in the presence of 

water, CO2 can be corrosive. These properties (of CO2), as well as the large volumes that 

may be injected for GS result in several unique challenges for protection of USDWs in 

the vicinity of GS sites from endangerment.

While CO2 itself is not a drinking water contaminant, CO2 in the presence of water forms 

a weak acid, known as carbonic acid, that, in some instances, could cause leaching and 

mobilization of naturally-occurring metals or other contaminants from geologic 

formations into ground water (e.g., arsenic, lead, and organic compounds). Another 

potential risk to USDWs is the presence of impurities in the captured CO2 stream, which 

may include drinking water contaminants such as hydrogen sulfide or mercury.

Additionally, pressures induced by injection may force native brines (naturally occurring 

salty water) into USDWs, causing degradation of water quality and affecting drinking 

water treatment processes. Research studies have shown that the potential migration of 

injected CO2 or formation fluids into a USDW could cause impairment through one or 

several of these processes (e.g., Birkholzer et al., 2008a). 

Today’s action addresses endangerment to USDWs by establishing new minimum

Federal requirements for the proper management of CO2 injection and storage in several 

program areas, including permitting, site characterization, AoR and corrective action, 

well construction, mechanical integrity testing (MIT), financial responsibility, 

monitoring, well plugging, PISC, and site closure. EPA believes that proper GS project 

management will appropriately mitigate potential risks of endangerment to USDWs 

posed by injection activities. 

B. Under What Authority is This Rulemaking Promulgated? 

Today’s rule is focused on USDW protection under the authority of Part C of SDWA

(SDWA, section 1421 et seq., 42 U.S.C. 300h et seq.). Part C of the SDWA requires EPA 

to establish minimum requirements for State

1

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

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

jurisdiction of States

2

.

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.” 

 2 The Submerged Lands Act and Territorial Submerged Lands Act define the scope of territorial 

jurisdiction of States and Territories respectively. 
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EPA promulgated administrative and permitting regulations, now codified in 40 CFR 

parts 144 and 146, on May 19, 1980 (45 FR 33290), and technical requirements, in 40 

CFR part 146, on June 24, 1980 (45 FR 42472). The regulations were subsequently 

amended on August 27, 1981 (46 FR 43156), February 3, 1982 (47 FR 4992), January 21, 

1983 (48 FR 2938), April 1, 1983 (48 FR 14146), May 11, 1984 (49 FR 20138), July 26, 

1988 (53 FR 28118), December 3, 1993 (58 FR 63890), June 10, 1994 (59 FR 29958), 

December 14, 1994 (59 FR 64339), June 29, 1995 (60 FR 33926), December 7, 1999 (64 

FR 68546), May 15, 2000 (65 FR 30886), June 7, 2002 (67 FR 39583), and November 

22, 2005 (70 FR 70513). 

Under the SDWA, the injection of any “fluid” must meet the requirements of the UIC 

program. A “fluid” is defined under 40 CFR 144.3 as any material or substance which 

flows or moves whether in a semisolid, liquid, sludge, gas or other form or state, and 

includes the injection of liquids, gases, and semisolids (i.e., slurries) into the subsurface. 

The types of fluids currently injected into wells subject to UIC requirements include: CO2

for the purposes of enhancing recovery of oil and natural gas, water that is stored to meet 

water supply demands in dry seasons, and wastes generated by industrial users. CO2 

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

C. How Does This Rulemaking Relate to the Greenhouse Gas (GHG) Reporting 

Program?

Today’s rulemaking under SDWA authority complements the CO2 Injection and GS 

Reporting rulemaking (subparts RR and UU) under the Greenhouse Gas Reporting 

Program’s Clean Air Act (CAA) authority developed by EPA’s Office of Air and 

Radiation (OAR).

The CAA defines EPA's responsibilities for protecting and improving the nation's air 

quality and the stratospheric ozone layer. The GHG Reporting Program requires reporting 

of GHG emissions and other relevant information from certain source categories in the 

US. The GHG Reporting Program, which became effective on December 29, 2009, 
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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

PLACEHOLDER FOR MODIFICATION DEPENDING ON TIMING OF RULES, EPA 

is amending 40 CFR part 98, which provides the regulatory framework for the GHG

Reporting Program, to add reporting requirements covering facilities that conduct GS 

(subpart RR) and all other facilities that inject CO2 underground (subpart UU). This data 

will inform Agency policy decisions under CAA sections 111 and 112 related to the use 

of CCS for mitigating GHG emissions. In combination with data from other subparts of 

the GHG Reporting Program, data from subpart UU and subpart RR will allow EPA to 

track the flow of CO2 across the CCS system. EPA will be able to reconcile subpart RR 

data on CO2 received with CO2 supply data in order to understand the quantity of CO2

supply that is geologically sequestered. 

Owners or operators subject to today’s rule are required to report under subpart RR. 

Subpart RR establishes reporting requirements for facilities that inject a CO2 stream for 

long-term containment into a subsurface geologic formation, including sub-seabed 

offshore formations. These facilities are required to develop and implement a site-specific 

Monitoring, Reporting, and Verification (MRV) plan which, once approved by EPA (in a 

process separate from the UIC permitting process), would be used to verify the amount of 

CO2 sequestered and to quantify emissions in the event that injected CO2 leaks to the 

surface. For more information on subpart RR, see [INSERT WEB REFERENCE OR 

FRN].

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 
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amount of CO2 sequestered and collecting data on any CO2 surface emissions from GS 

facilities as identified under subpart RR of part 98. 

The Agency acknowledges that there are similar data elements that must be reported 

pursuant to requirements in this action and those required to be reported under subpart 

RR. Specifically, owners or operators subject to both regulations must report the amount

(flow rate) of injected CO2. The Class VI and subpart RR rules differ, not only in purpose 

but in the specific requirements for the measurement unit and collection/reporting 

frequency. The UIC program Class VI rule requires that owners or operators report

information on the CO2 stream to ensure appropriate well siting, construction, operation, 

monitoring, post-injection site care, site closure, and financial responsibility to ensure 

protection of USDWS. Under subpart RR, owners or operators must report the amount 

(flow rate) of injected CO2 for the mass balance equation that will be used to quantify the 

amount of CO2 sequestered by a facility. 

Table II-1. Comparison of Reporting Requirements under Subpart RR and Select 

UIC Class VI Requirements

Reporting Requirement Subpart RR UIC Class VI 

Quantity of CO2 transferred 

onsite

Yes N/A

Quantity (flow rate) of CO2

injected

Yes Yes

Fugitive and vented emissions 

from surface equipment

Yes N/A

Quantity of CO2 produced with 

oil or natural gas (ER)

Yes N/A

Percent of CO2 estimated to 

remain with the oil and gas 

(ER)

Yes N/A
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Quantity of CO2 emitted from 

the subsurface

Yes N/A

Quantity of CO2 sequestered in 

the subsurface

Yes N/A

Cumulative mass of CO2

sequestered in the subsurface

Yes N/A

Monitoring plan for detecting 

air emissions

Yes Yes1

Monitoring plan for quantifying 

air emissions

Yes N/A

(1) UIC Class VI rule allows for surface air/soil gas monitoring for USDW protection. 

EPA requires reporting of other data to satisfy various programmatic needs. See section 

III of this preamble and associated requirements in subpart H of part 146 and the 

preamble to subpart RR for additional information on these specific requirements and 

their purpose. Table II-1 provides a comparison of the major reporting requirements in 

subpart RR and the extent to which there is overlap with Class VI requirements. For the 

monitoring plan listed in Table II-1, EPA will accept a UIC Class VI permit to satisfy 

certain subpart RR MRV plan requirements. However, the reporter must include 

additional information to outline how monitoring will achieve surface detection and 

quantification of CO2. EPA is pursuing ways to better integrate data management 

between the UIC and GHG Reporting Programs to ensure that data needs are harmonized 

and the burden to regulated entities is minimized. 

D. How Does This Rulemaking Relate to Other Federal Authorities and GS and 

CCS Activities?

While the SDWA provides EPA with the authority to develop regulations to protect 

USDWs from endangerment, it does not provide authority to develop regulations for all 

areas related to GS. EPA received a number of public comments on the proposal (73 FR 

43492, July 25, 2008) indicating that the Agency should further explore environmental 
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and regulatory issues beyond the scope of the proposed SDWA requirements for 

underground injection of CO2 for GS. 

In response to comments and as a result of the presidential memo “A Comprehensive 

Strategy on Carbon Capture and Storage” (http://www.whitehouse.gov/the-pressoffice/presidential-memorandum-a-comprehensive-federal-strategy-carbon-capture-andstorage), 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 INSERT WEBISTE WHEN FINAL. 

This section clarifies the distinction between today’s rulemaking and a number of other 

Federal rulemakings and initiatives. 

National Environmental Protection Act (NEPA): The SDWA UIC program is exempt 

from performing an Environmental Impact Statement (EIS) under section 101(2)(C) and 

an alternatives analysis under section 101(2)(E) of NEPA under a functional equivalence 

analysis. See Western Nebraska Resources Council v. US EPA, 943 F.2d 867, 871-72 (8th

Cir. 1991) and EPA Associate General Counsel Opinion (August 20, 1979).

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

Implementation: Sub-seabed CO2 injection for GS may, in certain circumstances, be 

defined as ocean dumping and subject to regulation under the MPRSA. Application of the 
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MPRSA would entail coordination of the permitting processes under the SDWA and 

MPRSA, pursuant to MPRSA sections 106(a) and (d). The substantive environmental 

protection requirements of both statutes would need to be satisfied prior to the 

commencement of GS. The MPRSA was enacted in 1972 and implements the London 

Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other 

Matter (the “London Convention”). In 1996, the Protocol to the London Convention (the 

“London Protocol”) was established. The Protocol stipulates that sub-seabed GS may be 

approved provided that: 1) disposal is into a sub-seabed geologic formation; 2) the CO2

stream consists overwhelmingly of CO2, with only incidental associated substances 

derived from the source material and capture and sequestration process used; and, 3) no 

wastes or other matter are added for the purpose of disposal. The US has signed, but has 

not yet ratified, the Protocol. In 2008, EPA submitted to Congress proposed changes to 

the MPRSA to implement the London Protocol and subsequent amendments to the 

Protocol. Among the proposed changes was a provision for the regulation of sub-seabed 

GS under the MPRSA. 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 (BOEM) Outer 

Continental Shelf Lands Act (OCSLA): BOEM, 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). 

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 (P.L. 110-140, HR 6) to prepare a report 

outlining a regulatory framework that could be applied to lands managed by the Bureau 
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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” (2009). This report affirms BLM’s role in appropriately 

managing Federal lands where GS injection projects may be sited. Additionally, the 

report makes recommendations regarding approaches for effective regulation of such 

activities under existing Federal authorities including the SDWA and UIC program

requirements.

United States Geological Survey (USGS) GS Capacity Methodology: USGS, another

agency within the Department of Interior and the primary Federal agency responsible for 

national geological research, has been an active participant with DOE and EPA at 

conferences and workshops on CCS. In 2008, in response to the EISA, USGS initiated 

development of a methodology for estimating the capacity to store CO2 in geologic 

formations of the US. While previous capacity estimates published by DOE/ National 

Energy Technology Laboratory (NETL) have been broad in scope (i.e., geologic basinwide), the USGS is focusing on small-scale, refined estimates. In 2009, USGS published 

a proposed, risk-based methodology for GS capacity estimation. This report,

Development of a Probabilistic Assessment Methodology for Evaluation of Carbon 

Dioxide Storage, is available at http://pubs.usgs.gov/of/2009/1035/ofr2009-1035.pdf

(USGS, 2009). USGS continues to work on capacity estimation as required under the 

EISA.

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

to the Energy Improvement and Extension Act of 2008, IRS, in consultation with EPA 

and DOE, issued guidance 2009-44 IRB (IRS, 2009) for taxpayers seeking to claim tax 

credits for capturing and sequestering CO2 from a qualified facility in the US. Under 

section 45Q of the Internal Revenue Code, a taxpayer who stores CO2 under the 

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

CO2 at ER projects; $20 per metric ton of qualified CO2 for non-ER projects). The 

taxpayer will be responsible for maintaining records for inspection by the IRS and tax 
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credit amounts will be adjusted for inflation for any taxable year beginning after 2009. 

The Internal Revenue Service published IRS Notice 2009-83 (available at:

http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860) to provide guidance regarding 

eligibility for the section 45Q tax credit, computation of the section 45Q tax credit, 

reporting requirements for taxpayers claiming the section 45Q tax credit, and rules 

regarding adequate security measures for “secure geological storage of CO2.”

Following publication of today’s final Class VI requirements, and as clarified in the 

guidance, taxpayers claiming the section 45Q tax credit must follow the appropriate UIC 

requirements (e.g., Class II or Class VI). The guidance also clarifies that taxpayers 

claiming section 45Q tax credit must follow the GS monitoring, reporting, and 

verification procedures finalized in the CO2 Injection and GS Reporting Rule that is part 

of the GHG Reporting Program. 

General Accountability Office Reports on GS and CCS: The United States General 

Accountability Office (GAO) has prepared, or is in the process of preparing, several 

reports for Congressional requestors related to the GS of CO2. In September 2008, GAO 

(GAO-08-1080) completed a report related to assessing the application of CCS 

technologies entitled: Climate Change – Federal Actions Will Greatly Affect the Viability 

of Carbon Capture and Storage as a Key Mitigation Option. GAO 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. In May 2010, GAO initiated a study with a focus on 

Geoengineering Climate Change including the use of GS to ameliorate greenhouse gas 

impacts. The report will also assess innovative technologies that may alter climate change 

in a positive manner.

EPA will continue to coordinate internally and with other Federal agencies to promote 

consistency in existing and future GS and CCS initiatives.
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E. What Steps Did EPA Take to Develop This Rulemaking? 

Today's final rule builds upon longstanding programmatic requirements for underground 

injection that have been in place since the 1980s and that are used to manage over 

800,000 injection wells nationwide. These programmatic requirements are designed to 

prevent fluid movement into USDWs by addressing the potential pathways through 

which injected fluids can migrate into USDWs and cause endangerment. 

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

how best to tailor existing UIC requirements to CO2 for GS. 

EPA has taken a number of steps in advance of today’s action including: 1) developing

guidance for experimental GS projects; 2) conducting research; 3) conducting stakeholder 

coordination and outreach; 4) issuing a proposed rulemaking and soliciting and reviewing 

public comment; and, 5) publishing a Notice of Data Availability (NODA) and Request 

for Comment to seek additional input on the rulemaking.

1. Developing Guidance for Experimental GS Projects

In 2007, EPA issued technical guidance to assist State and EPA Regional UIC programs 

in processing permit applications for pilot and other small scale experimental GS 

projects. The guidance was developed in cooperation with DOE and States, the Ground 

Water Protection Council (GWPC), the Interstate Oil and Gas Compact Commission 

(IOGCC), and other stakeholders. UIC Program Guidance # 83: Using the Class V 

Experimental Technology Well Classification for Pilot Carbon GS Projects (USEPA, 

2007) provides recommendations for permit writers regarding the use of the UIC Class V 

experimental technology well classification at demonstration GS projects while ensuring 

USDW protection. Program guidance #83 is available at: 

http://www.epa.gov/safewater/uic/wells_sequestration.html. EPA is preparing additional 

guidance for owners or operators and Directors regarding the use of Class V experimental 

technology wells for GS following promulgation of today’s rule. 

2. Conducting Research
Page 34 of 259

EPA participated in and supported research to inform today’s rulemaking including: 

supporting and tracking the development and results of national and international CO2 GS 

field and research projects; tracking GS-related State regulatory and legislative efforts; 

and conducting technical workshops on issues associated with CO2 GS. EPA described 

these research activities in detail in the proposed rule (July 2008) and the NODA and 

Request for Comment (August 2009). Additional information pertaining to these 

activities, which are summarized below, may be found in the rulemaking docket. 

a. Tracking the Results of CO2 GS Research Projects

To inform today’s rulemaking, EPA tracked the progress and results of national and 

international GS research projects. DOE leads field research on GS in the US in 

conjunction with the Regional Carbon Sequestration Partnerships (RCSPs). Currently, 

DOE’s NETL is developing and/or operating GS projects, a number of which have either 

completed injection or are in the process of injecting CO2. The seven RCSPs are 

conducting pilot and demonstration projects to study site characterization (including 

injection and confining formation information, core data and site selection information); 

well construction (well depth, construction materials, and proximity to USDWs); 

frequency and types of tests and monitoring conducted (on the well and on the project 

site); modeling and monitoring results; and injection operation (injection rates, pressures, 

and volumes, CO2 source and co-injectates). See section II.E.5 for more information on 

the status of these projects. 

Lawrence Berkeley National Laboratory (LBNL) research: EPA and DOE are jointly 

funding work by the LBNL to study potential impacts of CO2 injection on ground water 

aquifers and drinking water sources. The preliminary results have been used to inform 

today’s rulemaking and are described in detail in section II.E.5. 

In addition, EPA is funding an analysis by LBNL to integrate experimental and modeling 

information. LBNL will characterize ground water samples and aquifer mineralogies 

from select sites in the US and conduct controlled laboratory experiments to assess the 

potential mobilization of hazardous constituents by dissolved CO2. These experiments 
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will provide data that will be used to validate previous predictive modeling studies (of 

aquifer vulnerabilities to potential CO2 leaks) and may be applied to other GS sites in the 

future to assess the fate and migration of CO2-mobilized constituents in ground water. 

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

Agency scientists and engineers in targeted research to provide information to 

stakeholders and policy makers focused on areas of national environmental concern, 

including climate change and GS. In addition, ORD’s National Center for Environmental 

Research (NCER) provides extramural research grants for similar investigations through 

a competitive solicitation process. In the fall of 2009, NCER awarded six Science To 

Achieve Results (STAR) grants to recipients from major universities and institutions. The 

awards were granted to projects focused on Integrated Design, Modeling and Monitoring 

of GS of Anthropogenic CO2 to Safeguard Sources of Drinking Water. Work under the 

grants began in late 2009 and includes: evaluating potential impacts on drinking water 

aquifers of CO2-rich dissolved brines (Clemson University); reducing the hydrologic and 

geochemical uncertainties associated with CO2 sequestration in deep, saline reservoirs 

(University of Illinois-Urbana); assessing appropriate monitoring approaches at GS sites 

(University of Texas at Austin); integrating design, monitoring, and modeling of GS to 

assist in developing a practical methodology for characterizing risks to USDWs 

(University of Utah); conducting laboratory experiments on shallow aquifer systems to 

improve our understanding of geochemical and microbiological reactions under low 

pH/high CO2 stress (Columbia University); and, developing a set of computational tools 

to model CO2 and brine movement associated with GS (Princeton University).

International projects: EPA is tracking the progress of international GS efforts. The 

largest and longest-running commercial, large-scale projects in operation today include: 

the Sleipner Project in the Norwegian North Sea (operating since 1996); the Weyburn 

enhanced oil recovery (EOR) project in Saskatchewan, Canada (operating since 2000); 

the In Salah Gas Project in Algeria (operating since 2004); and Snohvit, also in offshore 

Norway in the Barents Sea (operating since 2008). Other projects EPA is tracking include 

Otway in Australia (operating since 2008); Ketzin in Germany (operating since 2008); 
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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 State’s regulatory efforts and approaches and sought input on State activities 

related to addressing GS in the proposed rule and NODA. At present, several States have 

published GS regulations, while others are investigating and developing strategies to 

address GS issues (e.g., management of multi-purpose injection wells in oil and gas 

reservoirs). EPA is tracking regulatory efforts in 18 States: Colorado, Illinois, Kansas, 

Kentucky, Louisiana, Michigan, Mississippi, Montana, New Mexico, New York, North 

Dakota, Oklahoma, Pennsylvania, Texas, Utah, Washington, West Virginia, and 

Wyoming. EPA is considering this information as it develops guidance on the primacy 

application and approval process for Class VI wells. Information about these State 

activities may be found in the docket for today’s rulemaking.

c. Conducting Technical Workshops on Issues Associated with CO2 GS 

EPA conducted a series of technical workshops with regulators, industry, utilities, and 

technical experts to identify and discuss questions relevant to the effective management 

of CO2 GS. The workshops included the following: Measurement, Monitoring, and 

Verification (in New Orleans, Louisiana on January 16, 2008); Geological Setting and 

AoR Considerations for CO2 GS (in Washington, DC on July 10-11, 2007); Well 
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Construction and MIT (in Albuquerque, New Mexico on March 14, 2007); a State 

Regulators’ Workshop on GS of CO2 (in collaboration with DOE in San Antonio, Texas 

on January 24, 2007); an International Symposium on Site Characterization for CO2

Geological Storage (co-sponsored with LBNL in Berkeley, California on March 20-22, 

2006); Risk Assessment for Geologic CO2 Storage (co-sponsored with the Ground Water 

Protection Council (GWPC) in Portland, Oregon on September 28-29, 2005); and 

Modeling and Reservoir Simulation for Geologic Carbon Storage (in Houston, Texas on 

April 6-7, 2005). Summaries of these workshops are available on EPA’s web site, at 

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

3. Conducting Stakeholder Coordination and Outreach

Throughout the rulemaking process, the Agency conducted public workshops and public 

hearings, consulted with specific groups, and EPA representatives 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 IOGCC have specific expertise 

regulating the injection of CO2 for the ER of oil and gas. EPA staff attended national 
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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 StateTribal 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 coregulators post-proposal. Summaries of the Tribal consultation conference calls are 

included in the docket for today’s rulemaking. 
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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 US 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. The Agency addressed questions and comments 

and HHS certified that the EPA satisfied consultation obligations under the SDWA. The 

memo certifying this consultation is available in the docket for today’s rulemaking. 

4. Proposed Rulemaking

On July 25, 2008, EPA published the proposed Federal Requirements Under the 

Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic 

Sequestration (GS) Wells (73 FR 43492). The Agency proposed a new class of injection 

well (Class VI), along with technical criteria for permitting Class VI wells that tailored 

the existing UIC regulatory framework to address the unique nature of CO2 injection for 

GS, including:

• Site characterization requirements that would apply to owners or operators of Class 

VI wells and require submission of extensive geologic, hydrogeologic, and 

geomechanical information on the proposed GS site to ensure that Class VI wells are 

located in suitable formations. EPA also proposed that owners or operators identify 
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additional containment/confining zones, if required by the Director, to improve 

USDW protection. 

• Enhanced AoR and corrective action requirements (e.g., plugging abandoned wells) 

to delineate the AoR for GS projects using computational modeling that accounts for 

the physical and chemical properties of all phases of the injected CO2 stream. EPA 

also proposed that owners or operators periodically reevaluate the AoR around the 

injection well to incorporate monitoring and operational data and verify that the CO2

is moving as predicted within the subsurface.

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

with CO2 over the life of the GS project. 

• Multi-faceted monitoring of the CO2 stream, injection pressures, the integrity of the 

injection well, groundwater quality above the confining zone(s), and the position of 

the CO2 plume and the pressure front throughout injection.

• Comprehensive post-injection monitoring and site care until it can be demonstrated 

that movement of the plume and pressure front have ceased and the injectate does not 

pose a risk to USDWs. 

• Financial responsibility requirements to ensure that financial resources would be 

available for corrective action, injection well plugging, post-injection site care, and 

site closure, and emergency and remedial response.

Following publication of the proposed rule, EPA initiated a 120-day public comment 

period, which the Agency extended by 30 days to accommodate requests from interested 

parties. The public comment period for the proposed rule closed on December 24, 2008. 

EPA received approximately 400 unique submittals from 190 commenters, including late 

submissions. Commenters represented States; industry (including the oil and gas industry, 

electric utilities, and energy companies); environmental groups; and associations 

(including water organizations and CCS associations). 

During the public comment period, the Agency held public hearings on the proposed rule 

in Chicago, IL on September 30, 2008 and in Denver, CO on October 2, 2008. The two 

hearings collectively drew approximately 100 people representing non-governmental 
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organizations, academia, industry, and other organizations. At the hearings, 29 people 

submitted oral comments. Transcripts of the public hearings are in the rulemaking docket 

(Docket ID Nos. EPA-HQ-OW-2008-0390-0185 and EPA-HQ-OW-2008-0390-0256). 

5. Notice of Data Availability and Request for Comment

Based on public comments received on the proposed rule, the Agency identified several 

topics on which it needed additional public comment. EPA published Federal 

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

Dioxide (CO2) Geologic Sequestration (GS) Wells; Notice of Data Availability and 

Request for Comment (74 FR 44802) on August 31, 2009, to describe additional topics 

and request comment. 

The NODA and Request for Comment presented new data and information from three 

DOE-sponsored RCSP projects including: 1) the Escatawpa, Mississippi project; 2) the 

Aneth Field, Paradox Basin project in Southeast Utah; and, 3) the Pump Canyon Site

project in New Mexico. Additional information on these projects and responses to 

comments received on the NODA and Request for Comment are available in the docket 

for this rulemaking. 

The NODA and Request for Comment also provided results of two GS-related modeling 

studies conducted by the LBNL. The first study (Birkholzer et al., 2008a) focused on the 

potential for GS to cause changes in ground water quality as a result of potential CO2

leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, 

mercury, lead, antimony, selenium, zinc, and uranium. Results from this model 

simulation suggest that if CO2 were to leak into a shallow aquifer, mobilization of lead 

and arsenic could occur, causing increases in the concentration of these trace elements in 

ground water and potential for drinking water standard exceedances. 

The second study modeled a theoretical scenario of GS in a sedimentary basin to 

demonstrate the potential for basin-scale hydrologic impacts of CO2 storage (Birkholzer 

et al., 2008b). Model results indicate that basin-wide pressure influences may be large 
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and that predicted pressure changes could move saline water upward into overlying 

aquifers if localized pathways, such as conductive faults, are present. This example 

illustrates the importance of basin-scale evaluation of reservoir pressures and far-field 

pressures resulting from CO2 injection. 

Additional information on LBNL’s research and responses to comments received on the 

NODA and Request for Comment are available in the docket for this rulemaking. 

The full publications on the LBNL research are also available on LBNL’s web site at 

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

Lastly, the NODA and Request for Comment presented an alternative to address public 

comments and concerns about the proposed injection depth requirements for Class VI 

wells. Section III.D of today’s action contains more information on this subject. 

Following publication of the NODA and Request for Comment, EPA initiated a 45-day 

public comment period, which closed on October 15, 2009. EPA received 67 unique 

submittals from 64 commenters, many of whom commented on the proposed rule. The 

Agency also held a public hearing in Chicago, IL on September 17, 2009. Six people, 

representing the oil and gas industry, electric utilities, water associations, and academia 

attended the hearing. Two attendees submitted oral comments at the hearing. A transcript 

of the public hearing is in the rulemaking docket (EPA-HQ-OW-2008-0390-391). 

F. How Will EPA’s Adaptive Rulemaking Approach Incorporate Future 

Information and Research? 

In the preamble to the proposed rule (73 FR 43492), EPA explained the need for and 

merits of using an adaptive approach to regulating injection of CO2 for GS at 40 CFR 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 
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continue to evaluate ongoing research and demonstration projects and gather other 

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

Many commenters strongly supported an adaptive, flexible approach and suggested that 

the Agency initially take a conservative approach in developing the UIC-GS 

requirements, with a provision for periodic review of the rule to allow EPA to incorporate 

operational experience as it is gained. These commenters also urged EPA not to wait until 

the completion of DOE’s pilot projects before finalizing the GS rule, expressing a need 

for early regulatory certainty.

Some commenters expressed concerns about an adaptive approach, stating that it could 

lead to regulatory uncertainty because modifications could be made after the initial 

regulations are promulgated. One commenter said that GS will not scale-up rapidly, 

leaving ample time to study and assess possible regulatory approaches. 

EPA agrees with commenters who supported an adaptive approach to the UIC 

rulemaking for GS. Additionally, the Agency believes that there is a need to have 

regulations in place during the earliest phases of GS deployment. Finalizing today’s 

requirements will allow early Class VI wells to be permitted in a manner that addresses 

the unique characteristics of CO2 injection for GS and allow early projects to demonstrate 

successful confinement of CO2 in a manner that is protective of USDWs. EPA also 

believes that an adaptive approach enables the Agency to make changes to the program as 

necessary to incorporate new research, data, and information about GS and associated 

technologies (e.g., modeling and well construction). This new information may increase 

protectiveness, streamline implementation, or otherwise inform the requirements for GS 

injection of CO2. The Agency plans to, every six years, 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.
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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 minimum 

administrative, civil, and criminal enforcement penalty 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 minimum 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 
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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 
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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 
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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 acknowledges 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.
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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 

[INSERT DATE] 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 
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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 submits a primacy application after the 270-day deadline and the 

application is approved, EPA will publish a subsequent notice of the approval as required 

by the SDWA. 

The Agency clarifies that States may not issue Class VI UIC permits until their Class VI 

UIC programs are approved. During the first 270-days and prior to EPA approval of a 

Class VI primacy application, States without existing SDWA section 1422 primacy

programs must direct all Class VI GS permit applications to the appropriate EPA Region. 

EPA Regions will issue permits using existing authorities and well classifications (e.g., 

Class I or Class V), as appropriate. 

States with existing UIC primacy for all non-Class VI well classes under section 1422 

that receive Class VI permit applications within the first 270 days after promulgation of 

the final rule may consider using existing authorities (e.g., Class I or Class V), as 

appropriate, to issue permits for CO2 injection for GS while EPA is evaluating their Class 

VI primacy application. EPA encourages States to issue permits that meet the 

requirements for Class VI wells to ensure that Class V and Class I wells previously used 

for GS can be re-permitted as Class VI wells that meet the protective requirements of 

today’s final rule within one year of promulgation of the Class VI regulation, pursuant to 

requirements at §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.
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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), i.e., the 

UIC program's 7520 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 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 a description of the procedure whereby the Director must notify injection well 

owners or operators (no later than one year after the State receives program approval) of 

the requirement that owners or operators must obtain a permit within two years after the 

State receives program approval. These requirements are tailored for Class VI wells to 
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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)(14), the final rule also requires States to submit a description 

of (and supporting information related to) any expansions to the areal extent of an 

existing Class II EOR/EGR aquifer exemptions for Class VI injection, which the Director 

has identified and approved under §144.7(d). This requirement complements aquifer 

exemption requirements promulgated under today’s rule. 

The Agency plans to review these requirements as part of the adaptive rulemaking 

approach to ensure that the tailored requirements are appropriate to ensure USDW 

protection from endangerment. 

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

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

because CO2 injection for long-term storage presents several unique challenges that 

warrant the designation of a new well type. 

When EPA initially promulgated its UIC regulations in 1980, the Agency defined five 

classes of injection wells at 40 CFR 144.6, based on similarities in the fluids injected, 

construction, injection depth, design, injection practices, and operating techniques. These 

five well classes are still in use today and are described below.
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• Class I wells inject industrial non-hazardous liquids, municipal wastewaters, or 

hazardous wastes beneath the lowermost USDW. These wells are among the deepest 

of the injection wells and are subject to technically sophisticated construction and 

operation requirements. 

• Class II wells inject fluids (e.g., CO2; brine) in connection with conventional oil or 

natural gas production, enhanced oil and gas production, and the storage of 

hydrocarbons that are liquid at standard temperature and pressure. 

• Class III wells inject fluids associated with the extraction of minerals, including the 

mining of sulfur and solution mining of minerals (e.g., uranium). 

• Class IV wells inject hazardous or radioactive wastes into or above USDWs. Few 

Class IV wells are in use today. These wells are banned unless authorized under a 

Federal or State-approved ground water remediation project. 

• Class V includes all injection wells that are not included in Classes I-IV. In general, 

Class V wells inject non-hazardous fluids into or above USDWs; however, there are 

some deep Class V wells that are used to inject below USDWs. This well class 

includes Class V experimental technology wells including those permitted as GS pilot 

projects.

The Agency acknowledges that owners or operators of wells regulated under existing 

well classifications may want to change the purpose of their injection activity. The 

following sections describe the applicability of today’s rule to owners or operators of 

existing wells and considerations for Directors evaluating existing wells that may be repermitted 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 

[INSERT DATE 365 days after DATE OF PUBLICATION], pursuant to requirements at 

146.81(c). The Agency anticipates that well owners or operators applying for Class VI 

well permits following publication of today’s rule will follow the Class VI requirements 

and design permit applications (e.g., for Class I or Class V) in a manner that facilitates 
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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. Similarly, the Agency expects that previously permitted wells will use 

the year following rule promulgation to develop appropriate, tailored Class VI permits to 

re-permit their Class I (or Class V) wells. 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 injection wells designated for enhanced recovery: Enhanced oil recovery (EOR) 

and enhanced gas recovery (EGR) technologies, collectively referred to as enhanced 

recovery (ER), are used in oil and gas reservoirs to increase production. Injection of CO2

is one of several ER techniques that have successfully been used to boost production 

efficiency of oil and gas by re-pressurizing the reservoir, and in the case of oil, by also 

increasing mobility. Injection wells used for ER are regulated through the UIC Class II 

program. 

CO2 currently injected for ER in the US comes from both natural and anthropogenic 

sources, which provide 79 percent and 21 percent, respectively, of CO2 supply (NETL, 

2008a). Natural CO2 sources consist of geologic domes in Colorado, New Mexico, and 

Mississippi. Anthropogenic sources of CO2 supplied for ER today include natural gas 

processing, ammonia and fertilizer production, and coal gasification facilities. 

Historically, CO2 purchases comprise about 33 to 68 percent of the cost of a CO2-ER 

project (EPRI, 1999). For this reason, CO2 injection volumes are carefully tracked at ER 

sites. CO2 recovered from production wells during ER is recycled (i.e., separated and reinjected), and at the conclusion of an ER project as much CO2 as is feasible is recovered 

and transported to other ER facilities for re-use. However, a certain amount of CO2

remains underground. Current Class II ER requirements do not require tracking and 

monitoring of the injectate; therefore, the migration and fate of the unrecovered CO2 is 

not documented.
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As of 2008, there were 105 CO2-EOR projects within the US (Oil and Gas Journal, 

2008). The majority (58) of these projects are located in Texas, and the remaining 

projects are located in Mississippi, Wyoming, Michigan, Oklahoma, New Mexico, Utah, 

Louisiana, Kansas, and Colorado. CO2-EOR projects recovered 323,000 barrels of oil per 

day in 2008, 6.5 percent of total domestic oil production. A total of 6,121 CO2 injection 

wells among 105 projects were used to inject 51 million metric tons of CO2 (Oil and Gas 

Journal, 2008; EIA, 2009; NETL, 2008a). Compared to CO2-EOR, CO2-EGR remains 

largely in the development stage (e.g., Oldenburg et al., 2001). 

Future deployment of CCS may fundamentally alter CO2-ER in the US. 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. DOE expects that 

these early projects will be necessary to meet future GHG mitigation goals in the nearterm. Additionally, oil and gas fields now considered to be “depleted” may resume 

operation because of increased availability and decreased cost of anthropogenic CO2.

EPA believes that if the business model for ER changes to focus on maximizing CO2

injection volumes and permanent storage, then the risk of endangerment to USDWs is 

likely to increase. This is because reservoir pressure within the injection zone will 

increase as CO2 injection volumes increase. Elevated reservoir pressure is a significant 

risk driver at GS sites, as it may cause unintended fluid movement and leakage into 

USDWs that may cause endangerment. Additionally, increasing reservoir pressure within 

the injection zone as a result of GS will stress the primary confining zone (i.e., geologic 

caprock) and well plugs to a greater degree than during traditional ER (e.g., Klusman, 

2003). Finally, active and abandoned well bores are much more numerous in oil and gas 

fields than other potential GS sites, and under certain circumstances could serve as

potential leakage pathways. For example, in typical productive oil and gas fields, a CO2

plume with a radius of about 5 km (3.1 miles) may come into contact with several 

hundred producing or abandoned wells (Celia et al., 2004).
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EPA proposed that the Class VI GS requirements would not apply to Class II ER wells as 

long as any oil or gas production is occurring, but would apply only after the oil and gas 

reservoir is depleted. Under the proposed approach, Class II wells could be used for the 

injection of CO2, as long as oil production is simultaneously occurring from the same 

formation. The preamble to the proposal sought comment on the merits of this approach.

Some commenters agreed with the proposed approach while others suggested that the 

approach did not adequately address risks posed to USDWs by injection operations 

transitioning from production to long-term storage of CO2. A majority of commenters 

requested that EPA develop specific criteria for this transition. 

EPA agrees with commenters that owners or operators of wells injecting CO2 in oil and 

gas reservoirs for GS where there is an increased risk to USDWs compared to traditional 

Class II operations be required to obtain a Class VI permit. Additionally, EPA recognizes 

that further clarification is needed to sufficiently characterize the factors that lead to 

increased risks and warrant conversion from Class II to Class VI. 

Therefore, today’s rule clarifies that Class VI requirements apply to any CO2 injection 

project (regardless of formation type) when the risk posed to USDWs increases and is 

greater than traditional ER projects. Traditional ER projects are not impacted by this 

rulemaking and will continue operating under Class II permitting requirements. EPA 

recognizes that there may be an incidental amount of CO2 trapped in the subsurface at 

these operations; however, if there is no increased risk to USDWs, then these operations 

would continue to be permitted under Class II. 

EPA has developed specific, risk-based criteria 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 criteria 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 CO2
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injection rates; 3) decrease in reservoir production rates; 4) the distance between the 

injection zone and USDWs; 5) the suitability of the Class II AoR delineation; 6) the 

quality of abandoned well plugs within the AoR; 7) the owner’s or operator’s plan for 

recovery of CO2 at the cessation of injection; 8) the source and properties of injected 

CO2; and 9) any additional site-specific criteria as determined by the Director. Any single 

criterion may not necessarily result in a determination that a Class II owner or operator 

must apply for a Class VI permit; rather, all criteria 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 criteria and

making the determination on whether to apply Class VI requirements. 

EPA expects that, in most cases, the ER owners or operators will notify the Director of 

their intent to seek a Class VI permit because there is an increased risk to USDWs 

compared to traditional Class II operations. 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 

requiring a well to transition from Class II to Class VI will not cause undue regulatory 

burden and is necessary to ensure USDW protection. 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 
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§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 criteria 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 CO2. 

Class V Experimental Technology Wells: Prior to finalization of the Class VI regulation, 

a number of CO2 injection projects were permitted as Class V experimental technology 

wells for the purpose of testing GS technology in the US. 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 
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CO2 for the purpose of GS) to apply for Class VI permits within one year of rule 

promulgation and to comply with the requirements of today’s rule. However, EPA is 

allowing the constructed components of Class V experimental technology wells to be 

grandfathered into the Class VI permitting regime at the discretion of the Director and 

pursuant to requirements at §146.81(c). EPA anticipates that Class V well owners or 

operators that plan to re-permit their wells as Class VI wells will initiate the permit 

application process following promulgation of today’s rule. 

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 CO2 injection wells that are testing the injectivity or 

appropriateness of an individual formation (e.g., as a prelude to a commercial-scale 

operation) as Class V experimental technology wells. Such wells should be permitted as 

Class VI wells.

Other commenters suggested that owners or operators of wells injecting CO2 into basalts, 

coal seams, and salt domes should be able to seek a Class V experimental permit. EPA 

agrees with these commenters and acknowledges that the Class V experimental 

technology well classification may be appropriate for these projects provided they are 

experimental in nature. EPA expects that, following today’s rule, a limited number of 

experimental injection projects testing GS technology will continue. EPA anticipates that 

these projects will be small-scale and involve limited CO2 volumes. However, if these 

projects become larger scale and are no longer experimental, they will need to be 

permitted as Class VI wells. The construction, operation or maintenance of any nonexperimental 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
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following promulgation of today’s rule. The guidance will assist owners and operators 

and Directors in determining what constitutes a Class V experimental technology well for 

the purposes of testing GS technology. 

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

Recognizing that owners or operators of existing Class I, Class II, and Class V 

experimental technology wells may seek to change the purpose of their injection well,

EPA proposed to give the Director discretion to carry over or “grandfather” the 

construction requirements (e.g., permanent, cemented well components) provided he or 

she is able to make a determination that these wells would not endanger USDWs. EPA 

sought comment on this approach and how the proposed grandfathering provisions for 

existing wells may affect compliance with Class VI construction requirements.

Nearly all industry commenters favored grandfathering of Class I, II, and V well 

construction requirements for GS, indicating that most wells are built to appropriate 

specifications and would have sufficient mechanical integrity for GS in order to protect 

USDWs from endangerment. These commenters cited oil and gas industry experience 

with CO2 injection in the UIC Class II program and suggested that this experience 

demonstrates that construction requirements for Class II injection wells are sufficient to 

protect USDWs. Other commenters asserted that grandfathering Class II construction will 

expedite the transition of Class II ER projects to Class VI GS. 

Several commenters were concerned that the structural modifications that may be 

required for some existing Class II wells to comply with the proposed injection well 

construction requirements at §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. 
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In response, EPA recognizes that the oil and gas industry has decades of experience 

injecting CO2 for ER and that many Class V experimental technology wells, including 

those used in the RCSP’s projects, are specifically designed for injection of CO2 and are 

being constructed to Class I non-hazardous waste well specifications. In today’s final 

rule, at §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 CO2 for the purpose of GS. Today’s 

action includes requirements for the permitting, siting, construction, operation, financial 

responsibility, testing and monitoring, PISC, and site closure of Class VI injection wells 

that address the pathways through which USDWs may be endangered. These 

requirements are tailored from existing UIC program components to ensure that they are 

appropriate for the unique nature of injecting large volumes of CO2 for GS into a variety 

of geological formations to ensure that USDWs are not endangered. 

Today’s rule retains many of the requirements for Class VI wells that EPA proposed on 

July 25, 2008. However, based on a review of public comments on the proposed rule and 
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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 CO2 injection 

transitions from ER (i.e., a Class II well) to long-term storage (i.e., Class VI) and the 

risk posed to USDWs increases and is greater than traditional ER projects, today’s 

rule at §144.19 contains specific, risk-based criteria to be demonstrated by owners or 

operators and considered 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 
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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 CO2 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 CO2 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 use indirect, 

geophysical techniques unless the Director determines, based on site-specific 

geology, that such methods are not appropriate. See section III.F.
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EPA believes that these changes will result in a clearer, more protective approach to 

permitting GS projects across the US 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 US 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 highlights 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. 
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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 CO2 so that the injection activities will not endanger 

USDWs. Today’s requirements for Class VI wells are based extensively on the longstanding 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 CO2, 

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 
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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. 
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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 US. The Agency 

encourages transparency in the permitting process and anticipates that State-State/StateTribal 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. 
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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 CO2 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 

CO2 is moving as predicted within the subsurface.

AoR modeling and reevaluation are important components of the overall proposed 

strategy to track the CO2 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 CO2 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 storage operation 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 
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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 CO2 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 CO2 phases and areas of quantitative measures of elevated pressure 

should be included in the definition. 
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EPA evaluated all comments on the AoR definition, and determined that a performancebased 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 CO2 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 CO2 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 CO2, 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 
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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 CO2 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 CO2 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 CO2 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. 
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The majority of commenters agreed that AoR reevaluations are necessary, citing the large 

volumes of CO2 that may be injected, the uncertainty of CO2 movement in the 

subsurface, the need to incorporate monitoring data, and the lack of experience in 

tracking large volumes of CO2. 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 CO2 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 CO2 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 CO2 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 

CO2 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 
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consultation with the Director, would identify the wells that need corrective action to 

prevent the movement of CO2 or other fluids into or between USDWs. Owners or 

operators would perform corrective action to address deficiencies in any wells (regardless 

of ownership) that are identified as potential conduits for fluid movement into USDWs. 

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 CO2 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 CO2 exposure during the first years of injection as informed by sitecharacterization data and model predictions. Artificial penetrations in areas farther from 

the injection well would be addressed after injection has commenced, but prior to CO2

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.
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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 CO2 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 CO2 plume or pressure front. However, it is not 

appropriate to set a specific timeframe for completing corrective action because CO2

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 CO2 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 CO2, including its buoyancy relative to other fluids in the 

subsurface and the potential presence of impurities in captured CO2. In addition to 

protecting USDWs, today’s comprehensive construction requirements respond to 
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concerns about GS project safety and potential impacts on USDWs and, in turn, may 

promote acceptance of GS projects.

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 CO2 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 US. 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. 
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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 CO2 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 degradationresistant well construction materials, such as acid-resistant cements and corrosionresistant 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 
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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 

CO2 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 CO2 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 CO2 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 
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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 and packer 

in Class VI wells facilitate continuous monitoring of pressure in the annulus between the 

tubing and casing and effectively provide two barriers from USDWs. Additionally, 

tubing can be replaced relatively easily in the event that damage to the tubing is identified 

or a tubing diameter change is necessary. EPA agrees with commenters that the use of 

tubing and packer in accordance with specified requirements at §146.86(c) offers the best 

multiple-barrier protection of USDWs from endangerment and today’s final rule retains 

this requirement. 

Horizontal wells: In the proposed rule, EPA solicited comment on the merits of 

horizontal well drilling techniques for Class VI wells and the applicability of proposed 

well construction requirements to horizontal injection well design. Commenters strongly 

supported the use of horizontal well drilling techniques for Class VI wells. Many 

commenters cited the oil and gas industry’s extensive technical experience with 

horizontal injection well construction and the practical experience gained at GS pilot 

projects including the In Salah project in Algeria. Commenters also emphasized that 

horizontal well drilling helps to reduce surface impact by reducing the number of 

injection well heads required to achieve a given injection rate, which limits the number of 

potential leakage pathways into USDWs. Commenters stated that allowing the use of 

horizontal wells for GS would maximize CO2 injection volumes into a particular 

reservoir and increase the total effective GS CO2 storage capacity in the US.
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EPA agrees with commenters that horizontal well drilling techniques represent a potential 

and promising method for increasing efficiency of GS projects while simultaneously 

reducing impact and potential leakage pathways into USDWs. EPA agrees that using 

existing experience with horizontal well construction and use in conjunction with the 

Class VI requirements may help improve efficiency in GS operations while ensuring

protection of USDWs from endangerment. Therefore, the Agency will allow the use of 

horizontal wells for Class VI GS as long as the wells are constructed and implemented to 

meet the requirements under subpart H of part 146.

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

Today’s final rule includes requirements at §146.95 that allow owners or operators to 

seek a waiver from the Class VI injection depth requirements for GS to allow injection 

into non-USDW formations while ensuring that USDWs above and below the injection 

zone are protected from endangerment. The Agency anticipates that any issuance of

waivers will be limited to circumstances where there are deep USDWs (74 FR 44802, 

August 31, 2009) and/or where the lack of a waiver of injection depth requirements 

would result in impractical or technically infeasible well construction, and where USDW 

protection is demonstrated and maintained through the life of the GS project. These 

requirements are designed to ensure that the owner or operator and the Director consider, 

on a site-specific basis, the implications, benefits, and challenges associated with GS, 

water availability, and USDW protection. Today’s final rule also establishes limited 

circumstances under which aquifer exemption expansions may be granted for owners or 

operators of Class II EOR/EGR wells transitioning to Class VI injection wells for GS. 

1. Proposed Rule

Injection depth requirements for GS: In the proposed rule, EPA defined Class VI 

injection wells as “wells used for GS (injection) of CO2 beneath the lowermost formation 

containing a USDW.” The proposed injection depth requirements (i.e., that injection is 

below the lowermost USDW) for Class VI wells are consistent with the siting and 

operational requirements for deep, technically sophisticated wells and are an important 

component of the UIC program. The basis for these requirements is the principle that 
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placing distance between the injection formation and USDWs will decrease risks to 

USDWs. In deep-well injection scenarios, the added depth and distance between the 

injection zone and overlying formations serve both as a buffer allowing for pressure 

dissipation and as a zone for monitoring that may detect any excursions (of the injectate) 

out of the injection zone. Additional depth and distance also allow CO2 trapping 

mechanisms, including physical trapping, dissolution of CO2 in native fluids and 

mineralization, to occur over time – thereby reducing risks that CO2 may migrate from 

the injection zone and endanger USDWs. Added depth also allows the potential for the 

presence of additional confining layers (between the injection zone and overlying 

formations/USDWs). 

The Agency acknowledged that the proposed injection depth requirements would 

preclude injection of CO2 into zones in between and above USDWs and may restrict the 

use of GS in areas of the country with deep USDWs, where well construction would be 

impractical or technically infeasible. As proposed, the definition would also have 

effectively precluded injection of CO2 into shallow formations such as coal seams and 

basalts. The Agency requested comment on alternative approaches that would allow 

injection between USDWs and/or above the lowermost USDW and thus potentially allow 

for more areas to be available for GS while continuing to prevent endangerment of 

USDWs. 

The Agency received comments in support of, and opposition to, the proposed injection 

depth requirements for Class VI wells. Commenters who supported the proposed 

requirements cited the importance of USDW protection, the integrity and importance of 

the long-standing deep well UIC requirements, and concerns about water availability and 

the future use of deep USDWs. Commenters also indicated that in the early years of GS 

deployment, injection depth limitations would be prudent. 

Those opposed to the proposed requirements supported allowing injection above and 

between USDWs. These commenters indicated that injection depth flexibility for GS is 

important to ensure that no parts of the country are excluded from GS activities and that 
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CCS deployment is not restricted. Other commenters encouraged injection depth 

flexibility because, they asserted, some Class II, Class III, and Class V operations already 

inject above the lowermost USDW without any potential for threats to underlying (or 

overlying) USDWs. 

Use of aquifer exemptions for GS: The UIC requirements at §§146.4 and 144.7 establish 

criteria for and afford the Director discretion to issue aquifer exemptions which, when 

approved, removes an aquifer from protection as a USDW, in accordance with the 

requirements of §144.7(b)(1). Generally, aquifer exemptions are granted for mineral or 

hydrocarbon exploitation by Class III solution mining wells, or by Class II oil and gasrelated wells, respectively, and when there is no reasonable expectation that the exempted 

aquifer will be used as a drinking water supply (see specific aquifer exemption criteria at 

§146.4). There are also limited numbers of aquifer exemptions for Class I industrial 

injection. Aquifer exemptions associated with Class II and Class III operations are 

generally limited in area (e.g., a quarter of a mile around the injection well-bore for Class 

II wells). EPA attempts to limit aquifer exemptions for injection operations to the 

circumstances where the necessary criteria at §146.4 are met and not, in general, for the 

purpose of creating additional capacity for the subsurface emplacement of fluids.

The proposed rule acknowledged that there may be situations where owners or operators 

may seek aquifer exemptions for GS and sought comment on whether aquifer exemptions 

should be allowed for the purpose of Class VI injection. EPA also requested comment on 

the conditions under which aquifer exemptions for GS should be approved. 

Some commenters encouraged the Agency to allow the use of aquifer exemptions for 

Class VI injection and indicated that the existing criteria at 40 CFR 146.4 and 40 CFR 

144.7 are appropriate for GS. However, a number of commenters requested that the 

Agency modify the aquifer exemption criteria to provide regulatory certainty and ensure 

that the criteria specifically apply to CO2 injection for GS. Other commenters requested 

that the Agency modify the definition of a USDW to reduce the need for aquifer 

exemptions (e.g., lowering the upper TDS limit from 10,000 mg/l TDS). Additionally, 
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commenters acknowledged that there was a particular interest in aquifer exemptions for 

Class II fields that may be used for GS in the future. 

Other commenters suggested that the Agency limit or prohibit aquifer exemptions for 

Class VI injection, citing the need to ensure protection of current and future drinking 

water resources. Furthermore, several commenters opposed to the use of aquifer 

exemptions suggested modifications to the definition of a USDW to enhance protection 

for formations in excess of 10,000 mg/l TDS. 

Injection formations for GS: In the preamble to the proposed rule, EPA discussed and 

sought comment on the range of target geologic formations used or under investigation 

for GS of CO2 (e.g., deep saline formations, depleted oil and gas reservoirs, unmineable 

coal seams, basalts, and other formations). The proposed rule also sought comment on 

whether the final rule should prohibit injection into any specific formation types that are 

located above the lowermost USDW. 

Most commenters encouraged EPA not to automatically exclude any potential injection 

formations for GS at this stage of deployment. Commenters suggested, in particular, that 

there is a sufficient technical basis and scientific evidence to allow GS in depleted oil and 

gas reservoirs and in saline formations, noting that there is consensus on how to inject

into these formation types. 

Some commenters, including water associations, cautioned the Agency regarding 

injection into saline formations, citing concerns about the potential future need for these 

formations as drinking water sources. Other commenters suggested that basalts, salt 

domes, shales, coal seams, limestone formations, and fractured karst are not ready for 

commercial sequestration and suggested that additional research is needed into GS in 

these formation types. 

More detailed information on the comments is available in the NODA and Request for 

Comment and in the docket for this rulemaking. 
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2. Notice of Data Availability and Request for Comment

In response to comments received on the proposed injection depth requirements, the 

Agency published a NODA and Request for Comment to present additional information 

on an alternative for addressing injection depth in limited circumstances where there are 

deep USDWs and injection above and between USDWs would not endanger USDWs. 

Under the approach, the proposed Class VI injection depth requirements would remain 

unchanged but would allow an owner or operator seeking to inject into non-USDWs

above or between USDWs to apply for a waiver from the injection depth requirements. 

The waiver process, presented in the NODA and Request for Comment, would be 

informed by site-specific information and would be reviewed by both the UIC and Public 

Water System Supervision (PWSS) Directors to ensure appropriate siting of a GS project 

as well as consideration of water resource availability and demands. 

The NODA and Request for Comment sought comment on the merits of the injection 

depth waiver approach and whether the waiver process should apply only to saline 

formations and oil/gas reservoirs or to all formation types. Additionally, the Agency 

requested information on 1) locations in the US where injection depth is an issue; 2) data 

and information on the safety of injecting through/above/between USDWs; and, 3) 

strategies being considered by States, Tribes, and Regions to address competing resource 

issues. The Agency requested this information to enable a more comprehensive decision 

regarding the impacts of the proposed injection depth requirements and the need for 

waivers.

Comments on the waiver alternative presented in the NODA and Request for Comment: 

The Agency received comments both in support of and opposition to the injection depth 

waiver alternative discussed in the NODA and Request for Comment. 

Commenters supporting the waiver alternative presented in the NODA and Request for 

Comment acknowledged that the waiver approach is flexible, strikes the right balance 

between USDW protection and maximizing GS capacity, and would ensure a thorough 
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and scientifically based, site-specific assessment of the appropriateness of a waiver 

during the siting process. A number of commenters supportive of the waiver cited 

hydrocarbon storage, other injection operations, and production activities as evidence that 

GS into shallower geologic environments can be performed safely and successfully while 

ensuring USDW protection. 

There was limited opposition to the waiver alternative presented in the NODA and 

Request for Comment. Commenters who opposed the waiver approach maintained that 

all injection of CO2 for GS should be below the lowermost USDW and any new 

requirements should maximize protection of USDWs. However, some commenters who 

opposed the waiver process acknowledged the utility of the waiver, and urged the Agency 

to consider additional requirements for any wells that operate under injection depth 

waivers. The Agency did not receive any analytical or quantitative data in response to

publication of the NODA and Request for Comment.

The Agency also received comments on the waiver application and review process. 

Commenters questioned how the process would work and how waivers would apply to 

existing Class I, II, or V wells that may be re-permitted as Class VI wells in the future. 

Some commenters suggested that the waiver request should be part of the permit 

application process, while others felt that it should be a discrete submittal. Other 

commenters expressed concern about the nexus between the waiver process and aquifer 

exemptions. Some commenters who supported the waiver concept suggested that 

adoption of an injection depth waiver process should not be at the discretion of the 

individual UIC program Directors and that EPA should require waivers to be applied 

nationally.

A number of commenters supporting the concept of the waiver of injection depth 

requirements indicated that they did not support the joint review of waiver information by 

both the UIC and PWSS Directors. These commenters believed that the joint review 

process as discussed in the NODA and Request for Comment was inefficient and 

duplicative, and could introduce confusion and lack of clarity about the role of each 
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Director. However, a number of commenters did support the principle of affording the 

PWSS Director a consultative role for increased transparency and to ensure consideration 

of public water supply needs in a potential GS project area when siting a Class VI well. 

Noting the unique nature of the waiver process and the belief that injection above 

USDWs may present additional questions relative to movement of CO2 in the subsurface, 

many commenters supported the Agency’s assertion that additional requirements should 

apply to waivered wells. These commenters suggested that additional regional, 

hydrologic studies be required when an injection depth waiver is considered. Other 

commenters encouraged EPA to enhance the site characterization requirements when a 

waiver is granted to 1) ensure the identification of appropriate upper and lower confining 

units, 2) include requirements for more comprehensive, site-specific monitoring (above 

and below the injection zone), and 3) ensure appropriate public notification prior to 

issuance of a waiver. A number of commenters also suggested that the Agency develop 

guidance to support the waiver application process, waiver evaluation, and decision 

making. 

Comments on the use of aquifer exemptions for GS: Comments submitted in response to 

the NODA were similar to and built upon those received on the proposal. Some 

commenters indicated that, in addition to allowing injection above and between USDWs 

(through the waiver process), aquifer exemptions should also be allowed for Class VI 

injection. A number of these commenters requested that the Agency modify 1) the aquifer 

exemption criteria to ensure that the criteria specifically apply to CO2 injection for GS

and 2) the USDW definition to limit protection for formations currently afforded 

protection under the SDWA (i.e., by reducing the 10,000 mg/l TDS threshold). These 

commenters added that Class II EOR/EGR operations injecting into exempted aquifers 

would need a mechanism to continue the aquifer exemptions if the well were to be repermitted as a GS operation. 

However, a number of commenters encouraged the Agency to limit or prohibit aquifer 

exemptions for Class VI injection, citing the need to ensure protection of current and 
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future drinking water resources. Furthermore, several of these commenters suggested 

modifications to the definition of a USDW to enhance protection for formations in excess 

of 10,000 mg/l TDS. 

Comments on injection formations for GS: Commenters submitted comments similar to 

those received on the proposal. Some commenters encouraged the Agency to limit GS 

injection to only deep saline formations and depleted reservoirs. These commenters cited 

a lack of information about the viability of basalts, salt domes, shales, and coal seams for 

GS. Other commenters suggested that the Agency allow injection into all formation types 

for GS. Commenters that supported flexibility in injection formation types indicated that 

proper site-characterization is critical, regardless of the injection formation type. They 

indicated that a decision to allow injection for GS should be made on a site-by-site basis 

and a prohibition based on formation types is not appropriate. 

3. Final Approach

In response to comments on the proposed injection depth requirements, the use of aquifer 

exemptions for GS, the range of potential injection formations for GS, the waiver process 

discussed in the NODA and Request for Comment, and concerns about USDW protection 

and national capacity for GS, today’s rule finalizes requirements at §146.95 that allow 

owners or operators to seek a waiver of the Class VI injection depth requirements for 

injection into non-USDW formations above and/or between USDWs. It establishes: 1) 

requirements specifying information that owners or operators must submit, and Directors 

must consider, in consultation with PWSS Directors; 2) procedures for public notice of a 

waiver application and for Director-Regional Administrator communication; 3) the 

waiver issuance process; and, 4) additional requirements that apply to owners or 

operators of Class VI wells granted a waiver of the injection depth requirements to ensure 

USDW protection above and below the injection zone. Today’s final rule also establishes 

limited circumstances under which expansions of aquifer exemptions may be granted for 

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for 

GS. Additionally, today’s rule does not categorically preclude or prohibit injection into 

any type of formation. 
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The Agency is finalizing these requirements to ensure USDW protection while providing 

flexibility to UIC program Directors and owners or operators who will undertake CO2

injection for GS. The Agency believes this approach: 1) responds to concerns about local 

and regional geologic storage capacity limitations imposed by the proposed injection 

depth requirements; 2) allows for a more site-specific assessment of injection depth for 

GS projects; 3) accommodates injection into different formation types; 4) allows for 

injection of CO2 for GS into non-USDWs above and/or between USDWs when 

appropriate and where it can be demonstrated that USDWs will be protected from 

endangerment; and 5) responds to concerns about the use of aquifer exemptions for GS. 

Finally, EPA’s approach to addressing injection depth variability through a waiver 

process responds to concerns about future drinking water resource availability and the 

need to ensure that high quality water remains available in sufficient quantities to supply 

drinking water needs. 

The final injection depth waiver requirements at §146.95 apply to all non-USDWs 

including: 1) formations that have salinities greater than 10,000 mg/l TDS and 2) all 

eligible previously exempted aquifers situated above and/or between USDWs. EPA 

anticipates that previously exempted aquifers will, in many cases, not be appropriate 

receiving formations for GS due to their location, size, lithologic properties, and previous 

injection operations; and, therefore, the Agency expects that few owners or operators will 

seek Class VI permits for GS injection into previously exempted aquifers. 

Injection depth waivers for GS: Today’s final rule requires an owner or operator seeking 

a Class VI waiver of the injection depth requirements to submit additional information to 

the Director to inform a comprehensive assessment of site-suitability for a Class VI well

to inject into a non-USDW above or between USDWs. The Agency believes that it is 

appropriate and reasonable that the owner or operator and the Director consider

additional, specific information prior to waiver issuance in addition to the required Class 

VI permit information and the site characterization information collected (pursuant to 

requirements at §146.82(a) for the site-specific characterization of geologic, 
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hydrogeologic, geochemical, and geomechanical properties and §146.83 to determine the 

suitability of the proposed GS site).

In addition to submitting a Class VI permit application, the owner or operator must also 

submit a supplemental report (the GS Class VI injection depth waiver application report)

referenced at §146.82(d) and outlined at §146.95(a) with additional, specific information 

including: information about the injection zone; identification of confining units above 

and below the injection zone; tailored AoR modeling above and below the injection zone; 

a demonstration that well design is appropriate and protective of USDWs, in lieu of 

specific well construction requirements at §146.86; a description of how monitoring will 

be tailored for injection above/between USDWs; and information about public water 

supplies in the AoR. The purpose of the report is to ensure that the owner or operator 

collects appropriate information and demonstrates to the Director that the injection zone 

is suitable for GS and is confined by confining units above and below the injection zone;

that well construction, operation, and monitoring are tailored for the site; and, that 

USDWs are not and will not be endangered. This report, suggested by commenters on the 

NODA and Request for Comment, ensures that waiver information is discrete from the 

permit application as indicated at §146.82(d) and must be made available to the UIC 

Director, PWSS Directors, the Regional Administrator, and the public when the waiver is 

publicly noticed with the draft, Class VI permit application. 

EPA believes that, to be effective, a waiver of injection depth requirements should be 

granted only after the UIC program Director, the PWSS Director(s), and the public have 

evaluated information specific to the site and anticipated injection activity. In addition, 

the decision to waive injection depth requirements must be made using a clear and 

transparent public notification process. The requirements at §146.95(b) establish 

considerations that the UIC Director must assess when evaluating a waiver application in 

conjunction with the permit application for a Class VI GS project. These are designed to 

ensure that USDW protection, site-specific drinking water resource issues, and the use 

and impact of GS technologies are considered and documented. The requirements at 

§146.95(b)(2) also establish the manner in which the UIC Director will consult with the 
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PWSS Director(s) of States, Territories, and Tribes having jurisdiction over lands within 

the AoR of a well for which a waiver is sought to ensure that water system concerns are 

considered when evaluating a waiver application. The communication with the PWSS 

Director is consultative and does not constitute a final Agency decision making. 

Under §146.95(c) and pursuant to requirements at §124.10, the public notification 

process for a waiver of injection depth requirements for a Class VI well must occur 

concurrently with the Class VI permit notification in order to ensure that all necessary 

information is disclosed to the public for notice and comment and that the public 

understands that the site, if permitted, would be operating under a waiver from the 

injection depth requirements. In addition, the rule at §146.95(c) requires the Director to 

provide the public with appropriate, site-specific and waiver-specific information to 

inform public comment. If the permitting authority receives comments on the injection 

depth waiver during the public comment period for both the waiver and the permit 

application, the Director must evaluate comments prior to approving the waiver and

issuing the Class VI permit. These requirements balance USDW protection and 

disclosure of PWSS information with the GS permit application process requirements. 

Today’s final regulations, at §146.95(d), require the Director to provide the Regional 

Administrator with the information collected during the waiver application and the public 

notice processes. Based on this information and pursuant to requirements at §146.95(d), 

the Regional Administrator will provide written concurrence or non-concurrence 

regarding waiver issuance. The requirements at §146.95(d)(1) afford the Regional 

Administrator discretion to request limited, additional information to support the waiver 

decision. However, the Regional Administrator also has the discretion to require reinitiation of the public notice and comment period if necessary. Today's rule at 

§146.95(d)(2) clarifies that Directors of State-approved programs shall not issue waivers 

without the written concurrence of the Regional Administrator. EPA believes Agency 

input is necessary in making injection depth waiver decisions and agrees with 

commenters who expressed interest in ensuring that multi-State boundary and water 
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resource issues are addressed. EPA also believes that Agency involvement in the waiver 

decision process will contribute to national consistency in waiver issuance. 

The requirements at §146.95(e) identify the information that EPA will maintain on its 

Web site to provide transparency and inform the public regarding GS injection depth 

waiver issuance throughout the US. 

Today’s rule finalizes additional requirements at §146.95(f) to address comments and 

provide clarity to owners or operators who receive and operate with a waiver of the Class 

VI injection depth requirements. These requirements are a supplement to all other 

applicable requirements finalized today (see §146.95(f)(1)). The additional requirements 

are designed to complement existing requirements by: 

• Building upon the site characterization and AoR delineation conducted during the 

waiver application process (at §146.95(a)),

• Supplementing specific requirements that are not applicable due to the fact that 

certain Class VI requirements (e.g., at §146.86) reference the “lowermost USDW,” 

• Expanding the monitoring requirements during operation and PISC to address 

protection of USDWs underlying and overlying the injection zone, and,

• Ensuring protection of USDWs above and below an injection zone when a Class VI 

well is issued a waiver of the injection depth requirements. 

The Agency believes that collection and assessment of site- and project-specific 

information is integral to the waiver process. The Agency is developing guidance to 

support owners or operators in assessing a GS project site and applying for a waiver of 

the Class VI injection depth requirements and to assist Directors in evaluating waiver 

applications.

Today’s final approach for injection depth waivers represents minimum Federal 

requirements. Adoption of the waiver process will remain at the discretion of individual 

UIC programs, since States may choose to develop requirements that are more stringent 

than the minimum Federal requirements provided in today’s rule. Furthermore, States, 
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Territories and Tribes may be prohibited by state law to allow such a waiver process. 

Therefore, States, Territories, and Tribes seeking primacy for Class VI wells are not 

required to provide for injection depth waivers in their UIC regulations and may choose 

not to make this process available to owners or operators of Class VI wells under their 

jurisdiction. Although some commenters asked EPA to require that waivers be applied 

nationally, the Agency believes that the decision about whether a waiver program is 

appropriate in a specific State, Tribe, or Territory should be made by each program. This 

approach allows flexibility for individual program Directors to determine the 

appropriateness of allowing for waivers based on regional or State-specific conditions, 

such as the predominant geologic settings anticipated to be used for GS or other land uses 

in the State while ensuring maximum protection of USDWs from endangerment. UIC 

program Directors may adopt GS requirements that do not allow injection above or 

between USDWs if they determine this to be appropriate or if State law prohibits the 

injection depth waiver process. 

No waivers can be issued prior to the establishment of a Class VI UIC program in a State,

pursuant to the requirements at §145.21(see section II.E.2). This is designed to ensure 

that States determine whether a waiver process will be allowed as a part of their GS 

program.

Use of aquifer exemptions for GS: Today's rule allows for the expansion to the areal 

extent of existing aquifer exemptions for Class II EOR/EGR wells transitioning to Class 

VI injection for GS pursuant to requirements at §§146.4 and 144.7(d). Today’s final rule 

also precludes the issuance of new aquifer exemptions for Class VI wells. Aquifer 

exemptions will only be granted for projects that are transitioning from Class II 

EOR/EGR wells to Class VI, and are referred to as aquifer exemption expansions below. 

However, Class VI owners or operators granted expansions of existing Class II 

EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements 

for Class VI wells in today's rule. 
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If an owner or operator applies for a Class VI permit to inject CO2 into a previously 

exempted aquifer (non-USDW) that is located above and/or between USDWs, the permit 

applicant must also apply for a waiver of the injection depth requirements pursuant to 

§146.95 to ensure that if a waiver is granted, USDWs above and below the injection zone 

are protected from endangerment. 

While the Agency developed the waiver process to address comments and concerns 

about: 1) current and future drinking water resources and 2) the use of climate mitigation 

technology at appropriate sites, the Agency acknowledges that there are limited 

circumstances where aquifer exemptions for GS may be warranted. The aquifer 

exemption requirements in today's final rule afford owners or operators an opportunity to 

assess and select a suitable GS site while also preserving USDWs (i.e., 

formations/aquifers afforded SDWA protection). EPA agrees with commenters who 

expressed concerns about USDW preservation and protection and believes that, in most 

cases, the injection depth waiver is a more appropriate option than aquifer exemptions for 

Class VI injection, and believes that aquifer exemption expansions for GS should be 

granted in limited circumstances. 

The aquifer exemption requirements and the injection depth waiver requirements serve 

different purposes. The aquifer exemption criteria remove the injection formation from 

SDWA protection and allow injection into an exempted formation, while the injection 

depth waiver requirements allow CO2 injection for GS above or between USDWs and 

ensure protection of USDWs above and below the injection zone (or exempted aquifer). 

The Agency recognizes that a limited number of Class II EOR/EGR well owners or 

operators currently inject into exempted aquifers or exempted portions of aquifers and 

these owners or operators may transition to Class VI GS in the future (see section II.H). 

In response to commenters who believed that there is a need for aquifer exemptions in 

specific circumstances and in an effort to maintain USDW protection while providing 

flexibility to transitioning projects, today’s rule allows owners or operators of Class II 
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EOR/EGR operations injecting into exempted aquifers (or exempted portions of aquifers) 

to reapply for an aquifer exemption expansion for the re-permitted Class VI injection. 

For all Class II EOR/EGR aquifer exemption expansions for Class VI injection, public 

notice and opportunity for a public hearing is required under §144.7(b)(3). This modifies 

existing provisions that all aquifer exemption requests are either explicitly or implicitly 

approved by EPA pursuant to §144.7. In addition, today’s rule requires that all such 

aquifer exemption expansion requests be treated as substantial program revisions under 

§145.32 and will require revision of part 147. Furthermore, if EPA directly implements 

the UIC program in a State, an aquifer exemption expansion requires a revision to the 

UIC program of the applicable State under part 147. 

The Agency acknowledges that the expansion of an existing aquifer exemption for a GS 

project will remove additional USDWs (or portions of USDWs) from SDWA protection, 

and that owners or operators of other classes of injection wells could apply for a permit to 

inject into these exempted aquifers. However, EPA clarifies that aquifer exemption 

expansions granted under today's rule will only be granted for the purpose of GS (and the 

injection will be subject to today's tailored requirements for Class VI wells). Any other 

uses of an exempted aquifer (e.g., for Class I through V injection) require a separate 

permit, are subject to existing UIC requirements, and must be approved by the UIC 

Director. The Agency anticipates that a UIC Director will (and encourages the UIC 

Director to) consider the following types of risks when evaluating additional injection 

activities into the AoR of a GS project: the number of artificial penetrations in the AoR, 

potential adverse geochemical interactions between previously injected CO2 and other 

injection fluids, and an increase in reservoir pressure as a result of multiple injectors and 

subsurface plume interaction. EPA believes that these factors would reduce the likelihood 

that exempted aquifers associated with GS injection will be used for other activities.

Additionally, the Agency recognizes that an owner or operator could, in theory, request 

multiple expansions to the areal extent of a previously exempted aquifer used for Class II 

EOR/EGR injection. However, due to the nature of Class VI operations including the 

permit application process, the AoR evaluation, and the development of site-specific 
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plans, the Agency anticipates that an owner or operator will not be able to continually 

expand an aquifer exemption for a Class VI operation. Instead, the applicant will identify, 

up front, the full extent of the AoR of the associated GS project to develop an appropriate 

aquifer exemption request and the Director will comprehensively evaluate the permit 

application information in concert with the areal extent of the aquifer exemption 

expansion request.

Today's final approach is designed to ensure that the differences between traditional 

Class II EOR/EGR operations and Class VI operations are considered during the aquifer 

exemption application process and the Class VI permitting process. These differences 

include the anticipated large CO2 injection volumes associated with GS, the buoyant and 

mobile nature of the injectate, and its corrosivity in the presence of water. The Agency 

believes that this process will encourage owners or operators and Directors to consider 

the use of alternative formations for GS, including non-USDW formations through the 

waiver process, prior to applying for or approving aquifer exemption expansions for 

Class II EOR/EGR wells transitioning to Class VI GS operations. See the discussion on 

injection depth waivers for GS for information on scenarios that will require the use of 

both aquifer exemptions and waivers in this section.

Injection formations for GS: In response to comments received on the proposal and the 

NODA and Request for Comment, today’s rule does not categorically preclude or 

prohibit injection into any type of formation. Instead, the requirements are designed to 

ensure protection of USDWs from endangerment through proper siting, well 

construction, operation, monitoring, and PISC at all sites selected for GS. 

EPA recognizes that some types of formations, such as coal seams and basalts, are 

typically shallow and above the lowermost USDW. EPA expects that injection wells 

conducting GS in these shallow formations will be permitted as Class VI wells and such 

wells will be issued waivers, provided that their owners or operators can meet all of the 

requirements for an injection depth waiver at §146.95 and demonstrate that such injection 

can be performed in a manner that protects USDWs. EPA adds that wells used to inject 
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into these formation types or other formation types (e.g., salt domes and shales) for 

experimental purposes would be permitted as Class V experimental technology wells. See 

section II.H for additional information on the use of the Class V experimental technology 

well classification following finalization of today’s rulemaking. 

To facilitate experimental injection for GS and to increase understanding of injection into

basalts, shales, and other formation types, 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. 

Adaptive approach: In the early stages of GS deployment, EPA will collect and review 

project data on GS projects, including information on any Class VI wells granted a 

waiver of the injection depth requirements and any aquifer exemption expansions issued 

for Class II EOR/EGR wells transitioning to Class VI GS. Given the unique nature of the 

waiver of injection depth requirements, the Agency will further assess if the requirements 

provided in §146.95 are appropriately designed to evaluate waiver applications, issue 

waivers, and ensure protection of USDWs. The adaptive approach will also afford the 

Agency an opportunity to assess the manner in which waivers and expansions of existing 

Class II EOR/EGR aquifer exemptions for GS are issued across the US and evaluate the 

applicability of injection into all formation types. 

E. Injection Well Operation

Today’s final rule contains tailored requirements at §146.88 for the operation of Class VI

wells, including injection pressure limitations, use of down-hole shut-off systems, and 

annulus pressure requirements to ensure that injection of CO2 does not endanger USDWs.

The requirements for operation of Class VI injection wells are based on the existing 

requirements for Class I wells, with enhancements to account for the unique conditions 

that will occur during GS including buoyancy, corrosivity, and higher sustained pressures 

over a longer period of operation. 
Page 95 of 259

Injection pressure limitations: EPA proposed that owners or operators limit injection 

pressure such that pressure in the injection zone does not exceed 90 percent of the 

fracture pressure of the injection zone, and that injection may not initiate new fractures or 

propagate existing fractures. Most commenters opposed an arbitrary pressure limit, and 

advocated setting pressure limitations on a site-specific basis. Today’s final rule retains 

the requirement that pressure in the injection zone must not exceed 90 percent of the 

fracture pressure of the injection zone (§146.88(a)). The calculated fracture pressure—

and therefore, the injection pressure limit—are based on site-specific geologic and 

geomechanical data collected during the site characterization process as advocated by 

commenters.

Annulus pressure: EPA proposed that owners or operators fill the annulus with an 

approved non-corrosive fluid and maintain pressure on the annulus that exceeds the 

operating injection pressure. Many commenters disagreed with the requirement to 

maintain an annulus pressure greater than the injection pressure because they indicated 

that this could increase the potential for damage to the well. 

EPA acknowledges that, in some circumstances, maintaining an annulus pressure greater 

than the injection pressure could result in a greater chance for damage to the well or the 

formation. As a result, the final rule provides the Director discretion to adjust this 

requirement if maintaining an annulus pressure higher than the formation pressure may 

cause damage to the well or the formation. EPA changed the requirements in §146.88(c) 

to: “The owner or operator must maintain on the annulus a pressure that exceeds the 

operating injection pressure, unless the Director determines that such requirement might 

harm the integrity of the well or endanger USDWs.” 

Automatic down-hole shut-off devices: EPA proposed that owners or operators install and 

use alarms and automatic down-hole shut-off systems, in addition to the use of surface 

shut-off devices, to alert the owner or operator and shut-in the well in the event of a loss 

of mechanical integrity. Automatic down-hole shut-off devices are valves located in the 

well tubing (at a depth established based on the location of USDWs) that are set to close 
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if triggered by changes in flow rate or other monitored parameters. Automatic surface 

shut-off valves are commonly used in the oil and gas industry to prevent further well 

complications in the case of a triggered event such as inadvertent well backflow during a 

workover. The Agency sought comment on the merits of requiring such devices.

Commenters, including representatives of water associations, supported the requirement 

to construct Class VI wells with automatic down-hole shut-off devices. These 

commenters suggested that automatic down-hole shut-off devices provide an additional 

barrier against upward migration of CO2 and serve as an additional level of protection 

when used in concert with surface shut-off devices. 

Many industry commenters disagreed with the requirement to construct Class VI wells 

with automatic down-hole shut-off devices. These commenters indicated that down-hole 

shut-off devices are redundant of surface devices and unnecessary and would not provide 

additional protection to USDWs. Commenters suggested that these devices are more 

appropriate for offshore wells and that the likelihood of damage to surface wellheads is 

small. Other commenters stated that installation of automatic down-hole shut-off devices 

in new and pre-existing deep injection wells is complex and servicing of the devices 

necessitates removal of the tubing. Commenters also indicated that the use of such 

devices can complicate routine testing and well workovers, and that failure of such 

devices could damage the well. Several commenters suggested alternatives to automatic 

down-hole shut-off devices including: use of wireline retrievable plugs with landing 

nipples; and use of well materials designed to withstand the proposed injection pressures. 

EPA evaluated the range of comments on this topic and maintains that down-hole shutoff devices are an important barrier against endangerment of USDWs from the escape of

CO2. While stakeholders commented that automatic down-hole shut-off devices are 

primarily used in offshore oil and gas production applications, they are currently used in 

other situations where loss of well integrity could result in damage to the well or harm to 

humans (e.g., near high-density population areas, or in onshore acid gas injection; IEA, 

2003). While commenters indicated that down-hole monitoring is more difficult, or 
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impractical with an automatic down-hole shut-off device in place, EPA has identified 

examples of documented logging techniques, including ultrasonic and temperature logs, 

that can be performed with an automatic down-hole device emplaced (Julian et al., 2007; 

Somaschini et al., 2009). They are also used in high pressure, high temperature onshore 

wells and in permafrost areas.

EPA recognizes that, in limited circumstances, the sudden closing of an automatic shutoff valve could cause damage to a well, and that some of these devices may make well 

maintenance and operation more challenging. Additionally, EPA recognizes that well 

complications may increase as the frequency of routine or unexpected down-hole device 

maintenance workovers increases. However, the buoyant nature of CO2 and the elevated 

injection pressures associated with GS increase the likelihood of an uncontrolled flow of 

CO2 out of the well. If CO2 does begin to flow back up an injection well, it will rapidly 

cool and expand as it moves toward the surface and can result in a stream of solid CO2 

which can cause damage to the wellhead and other well instrumentation; such damage 

has been documented in CO2 ER wells (Skinner, 2003; Duncan et al., 2008). Automatic 

shut-off devices can help prevent such occurrences.

After evaluating the risks and benefits of down-hole shut-off systems and considering 

additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells. Instead, the final rule, at §146.88(e)(2), requires that owners or 

operators of onshore Class VI wells install automatic surface shut-off devices, and 

affords Director's discretion to mandate automatic down-hole shut-off devices in onshore 

situations that may warrant their use. EPA believes that requiring automatic surface shutoff devices instead of down-hole devices provides more flexibility to owners or operators 

when performing required mechanical integrity tests. Additionally, this requirement 

addresses concerns about risks associated with routine well workovers that may be 

complicated by the presence of down-hole devices while still maintaining USDW 

protection. 
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Today’s rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for 

Class VI wells located in the offshore submerged lands within the jurisdiction of a State 

UIC program. The Agency believes that the unique construction and operational 

conditions for offshore Class VI wells, including isolation from shorelines and the need 

to construct wells through the water column and the subsurface, may delay response time 

in the event of well difficulties. These conditions merit requiring automatic down-hole 

shut-off devices for offshore wells in the submerged lands of a State. 

In the event of onshore or offshore well complications, an automatic surface or downhole shut-off device will immediately shut-in the well to cease injection (limiting CO2

volume associated with the event), isolate the injectate, and minimizes the risk of 

subsurface fluid movement and associated problems that may endanger USDWs. EPA 

believes that requiring the installation of automatic surface shut-off devices for onshore 

wells (and affording Director's discretion to require down-hole devices where necessary) 

and automatic down-hole shut-off devices for offshore wells in submerged lands within 

the jurisdiction of a State ensures that proper precautions are taken to prevent subsurface 

fluid movement and ensure protection of USDWs, human health, and the environment.

Well stimulation: In the proposed rule, EPA sought comment on whether well stimulation 

or fracturing to enhance formation injectivity is appropriate and should be allowed for 

Class VI wells. EPA also requested submittal of information from commenters to better 

qualify the use of hydraulic fracturing for well stimulation in specific geologic settings 

and various lithologies. Well owners or operators often use stimulation techniques, 

including intentionally creating new or propagating existing fractures in the injection 

zone on wells that have experienced decreased oil and gas production. Additionally, 

increasing the number and size of fractures surrounding the injection zone can enhance or 

increase the injectivity of the formation. However, if fractures extend to the confining 

layer, USDWs can be endangered. 

Some commenters stated that while stimulation using a range of techniques including 

hydraulic fracturing is not appropriate in all geologic settings it should be allowed for 
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Class VI wells. Commenters supported the requirement that hydraulic fracturing only be 

allowed during well stimulation, noting that ER operations have successfully employed 

hydraulic fracturing to increase well injectivity without damaging the confining layer. 

These commenters thought that enhancing injectivity through stimulation would allow 

injection to occur with fewer injection wells and therefore fewer penetrations of the 

confining layer. 

Many commenters indicated that the Director should be able to determine, based on sitespecific information, whether stimulation techniques would pose a risk to the confining 

layer. Some commenters proposed considerations for determining whether stimulation, 

including hydraulic fracturing, is appropriate in a given situation and acknowledged that 

tools exist for owners or operators and Directors to manage the safe use of well 

stimulation practices. These tools include use of monitoring programs or computer 

simulations in conjunction with stimulation activities to determine if stimulation is 

negatively impacting confining layers. Others suggested that open-hole injection zones 

and multiple injection points can also aid in increasing well injectivity. 

A water association commented that activities such as hydraulic fracturing should not be 

allowed under any circumstances in order to prevent fracturing of the confining layer and 

the opening of pathways for fluid migration into a USDW. 

EPA agrees with commenters that well stimulation may be appropriate in situations 

where it is determined that it will increase well injectivity and provide better performance 

for some projects. However, EPA believes that protection of USDWs from endangerment 

is critical and the primary purpose of UIC regulations pursuant to SDWA. In order to 

allow appropriate well stimulation while protecting confining layers and USDWs, EPA 

intends to allow stimulation only at the discretion of the Director. The Director is in the 

best position to determine if well stimulation techniques, including but not limited to 

hydraulic fracturing, are appropriate in a given situation. EPA has added a requirement at 

§146.91(d)(2) that the owner or operator must notify the Director before any stimulation 

activities are undertaken. Such notice will provide the Director an additional opportunity 
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to review stimulation plans, assess the description of stimulation fluids to be used, 

determine that stimulation will not interfere with containment, assess plan 

appropriateness, and potentially witness the stimulation activity. In order to preserve the 

integrity of the confining layer, EPA is retaining the prohibition against fracturing the 

confining layer at any time and adds that fracturing should not be allowed except during 

well stimulation.

Tracers: In the proposed rule, EPA sought comment on the use of tracers in GS 

operations. Tracers are inert compounds added to or naturally occurring in the injection 

fluid, which can be easily detected through monitoring wells or through surface 

monitoring techniques. Detection of the tracer would indicate a leak of the injection fluid 

from the injection zone. Many types of tracers are available, including perfluorocarbons, 

SF6, noble gases, and stable isotopes such 18O and 14C. 

Some commenters supported the use of tracers in Class VI injection wells, maintaining 

that tracers are a useful method for detecting CO2 leaks. Many commenters suggested 

that tracers should not be required, but should be allowed at the discretion of the Director. 

Other commenters thought that owners or operators should be allowed to decide whether 

to use tracers. 

Most commenters asserted that tracers were unnecessary and that better methods for 

tracking CO2 movement were available. These commenters cited a variety of reasons, 

including that tracers were expensive, burdensome, and untested; that detection of a 

tracer at the surface would do nothing to protect USDWs from endangerment; and that 

some tracers may have health risks or can contribute to climate change. EPA received 

comments on specific tracers, such as perfluorocarbons (which have been proven in other 

applications), radioactive tracers (which have been used successfully in the oil and gas 

industry, but only with a limited radius), and the use of CO2 itself (which can act as a 

tracer). 
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EPA agrees that tracers can be a useful tool in some circumstances, but recognizes that 

some factors (e.g., the potential to contribute GHGs to the atmosphere, cost, and 

difficulties associated with monitoring for tracers) may make other methods of tracking 

CO2 movement more practical. Therefore, today’s rule does not require use of tracers for 

Class VI wells. However, EPA does believe that tracers may be valuable in some cases, 

and will retain Director’s discretion to require the use of tracers and to determine the type 

of tracer to be used if the Director determines that their use will increase USDW 

protection from endangerment. 

F. Testing and Monitoring 

Today’s final rule at §146.90 requires owners or operators of Class VI wells to develop 

and implement a comprehensive testing and monitoring plan for their projects that 

includes injectate monitoring, corrosion monitoring of the well’s tubular, mechanical, and 

cement components, pressure fall-off testing, ground water quality monitoring, CO2

plume and pressure front tracking, and, at the Director’s discretion, surface air and soil 

gas monitoring (SDWA section 1421 et al). The rule also requires MIT to verify proper 

well construction, operation, and maintenance. 

Monitoring associated with injection projects is an important component of the UIC 

program and is required to ensure that USDWs are not endangered. Monitoring data can 

be used to verify that the injectate is safely confined in the target formation, minimize 

costs, maintain the efficiency of the storage operation, confirm that injection zone 

pressure changes follow predictions, and serve as inputs for AoR modeling. Monitoring 

results will provide information about site performance when compared against baseline 

information (collected during the site characterization phase) or when compared to 

previous monitoring results. In conjunction with careful site selection and AoR

delineation, monitoring is critical to the successful operation, PISC, and site closure of a 

GS project. 

Today’s monitoring requirements are based on existing UIC regulations, tailored to 

address the needs and challenges posed by GS projects. For example, supercritical CO2 is 
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different from many Class I injectates in physical properties and chemical composition. 

Also, many GS projects are anticipated to be “large-scale,” with large volumes of CO2

injected over long project life-spans. In the proposed rule, EPA sought comment on the 

testing and monitoring plan, MIT, the use of pressure fall-off testing, the types and 

amounts of ground water quality monitoring, pressure front tracking, geophysical 

methods, and surface air and soil gas monitoring. 

The testing and monitoring requirements for Class VI wells at §146.90, incorporates 

elements of pre-existing UIC requirements for monitoring and testing, tailored and 

augmented as appropriate for GS projects. EPA recognizes that much will be learned 

about monitoring and testing technologies and their application in various geologic 

settings in the early phases of GS deployment. Therefore, the Agency will evaluate 

monitoring data from early GS projects as part of the Agency’s adaptive rulemaking 

approach (See section II.F). The Agency is developing guidance to support testing and 

monitoring at GS sites. 

1. Testing and Monitoring Plan

EPA proposed that owners or operators of Class VI wells submit monitoring plans with 

their permit applications. These plans would be tailored to the GS project and be 

implemented upon Director approval, and, at a minimum, include procedures and 

frequencies for analysis of the chemical and physical characteristics of the CO2 stream; 

MIT (internal and external); corrosion monitoring; determination of the position of the 

CO2 plume and area of elevated pressure; monitoring of geochemical changes in the 

subsurface; and, at the discretion of the Director, surface air and soil gas monitoring for 

CO2 fluctuations, and any additional tests necessary to ensure USDW protection from 

endangerment. 

EPA sought comment on the testing and monitoring plan. Commenters recommended 

that the plan be reevaluated concurrently with AoR reevaluations. Commenters agreed 

that the plan should be site-specific and flexible to allow the use of varied monitoring and 

testing technologies. The Agency acknowledges the importance of flexibility and today’s 
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rule maintains a testing and monitoring plan requirement that will allow for site 

specificity and selection of the most appropriate monitoring technologies. The Agency 

also acknowledges the importance of agreement between site-characterization data, AoR 

information, and monitoring and testing information. 

The final rule retains the requirement to develop and implement a testing and monitoring 

plan and requires that the approved plan be incorporated into the Class VI permit. 

Owners or operators must also periodically review the testing and monitoring plan to 

incorporate operational and monitoring data and the most recent AoR reevaluation 

(§146.90(j)). This review must take place within one year of an AoR reevaluation, 

following significant changes to the facility, or when required by the Director. The 

iterative process by which this and other required plans are reviewed throughout the life 

of a project will promote an ongoing dialogue between the owner or operator 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 other circumstances change, while adding little burden if the AoR 

reevaluation confirms that the plan is appropriate as written. The Agency is developing 

guidance that describes the contents of the project plans required in the GS rule, 

including the testing and monitoring plan.

2. CO2 Stream Analysis

Injectate analysis provides information on the chemical composition and physical 

characteristics of the injectate. Analysis of the CO2 stream for GS projects will provide 

information about any impurities that may be present and whether such impurities might 

alter the corrosivity of the injectate down-hole. Such information is necessary to inform 

well construction and the project-specific testing and monitoring plan, and enable the 

owner or operator to optimize well operating parameters while ensuring compliance with 

the Class VI permit. The proposed rule required that analysis of the CO2 stream be 

conducted prior to commencing injection and throughout injection operations at an 

appropriate frequency based on the CO2 source and the likelihood of variability in the 

injectate composition. Commenters supported the need for analysis of the CO2 stream. 
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The final rule retains the requirement that owners or operators need to characterize their 

CO2 stream as part of their UIC permit application (§146.82(a)(7)), and throughout the 

operational life of the injection facility (§146.90(a)). The details of the sampling process 

and frequency must be described in the Director-approved, site/project-specific testing 

and monitoring plan.

Resource Conservation and Recovery Act (RCRA) Applicability to CO2 Streams: EPA 

received public comment asserting that the proposed UIC Class VI requirements were 

unclear as to whether the CO2 stream would be a RCRA hazardous waste, and left 

uncertain the type of permit needed. Many commenters stated that a CO2 stream should 

not be treated as a RCRA hazardous waste on the grounds that it is neither a listed 

hazardous waste nor does it exhibit a hazardous characteristic. Other commenters 

asserted that CO2 in the presence of water could exhibit the RCRA corrosivity 

characteristic. Additionally, commenters indicated that analytic procedures used under 

RCRA (in particular, the toxicity characteristic leaching procedure (TCLP)) cannot be 

applied to supercritical CO2 streams and that the Class VI regulations would better ensure 

the proper management of a CO2 injectate. EPA did not receive any new data on CO2

stream characterization in the public comments.

In general, subtitle C of RCRA establishes a “cradle to grave” regulatory scheme over 

certain “solid wastes” which are also “hazardous wastes.” RCRA defines solid waste as, 

among other things, discarded material, including solid, liquid, semisolid, or contained 

gaseous material. EPA has further defined the term solid waste for purposes of its 

hazardous waste regulations. To be considered a hazardous waste, a material must first be 

classified as a solid waste under the regulations (40 CFR 261.2). Under EPA’s 

regulations at 40 CFR 262.11, generators of solid waste are required to determine 

whether their wastes are hazardous wastes. A solid waste is a hazardous waste if it 

exhibits any of four characteristics of a hazardous waste (i.e., ignitability, corrosivity, 

reactivity, or toxicity) under 40 CFR 261.20-.24, or is a listed waste under 40 CFR 

261.30-.33 (these include various used chemical products, by-products from specific 

industries, or unused commercial products). 
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A CO2 stream injected for purposes of GS is a RCRA solid waste, as it has been 

discarded. Additionally, EPA agrees that a CO2 stream is not itself a listed RCRA 

hazardous waste. The CO2 stream would be a hazardous waste if it exhibits any of the 

ignitability, corrosivity, reactivity or toxicity characteristics (40 CFR 261.20-.24) or is a 

listed waste (40 CFR 261.30-.33). EPA has reviewed estimates of CO2 injectate quality, 

which were based upon information such as the quality of flue gas from the burning of 

fossil fuels, existing flue gas emission controls (e.g., electrostatic precipitators and 

scrubbers), and data from applied CO2 capture technology. These estimates indicate that 

captured CO2 could contain some impurities. These estimates also indicate that the types 

of impurities and their concentrations would likely vary by facility, coal composition, 

plant operating conditions, and pollutant removal and carbon capture technologies. 

Under this final rule, owners or operators will need to determine whether the CO2 stream 

is hazardous under EPA’s RCRA regulations, and if so, any injection of the CO2 stream 

may only occur in a Class I hazardous waste injection well. Conversely, Class VI wells 

cannot be used for the co-injection of RCRA hazardous wastes (i.e., hazardous wastes 

that are injected along with the CO2 stream). EPA supports the use of CO2 capture 

technologies that minimize impurities in the CO2 stream. At the same time, the Agency 

agrees that any requirements for the CO2 stream should be clearly identified. EPA has 

begun to examine issues of RCRA regulation for CO2 streams, including options such as 

a conditional exemption from the RCRA requirements for CO2 GS. If appropriate, EPA 

will address these issues in a separate action from today’s final UIC rule. Today’s rule 

does not itself change applicable RCRA regulations.

Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA)

Applicability to CO2 Streams: EPA received a range of comments regarding CERCLA 

liability and GS. Some commenters suggested that the Agency allow for a GS exemption 

under CERCLA, while others requested that the rule specify that injectate intrusion into a 

USDW is not considered a CERCLA release and that the SDWA provides enough civil 

and criminal enforcement authority to address any environmental contamination that 
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might result from GS. Other commenters supported maximizing protection under 

CERCLA by writing Class VI GS permits as broadly as possible so that “unauthorized 

releases” are avoided. 

CERCLA, more commonly known as Superfund, is the law that provides broad Federal

authority to clean up releases or threatened releases of hazardous substances that may 

endanger human health or the environment. CERCLA references four other 

environmental laws to designate more than 800 substances as hazardous and to identify 

many more as potentially hazardous due to their characteristics pursuant to RCRA. 

CERCLA authorizes EPA to clean up sites contaminated with hazardous substances and 

seek compensation from responsible parties or compel responsible parties to perform 

cleanups themselves.

CO2 itself is not listed as a hazardous substance under CERCLA. However, the CO2

stream may contain a listed hazardous substance (such as mercury) or may mobilize 

substances in the subsurface that could react with ground water to produce listed 

hazardous substances (such as sulfuric acid). Whether such substances may result in 

CERCLA liability from a GS facility depends entirely on the composition of the specific 

CO2 stream and the environmental media in which it is stored (e.g., soil or ground water). 

CERCLA exempts from liability under CERCLA section 107, 42 U.S.C. 9607, certain 

“Federally permitted releases” (FPR) as defined in CERCLA, 42 U.S.C. 9601(10). Class 

VI permits will need to be carefully structured to ensure that they prevent potential 

releases from the well, which are outside the scope of the Class VI permit. 

The UIC program Director has authority under the SDWA to address potential 

compliance issues (e.g., potential releases that may endanger USDWs) resulting from 

injection violations in the unlikely event that an emergency or remedial response (at 

§146.94) is necessary. Although EPA anticipates that the need for emergency or remedial 

actions at GS sites will be rare, today’s rule requires that emergency and remedial 

response plans be developed and updated to address such events (in accordance with the 

remedial response requirements at §146.94) and that owners or operators demonstrate 
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that financial resources are set aside to implement the plans if necessary (pursuant to the 

financial responsibility requirements at §146.85).

3. Mechanical Integrity Testing (MIT)

Injection well MIT is a critical component of the UIC program’s requirements designed 

to ensure USDW protection from endangerment. Testing and monitoring the integrity of 

an injection well at an appropriate frequency throughout the injection operation, in 

conjunction with corrosion monitoring of well materials, can verify that the injection 

system is operating as intended or provide notice that there may be a loss of containment 

that may lead to endangerment of USDWs. Routine MITs enable owners or operators to 

ensure that well integrity is maintained from construction throughout the life of the 

injection project. UIC regulations for other deep-well classes require injection well 

owners or operators to demonstrate both internal and external mechanical integrity. 

Internal MIT: Internal mechanical integrity (MI) is an absence of significant leakage in 

the injection tubing, casing, or packer. Loss of internal MI is usually due to corrosion or 

mechanical failure of the injection well’s tubular and mechanical components. Typically, 

internal MI is demonstrated with an annual pressure test of the annular space between the 

injection tubing and long-string casing. 

For Class VI wells, EPA proposed that owners or operators perform an initial annulus 

pressure test and then continuously monitor injection pressure, injection rate, injected 

volume, pressure on the annulus between the tubing and long-stem casing, and annulus 

fluid during injection. EPA sought comment on the appropriate frequency of internal 

MIT and the practicality of continuous testing to measure internal MI. Commenters’ 

suggestions on the appropriate frequency varied and some believed that the proposed

requirement for continuous monitoring seemed excessive and/or impractical.

Today’s rule at §146.89 retains the requirements for continuous monitoring to 

demonstrate internal MI presented in the proposed rule. This is driven by concerns that 

the potential corrosivity of CO2 in the presence of water and the anticipated high 
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pressures and volumes of injectate could compromise the integrity of the well. 

Continuous monitoring to demonstrate internal MI for Class VI wells is essential because 

it allows for the immediate identification of corrosion-related mechanical integrity 

problems or problems due to temperature and pressure effects associated with injection of 

supercritical CO2. Furthermore, the technologies used for continuous monitoring are

currently available and widely used. 

External MIT: External well MI is demonstrated by establishing the absence of 

significant fluid movement along the outside of the casing, generally between the cement 

and the well structure, and between the cement and the well-bore. Failure of an external 

MIT can indicate improper cementing or degradation of the cement that was emplaced to 

fill and seal the annular space between the outside of the casing and the well-bore. This 

type of failure can lead to movement of injected fluids out of intended injection zones 

and toward USDWs. 

EPA proposed annual external MIT using a tracer survey, a temperature or noise log, a 

casing inspection log, or any other test the Director requires. EPA sought comment on the 

appropriate frequency and types of MITs for Class VI wells. In general, commenters 

requested flexibility in methods and timing of testing, with some suggesting a five-year 

frequency for external MIT. 

Because GS is a new technology and there are a number of unknowns associated with the 

long-term effects of injecting large volumes of CO2, today’s rule requires owners or 

operators of CO2 injection wells to demonstrate external MI at least once annually during 

injection operations using a tracer survey or a temperature or noise log (§146.89(c)). This 

increase in required testing frequency relative to other injection well classes ensures the 

protection of USDWs from endangerment given the potential corrosive effects of CO2 (in 

the presence of water) on well components (steel casing and cement) and the buoyant 

nature of supercritical CO2 relative to formation brines, which could enable it to migrate 

up a compromised wellbore. 
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In addition, the final rule is modified from the proposal to allow the Director discretion to 

require use of casing inspection logs to determine the presence or absence of any casing 

corrosion at §146.89(d). To ensure the appropriate application of this test and to afford 

flexibility to owners or operators and Directors, the final rule requires that the frequency 

of this test be established based on site-specific and well-specific conditions and 

incorporated into the testing and monitoring plan. This modification is made to clarify 

that such logs, while not used to directly assess mechanical integrity, may be used to 

measure for corrosion of the long-string casing and thus may serve as a useful predictor 

of potential mechanical integrity problems in the future. 

4. Corrosion Monitoring

Existing UIC Class I deep well operating requirements allow the Director discretion to 

require corrosion monitoring and control where corrosive fluids are injected. Corrosion 

monitoring can provide early warning of well material corrosion that could compromise 

the well’s MI. Given the potential for corrosion of well components if they are in contact 

with water saturated with CO2 or CO2 in the presence of water, corrosion monitoring is 

included as a routine part of Class VI well testing. EPA proposed quarterly monitoring 

using coupons, routing the CO2 injectate through a loop of well material, or an alternative 

method proposed by the Director. 

Some commenters believed that such testing was unnecessary given that well materials 

will need to be constructed with materials compatible with the injectate. EPA notes, 

however, that the long-term effects of CO2 on cement and other well components are not 

yet completely understood. Given the anticipated long life-span of a Class VI well and 

the difficulties that would be associated with a corrosion-related well failure, EPA 

believes that quarterly corrosion monitoring is justified and retains the requirement in the 

final rule (at §146.90(c)). 

5. Ground Water/Geochemical Monitoring

Ground water and geochemical monitoring are important monitoring techniques that 

ensure protection of USDWs from endangerment, preserve water quality, and allow for 
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timely detection of any leakage of CO2 or displaced formation fluids out of the target 

formation and/or through the confining layer. Periodically analyzing ground water quality 

(e.g., salinity, pH, and aqueous and pure-phase CO2) above the confining layer can reveal 

geochemical changes that result from leaching or mobilization of heavy metals and 

organic compounds, or fluid displacement. 

EPA proposed periodic monitoring of the ground water quality and geochemical changes 

above the confining zone and sought comment on the types and frequencies of 

monitoring to be performed. The Agency agrees with commenters who support a flexible 

monitoring regime, and believes that the amounts and types of monitoring should be site 

specific. 

Some commenters expressed concern that monitoring wells penetrating the confining 

layer could become conduits for fluid movement. EPA clarifies that direct geochemical 

monitoring is not required in the target formation itself, although sampling via wells in 

the target formation may be desirable in some circumstances, e.g., to perform 

geochemical monitoring in wells used for direct pressure monitoring to meet 

requirements of §146.90(g). Furthermore, EPA believes that the benefits of direct 

monitoring using wells outweigh the risks of unintended fluid migration. Monitoring 

wells provide important information that confirms injectate confinement. Careful siting 

and appropriate construction of monitoring wells are critical to effective monitoring and 

can minimize the potential that monitoring wells serve as conduits for fluid movement. 

The final rule, at §146.90(d), retains the requirement for direct ground water quality 

monitoring as specified in the site-specific monitoring plan. Such monitoring is required 

above the confining zone (and below the lower confining zone for waivered wells

pursuant to requirements at §146.95(f)). The number, placement, and depth of monitoring 

wells will be site-specific and will be based on information collected during baseline site 

characterization. Ground water and geochemical monitoring results, when compared to 

baseline site characterization data, previous monitoring results, and operational 

parameters will enable owners or operators and Directors to assess project performance, 
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confirm that the injectate, formation fluids, and the injection operation are not impacting 

overlying (and underlying, for wells operating under injection depth waivers) formations, 

identify formation fluid changes, inform modifications to the monitoring plan, and ensure 

USDW protection from endangerment. 

6. Pressure Fall-Off Testing

Pressure fall-off tests are designed to determine if reservoir pressures are tracking 

predicted pressures and modeling inputs. The results of pressure fall-off tests will 

confirm site characterization information, inform AoR reevaluations, and verify that 

projects are operating properly and the injection zone is responding as predicted. 

EPA proposed that owners or operators perform pressure fall-off testing at least once 

every five years and requested comment on the use and frequency of these tests. Some 

commenters expressed support for the tests, and suggested frequencies of annually to

every five years. Some commenters expressed opposition to the tests stating that they are 

not necessary and the information they provide is not unique and may be obtained from 

other tests.

The Agency believes that pressure fall-off testing provides valuable information and that 

a five-year frequency is appropriate. The final rule, at §146.90(f), retains the requirement 

for testing at least once every five years. EPA believes that this frequency will allow for 

pressure tracking in the injection formation. It will also help to verify that the operation is 

responding as modeled/predicted and allow the owner or operator to take appropriate 

action (e.g., recalibration of the AoR model) in the event that the monitoring results do 

not match expectations. 

7. CO2 Plume and Pressure Front Monitoring/Tracking

Monitoring the movement of the CO2 and the pressure front are necessary to identify 

potential risks to USDWs posed by injection activities, verify predictions of plume 

movement, provide inputs for modeling, identify needed corrective actions, and target 

other monitoring activities. The proposed rule required tracking of the plume and 
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pressure front by direct pressure monitoring via monitoring wells in the first formation 

overlying the confining zone or by using indirect geophysical techniques such as seismic 

profiling, electrical, gravity, and electromagnetic surveys. 

EPA sought comment on the requirement to track the CO2 plume and pressure front and 

the appropriate technologies and geophysical methods that can be used for such 

monitoring. Commenters focused on appropriate testing frequency and technologies, 

expressing concerns about cost and the belief that the requirements were too stringent and 

might negatively affect public opinion. With respect to direct monitoring of pressure, 

some commenters supported the proposed approach, while others believed the use of 

monitoring wells would be costly and difficult. Some commenters supported indirect 

(i.e., geophysical) monitoring of the plume, while others expressed concerns that seismic 

methods may not be effective in all settings. 

In consideration of all public comments, today’s final rule at §146.90 requires Class VI 

well owners or operators to perform monitoring to track the extent of the CO2 plume and 

pressure front. The owner or operator must use direct methods to monitor for pressure 

changes in the injection zone. Indirect methods (e.g., seismic, electrical, gravity, or 

electromagnetic surveys and/or down-hole CO2 detection tools) are required unless the 

Director determines, based on site-specific geology that such methods are not appropriate 

(§146.90(g)). 

The purpose of monitoring in the injection zone (§146.90(g)(1)) is to track the 

development and movement of the pressure front and CO2 plume. This will support an 

understanding of site performance and verify predictive modeling. Pressure monitoring 

within the injection zone is necessary because any such monitoring above the confining 

zone would not detect movement of the pressure front unless a breach of the confining 

zone occurs. EPA believes that monitoring using wells in the injection zone (i.e., that 

penetrate the confining zone) can be safely performed if the wells are constructed to 

prevent flow between the injection zone and USDWs or other layers above the confining 

zone. Such construction technologies exist and have been used in the oil and gas industry 
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for years. EPA believes that the benefits of monitoring in the injection formation 

outweigh the manageable risk of those monitoring wells serving as conduits for fluid 

movement. EPA adds that owners or operators may consider performing additional 

pressure monitoring in wells that are above the confining zone (e.g., in the same wells 

used to perform ground water quality monitoring required at §146.90(d)) to provide 

additional verification that no pressure changes are occurring above the confining zone 

due to CO2 leakage or displacement of native fluids. An appropriate monitoring regimen 

will enhance public confidence in GS. EPA disagrees that the use of monitoring wells to 

track the plume and pressure front will be too costly and believes that the benefits 

outweigh the costs.

Additionally, §146.90(g)(2) requires owners or operators to track the position of the CO2

plume using indirect methods (e.g., seismic, electrical, gravity, or electromagnetic 

surveys and/or down-hole CO2 detection tools), unless the Director determines based on 

site-specific geology, that such methods are not appropriate. EPA is affording Director’s 

discretion regarding the use of geophysical techniques at some sites because the Agency 

recognizes that geophysical methods are not appropriate in all geologic settings. For 

example, geophysical methods are difficult to execute in areas that are structurally and 

topographically complex or where lithologies have limited contrast in density, porosity, 

permeability, and other physical properties. EPA clarifies that this determination will be 

made by the Director based on the site-specific geologic information submitted by the 

owner or operator with their permit application. However, because the use of geophysical 

methods can yield valuable information about the extent of the CO2 plume and pressure 

front, EPA is requiring their use unless they are determined not to be appropriate. 

EPA believes that this approach – requiring direct pressure monitoring at all sites and the 

use of indirect geophysical or down-hole techniques except where the Director 

determines that such methods are not appropriate based on site-specific information –

provides owners or operators the flexibility to develop a site-specific monitoring plan, 

ensures that direct monitoring is available to track the movement of the CO2 and validate 

models, and recognizes that indirect techniques may not be appropriate in all situations. 
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8. Surface Air/Soil Gas Monitoring

EPA proposed that Directors have discretion to require surface air and/or soil gas 

monitoring at GS sites. Surface air and soil gas monitoring can be used to monitor the 

flux of CO2 out of the subsurface, with elevation of CO2 levels above background levels 

indicating potential leakage and USDW endangerment. While deep subsurface well 

monitoring forms the primary basis for detecting threats to USDWs, knowledge of leaks 

to shallow USDWs is of critical importance because these USDWs are more likely to 

serve public water supplies than deeper formations. If leakage to a USDW should occur, 

near-surface and surface monitoring may assist owners or operators in identifying the 

general location of the leak and what USDWs may have been impacted by the leak, and 

initiating targeted emergency and remedial response actions. 

EPA sought comment on the use of surface air and soil gas monitoring technologies to 

ensure USDW protection. Commenters that supported the use of surface air and soil gas 

monitoring technologies stressed the importance of USDW protection and noted that this 

monitoring can provide a potential indication that a leak into a USDW has occurred and 

may need to be remediated. These commenters suggested that such monitoring should be 

site-specific and that any data collected must be compared against baseline data 

(collected prior to commencing an injection project). Those who opposed the proposed 

surface air and soil gas monitoring requirements questioned the applicability of surface 

air and soil gas technologies to USDW protection, and expressed concerns about the 

potential for false positives, uncertainty and variability in measurements, and the negative 

impact that this requirement may have on public perception of GS. Some commenters 

also believed that requiring such monitoring would be outside the scope of SDWA 

authority. 

The Agency agrees that surface air and soil gas monitoring, when coupled with 

subsurface monitoring, may be appropriate at some GS projects to ensure USDW 

protection and agrees that baseline information is needed for this type of monitoring.

EPA also acknowledges that surface air and soil gas measurements are subject to 
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variability and may not be suitable for all settings as a method to ensure USDW 

protection. However, EPA does not believe that this should entirely preclude their use. 

The decision to use surface monitoring and the selection of monitoring methods will be 

site-specific (e.g., may be influenced by geology; injection depth; and operational 

conditions) and must be based on potential risks to USDWs within the AoR. EPA also 

believes that appropriately selected surface monitoring technologies will not negatively 

influence public opinion, but could help to assure the public that GS projects are being 

appropriately operated and monitored. Used in conjunction with deep subsurface 

monitoring, as required at §146.90, and as part of a multi-barrier approach to protecting 

USDWs from endangerment, surface air and soil gas monitoring are within the scope of 

SDWA’s general authority (SDWA sections 1421 et al). Furthermore, where deployed, 

such monitoring will increase USDW protection, enable immediate notification of the 

UIC Director in the case of potential USDW endangerment, and facilitate remedial 

action.

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring 

at the discretion of the Director as a means of identifying leaks that may pose a risk to 

USDWs and informing emergency notification of a Class VI owner or operator and UIC 

Director in the event of a USDW endangerment, pursuant to requirements at §146.91(c).

Since proposal of the Class VI UIC requirements (73 FR 43492, July 25, 2008), EPA 

proposed, and is finalizing concurrently with this rulemaking PLACEHOLDER FOR 

TIME SENSITIVE PHRASE, GS reporting requirements under the GHG Reporting 

Program (subpart RR). Subpart RR is being promulgated under authority of the CAA and 

builds on UIC requirements with the additional goals of verifying the amount of CO2

sequestered and collecting data on any CO2 surface emissions. If a Director requires 

surface air/soil gas monitoring pursuant to requirements at §146.90(h) and an owner or 

operator demonstrates that monitoring employed under §§98.440 to 98.449 of subpart RR 

meets the requirements at §146.90(h)(3), the Director must approve the use of monitoring 

employed under subpart RR. 
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The Agency recognizes that there may be unique circumstances wherein the UIC Director 

requires the use of surface air/soil gas monitoring other than monitoring deployed under 

subpart RR due to site-specific considerations. For example, a UIC Director may identify 

a sensitive USDW such as a sole source aquifer, as defined at 40 CFR 149, in the AoR of 

a GS project. He or she may determine that the most appropriate method of enhancing 

protection of such resources is to require the owner or operator to deploy an array of soil 

gas probes, pursuant to §146.90(h), around the sole source aquifer at specified depths and 

lateral spacing, with specified sampling and reporting frequencies, to ensure USDW 

protection. 

EPA believes that the requirements of these two rules complement one another by 

concurrently ensuring USDW protection, as appropriate, and requiring reporting of CO2

surface emissions under subpart RR. Subpart RR is discussed further in section II.C.

9. Additional Requirements

EPA recognizes that monitoring and testing technologies used at GS sites will vary and 

be project-specific, influenced by both geologic conditions and project characteristics. At 

certain sites additional monitoring may be needed. Furthermore, EPA acknowledges that 

the science and technology behind subsurface monitoring and testing will continue to 

develop, and new methods may emerge to provide additional monitoring options. 

Therefore, the final rule (at §146.90(i)) allows the Director discretion to require 

additional monitoring where appropriate. For example, a Director may require a Class VI 

owner or operator to conduct ground water quality monitoring in additional formations or 

zones or require the use of multiple indirect geophysical methods for plume and pressure 

front tracking if he or she determines it is necessary based on review of project-specific 

information submitted.

The final rule, at §146.90(k), requires owners or operators to submit a quality assurance 

and surveillance plan (QASP) for all testing and monitoring requirements. A QASP 

ensures that all aspects of monitoring and testing are verifiable, including the 

technologies, methodologies, frequencies, and procedures involved. Each QASP will be 
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unique to a given GS project, informed by site-specific details, monitoring technologies 

selected, and will be updated as the project evolves in concert with the testing and 

monitoring plan. 

G. Recordkeeping and Reporting 

Pursuant to §1445(a)(1) of the SDWA, today’s final rule at §146.91 requires owners or 

operators of Class VI wells to submit the results of required periodic testing and 

monitoring associated with the GS project. Furthermore, today’s rule at §146.91(e) also 

requires that all required reports, submittals, and notifications under subpart H be 

submitted to EPA in an electronic format. This requirement applies to owners or 

operators in Class VI primacy States and those in States where EPA implements the Class 

VI program, pursuant to §147.1. All Directors will have access to the data through the 

EPA electronic data system. 

EPA expects that the Class VI permit application process will be an iterative process,

during which the owner or operator must submit information to the Director to inform 

permitting decisions and permit issuance. During this process, the Director is responsible 

for reviewing and approving the required information. The Agency is requiring that 

owners or operators submit information in an electronic format to facilitate accessibility 

and transferability; however, if an owner or operator cannot submit the required data 

using EPA’s electronic reporting system, EPA expects the Director to coordinate with 

EPA regarding when alternate reporting is necessary. Following EPA’s approval of a 

non-electronic submittal format, an alternate reporting procedure may be allowed.

The reporting requirements are designed to provide the Director with the information 

needed to ensure compliance with UIC Class VI permits, while also ensuring that GS 

projects are operating properly, are in compliance with their permit conditions, and are

sufficiently protective of USDWs. The information compiled under §146.91 may be used 

as evidence of a permit violation. EPA plans to use the data and information submitted by 

owners or operators to periodically evaluate the effectiveness of the GS program,
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enabling the Agency to make changes to the Class VI program as necessary to 

incorporate new research, data, and information about GS and associated technologies.

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

Today’s rule identifies the technical information and reports that Class VI owners or 

operators must submit to the Director to obtain a Class VI permit to construct, operate, 

monitor, and close a Class VI well. The information submitted as a demonstration, to the 

Director, must be in the appropriate format and level of detail necessary to support 

permitting and project-specific decisions by the Director to ensure USDW protection. 

The final decision regarding the appropriateness and acceptability of all owner or 

operator submissions rests with the Director.

Class VI Permit Application Information: Today’s rule requires owners or operators to 

submit, pursuant to the requirements at §146.91(e), information to the Director to support 

Class VI permit applications (this information is enumerated at §146.82). This 

information includes site characterization information on the stratigraphy, geologic 

structure, and hydrogeologic properties of the site; a demonstration that the applicant has 

met financial responsibility requirements; proposed construction, operating, and testing 

procedures; and AoR/ corrective action, testing and monitoring, well plugging, PISC and 

site closure, and emergency and remedial response plans. The specific requirements for 

the content of this information are discussed in other sections of this preamble.

Operational and Monitoring Reports: Today’s rule, at §146.91, requires owners or 

operators to submit project monitoring and operational data at varying intervals (e.g., 

semi-annually, 30 days, and 24 hours). 

EPA proposed that operating data be reported semi-annually. EPA also proposed that 

monitoring data be submitted semi-annually in certain circumstances. Several 

commenters asked that the Director have discretion to authorize reporting less frequently 

than semi-annually, while other commenters suggested monthly or quarterly reporting. 

EPA is retaining the semi-annual reporting requirement for operating data and some 
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monitoring data in the final rule (§146.91(a)). However, permitting authorities may 

choose to require more frequent reporting. 

The final rule also requires owners or operators to report the results of mechanical 

integrity tests, any other injection well testing required by the Director, and any well 

workovers within 30 days (§146.91(b)), as proposed. 

Today’s final rule consolidates notification requirements and clarifies the manner in 

which the data must be reported. Owners or operators must notify the Director in writing 

30 days prior to any planned well workover, stimulation, or test of the injection well 

(§146.91(d)). The final rule also requires owners or operators to notify the Director 

within 24 hours of obtaining any evidence that the injected CO2 stream and associated 

pressure front may cause an endangerment to a USDW, any noncompliance with a permit 

condition, or of an event (such as malfunction of the injection system or triggering of a 

down-hole automatic shut-off system) that may endanger USDWs, or any release of 

carbon dioxide to the atmosphere or biosphere detected through any required soil/air 

monitoring (§146.91(c)). 

Area of review reevaluations and plan amendments: Today’s final rule requires owners 

or operators to electronically submit AoR reevaluation information and all plan 

amendments, pursuant to §146.84, at a minimum of every five years. 

Annual report: In addition to the recordkeeping and reporting requirements, EPA sought 

comment on requiring submittal of an annual report throughout the duration of a GS 

project. Most commenters did not support annual reports. 

Today’s final rule does not include a requirement for an annual report. EPA recognizes 

the concerns expressed by commenters about the burden associated with an annual report, 

and believes that the reporting required at §146.91(a) in conjunction with the AoR 

reevaluations and associated plan updates, which are required no less frequently than 

every five years, will facilitate a continuous dialogue between owners or operators and 
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the permitting authority, provide evidence of compliance with the Class VI permit, and 

ensure protection to USDWs. 

2. How Must Information Be Submitted?

Electronic Reporting: Recognizing that much of the data generated during Class VI site 

characterization, operation, testing and monitoring, mechanical integrity testing, and 

during the post-injection site care period will be generated in electronic format, EPA 

proposed that owners or operators report data in an electronic format acceptable to the 

Director (§146.91). EPA also proposed that the Director have discretion to accept data in 

other formats, if appropriate. EPA sought comment on electronic data submissions and 

the concept of providing Directors discretion to accept other data formats. See section 

II.C for additional information on mandatory reporting of greenhouse gases under the 

Clean Air Act.

Most commenters supported the concept of requiring data to be submitted electronically. 

Commenters also recognized that there may be a need to accept data in other formats. 

Several commenters expressed concern about whether States would have the capabilities 

to accept electronic data submissions from owners or operators.

In light of the prevalent use of electronic data, the expectation that Class VI wells will be 

used into the future, that the capability to send and receive electronic data will improve 

over time, and that today, information generated during GS site characterization, 

operation, monitoring, and testing is generated in electronic formats, the final rule 

requires that owners or operators submit data in an electronic format. 

Acknowledging that some States may have to develop electronic data systems to receive 

electronic information from the owner or operator, and that many States which already 

have electronic data systems will have to make changes to accommodate a new class of 

UIC well (Class VI), EPA believes that it is prudent to provide assistance by developing a 

central framework for the electronic system that will be used by States to gather and track 

owner or operator data. This will enable owners or operators to submit data without 
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having to wait for a State to develop a system. It will also provide for standardized 

submissions across the country and enable States to focus State resources on reviewing 

and approving permit applications rather than building or upgrading separate, 

independent databases for GS information.

EPA recognizes that there may be some circumstances where it may be necessary to 

collect data in other formats, e.g., for historical data, etc. Therefore, the Agency is 

providing for the Director to allow submission of data in alternative formats on a case-bycase basis. EPA expects that decisions to allow submission of data in formats other than 

electronic will be based on the inability or inefficiency of converting data to electronic 

formats, rather than the ability of the State to accept electronic data.

3. What are the Recordkeeping Requirements under This Rule?

Today’s final rule requires that owners or operators retain most operational monitoring 

data as required under §146.91 for 10 years after the data are collected. In addition, the 

rule requires that owners or operators retain certain data until 10 years after site closure. 

This recordkeeping timeframe, which is longer than requirements for other injection well 

classes, is appropriate and tailored to the longer life-spans of GS projects. 

The proposed rule did not include any requirements for operational data recordkeeping. 

However, existing UIC requirements at 40 CFR 144.51(j), which apply to all permitted 

injection wells require retention of certain operational data and permit application data 

for three years and retention of injectate quality data throughout the life of the project and 

for three years after injection well plugging. Commenters requested clarity on the 

recordkeeping requirements for Class VI well owners or operators, particularly related to 

well plugging and site closure reports.

Today’s final rule clarifies the recordkeeping requirements for Class VI well owners or 

operators. These include the requirements at 40 CFR 144.51(j) and the Class VI-specific 

recordkeeping requirements in today’s rule at §146.91(f). Class VI well owners or 

operators must retain data collected to support permit applications and data on the CO2
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stream until 10 years after site closure. Owners or operators must retain monitoring data 

collected under the testing and monitoring requirements at §146.90(b-i) for 10 years after 

it is collected. Today’s rule allows the Director authority to require the owner or operator 

to retain specific operational monitoring data for a longer duration of time 

(§146.91(f)(4)). Well plugging reports, PISC data, and site closure reports must be kept 

for 10 years after site closure (§§146.92(d), 146.93(e), and 146.93(g)).

EPA believes that longer record retention timeframes are appropriate for Class VI wells 

to ensure that all necessary data are available to support AoR reevaluations, updates to 

the various plans which will occur at least every five years, and non-endangerment 

demonstrations during PISC. In addition, extended retention periods will ensure that data 

are available should any project-specific questions or concerns arise following site 

closure. These data will also support EPA’s review of project data as part of the adaptive 

rulemaking approach.

Class VI compliance: Today’s final Class VI rule includes requirements for permitting, 

siting, construction, operation, financial responsibility, testing and monitoring, PISC, and 

site closure of Class VI injection wells to ensure that USDWs are not endangered. Sitespecific information collected during the site characterization process and periodically 

updated throughout the life of the project is incorporated into the GS project plans and 

used to establish permit conditions. This information establishes the manner in which an 

owner or operator must construct, operate, monitor, report on, and close a Class VI GS 

project – the conditions the owner or operator must meet to ensure compliance. Pursuant 

to requirements at 40 CFR 144.8, an owner or operator’s failure to comply with the sitespecific permit conditions, failure to complete construction elements, failure to complete 

or provide compliance schedules or monitoring reports, failure to submit complete 

reports, and any action that causes USDW endangerment during the life of the GS project 

are considered instances of noncompliance and will result in a violation of the permit 

under SDWA section 1423. Additionally, EPA may use this information as evidence of 

an imminent and substantial endangerment of a USDW, which may require remedial

action under SDWA section 1431. 
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Data and information gathered through information requests, semi-annual and 30-day 

reporting, and other project records will provide information to demonstrate and confirm 

that a Class VI project is in compliance. Information reported within 24 hours as required 

under §146.91(c), including, but not limited to: evidence that the injected CO2 stream or 

associated pressure front may cause an endangerment to a USDW; triggering of a shutoff system; or failure to maintain mechanical integrity is used to inform the Director of 

any evidence indicating that an owner or operator of a Class VI well has violated a permit 

condition or caused endangerment to USDWs. An owner or operator that fails to reestablish operation within the established permit conditions within 45 days is also 

considered noncompliant, pursuant to the requirements at 40 CFR 144.8.

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

Today’s final action, at §146.92 requires owners or operators of Class VI wells to plug 

injection and monitoring wells in a manner that protects USDWs. The final rule, at 

§146.93, also contains tailored requirements for extended, comprehensive post-injection 

monitoring and site care of GS projects following cessation of injection until it can be 

demonstrated that movement of the CO2 plume and pressure front no longer pose a risk

of endangerment to USDWs. 

Proper plugging of injection and monitoring wells is a long-standing requirement in the 

UIC program designed to ensure that injection wells do not serve as conduits for fluid 

movement following cessation of injection and site closure in order to ensure protection 

of USDWs. PISC, which is unique to GS, is necessary to ensure that site monitoring 

continues until the injectate and any mobilized fluids do not pose a risk to USDWs.

1. Injection Well Plugging

EPA proposed that, after injection ceases at a GS project, the injection well must be 

plugged in order to ensure that the well itself does not become a conduit for fluid 

movement into USDWs. Well plugging activities include flushing the well with a buffer 

fluid, testing the external mechanical integrity of the well, and emplacing cement into the 
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well in a manner that will prevent fluid movement that may endanger USDWs. In the 

proposed rule, EPA did not specify the types of materials or tests that must be used 

during well plugging, acknowledging that there are a variety of methods that are 

appropriate and new materials and tests may become available in the future. However, all 

plugging materials must be compatible with the injectate (i.e., such that plugging 

materials would not degrade over time). EPA sought comment on the injection well 

plugging activities identified in the proposed rule. 

Most commenters supported EPA’s proposed approach regarding well plugging. Because 

the injection well plugging requirements provide owners or operators flexibility in 

meeting the well plugging requirements by allowing them to choose from available 

materials and tests to carry out the requirements, EPA retains the requirements as 

proposed in today’s rule at §146.92. The owners or operators must prepare and comply 

with a Director-approved injection well plugging plan submitted with their permit 

application (§146.92(b)). The approved injection well plugging plan will be incorporated 

into the Class VI permit. The Agency is developing guidance that describes the contents 

of the project plans required in the GS rule, including the injection well plugging plan. 

Owners or operators must submit a notice of intent to plug at least 60 days prior to 

plugging the well. At this time, if any changes have been made to the original well 

plugging plan (e.g., based on operational and monitoring data or data collected during 

AoR reevaluations), the owner or operator must submit a revised injection well plugging 

plan (§146.92(c)). Any amendments to the injection well plugging plan must be 

incorporated into the permit following public notice and comment and approval by the 

Director. EPA envisions that owners or operators will take into account similar 

considerations that guide updates to other project plans, e.g., the testing and monitoring 

plan, as they update the injection well plugging plan. However, EPA is not requiring 

formal periodic review and updates to the injection well plugging plan throughout the 

injection phase because it is not expected that changes to this plan will be implemented 

until the point at which the injection well is to be plugged. EPA also encourages an 

ongoing dialogue between owners or operators and Directors regarding planned well 
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plugging activities. Finally, owners or operators must submit, to the Director, a plugging 

report within 60 days after plugging. The Agency is developing guidance on injection 

well plugging, PISC, and site closure that addresses performing well plugging activities.

2. Post-Injection Site Care (PISC)

Today’s final rule at §146.93 incorporates a PISC period, specific to Class VI wells. 

PISC is the period after CO2 injection ceases—but prior to site closure – during which the 

owner or operator must continue monitoring to ensure USDW protection from 

endangerment. 

PISC and site closure plan submittal and updates: EPA proposed that owners or 

operators would prepare, update, and comply with a Director-approved PISC and site 

closure plan that would describe the anticipated PISC monitoring activities and 

frequency. 

EPA sought comment on the PISC and site closure plan requirements. Most commenters 

supported the requirement for PISC monitoring and the proposed approach regarding 

submittal, revision, and implementation of a PISC and site closure plan. Many 

commenters agreed that a PISC monitoring plan is a necessary and important part of the 

permitting process. These commenters supported the option to amend the plan. However, 

they contended that, upon cessation of injection, if evaluation of monitoring and 

modeling results indicates that the project is performing as expected, an owner or 

operator should not have to submit amendments to the plan. 

Today’s final regulation retains the PISC and site closure plan requirements (§146.93) as 

proposed. The requirement to maintain and implement the approved PISC and site 

closure plan is directly enforceable regardless of whether the requirement is a condition 

of the Class VI permit. The PISC and site closure plan will serve to clarify PISC 

requirements and procedures prior to commencement of a project. 
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Upon cessation of injection, today’s rule requires that owners or operators of Class VI 

wells either submit an amended PISC and site closure plan or demonstrate to the Director 

through monitoring data and modeling results that no amendment to the plan is needed 

(§146.93(a)(3)). Any amendments to the PISC and site closure plan would be 

incorporated into the permit once they are approved by the Director. EPA envisions that 

owners or operators would take into account similar considerations that guide updates to 

other project plans, e.g., the testing and monitoring plan, as they update the PISC and site 

closure plan. However, EPA is not requiring formal periodic review and updates to the 

PISC and site closure plan throughout the injection phase because it is not expected that 

changes to this plan would be implemented until cessation of injection activities. EPA 

also encourages an ongoing dialogue between owners or operators and Directors 

regarding planned PISC and site closure activities. The Agency is developing guidance 

that describes the content of the project plans required in the GS rule, including the PISC

and site closure plan.

PISC timeframe: EPA proposed that during PISC, owners or operators of Class VI wells 

would be required to periodically monitor the site and track the position of the CO2

plume and pressure front to ensure USDWs are not endangered. The proposed rule 

identified a default PISC timeframe of 50 years following the cessation of injection. This 

timeframe was based on a review of research studies, industry reports, and existing 

environmental programs. In order to support site-specific flexibility, the proposed rule 

stipulated that the PISC timeframe could be shortened by the Director if the owner or 

operator could demonstrate that USDWs would not be endangered prior to 50 years. 

Similarly, if after 50 years the Director determined that USDWs may still become 

endangered by the CO2 plume and/or pressure front, he or she could lengthen the PISC 

timeframe. EPA sought comment on the proposed PISC timeframe and whether the 

timeframe should be adjusted. 

Most industry commenters supported reducing the default PISC timeframe, stating that 

the 50-year default timeframe in the proposal would make GS prohibitively expensive, 

and is not warranted based on the probable timeframes of CO2 trapping. Other 
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commenters supported the proposed 50-year PISC period and indicated that the risks of 

GS to USDWs are still unclear, and thus a conservative PISC monitoring time period 

should be implemented. Other commenters asserted that a combination of a fixed 

timeframe and a performance standard would strike a good balance and is preferable to 

relying on only one approach. 

EPA evaluated comments advocating for a shorter timeframe, including suggestions of 10 

and 30 years. However, EPA has not obtained any data from commenters or identified 

other research that contradict EPA’s initial analysis and supports a default timeframe 

shorter than 50 years. EPA acknowledges the merits of a performance-based approach for 

the PISC timeframe, recognizing the variety of site conditions that will affect the 

appropriate PISC timeframe. EPA believes that the Director will be in the best position to 

make a site-specific determination allowing for the PISC timeframe to be modified while 

ensuring USDWs are not endangered.

Therefore, EPA retains the proposed hybrid approach of a default 50-year timeframe, 

while allowing the Director discretion to shorten the PISC timeframe if the owners or 

operators can demonstrate that there is substantial evidence that the GS project no longer 

poses a risk of endangerment to USDWs (§146.93(b)). Likewise, the Director may 

lengthen the PISC timeframe if, after 50 years, USDWs still may become endangered. 

The Agency is developing guidance on injection well plugging, PISC, and site closure.

3. Site Closure

EPA proposed that, following a determination under §146.93 that the site no longer poses 

a risk of endangerment to USDWs, the Director would approve site closure and the 

owner or operator would be required to properly close site operations. EPA proposed site 

closure activities similar to those for other well classes. These include plugging all 

monitoring wells; submitting a site closure report; and recording a notation on the deed to 

the facility property or other documents that the land has been used to sequester CO2. Site 

closure would proceed according to the approved PISC and site closure plan. Today’s 

final regulation retains these closure requirements (at §146.93(c) through (g)).
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The site closure report will provide documentation of injection and monitoring well 

plugging; copies of notifications to State and local authorities that may have authority 

over future drilling activities in the region; and records reflecting the nature, composition, 

and volume of the injected CO2 stream. The purpose of this report will be to provide 

information to potential, future users and authorities of the land surface and subsurface

pore space regarding the operation. Well plugging reports, PISC data, and site closure 

reports must be kept for 10 years after site closure (or longer at the Director’s discretion), 

pursuant to the requirements at §146.93(e) and §146.93(g). See section III.G for more 

about the recordkeeping requirements in today’s rule.

I. Financial Responsibility 

Today’s rule finalizes regulations at §146.85 to require that owners or operators 

demonstrate and maintain financial responsibility as approved by the Director for 

performing corrective action on wells in the AoR, injection well plugging, PISC and site 

closure, and emergency and remedial response. 

The purpose of these financial responsibility requirements is to ensure that owners or 

operators have the resources to carry out activities related to closing and remediating GS 

sites if needed during injection or after wells are plugged but before site closure is 

approved so that they do not endanger USDWs. The end result is ensuring that all the GS 

injection sites are cared for and maintained appropriately and that there is no gap in 

coverage throughout injection and post-injection site care and site closure. 

EPA's Proposed Approach: Financial assurance for wells under the UIC program is 

typically demonstrated through two broad categories of financial instruments: 1) third 

party instruments, including surety bond, financial guarantee bond or performance bond, 

letters of credit (the above third party instruments must also establish a standby trust 

fund), and an irrevocable trust fund; and 2) self-insurance instruments, including the 

corporate financial test and the corporate guarantee. In the preamble to the proposed rule, 

EPA described these instruments and sought comment on the need to adjust financial 
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responsibility instruments for GS projects and the need for additional financial 

responsibility instruments. The Agency also sought comment on allowing separate 

financial demonstrations for injection well plugging and PISC (i.e., a demonstration 

submitted prior to well plugging and the beginning of the post-injection site care period 

rather than with the permit application).

Summary of Public Comments and Other Input: Commenters identified strengths and 

weaknesses of the various financial responsibility instruments and expressed concerns 

about the risk of bank failures and corporate insolvency, which could leave financial 

obligations unfunded. Some commenters supported the use of self insurance (i.e., a 

financial test and a corporate guarantee) as a mechanism to demonstrate financial 

responsibility for GS projects, but expressed concerns that companies that have passed 

financial tests can fail, and also that the current tangible net worth requirement of $10 

million is not adequate for GS projects. Generally, commenters supported allowing 

separate financial demonstrations for injection well plugging and PISC. Many 

commenters expressed concern about the potential high cost and long time frames 

involved with GS projects. They believed that financial assurance would be difficult to 

obtain, particularly throughout the duration of the PISC period and that it may discourage 

investment in GS. 

Commenters also expressed a need for regulatory certainty to help inform financial 

responsibility requirements for well owners or operators. They suggested that EPA 

specify the acceptability of various financial responsibility instruments and that States 

needed guidance including information on what instruments they should approve in order 

to avoid approving financial assurance that did not meet the Federal requirements or that 

was financially inadvisable. Other commenters suggested that the proposed rule left too 

much discretion to the Director, possibly causing operators to run a higher risk of having 

their instrument rejected. Other commenters suggested that the rule provide flexibility to 

owners or operators in the choice of financial instruments, while allowing the Director 

discretion to assess instruments in the context of operational and site-specific factors, 
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including the level of risk over time, when approving financial responsibility for each 

project. 

Many commenters addressed the use of a pay-in period for trust funds. Some commenters 

expressed concern that an initial three-year pay-in period would increase upfront costs, 

while others suggested that an initial pay-in period could help lower financial risk. A 

commenter suggested that the duration of the pay-in period could coincide with the 

estimated project risk. 

In addition to evaluating public comments, EPA worked with members of the public, 

academia, industry, regulatory agencies, and financial experts to address the unique 

financial responsibility issues associated with GS projects. In April and May of 2009, 

EPA held webinars for the public and industry stakeholders to gather information to 

inform the financial responsibility requirements and guidance. The webinars facilitated 

information sharing among stakeholders on financial instruments that could be used to 

meet the financial responsibility requirements for GS projects. Approximately 100 

webinar participants, representing a range of organizations with interest in and unique 

perspectives on financial responsibility, attended the workshop series which focused on 

the strengths and weaknesses of various financial instruments and their applicability for 

various injection activities. The material presented during the webinars and summaries of 

participant discussions can be found in the docket for today’s rulemaking. 

EPA is also aware of recent published literature on the topic of financial responsibility for 

GS. In particular, the World Resources Institute (WRI) and CCS Regulatory Project 

(affiliated with Carnegie Mellon University, Department of Engineering and Public 

Policy) have published research on climate change technologies and policy issues. These 

and other resources are informing EPA's financial responsibility guidance. These reports 

can be found in the docket for today’s rulemaking. 

To supplement publicly available literature and public comments, EPA reevaluated the 

current minimum Tangible Net Worth (TNW) requirement of $10 million used in the 
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Class I regulations and will recommend a TNW threshold for Class VI wells in guidance. 

EPA guidance on TNW for GS will help ensure that the risk borne by the public from a 

self-insured owner or operator is no greater than the riskiest scenario where independent 

third-party instruments are used. The financial responsibility guidance also includes a 

recommended cost estimation methodology to assist owners or operators of Class VI 

wells. The guidance provides examples of cost considerations and activities that may 

need to be performed to satisfy the requirements of today’s rule. 

EPA solicited input from the Environmental Financial Advisory Board (EFAB) to 

develop recommendations on financial responsibility for Class VI wells absent any 

constraints under the SDWA. EFAB made several recommendations that support the 

financial responsibility requirements in today’s final rule. EFAB agreed that both self 

insurance and third-party insurance should be made available to responsible parties. They 

also supported the requirement that third-party providers, such as insurers, pass financial 

strength requirements, the use of credit ratings to demonstrate financial strength, and that 

the owner or operator notify the Director in the event of bankruptcy. EFAB also agreed 

that financial responsibility requirements be linked to cost estimates, with regular updates 

to both cost estimates and financial responsibility demonstrations. Additionally, EFAB 

specifically recommended:

• The use of standardized language for financial instruments. Although EFAB did not 

recommend the use of standardized policy language for insurance, they did suggest

that procedures be adopted so that the Director can specifically agree to limitations 

contained in the insurance policy or specifically reject such limitations during the 

review process;

• That the owner or operator be required to notify the Director by certified mail of any 

proceeding under Title 11 (Bankruptcy), US Code, within 10 business days after the 

commencement of the proceeding; that owners or operators be deemed to not possess 

the required financial responsibility in the event of bankruptcy or loss of authority of 

the third party when using letters of credit, surety bonds, or insurance policies; 
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• That, because the RCRA financial mechanisms, which are largely used in the SDWA 

Class I program, were developed based on hazardous waste facility owner’s or 

operator’s considerations, there may be differences in the owner or operator profiles 

for proposed GS facilities that warrant additional assurance mechanisms. Thus, the 

Agency should consider adding a new category of financial assurance to the Class VI 

program that provides the Agency with the flexibility to approve the “functional 

equivalent” to the established RCRA financial assurance tests; and

• That EPA consider the use of rate-based financing, a new category of instrument that 

would provide the Director with the flexibility to approve instruments that are 

functionally equivalent to existing qualifying instruments.

Today's Final Approach: Today’s final regulation retains the substantive requirements

that owners or operators of Class VI wells demonstrate and maintain financial 

responsibility to cover the cost of corrective action, injection well plugging, PISC and 

site closure, and emergency and remedial response. In response to public comments EPA 

requested in the proposed rule and other input, this final regulation at §146.85, modifies 

the proposed requirements to provide clarity on acceptable instruments to enhance 

enforceability of the requirements, and to set reporting timeframes to provide consistency 

with other EPA regulations. Specifically, EPA has clarified the financial responsibility 

requirements by: 

1) Describing “qualifying instruments” to cover the cost of corrective action, injection 

well plugging, PISC and site closure, and emergency and remedial response in a 

manner that prevents endangerment of USDWs. 

2) Adding language clarifying that the financial responsibility instrument is directly 

enforceable regardless of whether the requirement is a condition of the permit. 

3) Requiring submission of annual inflationary updates and specifying a 60-day 

timeframe after notification by the Director for the submission of written updates of 

adjustments to the cost estimate. 
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4) Requiring owners or operators to notify the Director no later than 10 days after filing 

for bankruptcy. 

5) Requiring an owner or operator or its guarantor using self insurance to demonstrate 

financial responsibility for GS to meet a Tangible Net Worth of an amount approved 

by the Director; have both a net working capital and a tangible net worth of at least 

six times the sum of the current well plugging, post-injection site care and site closure 

cost; have assets located in the US amounting to at least 90 percent of total assets or 

at least six times the sum of the current well plugging, post-injection site care and site 

closure cost; submit annual report of bond rating and financial information; and 

either: 1) Pass a bond rating test issued by one or both of the nationally recognized 

bond rating agencies, Standard & Poor’s and Moody’s for which the bond’s rating 

must be one of the four highest categories (i.e., AAA, AA, A, or BBB for Standard & 

Poor’s or Aaa, Aa, A, or Baa for Moody’s)); or, 2) Meet all of the following five 

financial ratio thresholds:

• A ratio of total liabilities to net worth less than 2.0; 

• A ratio of current assets to current liabilities greater than 1.5; 

• A ratio of the sum of net income plus depreciation, depletion, and amortization to 

total liabilities greater than 0.1; 

• A ratio of current assets minus current liabilities to total assets greater than -0.1; 

and

• A net profit (revenues minus expenses) greater than 0.

These financial responsibility requirements are not made to duplicate existing financial 

responsibility regulations, but are tailored to the unique characteristics and requirements 

of GS. Considering the potential high costs associated with large-scale deployment of GS 

projects, EPA would like to ensure that adequate and continuous financial responsibility 

mechanisms are in place throughout the life of each GS project and that the cost 

associated with operation of GS projects is not passed along to the public. EPA also 

believes that having stringent self-insurance requirements in addition to an annual 

evaluation of the financial instrument minimizes the potential for a financial institution 
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(that has passed the test) to be likely to undergo financial difficulties that can hinder the 

financial responsibility demonstration for a GS project.

EPA's final approach for financial responsibility for Class VI wells: EPA does not have 

authority under SDWA to be the direct or indirect beneficiary of a trust fund under this 

statute for the purpose of establishing financial responsibility for GS projects. EPA must 

comply with the Miscellaneous Receipts Act, 31 U.S.C. §3302. Standby trust funds are 

not stand-alone financial instruments that can be used by an owner or operator to 

demonstrate financial responsibility. Standby trusts must be used to enable EPA to be 

party to the financial responsibility agreement without EPA being the beneficiary of any 

funds. Standby trust funds must be used along with other financial responsibility 

instruments (e.g., surety bonds, letters of credit, or escrow accounts) to provide a location 

to place funds if needed. The final rule, at §146.85(a)(1), identifies the following 

qualifying financial instruments for Class VI wells, all of which must be sufficient to 

address endangerment of USDWs.

1) Trust Funds: If using a trust fund, owners or operators are required to set aside funds

with a third party trustee sufficient to cover estimated costs. During the financial 

responsibility demonstration, the owner or operator may be required to deposit the 

required amount of money into the trust prior to the start of injection or during the “payin period” if authorized by the Director. 

2) Surety Bond: Owners or operators may use a payment surety bond or a performance 

surety bond to guarantee that financial responsibility will be fulfilled. In case of operator 

default, a payment surety bond funds a standby trust fund in the amount equal to the face 

value of the bond and sufficient to cover estimated costs, and a performance bond 

guarantees performance of the specific activity or payment into a standby trust fund.

3) Letter of Credit: A letter of credit is a credit document, issued by a financial 

institution, guaranteeing that a specific amount of money will be available to a designated 

party under certain conditions. In case of operator default, letters of credit fund standby 

trust funds in an amount sufficient to cover estimated costs.
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4) Insurance: The owner or operator may obtain an insurance policy to cover the 

estimated costs of GS activities requiring financial responsibility. This insurance policy 

must be obtained from a third party to decrease the possibility of failure (i.e., non-captive 

insurer).

5) Self Insurance (i.e., Financial Test and Corporate Guarantee): Owners or operators 

may self insure through a financial test provided certain conditions are met. The owner or 

operator needs to pass a financial test to demonstrate profitability, with a margin 

sufficient to cover contingencies and unknown obligations, and stability. If the owner or 

operator meets corporate financial test criteria, this is an indication that the owner or 

operator can guarantee its ability to satisfy financial obligations based solely on the 

strength of the company’s financial condition. An owner or operator who is not able to 

meet corporate financial test criteria may arrange a corporate guarantee by demonstrating 

that its corporate parent meets the financial test requirements on its behalf. The parent’s 

demonstration that it meets the financial test requirement is insufficient if it has not also 

guaranteed to fulfill the obligations for the owner or operator.

6) Escrow Account: Owners or operators may deposit money to an escrow account to 

cover financial responsibility requirements. This account must segregate funds sufficient 

to cover estimated costs for GS financial responsibility from other accounts and uses. 

7) Other instrument (s) satisfactory to the Director: In addition to these instruments, EPA 

anticipates that new instruments that may be tailored to meet GS needs may emerge, and 

may be determined appropriate for use by the Director for the purpose of financial 

responsibility demonstrations. 

The final rule specifies that the qualifying financial responsibility instrument must 

comprise protective conditions of coverage, including, but not limited to: cancellation, 

renewal, and continuation provisions; specifications on when the provider becomes liable 

in case of cancellation if there is a failure to renew with a new qualifying financial 
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instrument; and requirements for the provider to meet a minimum rating, minimum 

capitalization, and ability to pass the bond rating when applicable. This clarification was 

made in direct response to issues raised by commenters for numerous instruments, and

also to make sure that there is no gap in coverage if a financial instrument fails. 

Today’s rule, at §146.85(c), requires the owner or operator to have a detailed written 

estimate, in current dollars, of the cost of: performing corrective action on wells in the 

AoR, plugging the injection well(s), PISC and site closure, and emergency and remedial 

response. A cost estimate must be prepared separately for each of these activities and be 

based on the costs to the owner or operator of hiring a third party (who is neither a parent 

nor a subsidiary of the owner or operator) to perform the activities. EPA recommends 

that owners or operators take the following into account when determining the cost 

estimate for GS projects:

1) Performing corrective action on wells in the AoR. This includes conducting 

corrective action on deficient wells in the AoR during the initial AoR, under a phased 

corrective action approach; and for newly-identified deficient wells in subsequent 

AoR re-evaluations. See section III.B for more details on the AoR and corrective 

action plan requirements.

2) Plugging the injection well(s). This includes performing a final external MIT and 

plugging the wells in a manner that considers the well depth, the number of plugs and

the amount of cement needed, the composition of the captured CO2, and the types of 

subsurface formations. See section III.H for more details on plugging requirements.

3) Post-injection site care and closure. This includes all needed monitoring and site care 

until it can be demonstrated that the site no longer poses an endangerment to USDWs. 

See section III.H for more details on post-injection site care and site closure 

requirements.
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4) Emergency and remedial response. This includes the cost to perform any necessary 

responses or remediation to address potential USDW endangerment. See section III.J 

for more details on the emergency and remedial response requirements.

Owners or operators have the flexibility to choose from a variety of financial instruments 

to meet their financial responsibility obligations. Owners or operators may use one or 

multiple financial responsibility instruments for well plugging and PISC (§146.85(a)(6)). 

However, EPA will not allow for a separate financial responsibility demonstration for 

well plugging and PISC (i.e., a demonstration submitted prior to well plugging and the 

beginning of the PISC period rather than with the permit application). A demonstration of 

financial responsibility for all phases of the GS project will be required prior to the 

issuance of a Class VI permit (§146.85(a)(5)(i)). 

EPA adds that under today’s final rulemaking at §146.85(a), the Director will only 

approve instruments determined to be sufficient to address endangerment of USDWs, and 

has the discretion to disapprove of instruments that he/she determines may not be 

sufficient based on the following:

1) The financial instrument is not determined to be a qualifying instrument;

2) The financial instrument is not sufficient to cover the cost to properly plug and 

abandon, remediate, and manage wells;

3) The financial instrument is not sufficient to address endangerment of USDWs; or 

4) The financial instrument does not comprise required conditions of coverage to 

facilitate enforceability and prevent gaps in coverage for the life of the GS project.

EPA has added language, at §146.85(b), that a financial responsibility instrument is 

directly enforceable regardless of whether the requirement is a condition of the permit. 

EPA also specifies circumstances under which an owner or operator may be released 

from a financial instrument, including that the owner or operator has completed the GS 
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project activity for which the financial instrument was required and has fulfilled all 

financial obligations as determined by the Director, or has submitted a replacement 

financial instrument and received written approval from the Director accepting the new 

financial instrument and releasing the owner or operator from the previous financial 

instrument. The Director’s determination of completion of a GS project activity may be 

sustained by a professional engineer’s report on completion. The Director must notify the 

owner or operator in writing that the owner or operator is no longer required to maintain 

financial responsibility for the project or activity. This clarification was added to address 

unforeseen situations where EPA may need to directly enforce the financial responsibility 

provisions should the permit inadequately provide protection of USDWs from 

endangerment. 

This rule, at §146.85(c), also requires that the owner or operator adjust the cost estimates 

to address amendments to the AoR and corrective action plan (§146.84), the injection 

well plugging plan (§146.92), the PISC and site closure plan (§146.93), and the 

emergency and remedial response plan (§146.94). Within 60 days after the Director has 

approved any modifications to the plan(s), the owner or operator must review and update 

the cost estimate for well plugging, PISC and site closure, and emergency and remedial 

response to account for any amendments if the change in the plan increases the cost. The 

revised cost estimate must also be adjusted for inflation as specified at §146.85(c)(2). 

Any changes to the approved cost estimate must be approved by the Director. 

Today’s rule does not allow a separate demonstration for financial responsibility 

requirements (i.e., a demonstration submitted prior to well plugging and the beginning of 

the post-injection site care period rather than with the permit application). Although the 

owner or operator may use a financial instrument or a combination of financial 

instruments for the purpose of financial responsibility for specific phases of the GS 

project, the demonstration of financial responsibility must be done for the overall GS 

project at the time of permit application. However, today’s rule, at §146.85(a)(6) provides 

that, prior to obtaining a Class VI permit, an owner or operator may demonstrate financial 

responsibility by using one or multiple qualifying financial instruments for specific GS 

activities, thereby realizing greater flexibility and cost savings from this regulation. In the 
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event that the owner or operator combines more than one instrument for a specific GS 

activity (e.g., well plugging), such combination must be limited to instruments that are 

not based on financial strength or performance (i.e., self insurance or performance bond), 

for example trust funds, surety bonds guaranteeing payment into a trust fund, letters of 

credit, escrow account, and insurance. In this case, it is the combination of instruments, 

rather than the single instrument, which must provide financial responsibility for an 

amount at least equal to the current cost estimate. EPA also notes that today’s rule 

requires the Director to approve the use and length of pay-in-periods for trust funds or 

escrow accounts. EPA understands that in some cases a short pay-in period (e.g., threeyears or less) will provide some financial flexibility for owners or operators while 

balancing financial risk.

EPA has further clarified financial responsibility requirements by requiring owners or 

operators or a guarantor to notify the Director no later than 10 days after filing for 

bankruptcy, at §146.85(d). This requirement is added in direct response to commenters 

who addressed the necessity of adequate financial responsibility requirements, even in the 

event of operator bankruptcy. EPA is adding this requirement in order to avoid a gap in 

coverage in the event that an instrument fails. This timeframe is consistent with the 

current US bankruptcy code. In the event that the third party files for bankruptcy, today’s 

rule requires that the owner or operator establish alternative financial assurance within 

sixty (60) days.

Today’s rule, at §146.85(e), also requires the owner or operator to adjust cost estimates if 

the Director has reason to believe that the most recent demonstration is no longer 

adequate to cover the cost of the identified activities. This clarification is made in direct 

response to commenters who stressed the importance of accurate cost estimates. The 

Agency is developing guidance, which will provide direction to the Director for when a 

demonstration may no longer be adequate to cover the GS activities.

As a Federal agency, EPA is working to create a nationally consistent financial 

responsibility program for GS activities while providing permitting authorities an 
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appropriate level of flexibility. EPA is developing guidance on financial responsibility for 

owners or operators of Class VI wells to assist owners or operators in evaluating the 

financial responsibility requirements for Class VI wells and to assist Directors in 

evaluating financial responsibility demonstrations. The guidance will describe financial 

responsibility options, demonstrations, types of financial instruments for Class VI wells 

as well as how to estimate the costs to support accurate financial responsibility 

demonstrations specific to the needs of a GS project. 

Long-term liability and stewardship for GS projects under the SDWA: EPA received a 

range of comments from stakeholders regarding liability following site closure. Many 

commenters suggested that, after a GS site is closed, liability should be transferred to the 

State or Federal government or to a publicly- or industry-funded entity based on a series 

of rationales (e.g., the need for certainty; the potential for high cost; insurance and legal 

concerns). EPA also received comments from those who disagreed with the assertion that 

a public entity should bear liability following site closure based on the belief that, if 

owners or operators face potential liability following site closure, they would use 

precaution in their operations to avoid risks and potential environmental damage. 

Additionally, many commenters encouraged EPA to consider other State or Federal laws 

under which liability transfers may be accomplished as models for GS liability transfer. 

Under SDWA authority, owners or operators of injection wells must ensure protection of 

USDWs from endangerment and are subject to liability for enforcement under the Act. 

The final rule requires that an owner or operator must conduct monitoring as specified in 

the Director-approved PISC and site closure plan following the cessation of injection 

until the owner or operator can demonstrate to the Director that the geologic 

sequestration project no longer poses an endangerment to USDWs. For additional 

information about the PISC and site closure requirements, see section III.H of this action. 

Once an owner or operator has met all regulatory requirements under part 146 for Class 

VI wells and the Director has approved site closure pursuant to requirements at §146.93, 

the owner or operator will generally no longer be subject to enforcement under section 
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1423 of SDWA for noncompliance with UIC regulatory requirements. However, an 

owner or operator may be held liable for regulatory noncompliance under certain 

circumstances even after site closure is approved under §146.93, under section 1423 of 

the SDWA for violating §144.12, such as where the owner or operator provided 

erroneous data to support approval of site closure.

Additionally, an owner or operator may always be subject to an order the Administrator 

deems necessary to protect the health of persons under section 1431 of the SDWA after 

site closure if there is fluid migration that causes or threatens imminent and substantial 

endangerment to a USDW. For example, the Administrator may issue a SDWA section 

1431 order if a well may present an imminent and substantial endangerment to the health 

of persons, and the State and local authorities have not acted to protect the health of such 

persons. The order may include commencing a civil action for appropriate relief. If the 

owner or operator fails to comply with the order, they may be subject to a civil penalty 

for each day in which such violation occur or failure to comply continues. 

Furthermore, after site closure, an owner or operator may, depending on the fact scenario, 

remain liable under tort and other remedies, or under other Statutes including, but not 

limited to, Clean Air Act, 42 U.S.C. §§7401-7671; CERCLA, 42 U.S.C. §9601-9675; and

RCRA, 42 U.S.C. §6901-6992. 

EPA acknowledges stakeholder interest in liability and long-term stewardship in the 

context of development and deployment of GS technology, however, under current 

SDWA provisions EPA does not have authority to transfer liability from one entity (i.e., 

owner or operator) to another.

J. Emergency and Remedial Response

Today’s rule at §146.94 requires Class VI well owners or operators to develop and 

maintain an emergency and remedial response plan that describes actions to be taken to 

address events that may cause endangerment to a USDW during the construction, 

operation, and PISC periods of a GS project. Owners or operators must also periodically 
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update the emergency and remedial response plan to incorporate changes to the AoR or 

other significant changes to the project. Today’s requirements will support expeditious 

and appropriate response to protect USDWs from endangerment in the unlikely event of 

an emergency. 

Developing emergency and remedial response plans: EPA proposed that owners or 

operators submit an emergency and remedial response plan to the Director as part of the 

Class VI permit application. The plan would describe measures that would be taken in the 

event of adverse conditions at the well, such as a loss of mechanical integrity, the 

opening of faults or fractures within the AoR, or if movement of injection or formation 

fluids caused an endangerment to a USDW. Commenters were supportive of including an 

emergency and remedial response plan as part of the Class VI permit, and some 

commenters suggested that the plan should be risk based. EPA agrees that advanced 

planning for emergency and remedial response is an important part of ensuring protection 

of USDWs at GS sites from endangerment, and today’s rule retains the requirement for 

an emergency and remedial response plan (§146.94(a)), and also requires that the 

approved emergency and remedial response plan be incorporated into the Class VI 

permit. The purpose of the emergency and remedial response plan is to ensure that 

owners or operators comprehensively plan, in advance, what actions would be necessary 

in the unlikely event of an emergency. The plan will also ensure that operators know 

what entities and individuals must be notified and what actions might need to be taken to 

expeditiously mitigate any emergency situations and protect USDWs from endangerment. 

The Agency is developing guidance that describes the contents of the project plans 

required in the GS rule, including the emergency and remedial response plan. The docket 

for today's rulemaking includes brief research papers that discuss remedial technologies 

available to address potential impacts of CO2 on water resources (USEPA, 2010b) and 

remedial technologies that may be used to seal faults and fractures at GS sites (USEPA, 

2010c).

EPA agrees with commenters that the emergency and remedial response plan should be 

site-specific and “risk-based.” EPA expects that each emergency and remedial response 
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plan will be tailored to the site, and today’s rule provides flexibility to the owner or 

operator to design a site-specific plan that meets the requirements of §146.94(a). Rather 

than requiring specific information in the emergency and remedial response plan that may 

not be relevant to all GS projects, the plan allows such information to be determined on a 

site-specific basis. The details of an emergency and remedial response plan may be 

influenced by a variety of factors including: geology, USDW depth, and injection depth; 

the presence, depth, and age of artificial penetrations; proposed operating conditions and 

properties of the CO2; and activities in the AoR (e.g., the presence of population centers, 

land uses, and public water supplies). The Director will evaluate the proposed emergency 

and remedial response plan for a GS project in the context of all information submitted 

with the permit application (e.g., site characterization information, AoR evaluation data, 

and well construction, monitoring, and operational information) to ensure that the plan is 

appropriately comprehensive to address potential emergencies. 

Implementing the emergency and remedial response plan: EPA also proposed several 

steps that the owner or operator would need to follow if he or she obtained evidence that 

the injectate and associated pressure front may endanger a USDW. Most comments 

requesting clarity on this requirement recommended that EPA establish triggers during 

the initial permitting phase and identify appropriate mitigation options. 

EPA disagrees with commenters that it is appropriate or useful to identify specific 

triggers or response actions in the rule that would apply to all sites. EPA believes that 

decisions about responses should be made through consultation between owners or 

operators and Directors because each response action will be site- and event-specific. The 

purpose of the emergency and remedial response requirements in today’s rule is to ensure 

that a plan is in place for the owner or operator to take appropriate action (e.g., cease 

injection) in the unlikely event of an emergency or USDW endangerment. The plan also 

facilitates a dialogue between the owner or operator and the Director to expedite the 

necessary and appropriate response based on steps identified in advance.
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Today’s rule at §146.94(b) requires that, if an owner or operator obtains evidence of 

endangerment to a USDW, he or she must: 1) immediately cease injection; 2) take all 

steps reasonably necessary to identify and characterize any release; 3) notify the Director 

within 24 hours; and, 4) implement the approved emergency and remedial response plan.

Emergency and remedial response plan updates: Two water associations recommended 

that the emergency and remedial response plan be reviewed and updated throughout the 

course of a GS project. EPA agrees with these commenters and today’s rule includes a 

requirement that owners or operators must periodically review the emergency and 

remedial response plan to incorporate operational and monitoring data and the most 

recent AoR reevaluation at §146.94(d). This review must take place within one year of an 

AoR reevaluation, following significant changes to the facility, or when required by the 

Director. 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 Directors and ensure that owners or operators are complying with the 

conditions of their Class VI permits. Tying emergency and remedial response 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 other 

circumstances change, while adding little burden if the AoR reevaluation confirms that 

the plan is appropriate as written. 

K. Involving the Public in Permitting Decisions

Public input and participation in GS projects has a number of benefits, including: 1) 

providing citizens with access to decision-making processes that may affect them; 2) 

educating the community about a GS project; 3) ensuring that the public receives 

adequate information about the proposed GS project; and 4) allowing the permitting 

authority and owners or operators to become aware of public viewpoints, preferences and 

environmental justice concerns and ensuring these concerns are considered by decisionmaking officials. 
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GS of CO2 is a new technology that is unfamiliar to most people and maximizing the 

public’s understanding of the technology can result in more meaningful public input and 

constructive participation as new GS projects are proposed and developed. Early and 

frequent public involvement through education and information exchange is critical to the 

success of GS and can provide early insight into how the local community and 

surrounding communities perceive potential environmental, economic, or health effects 

associated with a specific GS project. Owners or operators can increase the likelihood of 

success by integrating social, economic, and cultural concerns of the community into the 

permit decision-making process.

In the proposed rule, EPA sought comment on: 1) the appropriateness of adopting 

existing public participation requirements at 40 CFR parts 25 and 124 for GS; 2) the need 

for additional public participation requirements to reflect availability of new information 

technology to disseminate and gather information; and 3) ways to enhance the public 

participation process. 

Nearly all commenters agreed that early and frequent public education and participation 

would enhance public acceptance of GS projects. Several commenters supported 

adopting the existing public participation requirements used for other injection well 

classes. Many commenters favored requiring the use of new information technology to 

improve public notification and involvement on GS projects and permitting.

Today’s final approach adopts the existing UIC public participation requirements at 40 

CFR part 25 and the permitting decision procedures at 40 CFR part 124. EPA encourages 

owners or operators and permitting agencies to involve the public by providing them 

information about the Class VI permit (and any requests for a waiver of the injection 

depth requirements or an expansion of the areal extent of an aquifer exemption) as early 

in the process as possible. Under 40 CFR parts 25 and 124, permitting authorities must 

provide public notice of pending actions via newspaper advertisements, postings, 

mailings, or e-mails to interested parties; hold public hearings if requested; solicit and 

respond to public comment; and involve a broad range of stakeholders. 
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EPA expects that there will be higher levels of public interest in GS projects than for 

other injection activities. The Agency believes that encouraging public participation will 

help permitting authorities understand public concerns about GS projects and will afford 

the public an opportunity to gain a clearer understanding of the nature and safety of GS 

projects and technologies. To address comments about stakeholder participation, EPA is 

amending the requirements for public notice of permit actions and public comment period 

at §124.10 to clarify that public notice of Class VI permitting activities must be given to 

State and local oil and gas regulatory agencies, State agencies regulating mineral 

exploration and recovery, the Director of the PWSS program in the State, and all agencies 

that have jurisdiction to oversee wells in the State in addition to the general public.

EPA agrees with commenters that the use of new forms of information technology can 

improve public participation and understanding of GS projects. EPA recognizes the 

importance of social media as a public outreach tool. Social media, which are primarily 

Internet and mobile based technologies for disseminating and discussing information, can 

help provide accessibility and transparency to a wide audience. Some social media tools 

that may be useful for sharing information on GS projects include blogs, social networks, 

podcasts, and webcasts. EPA encourages permit applicants and permitting authorities to 

use the Internet and other forms of social media to explain potential GS projects; describe 

GS technologies; and post information on the latest developments related to a GS project 

including schedules for hearings, briefings and other opportunities for involvement. 

L. Duration of a Class VI Permit

Today’s rule establishes that Class VI permits are issued for the life of the GS project, 

including the PISC period (§144.36). In lieu of the periodic permit reissuance required 

for most other deep-well classes, owners or operators of Class VI wells must periodically 

reevaluate the AoR and prepare and implement a series of plans for AoR and corrective 

action, testing and monitoring, injection well plugging, PISC and site closure, and 

emergency and remedial response. These plans must be reevaluated by the owner or 

operator throughout the life of the project to foster a continuing dialogue between the 
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owner or operator and the Director, and afford opportunities for public input as needed

and ensure compliance with the Class VI permit.

EPA proposed that Class VI injection well permits be issued for up to the operating life 

of the facility, including the PISC period. In the preamble to the proposed rule, EPA 

explained that, in lieu of permit renewals for Class VI wells, owners or operators must 

periodically re-evaluate the AoR, at least every 10 years. In existing UIC program

regulations, permit duration varies by injection well class: permits for Class I and Class V 

wells are effective for up to 10 years; while Class II and III permits may be issued for the 

operating life of the facility, but are subject to a review by the permitting authority at 

least once every five years. 

EPA sought comment on the proposed permit duration for Class VI wells, the 

appropriateness of GS project plans, and the merits of updating the AoR and corrective 

action plan in place of permit reissuance. Many commenters supported EPA’s proposal to 

issue permits for the life of a GS project, stating that the requirements for periodic

reevaluation of the AoR and corrective action plan would make a five-or ten-year permit 

review process unnecessary and that a lifetime permit would provide operational 

continuity. Some commenters suggested that other plans (e.g., the testing and monitoring 

plan) should also be periodically reviewed throughout the life of the project. Other 

commenters disagreed with EPA’s proposed permit duration for Class VI wells, believing 

that the proposed level and frequency of interaction (i.e., every 10 years) between the 

primacy agency and owner or operator would not be sufficient to justify a permit for the 

operating life of the project. Comments both in favor of and opposition to lifetime 

permits stressed the importance of incorporating new information, the value of permit 

review and modification, and the need for a transparent process. 

EPA agrees with commenters regarding the need for continuous interaction between 

permitting authorities and owners or operators of GS projects. Today’s rule retains the 

requirement that Class VI permits are issued for the lifetime of the project (§144.36). It 

also requires owners or operators to review and update the AoR and corrective action 
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plan, the testing and monitoring plan, and the emergency and remedial response plan 

throughout the life of the project (§146.84(e), §146.90(j), and §146.94(d)). 

Today’s rule requires owners or operators to review each plan as required by part 146 and 

either identify necessary amendments to the plan or demonstrate to the satisfaction of the 

Director that no amendment is needed. These reviews must be performed within one year 

of an AoR reevaluation, following any significant changes to the facility (e.g., the 

addition of monitoring or injection wells), or when required by the Director. In no case

can reviews occur less often than once every five years. This review frequency is 

necessary to ensure that reviews of the plans are conducted on a defined schedule or 

when there is a change in the AoR or significant change, while adding little burden if an 

AoR reevaluation confirms that the plans are appropriate as written. (EPA also revised 

the AoR reevaluation frequency from 10 years to five years; see section III.B.)

EPA is not requiring formal periodic review and updates to the injection well plugging

plan and PISC and site closure plan throughout the injection phase because it is not 

expected that changes to these plans would be implemented until injection operations 

cease. However, today’s rule at §§146.92 and 146.93 does require that owners or 

operators identify any needed changes to these plans at the cessation of injection 

operations. 

Because the approved plans required by today’s rule will be incorporated into the Class 

VI permit, today’s rule establishes permit modification requirements tailored for Class VI 

permits (e.g., associated with plan updates and other project changes). These 

requirements state that any changes to the plans will trigger a permit modification 

pursuant to §144.39(a)(5). 

These modifications invoke part 124 public participation requirements. The Director, 

through consultation with the owner or operator, may choose to provide public notice of 

permit modifications as they occur or concurrent with the five year permit review 

schedule at §144.36 (e.g., the Director may notice multiple modifications at once, every 
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five years). Minor changes to the plans (e.g., correction of typographical errors) that may 

result in a permit modification pursuant to requirements at §144.41 for minor 

modifications of permits will not require public notification. If any of the plans are 

changed because of significant changes they will be considered by the Director to be 

major modifications under §144.39. 

Periodic review and revision of required plans and the ongoing dialogue between owners 

or operators and Directors will address many of the comments in support of periodic 

permit renewal, without the associated time and expense of rewriting the entire permit. 

Instead, today’s final approach requires a close level of interaction between owners or 

operators and Directors. It requires permits to be informed with continually updated 

information, focuses resources on key issues, and provides for public transparency and 

involvement when needed. Periodic reevaluation of the AoR, along with reviews and 

updates to the plans, will provide an equivalent level of review and attention to address 

potential risks, while focusing time and resources on the most important components of 

GS operations. 

The iterative reviews and revisions of the various rule-required plans and the underlying 

computational models will also provide numerous opportunities for technical 

reassessments of the project. These reviews will ensure that the owner or operator and the 

Director have current knowledge of how the CO2 plume and pressure front are behaving 

and afford them time to assess the information and react appropriately to ensure 

protection of USDWs. 

Transfer of permits: Today’s final rule does not allow for automatic transfer of a Class VI 

permit to a new owner or operator (§144.38(b)). Given the unique nature of GS and the 

importance of interaction between GS project owners or operators and permitting 

authorities, the Agency believes that the Director should have an opportunity to review 

the permit and determine whether any changes are necessary at the time of the permit 

transfer, pursuant to requirements at §144.38(a). If information about the GS project and 
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existing permit conditions are determined to be adequate, the permit review and transfer 

may entail a minimal amount of new information and administrative effort. 

Area permits: Today’s rule does not allow area permits for Class VI wells 

(§144.33(a)(5)). Individual well permits are essential to ensure that every Class VI well is 

constructed, operated, monitored, plugged, and abandoned in a manner that protects 

USDWs from endangerment. Individual permitting of wells maximizes opportunities for 

the public to provide input on each well as it is brought into service. This also ensures 

that existing wells that are converted or re-permitted from other well classes (e.g., Class 

II EOR/EGR wells converted to Class VI) are 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).

While area permits allow for some administrative efficiency, this efficiency can also be 

achieved through appropriately executed plans for Class VI wells. For example, an owner 

or operator under §146.84(c)(1) must delineate the projected lateral and vertical 

movement of the CO2 plume and formation fluids from the commencement of injection 

activities until injection ceases. This delineation should account for any future wells that 

the owner or operator plans to construct in the AoR to ensure that the Director can 

consider all anticipated injection and resultant pressure changes when evaluating the plan 

and setting permit conditions. Similarly, testing and monitoring plans should account for 

future injection wells to ensure that ground water monitoring and CO2 plume and 

pressure front tracking are planned appropriately. Through this iterative planning and 

submission process, owners or operators and Directors can accomplish multiple 

efficiencies: permits to construct Class VI wells can be submitted and reviewed either 

separately or simultaneously, and common, static components of the project can be 

identified and incorporated into future permit applications, which would facilitate 

submittal of data by the owner or operator and review and approval by the Director of 

future wells in the same field.
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Owners or operators and permitting authorities may also achieve economies of scale by 

conducting the public process (e.g., noticing wells; holding hearings) for several Class VI 

permits simultaneously. This may improve efficiency and public understanding of how 

multiple wells may interact in a given GS site. EPA also believes that requiring separate 

permit applications for each well will ensure that the public has an opportunity to provide 

input on each well in the field as it is constructed or brought online. 

As part of the EPA’s adaptive rulemaking approach, the Agency will collect information 

on early GS projects and may consider the use of area permits in the future.

IV. Cost Analysis

Today’s rulemaking finalizes regulations for the protection of USDWs, but it does not 

require entities to sequester CO2. The costs and benefits associated with protection of 

USDWs from endangerment are the focus of this rule; however, those associated with the 

mitigation of climate change are not directly attributable to this rulemaking. 

To calculate the costs and benefits of compliance for the final GS Rule, EPA selected the 

existing UIC program Class I industrial waste disposal well category as the baseline for 

costs and benefits. EPA used this baseline to determine the incremental costs of today’s 

rule, based on the fact that permits issued to early pilot projects included requirements 

similar to those for Class I industrial wells.

The incremental costs of the rule include elements such as geologic site characterization, 

well construction and operation, monitoring equipment and procedures, well plugging, 

and post-injection site care (monitoring). The benefits of this rulemaking include the 

decreased risk of endangerment to USDWs and potentially a corresponding decrease in 

health-related risks associated with contaminated USDWs.

The scope of the GS Rule Cost Analysis includes the full range of activities associated 

with an injection project, from the end of the CO2 pipeline at the GS site to the 

underground injection and monitoring, as it occurs during the timeframe of the analysis. 
Page 152 of 259

The scope of the cost analysis does not include capturing or purifying the CO2, nor does 

it include transporting the CO2 to the GS site. Some costs as highlighted in this section 

have changed from the proposed rule based on cost updates or public comments received. 

The timeframe of the cost analysis was extended from 25 years in the proposed rule to 50 

years for the final rule. Although twice as long as the timeframes commonly used in 

drinking water-related cost analyses, EPA believes that 50 years reflects the fact that the 

full lifecycle of GS projects is expected to be well beyond 25 years while avoiding the 

extreme amount of uncertainty involved in projecting an analysis across multiple 

generations. Costs attributed to this rule are inclusive of GS projects begun during the 50 

years of the analysis, and all cost elements that occur during the 50-year timeframe are 

discounted to present year values. The number of GS projects projected to be 

implemented over the timeframe of the cost analysis (29) includes pilot projects and other 

projects associated with regulations that are in place today.3

 EPA consulted directly with 

DOE and Regional Partnerships and searched publicly available data to inform the 

estimated number of projects. Again, EPA emphasizes that the rule does not require 

anyone to undertake GS.

This section of the Preamble summarizes the results of the cost analysis conducted for 

this rule. For details, see the Cost Analysis for the Final GS Rule, which is included in the 

rule docket.

A. National Benefits and Costs of the Rule4

1. National Benefits Summary

This section summarizes the risk (and benefit) tradeoffs between compliance with 

existing requirements and with the regulatory alternative (RA) selected for the final rule 

during the regulatory development process and public comment (see Chapter 2 of the 

Cost Analysis for a description of each of the RAs). Evaluations in the Cost Analysis 

 3 Note that although pilot projects are conducted on a small scale, they are considered geologic 

sequestration demonstration projects for a given site, not Class V experimental technology well projects.

4 Although both estimated costs and benefits are discussed in detail, the final policy decisions regarding this 

rulemaking are not premised solely on a cost/benefit basis.
Page 153 of 259

include a nonquantitative analysis of the relative risks of contamination to USDWs for 

the RAs under consideration. The expected change in risk based on promulgation of the 

selected RA and the potential nonquantified benefits of compliance with this RA are also 

discussed. 

a. Relative Risk Framework—Qualitative Analysis

Table IV-1 below presents the estimated relative risks of the selected RA for compliance 

with the rule relative to the baseline. As detailed in Chapter 5 in the Cost Analysis, the 

term “baseline” in the exhibit refers to risks as they exist under the current UIC program

regulations for Class I industrial wells. The term “decrease” indicates the change in risk 

relative to this baseline. The Agency has used best professional judgment to qualitatively 

assess the relative risk associated with each RA. This assessment was made with 

contributions from a wide range of injection well and hydrogeological experts, ranging 

from scientists and well owners or operators to administrators and regulatory experts. 

Table IV-1. Relative Risk of Regulatory Components for Selected RA versus the 

Current Regulations5

Baseline

Direction of Change 

in Risk for Selected 

RA

(Relative to Baseline)

1. Geologic Characterization

Geologic system consisting of a receiving zone; trapping mechanism; and confining 

system to allow injection at planned rates and volumes. 

Operators provide maps and cross sections of local and regional geology, AoR, and 

USDWs; characterize the overburden and subsurface; and provide information on 

fractures, stress, rock strength, and in-situ fluid pressures within cap rock. 

Decrease

2. Area Of Review (AoR) Study and Corrective Action

The AoR determined as either a 1⁄4 mile radius or by mathematical formula. Identify all 

wells in the AoR that penetrate the injection zone and provide a description of each; 

identify the status of corrective action for wells in the AoR; and remediate those posing 

Decrease

 5 The activity baseline used for costing purposes in this analysis is based on the UIC program Class I 

industrial waste disposal well category because of the similarity of early CO2 sequestration permits to the 

permits from that well class.
Page 154 of 259

Baseline

Direction of Change 

in Risk for Selected 

RA

(Relative to Baseline)

the greatest risk to USDWs.

3. Injection Well Construction

The well must be cased and cemented to prevent movement of fluids into or between 

USDWs and to withstand the injected materials at the anticipated pressure, 

temperature and other operational conditions. (A waiver of the Class VI requirement 

that projects inject below the lowermost USDW may be permitted in limited cases.)

Decrease

4. Well Operation

Limit injection pressure to avoid initiating new fractures or propagate existing fractures 

in the confining zone adjacent to the USDWs. 

Decrease

5. Mechanical Integrity Testing (MIT)

Demonstrate internal and external mechanical integrity, conduct a radioactive tracer 

survey of the bottom-hole cement, and conduct a pressure fall-off test every 5 years.

Decrease

6. Monitoring

Monitor the nature of injected fluids at a frequency sufficient to yield data 

representative of their characteristics. Conduct ground water monitoring within the 

AoR. Report semi-annually on the characteristics of injection fluids, injection pressure, 

injection flow rate, injection volume and annular pressure, and on the results of MITs, 

and ground water and atmospheric monitoring.

Decrease 

7. Well Plugging

Ensure that the well is in a state of static equilibrium and plugged using approved 

methods. Plugs shall be tagged and tested. Conduct PISC monitoring to confirm that 

CO2 movement is limited to intended zones.

Decrease

8. Financial Responsibility

Demonstrate and maintain financial responsibility and resources to plug the injection 

well and for post-injection site care.

Decrease

9. Emergency and Remedial Response

No specific requirement under Baseline. Decrease

Overall Decrease

Note: Chapters 2 and 4 of the GS rule Cost Analysis provide detail on the components of the 

regulatory alternatives considered in this analysis and on the direction of change in risk 

associated with them, respectively.
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In considering the benefits of the GS rule, the direction of change in risk compared to the 

baseline regulatory scenario was assessed for each component of the four RAs 

considered. An overall assessment for each alternative as a whole requires consideration 

of the relative importance of the risk being mitigated by each component of the rule.

As shown in Table IV-1, EPA estimates that under the selected alternative, RA3, risk will 

decrease relative to the baseline for each of the nine components assessed. 

b. Other Nonquantified Benefits 

Finalization of this rule will result in direct benefits, that is, protection of USDWs as is 

required of EPA under SDWA; and indirect benefits, which are those protections 

afforded to entities as a by-product of protecting USDWs. Indirect benefits are described 

in Chapter 4 of the GS Rule Cost Analysis. They include mitigation of potential risk to 

surface ecology and to human health through exposure to elevated concentrations of CO2. 

Potential benefits from any climate change mitigation are not included in the assessment.

2. National Cost Summary

a. Cost of the Selected RA

EPA estimated the incremental one-time, capital, and operations and maintenance 

(O&M) costs associated with today’s rulemaking. As Table IV-2 shows, the total 

annualized incremental cost associated with the selected RA is $34.0 million (as 

compared to $15.0 million for the proposed rule) and $28.2 million (as compared to 

$15.6 million in the proposed rule), using a 3-percent and 7-percent discount rate, 

respectively. These costs are in addition to the baseline costs that would be incurred if GS 

activities were instead subject to the current rules for UIC Class I industrial wells. As can 

be seen from Table IV-2, today’s rule increases the costs of complying with UIC 

regulations for these wells from approximately a baseline total of $71.3 million ($32.3 

million in the proposed rule) to $105.3 million ($47.3 million in the proposed rule) in 

annualized terms using a 3-percent discount rate, which is an increase of 48 percent. EPA 

believes these increased costs are needed to ensure the protection of UDWSs from 
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endangerment. The details of the costs associated with each RA are presented in the Cost 

Analysis, along with a discussion of how EPA derived these estimates (EPA, 2010).

Table IV-2. Annualized Incremental Costs of Selected RA 

for Initial Baseline1 of 29 Projects (2008$, $million)

Regulatory 

Alternative One-Time Costs Capital Costs O&M Costs Total

RA0 $ 6.9 $ 15.5 $ 48.9 $ 71.3

RA3 $ 11.4 $ 21.5 $ 72.4 $ 105.3

RA3 Incremental $ 4.4 $ 6.0 $ 23.6 $ 34.0

RA0 $ 7.4 $ 16.5 $ 33.3 $ 57.2

RA3 $ 11.9 $ 23.5 $ 50.0 $ 85.4

RA3 Incremental $ 4.4 $ 7.0 $ 16.7 $ 28.2

Notes: 

2) Detail may not add due to rounding.

1) Initial baseline is modified in analysis prior to costing to reflect assumed attrition rates for projects with non-approved waivers and geo-mechanical 

issues.

7 Percent Discount Rate

3 Percent Discount Rate

Table IV-3 presents a breakout of the annualized incremental costs of the selected RA by 

rule component using a 3-percent discount rate:

• Monitoring activities account for approximately 48 percent of the incremental 

regulatory costs. Most of this cost is for the construction, operation, and maintenance 

of corrosion-resistant monitoring wells. This cost includes tracking of the plume and 

pressure front as well as the cost of incorporating monitoring results into fluid-flow 

models that are used to reevaluate the AoR. These activities are a key component of 

decreasing risk associated with GS because they facilitate early detection of 

unacceptable movement of CO2 or formation fluids. 

• The next largest cost component of the selected RA is injection well operation, which 

accounts for approximately 27 percent of the total incremental cost. This component 

ensures that the wells operate within established parameters in the permit to prevent 

unacceptable fluid movement. 

• Mechanical integrity testing accounts for approximately 7.6 percent of the cost. 

Continuous pressure monitoring is a key component of decreasing risk because it 

provides an early warning that a CO2 leak may have occurred and allows the owner or 

operator to prevent compromises to well integrity. 
Page 157 of 259

• Construction of Class VI wells using the corrosion-resistant design and materials 

necessary to withstand exposure to CO2 accounts for approximately 3.5 percent of the 

incremental cost of the selected RA.

• Geologic site characterization, which ensures that the site geology is safe and 

appropriate for GS, accounts for approximately 7.8 percent of the incremental cost of 

the selected RA. Costs for this component were determined using a site selection 

factor that accounts for the expense of characterizing multiple sites prior to finding an 

appropriate site. 

• Well plugging and post-injection site care activities, which ensure that the injection 

well is properly closed and that the geologic sequestration project no longer poses a 

risk to USDWs, account for approximately 4.2 percent of the total incremental cost of 

RA 3.

• AoR activities, which include modeling the AoR and remediating wells in the AoR, 

account for approximately 1.1 percent of the total incremental cost of RA3. 

Table IV-3. Annualized Incremental Rule Costs of Selected RA for Initial Baseline 

of 29 Projects by Rule Component 

(2008$, $million)

Geologic Site 

Characterization Monitoring

Injection Well 

Construction

Area of 

Review

Well 

Operation MIT

Well Plugging 

and PostInjection Site 

Care

Financial 

Responsibility1

Permitting 

Authority 

Admin TOTAL

Baseline $3.7 $3.7 $16.2 $1.1 $45.6 $0.2 $0.6 $0.0 $0.3 $71.3

Alternative 3 $6.3 $20.0 $17.4 $1.5 $55.0 $2.7 $2.0 $0.0 $0.4 $105.3

Alt 3 Incremental $2.7 $16.3 $1.2 $0.4 $9.3 $2.6 $1.4 $0.0 $0.1 $34.0

Alt 3 as % of 

Total 7.8% 48% 3.5% 1.1% 27% 7.6% 4.2% 0.0% 0.3% 100%

Baseline $4.6 $3.1 $17.0 $1.0 $30.9 $0.1 $0.2 $0.0 $0.3 $57.2

Alternative 3 $7.9 $17.4 $18.4 $1.3 $37.5 $1.7 $0.8 $0.0 $0.4 $85.4

Alt 3 Incremental $3.3 $14.3 $1.4 $0.3 $6.6 $1.6 $0.5 $0.0 $0.2 $28.2

Alt 3 as % of 

Total 12% 51% 4.8% 1.2% 23% 5.8% 1.9% 0.0% 0.6% 100%

Notes:

2) Detail may not add due to rounding.

1) Costs related to demonstration of Financial Responsibility are less than $100,000 in annualized terms.

7 Percent Discount Rate

Regulatory 

Alternative

Rule Component

3 Percent Discount Rate

b. Nonquantified Costs and Uncertainties in Cost Estimates
Page 158 of 259

The purpose of this rule is to mitigate any potential risk caused by GS injection activities 

to the quality, and indirectly the quantity, of current and potential future USDWs. 

Furthermore, the rule creates requirements that are intended to provide additional

safeguards. In the rare case where this rule is non-implementable and results in 

contamination of a USDW, the cost of clean-up or finding an alternative source of 

drinking water could be attributable to this rule. Based on data from States regarding 

implementation of the UIC program and current research, EPA considers the likelihood 

of this occurring very small and has not quantified this risk.

Should this rule somehow impede GS from happening, then the opportunity costs of not 

capturing the benefits associated with GS could be attributed to this regulation; however, 

the Agency has tried to develop a rule that balances risk with practicability, site specific 

flexibility and economic considerations and believes the probability of such impedance is 

very low. This rule ensures protection of USDWs from endangerment associated with GS 

activities while also providing regulatory certainty to industry and permitting authorities 

and an increased understanding of GS through public participation and outreach. Thus, 

EPA believes the rule will not impede GS from happening and has not quantified such 

risk.

Uncertainties in the analysis are inherent in some of the basic assumptions as well as 

some detailed cost items. Uncertainties related to economic trends, the future rate of CCS 

deployment, and GS implementation choices may affect three basic assumptions on 

which the analysis is based: 1) the estimated number of projects that will be affected by 

the GS rule; 2) the labor rates applied; and 3) the estimated number of monitoring wells 

to be constructed per square mile of the AoR to adequately monitor in a given geologic 

setting. 

First, the number of projects that will deploy from 2011 through 2060 may be 

significantly underestimated in this analysis given the uncertainty in future deployment of 

this technology. The current baseline assumption is that 29 projects (changed from 22 

projects in the proposed rule) will deploy during the 50-year period (changed from 25 
Page 159 of 259

years in the proposed rule), as described in Chapter 3 of the Cost Analysis. To address the 

uncertainty inherent in projecting the GS baseline, the final rule cost analysis also 

presents the alternative deployment scenarios of 50 percent more or 50 percent fewer 

projects. This sensitivity analysis is not intended to consider future legislative scenarios, 

the costs of which would not be attributed to this rule. Instead the 50 percent estimate is a 

large, round estimate that could reasonably be expected to represent a worst case scenario 

for the potential difference between the baseline information developed with DOE and 

actual deployment under the GS Rule in the context of existing legislation. 

Second, the labor rate adopted for each of the labor categories for owners or operators 

described in Section 5.2.1 of the Cost Analysis (i.e., geoscientist, mining and geological 

engineer) may be underestimated. The practice of GS represents an activity that, although 

already practiced widely in some contexts (i.e., ER), is expected to expand rapidly in the 

coming years. This expansion may be exponential under certain climate legislative 

scenarios, which may lead to shortages in labor and equipment in the short term and 

result in rapid cost escalation for many of the cost components discussed in this chapter. 

(Anecdotal evidence based on discussions with industry representatives suggests that 

there may already be labor shortages developing in some critical disciplines.) Because the 

cost analyses presented in this chapter are based on current industry costs, the level and 

pace of price responses as the level of GS deployment increases represent a highly 

uncertain component in the cost estimates presented in this chapter. 

Third, for the purpose of estimating national costs, the Agency assumes one monitoring 

well above the injection zone per two square miles of AoR; for monitoring wells into the 

injection zone, the Agency assumes one monitoring well per four square miles. EPA 

assumes monitoring wells into the injection zone will also be used to sample above the 

injection zone. However, the Agency recognizes that operators and primacy agency 

Directors may choose more or fewer monitoring wells depending on project site 

characteristics. Because the monitoring wells and associated costs represent a significant 

component of the cost analysis, the Agency acknowledges that this factor may be 

significant in the overall uncertainty of the cost analysis. 
Page 160 of 259

Additional uncertainties correspond more directly to specific assumptions made in 

constructing the cost model. If the assumptions for such items are incorrect, there may be 

significant cost implications outside of the general price level uncertainties discussed 

above. These cost items are described in Section 5.9.2 of the Cost Analysis. 

EPA requested and received comments on the cost analysis presented in the preamble of 

the proposed rule. One commenter expressed concern that EPA overstated risks to 

USDWs, which may discourage investment in CCS. EPA notes that the risks have been 

discussed as low, based on the rule requirements and the redundancy in those 

requirements. One commenter requested that costs be estimated for a range of projects, 

rather than only the number of projects estimated in the cost analysis. EPA notes that the 

cost analysis for the final rule (as for the proposal) presents a sensitivity analysis that 

considers a 50-percent increase and a 50-percent decrease in this estimated baseline 

number of projects. 

EPA received comments on the proposal cost analysis section that suggested that various 

estimated costs were too high, too low, or absent. EPA clarifies that cost estimates are 

presented in incremental terms. For this reason, costs may seem lower or less 

comprehensive than expected. However, EPA increased some costs, such as labor rates, 

in response to comments. Using industry survey data from the American Association of 

Petroleum Geologists and the Society for Petroleum Engineers, as presented in the Cost 

Analysis, EPA increased the estimated labor rates significantly from the Bureau of Labor 

Statistics estimates used in the analysis for the proposed rule. The updated rates 

(weighted by 1.6 for overhead) in the analysis for the final rule are $110.62 and $107.23 

in 2008$ for engineers and geologists, respectively. These correspond approximately to 

annual salaries of $143,800 and $139,400 and represent an approximately 115 percent 

and a one percent increase, respectively, for engineers and geologists from the proposed 

rule analysis. For more details please see the Cost Analysis for the Final GS Rule 

(USEPA, 2010d).
Page 161 of 259

Lastly, many commenters believed that an assumption of three monitoring wells per GS 

injection well was too high or too low a ratio, or should be modeled for a range of values. 

EPA changed the algorithm for calculating the number of monitoring wells to be based 

on the AoR, instead of the number of injection wells. For a representative saline project 

of approximately 23.3 square miles, EPA assumed 12 monitoring wells (six above the 

injection zone, and six into the injection zone), which EPA understands will be an 

overestimate in some cases and an underestimate in others. Because EPA recognizes the 

inherent uncertainty in this assumption, the cost analysis for the proposed rule presented 

and for the final rule presents a sensitivity analysis based on alternative estimates of 25 

percent more and 25 percent fewer monitoring wells than the number assumed for the 

primary analysis.

c. Supplementary Cost and Uncertainties in Cost Estimates 

To better establish the context in which to evaluate the cost analysis for this rule, EPA

considers three types of costs that are not accounted for explicitly for this rule: 1) costs 

that are incurred beyond the 50-year timeframe of the analysis, 2) costs that could arise 

due to a higher rate of deployment of CCS in the future in response to climate change 

legislation, and 3) the proportion of overall CCS costs attributable to the requirements. 

Because GS is in the early phase of development, and given the significant interest in 

research, development, and eventual commercialization of CCS, EPA provides a 

preliminary discussion of the impact of these costs below.

The cost analysis for this rule estimates costs that EPA anticipates will be incurred during 

a 50-year timeframe beginning with rule promulgation.

6

 6 A detailed discussion of the timeframe over which the costs of the final requirements were estimated can be found in 

the Cost Analysis. The 50 years of costs are calculated in terms of their present value (2008$) and then annualized over 

a 25- year period for a more consistent comparison to other regulations.

 When analyzing costs for a 

commercial-size saline formation sequestration project that begins in year one of the cost 

analysis, EPA assumes that the first year is a pre-construction and construction period, 

followed by 40 years of injection and then either 10, 50, or 100 years of PISC as 

indicated in the cost analysis for the RAs considered. Given the 50-year timeframe 

(changed from 25 years in the proposed rule) of the analysis, the first nine years (changed 
Page 162 of 259

from four years in proposed rule) of the PISC period would be captured in the cost 

analysis for a project beginning in year one, and fewer or no years of PISC for a project 

beginning later in the 50-year analytical timeframe would be included. EPA estimates 

that the incremental sequestration costs above the baseline costs incurred for one 

representative large deep saline project within the 50-year timeframe of the cost analysis 

are approximately $1.20/metric tonne CO2. These costs over the full lifetime of the

sequestration project are estimated to be $1.09/metric tonne CO2. Thus the 50-year 

timeframe (changed from 25 years in proposed rule) captures approximately 91 percent 

(changed from 75 percent in the proposed rule) of the lifetime incremental costs 

associated with implementing this rule. EPA notes, however, that the longer time horizon 

over which costs are estimated inherently introduces increasing amounts of uncertainty 

into those estimates.

The cost analysis assumes that Class VI well owners or operators will inject 

approximately 1.0 billion metric tons (or 1.0 Petagram, Pg) of CO2 cumulatively over the 

next 50 years.

7

 The start years of these projects, for both pilot and large-scale saline, are 

staggered over the first seven years of the period of analysis.8

 Based on the assumed 

deployment schedule, the analysis captures the full injection periods for approximately 10 

large scale saline projects (with an injection period of 40 years) and 2 pilot saline projects 

(with an injection period of four years), and for 14 ER projects (with an assumed 

injection period of 10 years), which are in oil and gas reservoirs. The analysis assumes 

that 10 percent of projects initiated will include waiver applications, and that 50 percent 

of those applications will be approved, while the other 50 percent of waiver applicants 

are removed from the baseline. The analysis also assumes that five percent of project 

permits for the initial baseline estimate of 29 projects will not be approved for geological 

or mechanical reasons.9

 7 A more detailed discussion of these projects can be found in the Cost Analysis.

While the baseline injection amount represents a significant step 

8 A detailed table of the scheduled deployment of projects assumed in the baseline over the 50-year timeframe can be 

found in Exhibit 3.1 of the Cost Analysis.

9 Of the 29 projects that compose the initial baseline, a total of 10 percent, or approximately 3 projects, will not be 

approved based on their permit or waiver applications; costs for compiling the applications and reviewing them are 

included in the cost analysis, but no further costs are incurred for those projects that do not get approved. 
Page 163 of 259

towards demonstrating the feasibility of CCS on an annual basis, it represents a small 

amount of current CO2 emissions in the United States (approximately one percent).

The US fleet of 1,493 coal-fired power generators emits 1.932 Pg CO2 equivalent per 

year. The technical or economic viability of retrofitting these or other industrial facilities 

with CCS is not the subject of this rulemaking. However, if some percentage of these 

facilities undertook CCS and used GS, they (or the owner or operator of the Class VI

injection wells) would be subject to the UIC requirements. For example, if 25 percent of 

these facilities undertook CCS (assuming a 90 percent capture rate and the incremental 

rule sequestration costs outlined in Table IV-4) the incremental sequestration costs 

associated with meeting the Class VI requirements would be on the order of $474 

million. Similarly, if 100 percent of these plants undertook CCS, the incremental costs 

would be on the order of $1.9 billion, although it is unlikely that all coal plants would 

deploy CCS simultaneously. These preliminary cost estimates represent the annualized 

incremental cost of meeting the additional sequestration requirements in the rule, which 

would be incurred over the lifetime of the sequestration projects, assuming that all 

sequestration projects begin in the same year. These cost estimates were not generated 

from a full economic analysis or included in the cost analysis for this rule, due to the 

uncertainty of what percentage, if any, of such facilities will deploy CCS in the future. 

These estimates represent a snapshot of potential costs, assuming that 25 percent or 100 

percent of all plants undertake CCS beginning in the same year, and do not take into 

consideration CCS deployment rates and project-specific costs. Actual annualized costs 

incurred as CCS deploys in the future could be higher or lower, depending on a number 

of factors, including deployment rates10, capital and labor cost trends, and the shape of 

the learning curve among industry and State/Federal operators.

Based on current literature, sequestration costs are expected to be a small component of 

total CCS project costs. Table IV-4 shows example total annualized CCS project costs 

 10 Potential increase in costs due to increased deployment rates and an associated rise in demand for labor or services in 

the field were considered in terms of the uncertainty this contributes to the analysis results. However, a rapid wide scale 

increase in deployment is not expected, according to the Joint Global Change Research Institute (Dooley, 2010), 

therefore the uncertainty in labor or services costs does not contribute significantly to the uncertainty in this cost 

analysis. 
Page 164 of 259

broken down by capture, transportation, and sequestration components. The largest 

component of total CCS project costs is the cost of capturing CO2 ($42.90/metric tonne 

CO2 for capture from an integrated gasification combined cycle power plant11). 

Transportation costs vary widely depending on the distance from emission source to 

sequestration site, but EPA uses a long-term average estimate of $4.60/metric tonne 

CO2.

12 EPA estimates total sequestration costs for a commercial-size deep saline project 

to be approximately $3.43/ metric tonne CO2, of which approximately $1.09/metric tonne

CO2 is attributable to complying with requirements of this rule (including PISC). Based 

on the project costs outlined in Table IV-4, the requirements amount to approximately 2.1

percent of the total CCS project costs.

Table IV-4. Example Total Annualized CCS Project Costs

Cost over lifetime of project 

($/metric tonne)

Percentage of Total CCS 

Project Cost (%)

Capture (IGCC plant) $ 42.90 84.2%

Transportation Estimate $ 4.60 9.0%

Baseline Sequestration $ 2.34 4.6%

Incremental Final Rule 

Sequestration Requirements $ 1.09 2.1%

Total CCS Project Cost $ 50.93 100%

Notes:

1) Detail may not add due to rounding.

2) Transportation cost estimates are based on a distance of 150 miles.

Example Total CCS Project Costs (including capture at an IGCC plant, transportation, 

and deep saline reservoir at commercial scale sequestration)

B. Comparison of Benefits and Costs of RAs Considered

1. Costs Relative to Benefits; Maximizing Net Social Benefits

EPA developed a relative risk analysis in place of a comparison of quantified benefits (a 

direct numerical comparison of costs to benefits) because GS is a new technology and 

 11 Cost and Performance Baseline for Fossil Energy Plants, Vol. 1, DOE/NETL-2007/1281, May 2007. 12 Costs of capture from the “Strategic Analysis of the Global Status of Carbon Capture and Storage Report 2: 

Economic assessment of carbon capture and storage technologies. Final Report,” 2009, Worley Parsons for Global CCS 

Institute. Costs of transport from “Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and 

Challenges,” Feb. 2009, INGAA Foundation.
Page 165 of 259

data collection on the potential effects of GS on USDWs are ongoing. Costs can only be 

compared to qualitative relative risks as discussed in section IV.A.1. 

Compared to the baseline, RA3 provides greater protection to USDWs because it is 

specifically tailored to GS injection activities. The current regulatory requirements do not 

specifically consider the injection of a buoyant, corrosive (in the presence of water) fluid. 

In particular, RA3 includes increased monitoring requirements that provide the amount of 

protection the Agency estimates is necessary for USDWs. As described in section IV.A. 

(National Benefits and Costs of the Rule), monitoring requirements account for 48

percent of the incremental regulatory costs, of which 81 percent is incurred for the 

construction, operation, and maintenance of monitoring wells, and the other 19 percent 

for tracking of the plume and pressure front through complex modeling at a minimum of 

every five years for all operators and for monitoring for CO2 leakage. Public awareness 

of these protective measures would be expected to enhance public acceptance of GS.

EPA also compared RA1 and RA2 to the baseline (discussed in the proposed rule of July 

2008). RA1 does not contain specific requirements but requires operators to meet a 

performance standard regarding protection of USDWs. RA2 is similar to the Class II UIC 

requirements, with some additional construction and PISC requirements. See the Cost 

Analysis (USEPA, 2010d) for a more detailed description. RA1 and RA2 do not provide 

the specific safeguards against CO2 migration that RA3 does because of a significantly 

greater amount of discretion allowed to Directors and operators for interpreting 

requirements, and less stringent requirements for some compliance activities. Only RA3 

and RA4 require the periodic complex modeling exercise for tracking the plume, for 

example. RA4 provides greater safeguards against CO2 migration, but at a much higher 

cost.

2. Cost Effectiveness and Incremental Net Benefits

RA1 and RA2 provide lower costs than RA3 but at increased levels of risk to USDWs. 

Although RA4 has more stringent requirements, EPA does not believe that the increased 
Page 166 of 259

requirements and the increased costs are necessary to provide protection to USDWs. 

Therefore EPA believes that RA3 is the most appropriate alternative. 

C. Conclusions

RA3 provides a high level of protection to USDWs overlying and underlying GS CO2

injection zones. It does so at lower costs than the more stringent RA4 while providing 

significantly more protection than RA1 or RA2. Therefore EPA has selected RA3 for the 

final GS Rule. 

V. Statutory and Executive Order Review 

A. Executive Order 12866: Regulatory Planning and Review 

Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is a 

"significant regulatory action,” because this action will raise novel legal or policy issues. 

Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) 

for review under EO 12866 and any changes made in response to OMB recommendations 

have been documented in the docket for this action.

B. Paperwork Reduction Act (PRA)

The information collection requirements in this rule will be submitted for approval to the 

Office of Management and Budget (OMB) under the Paperwork Reduction Act (PRA), 

44 U.S.C. 3501 et seq. The information collection requirements are not enforceable until 

OMB approves them. 

The information collected as a result of this rule will allow EPA and State permitting 

authorities to review geologic information about a proposed injection project to evaluate 

its suitability for safe and effective GS. It also allows the Agency to fulfill the 

requirements of the UIC program to verify throughout the life of the injection project that 

protective requirements are in place and that USDWs are protected. The collection 

requirements are mandatory under the SDWA (42 U.S.C. 300h et seq.). 
Page 167 of 259

For the first three years after publication of the final rule in the Federal Register, the 

major information requirements apply to a total of 38 respondents, for an average of 12.6

respondents per year. The total incremental burden (for owners or operators, permitting

authorities, and the Agency) associated with the change in moving from the information 

requirements of the UIC program for Class I non-hazardous wells (baseline) to the 

selected alternative under the GS Rule over the three years covered by the Information 

Collection Request (ICR) for the Geologic Sequestration Rule is 53,622 hours, for an 

average of 17,874 hours per year. The total incremental cost over the three year clearance 

period is $30.2 million, for an average of $10.1 million per year (simple average over 

three years). The average burden per response (i.e., the amount of time needed for each 

activity that requires a collection of information) is 422 hours; the average cost per 

response is $238,195. The collection requirements are mandatory under SDWA (42 

U.S.C. 3501 et seq.). Details on the calculation of the rule information collection burden 

and costs can be found in the ICR (USEPA, 2010e) and Chapter 5 of the Cost Analysis 

(USEPA, 2010). A summary of the burden and costs of the collection is presented in 

Exhibit V-1. 

Exhibit V-1 Average Annual Net Change Burden and Costs for the GS ICR

Annual Labor 

Cost

Annual 

Capital Cost

Annual O&M 

Cost

Total Annual 

Cost

Owners or 

Operators 1.0 1,510 $ 199,388 $ 5,827,027 $ 3,238,389 $ 9,264,805 6.9 

Permitting 

Authorities 10.7 11,241 $ 555,763 $ - $ - $ 555,763 23.6 

Agency 1.0 5,123 $ 256,880 $ - $ - $ 256,880 11.7 

Total 12.6 17,874 $ 1,012,032 $ 5,827,027 $ 3,238,389 $ 10,077,448 42.3 

Source: 

Information Collection Request for the Geologic Sequestration Rule (USEPA, 2010c).

Notes:

1) Detail may not add exactly to total due to independent rounding.

2) “Annual Burden Hours” reflects an annual average for all project types over the 3-year ICR period.

Annual 

Responses

Respondent 

Type

Annual 

Respondents

Annual 

Burden 

Hours

Cost

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The 

OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. In 

addition, EPA is amending the table in 40 CFR part 9 of currently approved OMB control 
Page 168 of 259

numbers for various regulations to list the regulatory citations for the information 

requirements contained in this final rule.

C. Regulatory Flexibility Act (RFA) 

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare regulatory 

flexibility analysis of any rule subject to notice and comment rulemaking requirements 

under the Administrative Procedures Act or any other statute unless the agency certifies 

that the rule will not have a significant economic impact on a substantial number of small 

entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts of today’s rule on small entities, small entity is 

defined as: (1) a small business primarily engaged in the generation, transmission, and/or 

distribution of electric energy for sale as defined by North American Industry 

Classification System (NAICS) codes 221111, 221112, 221113, 221119, 221121, 221122 

with total electric output for the preceding fiscal year that did not exceed 4 million 

megawatt hours; (2) a small business primarily engaged in petroleum production as 

defined by NAICS code 324110 with fewer than 1,500 employees and less than 125,000 

barrels per calendar day in total Operable Atmospheric Crude Oil Distillation capacity, as 

specified for government procurement purposes (capacity includes owned or leased 

facilities as well as facilities under a processing agreement or an arrangement such as an 

exchange agreement or a throughput); (3) a small governmental jurisdiction that is a 

government of a city, county, town, school district or special district with a population of 

less than 50,000; and (4) a small organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its field. 

After considering the economic impacts of today’s final rule on small entities, I certify

that this action will not have a significant economic impact on a substantial number of 

small entities. This rule does not impose any requirements on small entities. 
Page 169 of 259

GS is a voluntary action that would only be undertaken by a small entity if GS were in its 

interest compared to other alternatives it may have. Furthermore, GS is a technologically 

complex activity, the cost of which is anticipated to be prohibitive to small entities. 

Therefore it is anticipated small entities would not elect to sequester CO2 via injection 

wells, and thus the rule will not have any impact on them. 

D. Unfunded Mandates Reform Act (UMRA) 

This rule does not contain a Federal mandate that may result in expenditures of $100 

million or more for State, local, and tribal governments, in the aggregate, or the private 

sector in any one year. The total annual incremental costs estimated for the 

implementation of this rule are well under $100 million, resulting in expenditures for the 

entity groupings required under an UMRA analysis that also fall far below the $100 

million per year threshold. Thus, this rule is not subject to the requirements of sections 

202 or 205 of UMRA.

This rule is also not subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or uniquely affect small 

governments. Government responsibilities for oversight and implementation of this rule 

reside with State or Federal agencies and not with small governments.

E. Executive Order 13132: Federalism

Under section 6(b) of Executive Order 13132, EPA may not issue an action that has 

federalism implications, that imposes substantial direct compliance costs, and that is not 

required by statute, unless the Federal government provides the funds necessary to pay 

the direct compliance costs incurred by State and Local governments, or EPA consults 

with State and Local officials early in the process of developing the proposed action. In 

addition, under section 6(c) of Executive Order 13132, EPA may not issue an action that 

has federalism implications and that preempts State law, unless the Agency consults with 

State and Local officials early in the process of developing the proposed action. 

 
Page 170 of 259

EPA concluded that today’s action does not have federalism implications. This rule will 

not impose substantial direct compliance costs on State or Local governments, nor does 

EPA anticipate that it will preempt State law. Thus, the requirements of sections 6(b) and 

6(c) of the Executive Order do not apply to this action. 

Consistent with EPA policy, EPA nonetheless consulted with representatives of State and 

local governments early in the process of developing the proposed action to permit them 

to have meaningful and timely input into its development. Representatives included the 

National Governors’ Association, the National Conference of State Legislatures, the 

Council of State Governments, the National League of Cities, the US Conference of 

Mayors, the National Association of Counties, the International City/County 

Management Association, the National Association of Towns and Townships, and the 

County Executives of America. In the spirit of Executive Order 13132, and consistent 

with EPA policy to promote communications between EPA and State and local 

governments, EPA specifically solicited comment on the proposed action from State and 

local officials. See section II of the Preamble for more details on consultation with State 

and local officials. 

F. Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments

Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) EPA may not 

issue a regulation that has Tribal implications, that imposes substantial direct compliance

costs, and that is not required by statute, unless the Federal government provides the 

funds necessary to pay the direct compliance costs incurred by Tribal governments, or 

EPA consults with Tribal officials early in the process of developing the proposed

regulation and develops a Tribal summary impact statement. 

EPA has concluded that this action may have Tribal implications. However, it will 

neither impose substantial direct compliance costs on Tribal governments, nor preempt 

Tribal law. Indian Tribes may voluntarily apply for primary enforcement responsibility to 

regulate the UIC program in lands under their jurisdiction (See section II.G for more 
Page 171 of 259

details on primacy). Currently, two Tribes have received primacy for the UIC program

under section 1425 of the SDWA since the publication of the proposed rule. EPA is 

responsible for implementing the UIC program in the event that States or Tribes do not 

seek primary enforcement responsibility. EPA clarifies that regardless of whether Tribes 

have UIC program primacy, the rule protects USDWs from contamination and therefore 

protects all populations from adverse health effects related to potential USDW

contamination. 

EPA consulted with Tribal officials early in the process of developing this regulation to 

permit them to have meaningful and timely input into its development. A summary of the 

Tribal consultation calls are included in the docket for the GS rulemaking. See section 

II.E.3 for more information on the details of the Tribal consultation process. 

As required by section 7(a), EPA’s Tribal Consultation Official has certified that the 

requirements of the Executive Order have been met in a meaningful and timely manner. 

A copy of the certification is included in the docket for this action.

G. Executive Order 13045: Protection of Children from Environmental Health 

Risks and Safety Risks

This action is not subject to EO 13045 (62 FR 19885, April 23, 1997) because it is not 

economically significant as defined by EO 12866 and because the Agency does not 

believe the environmental health risks or safety risks addressed by this action present a 

disproportionate risk to children. Today’s rule does not require or provide incentive for 

firms to engage in GS, however, it does protect USDWs from potential negative impacts

from GS of CO2 should a firm decide to undertake such a project. Health and risk 

assessments related to GS of CO2 and its effects on humans and the environment are 

presented in the Vulnerability Evaluation Framework for Geologic Sequestration of 

Carbon Dioxide (USEPA, 2008b). Additionally, EPA notes that it is funding and 

monitoring research related to the potential for USDW contamination associated with GS 

projects. Much of this research focuses on potential exceedances of drinking water 
Page 172 of 259

standards (as suggested), which were developed by EPA and take into account impacts on 

children. Please see section II of this Preamble for more details on this research.

H. Executive Order 13211: Actions that Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a “significant energy action” as defined in Executive Order 13211 (66 

FR 28355 (May 22, 2001)), because it is not likely to have a significant adverse effect on 

the supply, distribution, or use of energy. The higher degree of regulatory certainty and 

clarity in the permitting process may, in fact, have a positive effect on the energy sector. 

Specifically, if climate change legislation that imposes caps or taxes on CO2 emissions is 

passed in the future, energy generation firms and other CO2 producing industries will 

have an economic incentive to reduce emissions, and this rule will provide regulatory 

certainty in determining how to maximize operations (for example, by increasing 

production while staying within the emissions cap or avoiding some carbon taxes). The 

rule may allow some firms to extend the life of their existing capital investment in plant 

machinery or plant processes. 

I. National Technology Transfer and Advancement Act 

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(NTTAA), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use 

voluntary consensus standards in its regulatory activities unless to do so would be 

inconsistent with applicable law or otherwise impractical. Voluntary consensus standards 

are technical standards (e.g., materials specifications, test methods, sampling procedures, 

and business practices) that are developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the 

Agency decides not to use available and applicable voluntary consensus standards. 

This rulemaking involves environmental monitoring or measurement. Consistent with the 

Agency’s Performance Based Measurement System (PBMS), EPA has decided not to 

require the use of specific, prescribed analytic methods. Rather, the rule will allow the 

use of any method that meets the performance criteria. The PBMS approach is intended 
Page 173 of 259

to be more flexible and cost-effective for the regulated community; it is also intended to 

encourage innovation in analytical technology and improved data quality. EPA is not 

precluding the use of any method, whether it constitutes a voluntary consensus standard 

or not, as long as it meets the performance criteria specified. 

J. Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations

Executive Order 12898 (59 FR 7629; February 16, 1994) establishes Federal executive 

policy on environmental justice. Its main provision directs Federal agencies, to the 

greatest extent practicable and permitted by law, to make environmental justice part of 

their mission by identifying and addressing, as appropriate, disproportionately high and 

adverse human health or environmental effects of their programs, policies, and activities 

on minority populations and low-income populations in the United States. 

EPA has determined that this final rule will not have disproportionately high and adverse 

human health or environmental effects on minority or low-income populations because it 

increases the level of environmental protection for all affected populations.

Existing electric power generation plants that burn fossil fuels may be more prevalent in 

areas with higher percentages of people who are minorities or have lower incomes on 

average, but it is hard to predict where new plants with CCS will be built. EPA is 

developing guidance for UIC Directors that places emphasis on considering the potential 

impact of any Class VI permits on communities (such as minority and low income 

populations) when evaluating Class VI injection well permit applications, as well as 

provides suggestions and tools for targeted outreach to ensure more meaningful public 

input and participation from the most affected communities during the permit evaluation 

and approval process. 

This rule does not require that GS be undertaken; but does require that if it is undertaken, 

operators will conduct the activity in such a way as to protect USDWs from 

endangerment caused by CO2. Additionally, this rule will ensure that all areas of the 

United States are subject to the same minimum Federal requirements for protection of 
Page 174 of 259

USDWs from endangerment from GS. Additional detail regarding the potential risk of 

the rule is presented in the Vulnerability Evaluation Framework for Geologic 

Sequestration of Carbon Dioxide (USEPA, 2008b). 

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business 

Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may 

take effect, the agency promulgating the rule must submit a rule report, which includes a 

copy of the rule, to each House of the Congress and to the Comptroller General of the 

United States prior to publication of the rule in the Federal Register. A Major rule cannot 

take effect until 60 days after it is published in the Federal Register. This action is not a 

“major rule” as defined by 5 U.S.C. 804(2). This rule will be effective [INSERT DATE 

60 DAYS AFTER DATE OF PUBLICATION]. 

VI. References

Benson. 2008. Multi-Phase Flow and Trapping of CO2 in Saline Aquifers. Sally M. 

Benson, SPE, Stanford University. Copyright 2008, Offshore Technology Conference.

Birkholzer, J., T. Apps, L. Zheng, Y. Zhang, T. Xu, and C-F. Tsang. 2008a. Research 

Project on CO2 Geological Storage and Groundwater Resources: Water Quality Effects 

Caused by CO2 Intrusion into Shallow Groundwater. LBNL paper #LBNL-1251E. 

http://repositories.cdlib.org/lbnl/LBNL-1251E.

Birkholzer, J., Zhou, Q., Zhang, K., Jordan, P., Rutqvist, J., and C.F. Tsang. 2008b. 

Research Project on CO2 Geological Storage and Groundwater Resources: Large-Scale 

Hydrological Evaluation and Modeling of the Impact on Groundwater Systems. NETL 

Project Annual Report, October 1, 2007 to September 30, 2008.

Celia, M.A., S. Bachu, J.M. Nordbotten, S.E. Gasda, and H.K. Dahle. 2004. Quantitative 

estimation of CO2 Leakage from Geological Storage: Analytical Models, Numerical 

Models, and Data Needs. p. 663–671. In M. Wilson et al. (ed.) Proc. Int. Conf. on 
Page 175 of 259

Greenhouse Gas Control Technologies, 7th, Vancouver, BC, Canada. 5–9 Sept. 2004. 

Vol. 1. Elsevier Science, Amsterdam.

DOE. 2007. Carbon Sequestration Atlas of the U.S. and Canada. U.S. Department of 

Energy, Office of Fossil Energy, National Energy Technology Laboratory. March, 2007.

DOE NETL. 2008a. Carbon Sequestration Atlas of the United States and Canada (Atlas 

II). Second Edition. National Energy Technology Laboratory, Pittsburgh, PA, USA. 

Dooley, J.J., R.T. Dahowski, C.L. Davidson. 2008. On the Long-Term Average Cost of 

CO2 Transport and Storage, Pacific Northwest National Laboratory, PNNL-17389.

Dooley, J., C. Davidson, and R. Dahowski. 2009. An Assessment of the Commercial 

Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. Joint 

Global Change Research Institute. Pacific Northwest National Laboratory. PNNL-18520. 

Duncan, I.J., J.P. Nicot, and J.W. Choi. 2008. Risk Assessment for Future CO2

Sequestration Projects Based on CO2 Enhanced Oil Recovery in the US Energy Procedia.

Energy Information Administration (EIA). 2009. Annual Energy Review, 2008. 

EPRI. 1999. Enhanced Oil Recovery Scoping Study. Report TR-113836.

Holloway, S., J. Pearce, V. Hards, T. Ohsumi, and J. Gale. 2007. Natural Emissions of 

CO2 from the Geosphere and their Bearing on the Geological Storage of Carbon Dioxide. 

Energy 32: 1194-1201.

IEA. 2003. Acid Gas Injection: A Study of Existing Operations. Phase 1: Final Report.

IEA. 2008. CO2 Capture and Storage: A key abatement option. Energy Technology 

Analysis. Paris: IEA/OECD, 2008. 
Page 176 of 259

IPCC. 2005. IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared by 

Working Group III of the Intergovernmental Panel on Climate Change. Metz, B., O. 

Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.). New York: Cambridge 

University Press.

IPCC. 2007. Climate Change 2007: Synthesis Report: Summary for Policymakers. 

Intergovernmental Panel on Climate Change.

IRS. 2009. Internal Revenue Service (IRS) Guidance for Tax Incentives for GS Projects 

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

Julian, J.Y., G.E. King, J.E. Johns, J.K. Sack, and D.B. Robertson. 2007. Detecting UltraSmall Leaks with Ultrasonic Leak Detection-Case Histories from the North Slope, 

Alaska. Presented at International Oil Conference and Exhibition, 27-30 June, Veracruz, 

Mexico. Society of Petroleum Engineers. Paper Number 108906-MS

Klusman, R. W. 2003. Evaluation of Leakage Potential from a Carbon Dioxide 

EOR/Sequestration Project. Energy Conversion and Management, 44: 1921-1940.

Oldenburg, C.M., K. Pruess, and S.M. Benson. 2001. Process modeling of CO2 injection 

into natural gas reservoirs for carbon sequestration and enhanced gas recovery. Energy 

and Fuels, 15: 293-298.

Oil and Gas Journal. Enhanced Oil Recovery Survey. April 21, 2008, p. 41-59. 2008.

Schnaar, G. and D.C. Digiulio. 2009. Computational Modeling of the Geologic 

Sequestration of Carbon Dioxide. Vadose Zone J. 8:389–403.

Skinner, L. 2003. CO2 Blowouts: An Emerging Problem. World Oil. 224(1). 
Page 177 of 259

Somaschini, G., SPE, J. Lovell, H. Abdullah, B. Chariyev, P. Singh, and F. Arachman. 

2009. Subsea Deployment of Instrumented Sand Screens in High-Rate Gas Wells. 

Presented at SPE Annual Technical Conference and Exhibition, 4-7 October 2009, New 

Orleans, Louisiana. Society of Petroleum Engineers. Paper Number 125047-MS.

USEPA. 2001. Class I Underground Injection Control Program: Study of the Risks 

Associated with Class I Underground Injection Wells. 

USEPA. 2007. Using the Class V Experimental Technology Well Classification for Pilot 

Carbon Geologic Sequestration Projects – Underground Injection Control program

Guidance (UICPG # 83). March 2007.

USEPA. 2008a. Climate Change – Climate Economics. Economic Analyses. Updated 

May 7, 2008. http://www.epa.gov/climatechange/economics/economicanalyses.html

USEPA. 2008b. Vulnerability Evaluation Framework for Geologic Sequestration of 

Carbon Dioxide.

USEPA. 2010. Climate Change Science Facts. 430-10-F-002.

USEPA. 2010a. International GS Efforts: A look at the Sleipner, Weyburn, and In Salah 

Projects and other International Regulatory Developments. 816-R10-011.

USEPA. 2010b. Potential Impacts of Leaking Sequestered Carbon Dioxide on Water 

Treatment. 816-R10-014.

USEPA. 2010c. Characterization of Faults and Fractures for GS Operations: Possible 

Induced Changes. 816-R10-xxxx.
Page 178 of 259

USEPA. 2010d. Cost Analysis for the Federal Requirements Under the Underground 

Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS 

Rule). 816-R10-013. 

USEPA. 2010e. Information Collection Request for the Federal Requirements Under The

Underground Injection Control Program for Carbon Dioxide Geologic Sequestration. 

816-R10-012.

USGS. 2009. GS Capacity Methodology http://pubs.usgs.gov/of/2009/1035/ofr2009-

1035.pdf. 

WRI. 2007. J. Logan, J. Venezia, and K. Larsen. Issue Brief: Opportunities and 

Challenges for Carbon Capture and Sequestration. WRI Issue Brief, No. 1. World 

Resources Institute. October, 2007. Washington, DC.
Page 179 of 259

List of Subjects 

40 CFR Part 124

Environmental protection, Administrative practice and procedure, Air pollution control, 

Hazardous waste, Indians-lands, Reporting and recordkeeping requirements, Water 

pollution control, Water supply.

40 CFR Part 144

Environmental protection, Administrative practice and procedure, Confidential business 

information, Hazardous waste, Indians-lands, Reporting and recordkeeping requirements, 

Surety bonds, Water supply. 

40 CFR Part 145

Environmental protection, Confidential business information, Indian-lands, 

Intergovernmental relations, Penalties, Reporting and recordkeeping requirements, Water 

supply.

40 CFR Part 146 

Environmental protection, Hazardous waste, Indian-lands, Reporting and record keeping 

requirements, Water supply.
Page 180 of 259

Federal Requirements Under the Underground Injection Control (UIC) Program 

for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells, Page 180 of 259]

40 CFR Part 147

Environmental protection, Indian-lands, Intergovernmental relations, Penalties, Reporting 

and record keeping requirements, Water supply.

Dated:

Lisa P. Jackson,

Administrator.

For the reasons set forth in the preamble, title 40 chapter I of the Code of Federal 

Regulations is amended as follows:

PART 124—PROCEDURES FOR DECISION MAKING

1. The Authority citation for part 124 continues to read as follows: 

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

Safe Drinking Water Act, 42 U.S.C. 300f et seq.; Clean Water Act, 33 U.S.C. 1251 et 

seq.; Clean Air Act, 42 U.S.C. 7401 et seq.

Subpart A—General Program Requirements
Page 181 of 259

2. Section 124.10 is amended by revising paragraph (c) introductory text and by adding 

paragraph (c)(1)(xi) to read as follows:

§ 124.10 Public notice of permit actions and public comment period.

* * * * *

(c) Methods (applicable to State programs, see 40 CFR 123.25 (NPDES), 145.11 (UIC), 

233.23 (404), and 271.14 (RCRA)). Public notice of activities described in paragraph 

(a)(1) of this section shall be given by the following methods:

(1) * * *

(xi) For Class VI injection well UIC permits, mailing or emailing a notice to State 

and local oil and gas regulatory agencies and State agencies regulating mineral 

exploration and recovery, the Director of the Public Water Supply Supervision 

program in the State, and all agencies that oversee injection wells in the State.

*****

PART 144—UNDERGROUND INJECTION CONTROL PROGRAM

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

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

Conservation and Recovery Act, 42 U.S.C. 6901 et seq.

Subpart A —General Provisions
Page 182 of 259

4. Section 144.1 is amended by adding paragraph (f)(1)(viii) and by revising paragraph 

(g) introductory text to read as follows.

§144.1 Purpose and scope of part 144.

* * * * *

(f) ***

(1) ***

(viii) Subpart H of part 146 sets forth requirements for owners or operators of 

Class VI injection wells.

* * * * *

(g) Scope of the permit or rule requirement. The UIC permit program regulates 

underground injection by six classes of wells (see definition of ‘‘well injection,’’ §144.3). 

The six classes of wells are set forth in §144.6. All owners or operators of these injection 

wells must be authorized either by permit or rule by the Director. In carrying out the 

mandate of the SDWA, this subpart provides that no injection shall be authorized by 

permit or rule if it results in the movement of fluid containing any contaminant into 

underground sources of drinking water (USDWs –see §144.3 for definition), if the 

presence of that contaminant may cause a violation of any primary drinking water 

regulation under 40 CFR part 141 or may adversely affect the health of persons 

(§144.12). Existing Class IV wells which inject hazardous waste directly into an 

underground source of drinking water are to be eliminated over a period of six months 

and new such Class IV wells are to be prohibited (§144.13). For Class V wells, if 

remedial action appears necessary, a permit may be required (§144.25) or the Director 
Page 183 of 259

must require remedial action or closure by order (§144.6(c)). During UIC program 

development, the Director may identify aquifers and portions of aquifers which are actual 

or potential sources of drinking water. This will provide an aid to the Director in carrying 

out his or her duty to protect all USDWs. An aquifer is a USDW if it fits the definition 

under §144.3, even if it has not been “identified.” The Director may also designate 

“exempted aquifers” using the criteria in §146.4 of this chapter, except that the Director 

may not expand the areal extent of an existing Class II enhanced oil recovery or enhanced 

gas recovery aquifer exemption for Class VI injection wells during initial program 

development and EPA may not approve a program with expanded Class II-Class VI 

exemptions. Such aquifers are those which would otherwise qualify as “underground 

sources of drinking water” to be protected, but which have no real potential to be used as 

drinking water sources. Therefore, they are not USDWs. No aquifer is an exempted 

aquifer until it has been affirmatively designated under the procedures at §144.7. 

Aquifers which do not fit the definition of “underground source of drinking water” are 

not “exempted aquifers.” They are simply not subject to the special protection afforded 

USDWs. ***

* * * * *

5. Section 144.3 is amended by adding in alphabetic order “geologic sequestration” to 

read as follows:

§144.3 Definitions

*****
Page 184 of 259

Geologic sequestration means the long-term containment of a gaseous, liquid, or 

supercritical carbon dioxide stream in subsurface geologic formations. This term does not 

apply to carbon dioxide capture or transport.

*****

6. Section 144.6 is amended by revising paragraph (e) and adding paragraph (f) to read as 

follows:

§144.6 Classification of wells.

* * * * *

(e) Class V. Injection wells not included in Class I, II, III, IV, or VI. Specific 

types of Class V injection wells are described in §144.81.

(f) Class VI. Wells that are not experimental in nature that are used for geologic 

sequestration of carbon dioxide 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 of this 

chapter; or, wells used for geologic sequestration of carbon dioxide that have received an 

expansion to the areal extent of an existing Class II enhanced oil recovery or enhanced 

gas recovery aquifer exemption pursuant to §§146.4 of this chapter and 144.7(d).

.

7. Section 144.7 is amended as follows: 

a. Revising paragraph (a); 

b. Revising paragraph (b); and
Page 185 of 259

c. Adding paragraph (d) as follows:

§144.7 Identification of underground sources of drinking water and exempted 

aquifers

(a) The Director may identify (by narrative description, illustrations, maps, or 

other means) and shall protect as underground sources of drinking water, all aquifers and 

parts of aquifers which meet the definition of “underground source of drinking water” in 

§144.3, except to the extent there is an applicable aquifer exemption under paragraph (b) 

of this section or an expansion to the areal extent of an existing Class II enhanced oil 

recovery or enhanced gas recovery aquifer exemption under paragraph (d) of this section. 

No exempted aquifer may be used for Class VI injection unless the owner or operator 

and/or Director requests, and EPA approves, a request to expand an existing Class II

(EOR/EGR) aquifer exemption for a Class VI well in accordance with the criteria set 

forth in §146.4(d) of this chapter. Even if an aquifer has not been specifically identified

by the Director, it is an underground source of drinking water if it meets the definition in 

§144.3.

(b)(1) The Director may identify (by narrative description, illustrations, maps, or 

other means) and describe in geographic and/or geometric terms (such as vertical and 

lateral limits and gradient) which are clear and definite, all aquifers or parts thereof which 

the Director proposes to designate as exempted aquifers using the criteria in §146.4 of 

this chapter.

(2) No designation of an exempted aquifer submitted as part of a UIC program shall be 

final until approved by the Administrator as part of a UIC program. No designation of an 
Page 186 of 259

expansion to the areal extent of a Class II enhanced oil recovery or enhanced gas 

recovery aquifer exemption for the exclusive purpose of Class VI injection for geologic 

sequestration shall be final until approved by the Administrator as a revision to the 

applicable Federal UIC program under part 147 or as a substantial revision of an 

approved State UIC program in accordance with §145.32 of this chapter. ***

* * * * *

(d) Expansion to the Areal Extent of Existing Class II Aquifer Exemptions for 

Class VI Wells. Owners or operators of Class II wells may request that the Director 

approve an expansion to the areal extent of an aquifer exemption already in place for a 

Class II well for the exclusive purpose of Class VI injection for geologic sequestration. 

Such requests must be treated as a revision to the applicable Federal UIC program under 

part 147 or as a substantial program revision to an approved State UIC program under 

§145.32 of this chapter and will not be final until approved by EPA. 

8. Section 144.8 is amended by adding paragraph (b)(2)(iii) to read as follows:

§ 144.8 Noncompliance and program reporting by the Director. 

* * * * *

(b) ***

(2) ***

(iii) All Class VI program reports shall be consistent with reporting requirements 

set forth in §146.91 of this chapter.

* * * * *
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Subpart B —General Program Requirements

9. Section 144.12 is amended by revising the first sentence in paragraph (b) to read as 

follows:

§ 144.12 Prohibition of movement of fluid into underground sources of drinking 

water.

* * * * *

(b) For Class I, II, III, and VI wells, if any water quality monitoring of an underground 

source of drinking water indicates the movement of any contaminant into the 

underground source of drinking water, except as authorized under part 146, the Director 

shall prescribe such additional requirements for construction, corrective action, operation, 

monitoring, or reporting (including closure of the injection well) as are necessary to 

prevent such movement. ***

* * * * *

10. Section 144.15 is added to read as follows:

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

The construction, operation or maintenance of any non-experimental Class V 

geologic sequestration well is prohibited.

11. Section 144.18 is added to read as follows:
Page 188 of 259

§144.18 Requirements for Class VI wells. 

Owners or operators of Class VI wells must obtain a permit. Class VI wells 

cannot be authorized by rule to inject carbon dioxide.

12. Section 144.19 is added to read as follows:

§ 144.19 Transitioning from Class II to Class VI.

(a) Owners or operators 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 geologic 

sequestration permit when there is an increased risk to USDWs compared to Class II 

operations. 

(b) The Director shall determine when there is an increased risk to USDWs compared to 

Class II operations and a Class VI permit is required. In order to make this determination 

the Director must consider the following:

(1) Increase in reservoir pressure within the injection zone(s);

(2) Increase in carbon dioxide injection rates;

(3) Decrease in reservoir production rates;

(4) Distance between the injection zone(s) and USDWs;

(5) Suitability of the Class II area of review delineation; 

(6) Quality of abandoned well plugs within the area of review;

(7) The owner’s or operator’s plan for recovery of carbon dioxide at the cessation of 

injection;
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(8) The source and properties of injected carbon dioxide; and

(9) Any additional site-specific criteria as determined by the Director.

13. Section 144.22 is amended by revising paragraph (b) to read as follows:

§ 144.22 Existing Class II enhanced recovery and hydrocarbon storage wells. 

*****

(b) Duration of well authorization by rule. Well authorization under this section expires 

upon the effective date of a permit issued pursuant to §§144.19, 144.25, 144.31, 144.33 

or 144.34; after plugging and abandonment in accordance with an approved plugging and 

abandonment plan pursuant to §§144.28(c) and 146.10 of this chapter; and upon

submission of a plugging and abandonment report pursuant to §144.28(k); or upon 

conversion in compliance with §144.28(j). 

* * * * *

Subpart D—Authorization by Permit

14. Section 144.31 is amended by revising paragraph (e) introductory text to read as 

follows:

§ 144.31 Application for a permit; authorization by permit.

*****

(e) Information requirements. All applicants for Class I, II, III, and V permits shall 

provide the following information to the Director, using the application form provided by 
Page 190 of 259

the Director. Applicants for Class VI permits shall follow the criteria provided in §146.82

of this chapter.

* * * * *

15. Section 144.33 is amended by revising paragraph (a)(4) and adding paragraph (a)(5).

§ 144.33 Area permits. 

(a) ***

(4) Used to inject other than hazardous waste; and

(5) Other than Class VI wells. 

* * * * *

16. Section 144.36 is amended by revising paragraph (a) to read as follows:

§144.36 Duration of permits.

(a) Permits for Class I and V wells shall be effective for a fixed term not to exceed 10 

years. UIC permits for Class II and III wells shall be issued for a period up to the 

operating life of the facility. UIC permits for Class VI wells shall be issued for the 

operating life of the facility and the post-injection site care period. The Director shall 

review each issued Class II, III, and VI well UIC permit at least once every 5 years to 

determine whether it should be modified, revoked and reissued, terminated or a minor 

modification made as provided in §§144.39, 144.40, or 144.41.

* * * * *
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17. Section 144.38 is amended by revising paragraph (b) introductory text to read as 

follows:

§ 144.38 Transfer of permits.

* * * * *

(b) Automatic transfers. As an alternative to transfers under paragraph (a) of this section, 

any UIC permit for a well not injecting hazardous waste or injecting carbon dioxide for 

geologic sequestration may be automatically transferred to a new permittee if: 

* * * * *

18. Section 144.39 is amended as follows:

a. Revising the second sentence in paragraph (a) introductory text;

b. Revising the second sentence in paragraph (a)(3) introductory text; and 

c. Adding a new paragraph (a)(5) to read as follows:

§144.39 Modification or revocation and reissuance of permits.

* * * * *

(a) *** For Class I hazardous waste injection wells, Class II, Class III or Class VI wells 

the following may be causes for revocation and reissuance as well as modification; and 

for all other wells the following may be cause for revocation or reissuance as well as 

modification when the permittee requests or agrees. ***

*****
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(3) *** Permits other than for Class I hazardous waste injection wells, Class II, 

Class III or Class VI wells may be modified during their permit terms for this 

cause only as follows: ***

*****

(5) Basis for modification of Class VI permits. Additionally, for Class VI wells, 

whenever the Director determines that permit changes are necessary based on:

(i) Area of review reevaluations under §146.84(e)(1) of this chapter;

(ii) Any amendments to the testing and monitoring plan under §146.90(j) of this 

chapter; 

(iii) Any amendments to the injection well plugging plan under §146.92(c) of this 

chapter;

(iv) Any amendments to the post-injection site care and site closure plan under 

§146.93(a)(3) of this chapter; 

(v) Any amendments to the emergency and remedial response plan under 

§146.94(d) of this chapter; or

(vi) A review of monitoring and/or testing results conducted in accordance with 

permit requirements.

* * * * *

19. Section 144.41 is amended by adding a new paragraph (h) to read as follows:

§ 144.41 Minor modifications of permits.
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* * * * *

(h) Amend a Class VI injection well testing and monitoring plan, plugging plan, postinjection site care and site closure plan, or emergency and remedial response plan where 

the modifications merely clarify or correct the plan, as determined by the Director. 

Subpart E—Permit Conditions

20. Section 144.51 is amended to read as follows:

a. Adding a new paragraph (j)(4); 

b. Revising paragraph (o); and 

c. Revising the first two sentences in paragraph (q)(1) and the first sentence in 

paragraph (q)(2). 

§ 144.51 Conditions applicable to all permits.

*****

(j) ***

(4) Owners or operators of Class VI wells shall retain records as specified in subpart H 

of part 146, including §§146.84(g), 146.91(f), 146.92(d), 146.93(e), and 146.93(g) of this 

chapter.

*****

(o) A Class I, II or III permit shall include and a Class V permit may include conditions 

which meet the applicable requirements of §146.10 of this chapter to ensure that plugging 

and abandonment of the well will not allow the movement of fluids into or between 
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USDWs. Where the plan meets the requirements of §146.10 of this chapter, the Director 

shall incorporate the plan into the permit as a permit condition. Where the Director's 

review of an application indicates that the permittee's plan is inadequate, the Director 

may require the applicant to revise the plan, prescribe conditions meeting the 

requirements of this paragraph, or deny the permit. A Class VI permit shall include 

conditions which meet the requirements set forth in §146.92 of this chapter. Where the 

plan meets the requirements of §146.92 of this chapter, the Director shall incorporate it 

into the permit as a permit condition. For purposes of this paragraph, temporary or 

intermittent cessation of injection operations is not abandonment. 

*****

(q) ***

(1) The owner or operator of a Class I, II, III or VI well permitted under this part 

shall establish mechanical integrity prior to commencing injection or on a 

schedule determined by the Director. Thereafter the owner or operator of Class I, 

II, and III wells must maintain mechanical integrity as defined in §146.8 of this 

chapter and the owner or operator of Class VI wells must maintain mechanical 

integrity as defined in §146.89 of this chapter. ***

(2) When the Director determines that a Class I, II, III or VI well lacks 

mechanical integrity pursuant to §§146.8 or 146.89 of this chapter for Class VI of this 

chapter, he/she shall give written notice of his/her determination to the owner or operator. 

***

* * * * *
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21. Section 144.52 is amended as follows:

a. By revising paragraph (a) introductory text;

b. Revising paragraph (a)(2);

c. Revising paragraphs (a)(7)(i)(A) and (a)(7)(ii); and,

d. Revising paragraph (a)(8).

§ 144.52 Establishing permit conditions. 

(a) In addition to conditions required in §144.51, the Director shall establish conditions, 

as required on a case-by-case basis under §144.36 (duration of permits), §144.53(a) 

(schedules of compliance), §144.54 (monitoring), and for EPA permits only §144.53(b) 

(alternate schedules of compliance), and §144.4 (considerations under Federal law). 

Permits for owners or operators of hazardous waste injection wells shall include 

conditions meeting the requirements of §144.14 (requirements for wells injecting 

hazardous waste), paragraphs (a)(7) and (a)(9) of this section, and subpart G of part 146. 

Permits for owners or operators of Class VI injection wells shall include conditions 

meeting the requirements of subpart H of part 146. Permits for other wells shall contain 

the following requirements, when applicable. 

*****

(2) Corrective action as set forth in §§144.55, 146.7, and 146.84 of this chapter.

*****

(7) ***

(i) ***
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(A) The well has been plugged and abandoned in accordance with an approved 

plugging and abandonment plan pursuant to §§144.51(o), 146.10, and 146.92 of 

this chapter, and submitted a plugging and abandonment report pursuant to 

§144.51(p); or 

*****

(ii) The permittee shall show evidence of such financial responsibility to the 

Director by the submission of a surety bond, or other adequate assurance, such as 

a financial statement or other materials acceptable to the Director. For EPA 

administered programs, the Regional Administrator may on a periodic basis 

require the holder of a lifetime permit to submit an estimate of the resources 

needed to plug and abandon the well revised to reflect inflation of such costs, and 

a revised demonstration of financial responsibility, if necessary. The owner or 

operator of a well injecting hazardous waste must comply with the financial 

responsibility requirements of subpart F of this part. For Class VI wells, the 

permittee shall show evidence of such financial responsibility to the Director by 

the submission of a qualifying instrument (see §146.85(a) of this chapter), such as 

a financial statement or other materials acceptable to the Director. The owner or 

operator of a Class VI well must comply with the financial responsibility 

requirements set forth in §146.85 of this chapter.

(8) Mechanical integrity. A permit for any Class I, II, III or VI well or injection 

project which lacks mechanical integrity shall include, and for any Class V well 

may include, a condition prohibiting injection operations until the permittee 
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shows to the satisfaction of the Director under §§146.8, or 146.89 for Class VI,

that the well has mechanical integrity.

* * * * *

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

22. Section 144.80 is amended by revising the first sentence in paragraph (e) and by 

adding paragraph (f) to read as follows:

§144.80 What is a Class V injection well?

* * * * *

(e) Class V. Injection wells not included in Class I, II, III, IV or VI. *** 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath the 

lowermost formation containing a USDW, except those wells that are experimental in 

nature; 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 of this 

chapter; or, wells used for geologic sequestration of carbon dioxide that have received an 

expansion to the areal extent of a existing Class II enhanced oil recovery or enhanced gas 

recovery aquifer exemption pursuant to §§146.4 of this chapter and 144.7(d).

PART 145—STATE UIC PROGRAM REQUIREMENTS

23. The authority citation for part 145 continues to read as follows:

Authority: 42 U.S.C. 300f et seq.
Page 198 of 259

Subpart A—General Program Requirements

24. Section 145.1 is amended by adding paragraph (i) to read as follows:

§ 145.1 Purpose and scope.

* * * * *

(i) States seeking primary enforcement responsibility for Class VI wells must submit a 

primacy application in accordance with subpart C of this part and meet all requirements 

of this part. States may apply for primary enforcement responsibility for Class VI wells 

independently of other injection well classes. 

Subpart C—State Program Submissions

25. Section 145.21 is amended by adding paragraph (h) to read as follows:

§145.21 General requirements for program approvals.

* * * * *

(h) To establish a Federal UIC Class VI program in States not seeking full UIC primary 

enforcement responsibility approval, pursuant to the SDWA section 1422(c), States shall, 

by [INSERT DATE 270 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], submit to the Administrator a new or revised State UIC program complying 

with §§145.22 or 145.32 of this part. Beginning on [INSERT DATE 270 DAYS AFTER 
Page 199 of 259

DATE OF PUBLICATION IN THE FEDERAL REGISTER] the requirements of subpart 

H of part 146 will be applicable and enforceable by EPA in each State that has not 

received approval of a new Class VI program application under section 1422 of the Safe 

Drinking Water Act or a revision of its UIC program under section 1422 of the Safe 

Drinking Water Act to incorporate subpart H of part 146. Following [INSERT DATE 270 

DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER], EPA will 

publish a list of the States where subpart H of part 146 has become applicable.

26. Section 145.22 is amended by revising paragraphs (a) introductory text and (a)(5) to 

read as follows:

§ 145.22 Elements of a program submission.

(a) Any State that seeks to administer a program under this part shall submit to the 

Administrator at least three copies of a program submission. For Class VI programs, the 

entire submission can be sent electronically. The submission shall contain the following:

*****

(5) Copies of all applicable State statutes and regulations, including those 

governing State administrative procedures;

*****

27. Section 145.23 is amended as follows: 

a. By revising the introductory text; 

b. Revising paragraph (c);

c. Revising paragraph (d);
Page 200 of 259

d. Revising paragraphs (f)(1), (f)(2), (f)(3), (f)(4), (f)(9); and,

e. Adding paragraphs (f)(13) and (f)(14) to read as follows:

§ 145.23 Program description.

Any State that seeks to administer a program under this part shall submit a description of 

the program it proposes to administer in lieu of the Federal program under State law or 

under an interstate compact. For Class VI programs, the entire submission can be sent 

electronically. The program description shall include:

*****

(c) A description of applicable State procedures, including permitting procedures and any 

State administrative or judicial review procedures.

(d) Copies of the permit form(s), application form(s), reporting form(s), and manifest 

format the State intends to employ in its program. Forms used by States need not be 

identical to the forms used by EPA but should require the same basic information. The 

State need not provide copies of uniform national forms it intends to use but should note 

its intention to use such forms. For Class VI programs, submit copies of the current forms 

in use by the State, if any.

*****

(f) ***

(1) A schedule for issuing permits within five years after program approval to all 

injection wells within the State which are required to have permits under this part 

and 40 CFR part 144. For Class VI programs, a schedule for issuing permits 

within two years after program approval;
Page 201 of 259

(2) The priorities (according to criteria set forth in §146.9 of this chapter) for 

issuing permits, including the number of permits in each class of injection well 

which will be issued each year during the first five years of program operation. 

For Class VI programs, include the priorities for issuing permits and the number 

of permits which will be issued during the first two years of program operation;

(3) A description of how the Director will implement the mechanical integrity 

testing requirements of §146.8 of this chapter, or, for Class VI wells, the 

mechanical integrity testing requirements of §146.89 of this chapter, including the 

frequency of testing that will be required and the number of tests that will be 

reviewed by the Director each year; 

(4) A description of the procedure whereby the Director will notify owners or

operators of injection wells of the requirement that they apply for and obtain a 

permit. The notification required by this paragraph shall require applications to be 

filed as soon as possible, but not later than four years after program approval for 

all injection wells requiring a permit. For Class VI programs, this paragraph shall 

require applications to be filed as soon as possible, but not later than one year 

after program approval;

*****

(9) A description of aquifers, or parts thereof, which the Director has identified 

under §144.7(b) as exempted aquifers, and a summary of supporting data. New 

aquifer exemptions shall not be issued for Class VI wells or injection activities, 

and Class VI wells cannot inject into previously exempted aquifers;

*****
Page 202 of 259

(13) For Class VI programs, a description of the procedure whereby the Director 

must notify, in writing, any States, Tribes, and Territories of any permit 

applications for geologic sequestration of carbon dioxide wherein the area of 

review crosses State, Tribal, or Territory boundaries, resulting in the need for 

trans-boundary coordination related to an injection operation. 

(14) For Class VI programs only, a description of any expansions to the areal 

extent of an existing Class II enhanced oil recovery or enhanced gas recovery

aquifer exemption, which the Director has identified and approved under 

§144.7(d) of this chapter and a summary of supporting data. 

28. Section 145.32 is amended by adding a sentence at the end of paragraph (b)(2) to read 

as follows

§ 145.32 Procedures for revision of State programs.

*****

(b) ***

(2) *** All requests for expansions to the areal extent of Class II enhanced oil recovery 

or enhanced gas recovery aquifer exemptions for Class VI wells must be treated as 

substantial program revisions.

*****

PART 146—UNDERGROUND INJECTION CONTROL PROGRAM: CRITERIA 

AND STANDARDS
Page 203 of 259

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

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

Conservation and Recovery Act, 42 U.S.C. 6901 et seq.

30. Section 146.4 is amended by revising the introductory text and adding paragraph (d) 

to read as follows:

§ 146.4 Criteria for exempted aquifers.

An aquifer or a portion thereof which meets the criteria for an “underground source of 

drinking water” in §146.3 may be determined under §144.7 of this chapter to be an 

“exempted aquifer” for Class I-V wells if it meets the criteria in paragraphs (a) through 

(c) of this section. Class VI wells must meet the criteria under paragraph (d) of this 

section:

*****

(d) The areal extent of an aquifer exemption for a Class II enhanced oil recovery or 

enhanced gas recovery well may be expanded for the exclusive purpose of Class VI 

injection for geologic sequestration under §144.7(d) of this chapter if it meets the 

following criteria:

(1) It does not currently serve as a source of drinking water; and

(2) The total dissolved solids content of the ground water is more than 3,000 mg/l 

and less than 10,000 mg/l; and

(3) It is not reasonably expected to supply a public water system.
Page 204 of 259

30. Section 146.5 is amended by revising the first sentence in paragraph (e) introductory 

text and by adding paragraph (f) to read as follows:

§146.5 Classification of injection wells.

* * * * *

(e) Class V. Injection wells not included in Class I, II, III, IV or VI. *** 

* * * * *

(f) Class VI. Wells that are not experimental in nature that are used for geologic 

sequestration of carbon dioxide 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 enhanced oil recovery or enhanced gas recovery 

aquifer exemption pursuant to §§146.4 of this chapter and 144.7(d). .

31. Subpart H is added to read as follows:

Subpart H—Criteria and Standards Applicable to Class VI Wells

Sec.

146.81 Applicability.

146.82 Required Class VI permit information.

146.83 Minimum criteria for siting.

146.84 Area of review and corrective action.
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146.85 Financial responsibility.

146.86 Injection well construction requirements.

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

146.88 Injection well operating requirements.

146.89 Mechanical integrity.

146.90 Testing and monitoring requirements.

146.91 Reporting requirements.

146.92 Injection well plugging.

146.93 Post-injection site care and site closure.

146.94 Emergency and remedial response.

146.95 Class VI injection depth waiver requirements. 

Subpart H—Criteria and Standards Applicable to Class VI Wells

§146.81 Applicability.

(a) This subpart establishes criteria and standards for underground injection control 

programs to regulate any Class VI carbon dioxide geologic sequestration injection wells.

(b) This subpart applies to any wells used to inject carbon dioxide specifically for the 

purpose of geologic sequestration, i.e., the long-term containment of a gaseous, liquid, or 

supercritical carbon dioxide stream in subsurface geologic formations. 

(c) This subpart also applies to owners or operators of permit- or rule-authorized Class I, 

Class II, or Class V experimental carbon dioxide injection projects who seek to apply for 

a Class VI geologic sequestration permit for their well or wells. Owners or operators 
Page 206 of 259

seeking to convert existing Class I, Class II, or Class V experimental wells to Class VI 

geologic sequestration wells must demonstrate to the Director that the wells were 

engineered and constructed to meet the requirements at §146.86(a) and ensure protection 

of USDWs, in lieu of requirements at §§146.86(b) and 146.87(a). By [INSERT DATE 

365 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER],

owners or operators of either 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 must apply for a Class VI permit. A converted well must still meet all other 

requirements under part 146.

(d) Definitions. The following definitions apply to this subpart. To the extent that these 

definitions conflict with those in §§144.3 or 146.3 of this chapter these definitions 

govern:

Area of review means 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.

Carbon dioxide plume means the extent underground, in three dimensions, of an 

injected carbon dioxide stream.

Carbon dioxide stream means carbon dioxide that has been captured from an 

emission source (e.g., a power plant), plus incidental associated substances 
Page 207 of 259

derived from the source materials and the capture process, and any substances 

added to the stream to enable or improve the injection process. This subpart does 

not apply to any carbon dioxide stream that meets the definition of a hazardous 

waste under 40 CFR part 261. 

Confining zone means a geologic formation, group of formations, or part of a 

formation stratigraphically overlying the injection zone(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 means 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 underground sources of drinking water (USDW). 

Geologic sequestration means the long-term containment of a gaseous, liquid, or 

supercritical carbon dioxide stream in subsurface geologic formations. This term 

does not apply to carbon dioxide capture or transport.

Geologic sequestration project means an injection well or wells used to emplace a 

carbon dioxide stream beneath the lowermost formation containing a USDW; 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 enhanced oil recovery or 

enhanced gas recovery aquifer exemption pursuant to §§146.4 of this chapter and 

144.7(d). It includes the subsurface three-dimensional extent of the carbon 
Page 208 of 259

dioxide plume, associated area of elevated pressure, and displaced fluids, as well 

as the surface area above that delineated region.

Injection zone means a geologic formation, group of formations, or part of a 

formation that is of sufficient areal extent, thickness, porosity, and permeability to 

receive carbon dioxide through a well or wells associated with a geologic 

sequestration project.

Post-injection site care means appropriate monitoring and other actions 

(including corrective action) needed following cessation of injection to ensure that 

USDWs are not endangered, as required under §146.93.

Pressure front means the zone of elevated pressure that is created by the injection 

of carbon dioxide into the subsurface. For the purposes of this subpart, the 

pressure front of a carbon dioxide plume refers to a zone where there is a pressure 

differential sufficient to cause the movement of injected fluids or formation fluids 

into a USDW.

Site closure means the point/time, as determined by the Director following the 

requirements under §146.93, at which the owner or operator of a geologic 

sequestration site is released from post-injection site care responsibilities. 

Transmissive fault or fracture means a fault or fracture that has sufficient 

permeability and vertical extent to allow fluids to move between formations.

§146.82 Required Class VI permit information.

This section sets forth the information which must be considered by the Director in 

authorizing Class VI wells. For converted Class I, Class II, or Class V experimental 
Page 209 of 259

wells, certain maps, cross-sections, tabulations of wells within the area of review and 

other data may be included in the application by reference provided they are current, 

readily available to the Director, and sufficiently identified to be retrieved. In cases where 

EPA issues the permit, all the information in this section must be submitted to the 

Regional Administrator.

(a) Prior to the issuance of a permit for the construction of a new Class VI well or the 

conversion of an existing Class I, Class II, or Class V well to a Class VI well, the owner 

or operator shall submit, pursuant to §146.91(e), and the Director shall consider the 

following:

(1) Information required in §144.31 (e)(1) through (6) of this chapter;

(2) A map showing the injection well for which a permit is sought and the 

applicable area of review consistent with §146.84. Within the area of review, the 

map must show the number or name, and location of all injection wells, producing 

wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, 

State- or EPA-approved subsurface cleanup sites, surface bodies of water, springs, 

mines (surface and subsurface), quarries, water wells, other pertinent surface 

features including structures intended for human occupancy, State, Tribal, and 

Territory boundaries, and roads. The map should also show faults, if known or 

suspected. Only information of public record is required to be included on this 

map;

(3) Information on the geologic structure and hydrogeologic properties of the 

proposed storage site and overlying formations, including:

(i) Maps and cross sections of the area of review;
Page 210 of 259

(ii) The location, orientation, and properties of known or suspected faults 

and fractures that may transect the confining zone(s) in the area of review 

and a determination that they would not interfere with containment;

(iii) Data on the depth, areal extent, thickness, mineralogy, porosity, 

permeability, and capillary pressure of the injection and confining zone(s); 

including geology/facies changes based on field data which may include 

geologic cores, outcrop data, seismic surveys, well logs, and names and 

lithologic descriptions; 

(iv) Geomechanical information on fractures, stress, ductility, rock 

strength, and in situ fluid pressures within the confining zone(s); 

(v) Information on the seismic history including the presence and depth of 

seismic sources and a determination that the seismicity would not interfere 

with containment; and

(vi) Geologic and topographic maps and cross sections illustrating 

regional geology, hydrogeology, and the geologic structure of the local 

area.

(4) A tabulation of all wells within the area of review which penetrate the 

injection or confining zone(s). Such data must include a description of each well's 

type, construction, date drilled, location, depth, record of plugging and/or 

completion, and any additional information the Director may require;

(5) Maps and stratigraphic cross sections indicating the general vertical and lateral 

limits of all USDWs, water wells and springs within the area of review, their 
Page 211 of 259

positions relative to the injection zone(s), and the direction of water movement, 

where known;

(6) Baseline geochemical data on subsurface formations, including all USDWs in 

the area of review; 

(7) Proposed operating data for the proposed geologic sequestration site:

(i) Average and maximum daily rate and volume and/or mass and total 

anticipated volume and/or mass of the carbon dioxide stream;

(ii) Average and maximum injection pressure; 

(iii) The source(s) of the carbon dioxide stream; and

(iv) An analysis of the chemical and physical characteristics of the carbon 

dioxide stream.

(8) Proposed pre-operational formation testing program to obtain an analysis of 

the chemical and physical characteristics of the injection zone(s) and confining 

zone(s) and that meets the requirements at §146.87;

(9) Proposed stimulation program, a description of stimulation fluids to be used

and a determination that stimulation will not interfere with containment;

(10) Proposed procedure to outline steps necessary to conduct injection operation;

(11) Schematics or other appropriate drawings of the surface and subsurface 

construction details of the well;

(12) Injection well construction procedures that meet the requirements of 

§146.86;
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(13) Proposed area of review and corrective action plan that meets the 

requirements under §146.84;

(14) A demonstration, satisfactory to the Director, that the applicant has met the 

financial responsibility requirements under §146.85;

(15) Proposed testing and monitoring plan required by §146.90;

(16) Proposed injection well plugging plan required by §146.92(b);

(17) Proposed post-injection site care and site closure plan required by 

§146.93(a);

(18) Proposed emergency and remedial response plan required by §146.94(a); and

(19) A list of contacts, submitted to the Director, for those States, Tribes, and 

Territories identified to be within the area of review of the Class VI project based 

on information provided in paragraph (a)(2) of this section;

(20) Any other information requested by the Director. 

(b) The Director shall notify, in writing, any States, Tribes, or Territories within the area 

of review of the Class VI project based on information provided in paragraphs (a)(2) and 

(a)(19) of this section of the permit application and pursuant to the requirements at 

§145.23(f)(13) of this chapter.

(c) Prior to granting approval for the operation of a Class VI well, the Director shall 

consider the following information:

(1) The final area of review based on modeling, using data obtained during 

logging and testing of the well and the formation as required by paragraphs (c)(2), 

(3), (4), (6), (7), and (10) of this section; 
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(2) Any relevant updates, based on data obtained during logging and testing of the 

well and the formation as required by paragraphs (c)(3), (4), (6), (7), and (10) of 

this section, to the information on the geologic structure and hydrogeologic 

properties of the proposed storage site and overlying formations, submitted to 

satisfy the requirements of paragraph (a)(3) of this section; 

(3) Information on the compatibility of the carbon dioxide stream with fluids in 

the injection zone(s) and minerals in both the injection and the confining zone(s), 

based on the results of the formation testing program, and with the materials used 

to construct the well; 

(4) The results of the formation testing program required at paragraph (a)(8) of 

this section;

(5) Final injection well construction procedures that meet the requirements of 

§146.86;

(6) The status of corrective action on wells in the area of review; 

(7) All available logging and testing program data on the well required by 

§146.87;

(8) A demonstration of mechanical integrity pursuant to §146.89;

(9) Any updates to the proposed area of review and corrective action plan, testing 

and monitoring plan, injection well plugging plan, post-injection site care and site 

closure plan, or the emergency and remedial response plan submitted under 

paragraph (a) of this section, which are necessary to address new information 

collected during logging and testing of the well and the formation as required by 

all paragraphs of this section; and
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(10) Any other information requested by the Director.

(d) Owners or operators seeking a waiver of the requirement to inject below the 

lowermost USDW must also refer to §146.95 and submit a supplemental report, as 

required at §146.95(a). The supplemental report is not part of the permit application. 

§146.83 Minimum criteria for siting.

(a) Owners or operators of Class VI wells must demonstrate to the satisfaction of the 

Director that the wells will be sited in areas with a suitable geologic system. The owners 

or operators must demonstrate that the geologic system comprises: 

(1) An injection zone(s) of sufficient areal extent, thickness, porosity, and 

permeability to receive the total anticipated volume of the carbon dioxide stream;

(2) Confining zone(s) free of transmissive faults or fractures and of sufficient 

areal extent and integrity to contain the injected carbon dioxide stream and 

displaced formation fluids and allow injection at proposed maximum pressures 

and volumes without initiating or propagating fractures in the confining zone(s).

(b) The Director may require owners or operators of Class VI wells to identify and 

characterize additional zones that will impede vertical fluid movement, are free of faults 

and fractures that may interfere with containment, allow for pressure dissipation, and 

provide additional opportunities for monitoring, mitigation, and remediation. 

§146.84 Area of review and corrective action. 
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(a) The area of review is 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 is based on available site 

characterization, monitoring, and operational data. 

(b) The owner or operator of a Class VI well must prepare, maintain, and comply with a 

plan to delineate the area of review for a proposed geologic sequestration project, 

periodically reevaluate the delineation, and perform corrective action that meets the 

requirements of this section and is acceptable to the Director. The requirement to 

maintain and implement an approved plan is directly enforceable regardless of whether 

the requirement is a condition of the permit. As a part of the permit application for 

approval by the Director, the owner or operator must submit an area of review and 

corrective action plan that includes the following information:

(1) The method for delineating the area of review that meets the requirements of 

paragraph (c) of this section, including the model to be used, assumptions that 

will be made, and the site characterization data on which the model will be based; 

(2) A description of:

(i) The minimum fixed frequency, not to exceed five years, at which the 

owner or operator proposes to reevaluate the area of review;

(ii) The monitoring and operational conditions that would warrant a 

reevaluation of the area of review prior to the next scheduled reevaluation 
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as determined by the minimum fixed frequency established in paragraph 

(b)(2)(i) of this section.

(iii) How monitoring and operational data (e.g., injection rate and 

pressure) will be used to inform an area of review reevaluation; and

(iv) How corrective action will be conducted to meet the requirements of 

paragraph (d) of this section, including what corrective action will be 

performed prior to injection and what, if any, portions of the area of 

review will have corrective action addressed on a phased basis and how 

the phasing will be determined; how corrective action will be adjusted if 

there are changes in the area of review; and how site access will be 

guaranteed for future corrective action.

(c) Owners or operators of Class VI wells must perform the following actions to 

delineate the area of review and identify all wells that require corrective action:

(1) Predict, using existing site characterization, monitoring and operational data,

and computational modeling, the projected lateral and vertical migration of the 

carbon dioxide plume and formation fluids in the subsurface from the 

commencement of injection activities until the plume movement ceases, until 

pressure differentials sufficient to cause the movement of injected fluids or 

formation fluids into a USDW are no longer present, or until the end of a fixed 

time period as determined by the Director. The model must:

(i) Be based on detailed geologic data collected to characterize the 

injection zone(s), confining zone(s) and any additional zones; and 
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anticipated operating data, including injection pressures, rates, and total 

volumes over the proposed life of the geologic sequestration project;

(ii) Take into account any geologic heterogeneities, other discontinuities, 

data quality, and their possible impact on model predictions; and

(iii) Consider potential migration through faults, fractures, and artificial 

penetrations.

(2) Using methods approved by the Director, identify all penetrations, including 

active and abandoned wells and underground mines, in the area of review that 

may penetrate the confining zone(s). Provide a description of each well’s type, 

construction, date drilled, location, depth, record of plugging and/or completion, 

and any additional information the Director may require; and 

(3) Determine which abandoned wells in the area of review have been plugged in 

a manner that prevents the movement of carbon dioxide or other fluids that may 

endanger USDWs, including use of materials compatible with the carbon dioxide 

stream.

(d) Owners or operators of Class VI wells must perform corrective action on all wells in 

the area of review that are determined to need corrective action, using methods designed 

to prevent the movement of fluid into or between USDWs, including use of materials 

compatible with the carbon dioxide stream, where appropriate. 

(e) At the minimum fixed frequency, not to exceed five years, as specified in the area of 

review and corrective action plan, or when monitoring and operational conditions 

warrant, owners or operators must: 

(1) Reevaluate the area of review in the same manner specified in paragraph 
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(c)(1) of this section;

(2) Identify all wells in the reevaluated area of review that require corrective 

action in the same manner specified in paragraph (c) of this section; 

(3) Perform corrective action on wells requiring corrective action in the 

reevaluated area of review in the same manner specified in paragraph (d) of 

this section; and

(4) Submit an amended area of review and corrective action plan or demonstrate 

to the Director through monitoring data and modeling results that no 

amendment to the area of review and corrective action plan is needed. Any 

amendments to the area of review and corrective action plan must be approved 

by the Director, must be incorporated into the permit, and are subject to the 

permit modification requirements at §§144.39 or 144.41 of this chapter, as 

appropriate.

(f) The emergency and remedial response plan (as required by §146.94) and the

demonstration of financial responsibility (as described by §146.85) must account for the 

area of review delineated as specified in paragraph (c)(1) of this section or the most 

recently evaluated area of review delineated under paragraph (e) of this section, 

regardless of whether or not corrective action in the area of review is phased.

(g) All modeling inputs and data used to support area of review reevaluations under 

paragraph (e) of this section shall be retained for 10 years.

§146.85 Financial responsibility. 
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(a) The owner or operator must demonstrate and maintain financial responsibility as 

determined by the Director that meets the following conditions:

(1) The financial responsibility instrument(s) used must be from the following list 

of qualifying instruments: 

(i) Trust Funds

(ii) Surety Bonds

(iii) Letter of Credit

(iv) Insurance

(v) Self Insurance (i.e., Financial Test and Corporate Guarantee)

(vi) Escrow Account

(vii) Any other instrument(s) satisfactory to the Director

(2) The qualifying instrument(s) must be sufficient to cover the cost of:

(i) Corrective action (that meets the requirements of §146.84);

(ii) Injection well plugging (that meets the requirements of §146.92);

(iii) Post injection site care and site closure (that meets the requirements of 

§146.93); and 

(iv) Emergency and remedial response (that meets the requirements of 

§146.94).

(3) The financial responsibility instrument(s) must be sufficient to address 

endangerment of underground sources of drinking water. 

(4) The qualifying financial responsibility instrument(s) must comprise protective 

conditions of coverage.
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(i) Protective conditions of coverage must include at a minimum 

cancellation, renewal, and continuation provisions, specifications on when 

the provider becomes liable in case of cancellation if there is a failure to 

renew with a new qualifying financial instrument, and requirements for 

the provider to meet a minimum rating, minimum capitalization, and 

ability to pass the bond rating when applicable. 

(A) Cancellation – for purposes of this part, an owner or operator must 

provide that their financial mechanism may not cancel, terminate or fail to 

renew except for failure to pay such financial instrument. If there is a 

failure to pay the financial instrument, the financial institution may elect to 

cancel, terminate, or fail to renew the instrument by sending notice by 

certified mail to the owner or operator and the Director. The cancellation 

must not be final for 120 days after receipt of cancellation notice. The 

owner or operator must provide an alternate financial responsibility 

demonstration within 60 days of notice of cancellation, and if an alternate 

financial responsibility demonstration is not acceptable (or possible), any 

funds from the instrument being cancelled should be released within 60 

days of notification by the Director.

(B) Renewal – for purposes of this part, owners or operators must renew 

all financial instruments, if an instrument expires, for the entire term of the 

geologic sequestration project. The instrument may be automatically 

renewed as long as the owner or operator has the option of renewal at the 

face amount of the expiring instrument. The automatic renewal of the 
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instrument must, at a minimum, provide the holder with the option of 

renewal at the face amount of the expiring financial instrument. 

(C) Cancellation, termination, or failure to renew may not occur and the 

financial instrument will remain in full force and effect in the event that on 

or before the date of expiration: the Director deems the facility abandoned; 

or the permit is terminated or revoked or a new permit is denied; or 

closure is ordered by the Director or a U.S. district court or other court of 

competent jurisdiction; or the owner or operator is named as debtor in a 

voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. 

Code; or the amount due is paid.

(5) The qualifying financial responsibility instrument(s) must be approved by the 

Director. 

(i) The Director shall consider and approve the financial responsibility 

demonstration for all the phases of the geologic sequestration project prior to 

issue a Class VI permit (§146.82).

(ii) The owner or operator must provide any updated information related 

to their financial responsibility instrument(s) on and annual basis and if there are 

any changes, the Director must evaluate, within a reasonable time, the financial 

responsibility demonstration to confirm that the instrument(s) used remain 

adequate for use. The owner or operator must maintain financial responsibility 

requirements regardless of the status of the Director’s review of the financial 

responsibility demonstration.
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(iii) The Director may disapprove the use of a financial instrument if he 

determines that it is not sufficient to meet the requirements of this section.

(6) The owner or operator may demonstrate financial responsibility by using one 

or multiple qualifying financial instruments for specific phases of the geologic 

sequestration project. 

(i) In the event that the owner or operator combines more than one 

instrument for a specific geologic sequestration phase (e.g., well plugging), such 

combination must be limited to instruments that are not based on financial 

strength or performance (i.e., self insurance or performance bond), for example 

trust funds, surety bonds guaranteeing payment into a trust fund, letters of credit, 

escrow account, and insurance. In this case, it is the combination of mechanisms, 

rather than the single mechanism, which must provide financial responsibility for 

an amount at least equal to the current cost estimate. 

(ii) When using a third-party instrument to demonstrate financial 

responsibility, the owner or operator must provide a proof that the third-party 

providers either have passed financial strength requirements based on credit 

ratings; or has met a minimum rating, minimum capitalization, and ability to pass 

the bond rating when applicable.

(iii) An owner or operator using a third party instrument must establish a 

standby trust to enable EPA to be party to the financial responsibility agreement 

without EPA being the beneficiary of any funds. The standby trust funds must be 

used along with other financial responsibility instruments (e.g., surety bonds, 
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letters of credit, or escrow accounts) to provide a location to place funds if 

needed.

(iv) An owner or operator may deposit money to an escrow account to 

cover financial responsibility requirements; this account must segregate funds 

sufficient to cover estimated costs for Class VI (geologic sequestration) financial 

responsibility from other accounts and uses. 

(v) An owner or operator or its guarantor may use self insurance to 

demonstrate financial responsibility for geologic sequestration projects. In order 

to satisfy this requirement the owner or operator must meet a Tangible Net Worth 

of an amount approved by the Director, have a Net working capital and tangible 

net worth each at least six times the sum of the current well plugging, post 

injection site care and site closure cost, have assets located in the United States 

amounting to at least 90 percent of total assets or at least six times the sum of the 

current well plugging, post injection site care and site closure cost, and must 

submit a report of its bond rating and financial information annually. In addition 

the owner or operator must either: have a bond rating test of AAA, AA, A, or 

BBB as issued by Standard & Poor’s or Aaa, Aa, A, or Baa as issued by Moody’s; 

or meet all of the following five financial ratio thresholds: a ratio of total 

liabilities to net worth less than 2.0; a ratio of current assets to current liabilities 

greater than 1.5; a ratio of the sum of net income plus depreciation, depletion, and 

amortization to total liabilities greater than 0.1; a ratio of current assets minus 

current liabilities to total assets greater than -0.1; and a net profit (revenues minus 

expenses) greater than 0.
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(vi) An owner or operator who is not able to meet corporate financial test 

criteria may arrange a corporate guarantee by demonstrating that its corporate 

parent meets the financial test requirements on its behalf. The parent’s 

demonstration that it meets the financial test requirement is insufficient if it has 

not also guaranteed to fulfill the obligations for the owner or operator. 

(vii) An owner or operator may obtain an insurance policy to cover the 

estimated costs of geologic sequestration activities requiring financial 

responsibility. This insurance policy must be obtained from a third party provider.

(b) The requirement to maintain adequate financial responsibility and resources is 

directly enforceable regardless of whether the requirement is a condition of the permit. 

(1) The owner or operator must maintain financial responsibility and resources 

until:

(i) The Director receives and approves the completed post-injection site 

care and site closure plan; and 

(ii) The Director approves site closure.

(2) The owner or operator may be released from a financial instrument in the 

following circumstances:

(i) The owner or operator has completed the phase of the geologic 

sequestration project for which the financial instrument was required and has 

fulfilled all its financial obligations as determined by the Director, including 

obtaining financial responsibility for the next phase of the GS project, if required; 

or
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(ii) The owner or operator has submitted a replacement financial 

instrument and received written approval from the Director accepting the new 

financial instrument and releasing the owner or operator from the previous 

financial instrument. 

(c) The owner or operator must have a detailed written estimate, in current dollars, of the 

cost of performing corrective action on wells in the area of review, plugging the injection 

well(s), post-injection site care and site closure, and emergency and remedial response. 

(1) The cost estimate must be performed for each phase separately and must be 

based on the costs to the regulatory agency of hiring a third party to perform the 

required activities. A third party is a party who is not within the corporate 

structure of the owner or operator. 

(2) During the active life of the geologic sequestration project, the owner or 

operator must adjust the cost estimate for inflation within 60 days prior to the 

anniversary date of the establishment of the financial instrument(s) used to 

comply with paragraph (a) of this section. The owner or operator must also 

provide to the Director written updates of adjustments to the cost estimate within 

60 days of any amendments to the area of review and corrective action plan 

(§146.84), the injection well plugging plan (§146.92), the post-injection site care 

and site closure plan (§146.93), and the emergency and remedial response plan 

(§146.94). 

(3) The Director must approve any decrease or increase to the initial cost estimate. 

During the active life of the geologic sequestration project, the owner or operator 

must revise the cost estimate no later than 60 days after the Director has approved 
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the request to modify the area of review and corrective action plan (§146.84), the 

injection well plugging plan (§146.92), the post-injection site care and site closure 

plan (§146.93), and the emergency and response plan (§146.94), if the change in 

the plan increases the cost. If the change to the plans decreases the cost, any 

withdrawal of funds must be approved by the Director. Any decrease to the value 

of the financial assurance instrument must first be approved by the Director. The 

revised cost estimate must be adjusted for inflation as specified at paragraph 

(c)(2) of this section. 

(4) Whenever the current cost estimate increases to an amount greater than the 

face amount of a financial instrument currently in use, the owner or operator, 

within 60 days after the increase, must either cause the face amount to be 

increased to an amount at least equal to the current cost estimate and submit 

evidence of such increase to the Director, or obtain other financial responsibility 

instruments to cover the increase. Whenever the current cost estimate decreases, 

the face amount of the financial assurance instrument may be reduced to the 

amount of the current cost estimate only after the owner or operator has received 

written approval from the Director. 

(d) The owner or operator must notify the Director by certified mail of adverse financial 

conditions such as bankruptcy that may affect the ability to carry out injection well 

plugging and post-injection site care and site closure. 

(1) In the event that the owner or operator or the third party provider of a financial 

responsibility instrument is going through a bankruptcy, the owner or operator 

must notify the Director by certified mail of the commencement of a voluntary or 
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involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the 

owner or operator as debtor, within 10 days after commencement of the 

proceeding. 

(2) A guarantor of a corporate guarantee must make such a notification to the 

Director if he/she is named as debtor, as required under the terms of the corporate 

guarantee.

(3) An owner or operator who fulfills the requirements of paragraph (a) of this 

section by obtaining a trust fund, surety bond, letter of credit, escrow account, or 

insurance policy will be deemed to be without the required financial assurance in 

the event of bankruptcy of the trustee or issuing institution, or a suspension or 

revocation of the authority of the trustee institution to act as trustee of the 

institution issuing the trust fund, surety bond, letter of credit, escrow account, or 

insurance policy. The owner or operator must establish other financial assurance 

within 60 days after such an event.

(e) The owner or operator must provide an adjustment of the cost estimate to the Director 

within 60 days of notification by the Director, if the Director determines during the 

annual evaluation of the qualifying financial responsibility instrument(s) that the most 

recent demonstration is no longer adequate to cover the cost of corrective action (as 

required by §146.84), injection well plugging (as required by §146.92), post-injection site 

care and site closure (as required by §146.93), and emergency and remedial response (as 

required by §146.94).

(f) The Director must approve the use and length of pay-in-periods for trust funds or 

escrow accounts. 
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§146.86 Injection well construction requirements. 

(a) General. The owner or operator must ensure that all Class VI wells are constructed 

and completed to:

(1) Prevent the movement of fluids into or between USDWs or into any 

unauthorized zones;

(2) Permit the use of appropriate testing devices and workover tools; and

(3) Permit continuous monitoring of the annulus space between the injection 

tubing and long string casing.

(b) Casing and Cementing of Class VI Wells.

(1) Casing and cement or other materials used in the construction of each Class 

VI well must have sufficient structural strength and be designed for the life of the 

geologic sequestration project. All well materials must be compatible with fluids 

with which the materials may be expected to come into contact and must meet or 

exceed standards developed for such materials by the American Petroleum 

Institute, ASTM International, or comparable standards acceptable to the Director. 

The casing and cementing program must be designed to prevent the movement of 

fluids into or between USDWs. In order to allow the Director to determine and 

specify casing and cementing requirements, the owner or operator must provide 

the following information:

(i) Depth to the injection zone(s);

(ii) Injection pressure, external pressure, internal pressure, and axial 

loading;
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(iii) Hole size;

(iv) Size and grade of all casing strings (wall thickness, external diameter, 

nominal weight, length, joint specification, and construction material);

(v) Corrosiveness of the carbon dioxide stream and formation fluids;

(vi) Down-hole temperatures;

(vii) Lithology of injection and confining zone(s);

(viii) Type or grade of cement and cement additives; and

(ix) Quantity, chemical composition, and temperature of the carbon 

dioxide stream.

(2) Surface casing must extend through the base of the lowermost USDW and be 

cemented to the surface through the use of a single or multiple strings of casing 

and cement. 

(3) At least one long string casing, using a sufficient number of centralizers, must 

extend to the injection zone and must be cemented by circulating cement to the 

surface in one or more stages. 

(4) Circulation of cement may be accomplished by staging. The Director may 

approve an alternative method of cementing in cases where the cement cannot be 

recirculated to the surface, provided the owner or operator can demonstrate by 

using logs that the cement does not allow fluid movement behind the well bore.

(5) Cement and cement additives must be compatible with the carbon dioxide 

stream and formation fluids and of sufficient quality and quantity to maintain 

integrity over the design life of the geologic sequestration project. The integrity 

and location of the cement shall be verified using technology capable of 
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evaluating cement quality radially and identifying the location of channels to 

ensure that USDWs are not endangered.

(c) Tubing and packer.

(1) Tubing and packer materials used in the construction of each Class VI well 

must be compatible with fluids with which the materials may be expected to come 

into contact and must meet or exceed standards developed for such materials by 

the American Petroleum Institute, ASTM International, or comparable standards 

acceptable to the Director.

(2) All owners or operators of Class VI wells must inject fluids through tubing 

with a packer set at a depth opposite a cemented interval at the location approved 

by the Director. 

(3) In order for the Director to determine and specify requirements for tubing and 

packer, the owner or operator must submit the following information:

(i) Depth of setting;

(ii) Characteristics of the carbon dioxide stream (chemical content, 

corrosiveness, temperature, and density) and formation fluids;

(iii) Maximum proposed injection pressure;

(iv) Maximum proposed annular pressure;

(v) Proposed injection rate (intermittent or continuous) and volume and/or 

mass of the carbon dioxide stream;

(vi) Size of tubing and casing; and

(vii) Tubing tensile, burst, and collapse strengths.
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§146.87 Logging, sampling, and testing prior to injection well operation.

(a) During the drilling and construction of a Class VI injection well, the owner or 

operator must run appropriate logs, surveys and tests to determine or verify the depth, 

thickness, porosity, permeability, and lithology of, and the salinity of any formation 

fluids in all relevant geologic formations to ensure conformance with the injection well 

construction requirements under §146.86 and to establish accurate baseline data against 

which future measurements may be compared. The owner or operator must submit to the 

Director a descriptive report prepared by a knowledgeable log analyst that includes an 

interpretation of the results of such logs and tests. At a minimum, such logs and tests 

must include:

(1) Deviation checks during drilling on all holes constructed by drilling a pilot 

hole which is enlarged by reaming or another method. Such checks must be at 

sufficiently frequent intervals to determine the location of the borehole and to 

ensure that vertical avenues for fluid movement in the form of diverging holes are 

not created during drilling; and

(2) Before and upon installation of the surface casing:

(i) Resistivity, spontaneous potential, and caliper logs before the casing is 

installed; and

(ii) A cement bond and variable density log to evaluate cement quality 

radially, and a temperature log after the casing is set and cemented.

(3) Before and upon installation of the long string casing:
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(i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, 

fracture finder logs, and any other logs the Director requires for the given 

geology before the casing is installed; and

(ii) A cement bond and variable density log, and a temperature log after 

the casing is set and cemented.

(4) A series of tests designed to demonstrate the internal and external mechanical 

integrity of injection wells, which may include:

(i) A pressure test with liquid or gas;

(ii) A tracer survey such as oxygen-activation logging;

(iii) A temperature or noise log;

(iv) A casing inspection log; and

(5) Any alternative methods that provide equivalent or better information and that 

are required by and/or approved of by the Director. 

(b) The owner or operator must take whole cores or sidewall cores of the injection zone 

and confining system and formation fluid samples from the injection zone(s), and must 

submit to the Director a detailed report prepared by a log analyst that includes: well log 

analyses (including well logs), core analyses, and formation fluid sample information.

The Director may accept information on cores from nearby wells if the owner or operator 

can demonstrate that core retrieval is not possible and that such cores are representative 

of conditions at the well. The Director may require the owner or operator to core other 

formations in the borehole.

(c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir 

pressure, and static fluid level of the injection zone(s).
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(d) At a minimum, the owner or operator must determine or calculate the following 

information concerning the injection and confining zone(s):

(1) Fracture pressure;

(2) Other physical and chemical characteristics of the injection and confining 

zone(s); and

(3) Physical and chemical characteristics of the formation fluids in the injection 

zone(s).

(e) Upon completion, but prior to operation, the owner or operator must conduct the 

following tests to verify hydrogeologic characteristics of the injection zone(s):

(1) A pressure fall-off test; and,

(2) A pump test; or

(3) Injectivity tests.

(f) The owner or operator must provide the Director with the opportunity to witness all 

logging and testing by this subpart. The owner or operator must submit a schedule of 

such activities to the Director 30 days prior to conducting the first test and submit any 

changes to the schedule 30 days prior to the next scheduled test.

§146.88 Injection well operating requirements.

(a) Except during stimulation, the owner or operator must ensure that injection pressure 

does not exceed 90 percent of the fracture pressure of the injection zone(s) so as to ensure 

that the injection does not initiate new fractures or propagate existing fractures in the 
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injection zone(s). In no case may injection pressure initiate fractures in the confining 

zone(s) or cause the movement of injection or formation fluids that endangers a USDW. 

(b) Injection between the outermost casing protecting USDWs and the well bore is 

prohibited.

(c) The owner or operator must fill the annulus between the tubing and the long string 

casing with a non-corrosive fluid approved by the Director. The owner or operator must 

maintain on the annulus a pressure that exceeds the operating injection pressure, unless 

the Director determines that such requirement might harm the integrity of the well or 

endanger USDWs. 

(d) Other than during periods of well workover (maintenance) approved by the Director 

in which the sealed tubing-casing annulus is disassembled for maintenance or corrective 

procedures, the owner or operator must maintain mechanical integrity of the injection 

well at all times.

(e) The owner or operator must install and use:

(1) Continuous recording devices to monitor: the injection pressure; the rate, 

volume and/or mass, and temperature of the carbon dioxide stream; and the 

pressure on the annulus between the tubing and the long string casing and annulus 

fluid volume; and

(2) Alarms and automatic surface shut-off systems or, at the discretion of the 

Director, down-hole shut-off systems (e.g., automatic shut-off check valves) for 

onshore wells or, other mechanical devices that provide equivalent protection; and

(3) Alarms and automatic down-hole shut-off systems for wells located offshore 

but within State territorial waters, designed to alert the operator and shut-in the 
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well when operating parameters such as annulus pressure, injection rate, or other 

parameters diverge beyond permitted ranges and/or gradients specified in the 

permit.

(f) If a shutdown (i.e., down-hole or at the surface) is triggered or a loss of mechanical 

integrity is discovered, the owner or operator must immediately investigate and identify 

as expeditiously as possible the cause of the shutoff. If, upon such investigation, the well 

appears to be lacking mechanical integrity, or if monitoring required under paragraph (e) 

of this section otherwise indicates that the well may be lacking mechanical integrity, the 

owner or operator must:

(1) Immediately cease injection;

(2) Take all steps reasonably necessary to determine whether there may have been 

a release of the injected carbon dioxide stream or formation fluids into any 

unauthorized zone;

(3) Notify the Director within 24 hours;

(4) Restore and demonstrate mechanical integrity to the satisfaction of the 

Director prior to resuming injection; and

(5) Notify the Director when injection can be expected to resume.

§146.89 Mechanical integrity.

(a) A Class VI well has mechanical integrity if:

(1) There is no significant leak in the casing, tubing, or packer; and
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(2) There is no significant fluid movement into a USDW through channels 

adjacent to the injection well bore.

(b) To evaluate the absence of significant leaks under paragraph (a)(1) of this section, owners 

or operators must, following an initial annulus pressure test, continuously monitor injection 

pressure, rate, injected volumes; pressure on the annulus between tubing and long-string 

casing; and annulus fluid volume as specified in §146.88 (e); 

(c) At least once per year, the owner or operator must use one of the following methods 

to determine the absence of significant fluid movement under paragraph (a)(2) of this 

section:

(1) An approved tracer survey such as an oxygen-activation log; or

(2) A temperature or noise log.

(d) If required by the Director, at a frequency specified in the testing and monitoring plan 

required at §146.90, the owner or operator must run a casing inspection log to determine 

the presence or absence of corrosion in the long-string casing. 

(e) The Director may require any other test to evaluate mechanical integrity under 

paragraphs (a)(1) or (a)(2) of this section. Also, the Director may allow the use of a test 

to demonstrate mechanical integrity other than those listed above with the written 

approval of the Administrator. To obtain approval for a new mechanical integrity test, the 

Director must submit a written request to the Administrator setting forth the proposed test 

and all technical data supporting its use. The Administrator may approve the request if he 
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or she determines that it will reliably demonstrate the mechanical integrity of wells for 

which its use is proposed. Any alternate method approved by the Administrator will be 

published in the Federal Register and may be used in all States in accordance with 

applicable State law unless its use is restricted at the time of approval by the 

Administrator. 

(f) In conducting and evaluating the tests enumerated in this section or others to be 

allowed by the Director, the owner or operator and the Director must apply methods and 

standards generally accepted in the industry. When the owner or operator reports the 

results of mechanical integrity tests to the Director, he/she shall include a description of 

the test(s) and the method(s) used. In making his/her evaluation, the Director must review 

monitoring and other test data submitted since the previous evaluation.

(g) The Director may require additional or alternative tests if the results presented by the 

owner or operator under paragraphs (a) through (d) of this section are not satisfactory to 

the Director to demonstrate that there is no significant leak in the casing, tubing, or 

packer, or to demonstrate that there is no significant movement of fluid into a USDW 

resulting from the injection activity as stated in paragraphs (a)(1) and (2) of this section.

§146.90 Testing and monitoring requirements. 

The owner or operator of a Class VI well must prepare, maintain, and comply with a 

testing and monitoring plan to verify that the geologic sequestration project is operating 

as permitted and is not endangering USDWs. The requirement to maintain and 

implement an approved plan is directly enforceable regardless of whether the requirement 
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is a condition of the permit. The testing and monitoring plan must be submitted with the 

permit application, for Director approval, and must include a description of how the 

owner or operator will meet the requirements of this section, including accessing sites for 

all necessary monitoring and testing during the life of the project. Testing and monitoring 

associated with geologic sequestration projects must, at a minimum, include:

(a) Analysis of the carbon dioxide stream with sufficient frequency to yield data 

representative of its chemical and physical characteristics; 

(b) Installation and use, except during well workovers as defined in §146.88(d), of 

continuous recording devices to monitor injection pressure, rate, and volume; the 

pressure on the annulus between the tubing and the long string casing; and the annulus 

fluid volume added;

(c) Corrosion monitoring of the well materials for loss of mass, thickness, cracking, 

pitting, and other signs of corrosion must be performed on a quarterly basis to ensure that 

the well components meet the minimum standards for material strength and performance 

set forth in §146.86(b), by:

(1) Analyzing coupons of the well construction materials placed in contact with 

the carbon dioxide stream; or

(2) Routing the carbon dioxide stream through a loop constructed with the 

material used in the well and inspecting the materials in the loop; or

(3) Using an alternative method approved by the Director;
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(d) Periodic monitoring of the ground water quality and geochemical changes above the 

confining zone(s) that may be a result of carbon dioxide movement through the confining 

zone(s) or additional identified zones including: 

(1) The location and number of monitoring wells based on specific information 

about the geologic sequestration project, including injection rate and volume, 

geology, the presence of artificial penetrations, and other factors; and

(2) The monitoring frequency and spatial distribution of monitoring wells based 

on baseline geochemical data that has been collected under §146.82(a)(6) and on 

any modeling results in the area of review evaluation required by §146.84(c).

(e) A demonstration of external mechanical integrity pursuant to §146.89(c) at least once 

per year until the injection well is plugged; and, if required by the Director, a casing

inspection log pursuant to requirements at §146.89(d) at a frequency established in the 

testing and monitoring plan; 

(f) A pressure fall-off test at least once every five years unless more frequent testing is 

required by the Director based on site-specific information;

(g) Testing and monitoring to track the extent of the carbon dioxide plume and the 

presence or absence of elevated pressure (e.g., the pressure front) by using:

(1) Direct methods in the injection zone(s); and,
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(2) Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys 

and/or down-hole carbon dioxide detection tools), unless the Director determines, 

based on site-specific geology, that such methods are not appropriate;

(h) The Director may require surface air monitoring and/or soil gas monitoring to detect 

movement of carbon dioxide that could endanger a USDW. 

(1) Design of Class VI surface air and/or soil gas monitoring must be based on 

potential risks to USDWs within the area of review;

(2) The monitoring frequency and spatial distribution of surface air monitoring 

and/or soil gas monitoring must be decided using baseline data, and the 

monitoring plan must describe how the proposed monitoring will yield useful 

information on the area of review delineation and/or compliance with standards 

under §144.12 of this chapter;

(3) If an owner or operator demonstrates that monitoring employed under 

§§98.440 to 98.449 of this chapter (Clean Air Act, 42 U.S.C. 7401 et seq.) 

accomplishes the goals of (h)(1) and (2) of this section, and meets the 

requirements pursuant to §146.91(c)(5), a Director that requires surface air/soil 

gas monitoring must approve the use of monitoring employed under §§98.440 to 

98.449 of this chapter. Compliance with §§98.440 to 98.449 of this chapter 

pursuant to this provision is considered a condition of the Class VI permit;

(i) Any additional monitoring, as required by the Director, necessary to support, upgrade, 

and improve computational modeling of the area of review evaluation required under 

§146.84(c) and to determine compliance with standards under §144.12 of this chapter; 
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(j) The owner or operator shall periodically review the testing and monitoring plan to 

incorporate monitoring data collected under this subpart, operational data collected under 

§146.88, and the most recent area of review reevaluation performed under §146.84(e). In 

no case shall the owner or operator review the testing and monitoring plan less often than 

once every five years. Based on this review, the owner or operator shall submit an 

amended testing and monitoring plan or demonstrate to the Director that no amendment 

to the testing and monitoring plan is needed. Any amendments to the testing and 

monitoring plan must be approved by the Director, must be incorporated into the permit, 

and are subject to the permit modification requirements at §§144.39 or 144.41 of this 

chapter, as appropriate. Amended plans or demonstrations shall be submitted to the 

Director as follows:

(1) Within one year of an area of review reevaluation; 

(2) Following any significant changes to the facility, such as addition of injection 

or monitoring wells, on a schedule determined by the Director; or 

(3) When required by the Director.

(k) A quality assurance and surveillance plan for all testing and monitoring requirements. 

§146.91 Reporting requirements.

The owner or operator must, at a minimum, provide, as specified in paragraph (e) of this 

section, the following reports to the Director, for each permitted Class VI well:

(a) Semi-annual reports containing:
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(1) Any changes to the physical, chemical, and other relevant characteristics of 

the carbon dioxide stream from the proposed operating data;

(2) Monthly average, maximum, and minimum values for injection pressure, flow 

rate and volume, and annular pressure; 

(3) A description of any event that exceeds operating parameters for annulus 

pressure or injection pressure specified in the permit;

(4) A description of any event which triggers a shut-off device required pursuant 

to §146.88(e) and the response taken;

(5) The monthly volume and/or mass of the carbon dioxide stream injected over 

the reporting period and the volume injected cumulatively over the life of the 

project;

(6) Monthly annulus fluid volume added; and 

(7) The results of monitoring prescribed under §146.90.

(b) Report, within 30 days, the results of:

(1) Periodic tests of mechanical integrity;

(2) Any well workover; and,

(3) Any other test of the injection well conducted by the permittee if required by 

the Director.
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(c) Report, within 24 hours of:

(1) Any evidence that the injected carbon dioxide stream or associated pressure 

front may cause an endangerment to a USDW; 

(2) Any noncompliance with a permit condition, or malfunction of the injection 

system, which may cause fluid migration into or between USDWs;

(3) Any triggering of a shut-off system (i.e., down-hole or at the surface);

(4) Any failure to maintain mechanical integrity; or.

(5) Pursuant to compliance with the requirement at §146.90(h) for surface air/soil 

gas monitoring or other monitoring technologies, if required by the Director, any 

release of carbon dioxide to the atmosphere or biosphere. 

(d) Owners or operators must notify the Director in writing 30 days in advance of:

(1) Any planned well workover; 

(2) Any planned stimulation activities, other than stimulation for formation testing 

conducted under §146.82; and

(3) Any other planned test of the injection well conducted by the permittee. 

(e) Regardless of whether a State has primary enforcement responsibility, owners or 

operators must submit all required reports, submittals, and notifications under subpart H 

of this part to EPA in an electronic format approved by EPA.
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(f) Records shall be retained by the owner or operator as follows:

(1) All data collected under §146.82 for Class VI permit applications shall be 

retained throughout the life of the geologic sequestration project and for 10 years 

following site closure.

(2) Data on the nature and composition of all injected fluids collected pursuant to 

§146.90(a) shall be retained until 10 years after site closure. The Director may 

require the owner or operator to deliver the records to the Director at the 

conclusion of the retention period. 

(3) Monitoring data collected pursuant to §146.90(b) through (i) shall be retained 

for 10 years after it is collected.

(4) The Director has authority to require the owner or operator to retain any 

records required in this subpart for longer than 10 years after site closure.

§146.92 Injection well plugging.

(a) Prior to the well plugging, the owner or operator must flush each Class VI injection 

well with a buffer fluid, determine bottomhole reservoir pressure, and perform a final 

external mechanical integrity test. 

(b) Well Plugging Plan. The owner or operator of a Class VI well must prepare, maintain, 

and comply with a plan that is acceptable to the Director. The requirement to maintain 

and implement an approved plan is directly enforceable regardless of whether the 

requirement is a condition of the permit. The well plugging plan must be submitted as 

part of the permit application and must include the following information:

(1) Appropriate tests or measures for determining bottomhole reservoir pressure;
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(2) Appropriate testing methods to ensure external mechanical integrity as 

specified in §146.89;

(3) The type and number of plugs to be used;

(4) The placement of each plug, including the elevation of the top and bottom of 

each plug;

(5) The type, grade, and quantity of material to be used in plugging. The material 

must be compatible with the carbon dioxide stream; and

(6) The method of placement of the plugs.

(c) Notice of intent to plug. The owner or operator must notify the Director in writing 

pursuant to §146.91(e), at least 60 days before plugging of a well. At this time, if any 

changes have been made to the original well plugging plan, the owner or operator must 

also provide the revised well plugging plan. The Director may allow for a shorter notice 

period. Any amendments to the injection well plugging plan must be approved by the 

Director, must be incorporated into the permit, and are subject to the permit modification 

requirements at §§144.39 or 144.41 of this chapter, as appropriate. 

(d) Plugging report. Within 60 days after plugging, the owner or operator must submit,

pursuant to §146.91(e), a plugging report to the Director. The report must be certified as 

accurate by the owner or operator and by the person who performed the plugging 

operation (if other than the owner or operator.) The owner or operator shall retain the 

well plugging report for 10 years following site closure.

§146.93 Post-injection site care and site closure.
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(a) The owner or operator of a Class VI well must prepare, maintain, and comply with a 

plan for post-injection site care and site closure that meets the requirements of paragraph 

(a)(2) of this section and is acceptable to the Director. The requirement to maintain and 

implement an approved plan is directly enforceable regardless of whether the requirement 

is a condition of the permit.

(1) The owner or operator must submit the post-injection site care and site closure 

plan as a part of the permit application to be approved by the Director. 

(2) The post-injection site care and site closure plan must include the following 

information:

(i) The pressure differential between pre-injection and predicted postinjection pressures in the injection zone(s);

(ii) The predicted position of the carbon dioxide plume and associated 

pressure front at site closure as demonstrated in the area of review 

evaluation required under §146.84(c)(1); 

(iii) A description of post-injection monitoring location, methods, and 

proposed frequency; and

(iv) A proposed schedule for submitting post-injection site care 

monitoring results to the Director pursuant to §146.91(e).

(3) Upon cessation of injection, owners or operators of Class VI wells must either 

submit an amended post-injection site care and site closure plan or demonstrate to 
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the Director through monitoring data and modeling results that no amendment to 

the plan is needed. Any amendments to the post-injection site care and site closure 

plan must be approved by the Director, be incorporated into the permit, and are 

subject to the permit modification requirements at §§144.39 or 144.41 of this 

chapter, as appropriate.

(4) At any time during the life of the geologic sequestration project, the owner or 

operator may modify and resubmit the post-injection site care and site closure 

plan for the Director’s approval within 30 days of such change. 

(b) The owner or operator shall monitor the site following the cessation of injection to 

show the position of the carbon dioxide plume and pressure front and demonstrate that 

USDWs are not being endangered. 

(1) The owner or operator shall continue to conduct monitoring as specified in the 

Director-approved post-injection site care and site closure plan for at least 50 

years following the cessation of injection, unless he/she makes a demonstration 

under (b)(2) of this section. At the Director’s discretion, the monitoring must 

continue until the geologic sequestration project no longer poses an endangerment 

to USDWs. 

(2) If the owner or operator can demonstrate to the satisfaction of the Director 

before 50 years, based on monitoring and other site-specific data, that the 

geologic sequestration project no longer poses an endangerment to USDWs, the 

Director may approve an amendment to the post-injection site care and site 
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closure plan to reduce the frequency of monitoring or may authorize site closure 

before the end of the 50-year period where he or she has substantial evidence that 

the geologic sequestration project no longer poses a risk of endangerment to 

USDWs.

(3) Prior to authorization for site closure, the owner or operator must submit to the 

Director a demonstration, based on monitoring and other site-specific data, that no 

additional monitoring is needed to ensure that the geologic sequestration project 

does not pose an endangerment to USDWs. 

(4) If the demonstration in paragraph (b)(3) of this section cannot be made (i.e., 

additional monitoring is needed to ensure that the geologic sequestration project 

does not pose an endangerment to USDWs) at the end of the 50-year period, the 

owner or operator must submit to the Director a plan to continue post-injection 

site care until a demonstration can be made. 

(c) Notice of intent for site closure. The owner or operator must notify the Director in 

writing at least 120 days before site closure. At this time, if any changes have been made 

to the original post-injection site care and site closure plan, the owner or operator must 

also provide the revised plan. The Director may allow for a shorter notice period.

(d) After the Director has authorized site closure, the owner or operator must plug all 

monitoring wells in a manner which will not allow movement of injection or formation 

fluids that endangers a USDW.
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(e) The owner or operator must submit a site closure report to the Director within 90 days 

of site closure, which must thereafter be retained at a location designated by the Director 

for 10 years. The report must include:

(1) Documentation of appropriate injection and monitoring well plugging as 

specified in §146.92 and paragraph (d) of this section. The owner or operator 

must provide a copy of a survey plat which has been submitted to the local zoning 

authority designated by the Director. The plat must indicate the location of the 

injection well relative to permanently surveyed benchmarks. The owner or 

operator must also submit a copy of the plat to the Regional Administrator of the 

appropriate EPA Regional Office;

(2) Documentation of appropriate notification and information to such State, local 

and Tribal authorities that have authority over drilling activities to enable such 

State, local, and Tribal authorities to impose appropriate conditions on subsequent 

drilling activities that may penetrate the injection and confining zone(s); and

(3) Records reflecting the nature, composition, and volume of the carbon dioxide 

stream.

(f) Each owner or operator of a Class VI injection well must record a notation on the deed 

to the facility property or any other document that is normally examined during title 

search that will in perpetuity provide any potential purchaser of the property the 

following information:

(1) The fact that land has been used to sequester carbon dioxide;
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(2) The name of the State agency, local authority, and/or Tribe with which the 

survey plat was filed, as well as the address of the Environmental Protection 

Agency Regional Office to which it was submitted; and

(3) The volume of fluid injected, the injection zone or zones into which it was 

injected, and the period over which injection occurred. 

(g) The owner or operator must retain for 10 years following site closure, records 

collected during the post-injection site care period. The owner or operator must deliver 

the records to the Director at the conclusion of the retention period, and the records must 

thereafter be retained at a location designated by the Director for that purpose.

§146.94 Emergency and remedial response.

(a) As part of the permit application, the owner or operator must provide the Director 

with an emergency and remedial response plan that describes actions the owner or 

operator must take to address movement of the injection or formation fluids that may 

cause an endangerment to a USDW during construction, operation, and post-injection site 

care periods. The requirement to maintain and implement an approved plan is directly 

enforceable regardless of whether the requirement is a condition of the permit.

(b) If the owner or operator obtains evidence that the injected carbon dioxide stream and 

associated pressure front may cause an endangerment to a USDW, the owner or operator 

must:

(1) Immediately cease injection;
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(2) Take all steps reasonably necessary to identify and characterize any release;

(3) Notify the Director within 24 hours; and 

(4) Implement the emergency and remedial response plan approved by the 

Director.

(c) The Director may allow the operator to resume injection prior to remediation if the 

owner or operator demonstrates that the injection operation will not endanger USDWs.

(d) The owner or operator shall periodically review the emergency and remedial response 

plan developed under paragraph (a) of this section. In no case shall the owner or operator 

review the emergency and remedial response plan less often than once every five years. 

Based on this review, the owner or operator shall submit an amended emergency and 

remedial response plan or demonstrate to the Director that no amendment to the 

emergency and remedial response plan is needed. Any amendments to the emergency and 

remedial response plan must be approved by the Director, must be incorporated into the 

permit, and are subject to the permit modification requirements at §§144.39 or 144.41 of 

this chapter, as appropriate. Amended plans or demonstrations shall be submitted to the 

Director as follows:

(1) Within one year of an area of review reevaluation; 

(2) Following any significant changes to the facility, such as addition of injection 

or monitoring wells, on a schedule determined by the Director; or 

(3) When required by the Director.
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§146.95 Class VI injection depth waiver requirements.

This section sets forth information which an owner or operator seeking a waiver of the 

Class VI injection depth requirements must submit to the Director; information the 

Director must consider in consultation with all affected Public Water System Supervision 

Directors; the procedure for Director – Regional Administrator communication and 

waiver issuance; and the additional requirements that apply to owners or operators of 

Class VI wells granted a waiver of the injection depth requirements. 

(a) In seeking a waiver of the requirement to inject below the lowermost USDW, the 

owner or operator must submit a supplemental report concurrent with permit application. 

The supplemental report must include the following, 

(1) A demonstration that the injection zone(s) is/are laterally continuous, is not a 

USDW, and is not hydraulically connected to USDWs; does not outcrop; has 

adequate injectivity, volume, and sufficient porosity to safely contain the injected 

carbon dioxide and formation fluids; and has appropriate geochemistry. 

(2) A demonstration that the injection zone(s) is/are bounded by laterally 

continuous, impermeable confining units above and below the injection zone(s)

adequate to prevent fluid movement and pressure buildup outside of the injection 

zone(s); and that the confining unit(s) is/are free of transmissive faults and 

fractures. The report shall further characterize the regional fracture properties and 

contain a demonstration that such fractures will not interfere with injection, serve 

as conduits, or endanger USDWs. 

(3) A demonstration, using computational modeling, that USDWs above and 

below the injection zone will not be endangered as a result of fluid movement. 
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This modeling should be conducted in conjunction with the area of review 

determination, as described in §146.84, and is subject to requirements, as 

described in §146.84(c), and periodic reevaluation, as described in §146.84(e).

(4) A demonstration that well design and construction, in conjunction with the 

waiver, will ensure isolation of the injectate in lieu of requirements at 

146.86(a)(1) and will meet well construction requirements in paragraph (f) of this 

section. 

(5) A description of how the monitoring and testing and any additional plans will 

be tailored to the geologic sequestration project to ensure protection of USDWs 

above and below the injection zone(s), if a waiver is granted. 

(6) Information on the location of all the public water supplies affected, 

reasonably likely to be affected, or served by USDWs in the area of review. 

(7) Any other information requested by the Director to inform the Regional 

Administrator’s decision to issue a waiver.

(b) To inform the Regional Administrator’s decision on whether to grant a waiver of the 

injection depth requirements at §§144.6 of this chapter, 146.5(f), and 146.86(a)(1), the 

Director must submit, to the Regional Administrator, documentation of the following :

(1) An evaluation of the following information as it relates to siting, construction, 

and operation of a geologic sequestration project with a waiver:

(i) The integrity of the upper and lower confining units;

(ii) The suitability of the injection zone(s) (e.g., lateral continuity; lack of 

transmissive faults and fractures; knowledge of current or planned 
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artificial penetrations into the injection zone(s) or formations below the 

injection zone);

(iii) The potential capacity of the geologic formation(s) to sequester 

carbon dioxide, accounting for the availability of alternative injection 

sites;

(iv) All other site characterization data, the proposed emergency and 

remedial response plan, and a demonstration of financial responsibility;

(v) Community needs, demands, and supply from drinking water 

resources;

(vi) Planned needs, potential and/or future use of USDWs and nonUSDWs in the area;

(vii) Planned or permitted water, hydrocarbon, or mineral resource 

exploitation potential of the proposed injection formation(s) and other 

formations both above and below the injection zone to determine if there 

are any plans to drill through the formation to access resources in or 

beneath the proposed injection zone(s)/formation(s);

(viii) The proposed plan for securing alternative resources or treating 

USDW formation waters in the event of contamination related to the Class 

VI injection activity; and,

(ix) Any other applicable considerations or information requested by the 

Director.
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(2) Consultation with the Public Water System Supervision Directors of all States 

and Tribes having jurisdiction over lands within the area of review of a well for 

which a waiver is sought.

(3) Any written waiver-related information submitted by the Public Water System 

Supervision Director(s) to the (UIC) Director. 

(c) Pursuant to requirements at §124.10 of this chapter and concurrent with the Class VI 

permit application notice process, the Director shall give public notice that a waiver 

application has been submitted. The notice shall clearly state:

(1) The depth of the proposed injection zone(s); 

(2) The location of the injection well(s);

(3) The name and depth of all USDWs within the area of review;

(4) A map of the area of review; 

(5) The names of any public water supplies affected, reasonably likely to be 

affected, or served by USDWs in the area of review; and,

(6) The results of UIC-Public Water System Supervision consultation required 

under paragraph (b)(2) of this section. 

(d) Following public notice, the Director shall provide all information received through 

the waiver application process to the Regional Administrator. Based on the information 

provided, the Regional Administrator shall provide written concurrence or nonconcurrence regarding waiver issuance. 

(1) If the Regional Administrator determines that additional information is 

required to support a decision, the Director shall provide the information. At his 
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or her discretion, the Regional Administrator may require that public notice of the 

new information be initiated. 

(2) In no case shall a Director of a State-approved program issue a waiver without 

receipt of written concurrence from the Regional Administrator.

(e) If a waiver is issued, within 30 days of waiver issuance, EPA shall post the following 

information on the Office of Water’s Web site:

(1) The depth of the proposed injection zone(s); 

(2) The location of the injection well(s);

(3) The name and depth of all USDWs within the area of review; 

(4) A map of the area of review; 

(5) The names of any public water supplies affected, reasonably likely to be 

affected, or served by USDWs in the area of review; and

(6) The date of waiver issuance.

(f) Upon receipt of a waiver of the requirement to inject below the lowermost USDW for 

geologic sequestration, the owner or operator of the Class VI well must comply with: 

(1) All requirements at §§146.84, 146.85, 146.87, 146.88, 146.89, 146.91, 146.92, 

and 146.94;

(2) All requirements at §146.86 with the following modified requirements:

(i) The owner or operator must ensure that Class VI wells with a waiver are

constructed and completed to prevent movement of fluids into any 

unauthorized zones including USDWs, in lieu of requirements at 

§146.86(a)(1).
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(ii) The casing and cementing program must be designed to prevent the 

movement of fluids into any unauthorized zones including USDWs in lieu of 

requirements at §146.86(b)(1).

(iii) The surface casing must extend through the base of the nearest USDW 

directly above the injection zone and be cemented to the surface; or, at the 

Director’s discretion, another formation above the injection zone and below 

the nearest USDW above the injection zone.

(3) All requirements at §146.90 with the following modified requirements: 

(i) The owner or operator shall monitor the groundwater quality, 

geochemical changes, and pressure in the first USDWs immediately above 

and below the injection zone(s); and in any other formations at the discretion 

of the Director. 

(ii) Testing and monitoring to track the extent of the carbon dioxide plume 

and the presence or absence of elevated pressure (e.g., the pressure front) by 

using direct methods to monitor for pressure changes in the injection zone(s);

and, indirect methods (e.g., seismic, electrical, gravity, or electromagnetic 

surveys and/or down-hole carbon dioxide detection tools), unless the Director 

determines, based on site-specific geology, that such methods are not 

appropriate.

(4) All requirements at §146.93 with the following, modified post-injection site 

care monitoring requirements:

(i) The owner or operator shall monitor the groundwater quality, 

geochemical changes and pressure in the first USDWs immediately above and 
Page 258 of 259

below the injection zone; and in any other formations at the discretion of the 

Director. 

(ii) Testing and monitoring to track the extent of the carbon dioxide plume 

and the presence or absence of elevated pressure (e.g., the pressure front) by 

using direct methods in the injection zone(s); and indirect methods (e.g., 

seismic, electrical, gravity, or electromagnetic surveys and/or down-hole 

carbon dioxide detection tools), unless the Director determines based on sitespecific geology, that such methods are not appropriate;

(5) Any additional requirements requested by the Director designed to ensure 

protection of USDWs above and below the injection zone(s). 

PART 147—STATE, TRIBAL, AND EPA-ADMINISTERED UNDERGROUND 

INJECTION CONTROL PROGRAMS

32. The authority citation for part 147 continues to read as follows:

Authority: 42, U.S.C. 300f et seq.; 42 U.S.C. 6901 et seq.

33. Section 147.1 is amended by adding paragraph (f) to read as follows:

§ 147.1 Purpose and scope.

* * * * *

(f) Class VI well owners or operators must comply with §146.91(e) notwithstanding any 

State program approvals. 
Page 259 of 259

Billing code 6560-50-P
Page 1 of 274

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 124, 144, 145, and 146

[EPA-HQ-OW-2008-0390 FRL-XXXX-X]

RIN 2040-AE98

Federal Requirements Under the Underground Injection Control (UIC) Program 

for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

SUMMARY: This action finalizes minimum Federal requirements under the Safe 

Drinking Water Act (SDWA) for underground injection of carbon dioxide (CO2) for the 

purpose of geologic sequestration (GS). GS is one of a portfolio of options that could be 

deployed to reduce CO2 emissions to the atmosphere and help to mitigate climate change. 

This final rule applies to owners or operators of wells that will be used to inject CO2 into 

the subsurface for the purpose of long-term storage. It establishes a new class of well, 

Class VI, and sets minimum technical criteria for the permitting, geologic site 

characterization, area of review (AoR) and corrective action, financial responsibility, well 

construction, operation, mechanical integrity testing (MIT), monitoring, well plugging, 

post-injection site care (PISC), and site closure of Class VI wells for the purposes of 

protecting underground sources of drinking water (USDWs). The elements of this 

rulemaking are based on the existing Underground Injection Control (UIC) regulatory 

framework, with modifications to address the unique nature of CO2 injection for GS. This 

rule will help ensure consistency in permitting underground injection of CO2 at GS 

operations across the United States and provide requirements to prevent endangerment of 

USDWs in anticipation of the eventual use of GS to reduce CO2 emissions to the 

atmosphere and to mitigate climate change. 

DATES: This regulation is effective [INSERT DATE 30 DAYS AFTER 

PUBLICATION OF THE RULE IN THE FEDERAL REGISTER]. For purposes of 

judicial review, this final rule is promulgated as of 1 p.m., Eastern time on [INSERT 

DATE TWO WEEKS AFTER THE DATE OF PUBLICATION OF THE RULE IN THE 

Deleted: 60 

Comment [A1]: OMB comment 10/27/10; Per 

Administrative Procedures Act 553(d).

Deleted: XX DAYS
Page 2 of 274

FEDERAL REGISTER], as provided in 40 CFR 23.7.

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

CO2 into the subsurface for the purposes of GS. Regulated categories and entities include, 

but are not limited to, the following:

------------------------------------------------------------------------

 Examples of regulated

 Category entities

------------------------------------------------------------------------
Page 3 of 274

Private................................... Owners or Operators of CO2 injection wells used 

for Class VI GS.

------------------------------------------------------------------------

Private................................... Owners or Operators of existing CO2 injection wells 

transitioning from Class I, II, or Class V injection 

activities to Class VI GS.

------------------------------------------------------------------------

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

CO2 Carbon Dioxide
Page 4 of 274

DOE United States Department of Energy

ECBM Enhanced Coal Bed Methane

EFAB Environmental Financial Advisory Board

EGR Enhanced Gas Recovery

EIS Environmental Impact Statement

EISA Energy Independence and Security Act of 2007

EO Executive Order

EOR Enhanced Oil Recovery

EPA United States Environmental Protection Agency

ER Enhanced Recovery

FPR Federally Permitted Releases

GAO General Accountability Office

GHG Greenhouse Gas

GS Geologic Sequestration

Gt CO2 Gigatons CO2

GWPC Ground Water Protection Council

HHS United States Department of Health and Human Services

ICR Information Collection Request

IOGCC Interstate Oil and Gas Compact Commission

IPCC Intergovernmental Panel on Climate Change

IRS United States Internal Revenue Service

LBNL Lawrence Berkeley National Laboratory

Mg/L Milligrams per liter
Page 5 of 274

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
Page 6 of 274

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
Page 7 of 274

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 
Page 8 of 274

differences in pressure or density.

Capillary force: adhesive force that holds a fluid in a capillary or a pore space. 

Capillary force is a function of the properties of the fluid, and surface and dimensions of 

the space. If the attraction between the fluid and surface is greater than the interaction of 

fluid molecules, the fluid will be held in place.

Caprock: see confining zone.

Carbon dioxide plume: the extent underground, in three dimensions, of an injected 

carbon dioxide stream.

Carbon dioxide (CO2) stream: carbon dioxide that has been captured from an 

emission source (e.g., a power plant), plus incidental associated substances derived from 

the source materials and the capture process, and any substances added to the stream to 

enable or improve the injection process. This subpart does not apply to any carbon 

dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261.

Casing: the pipe material placed inside a drilled hole to prevent the hole from 

collapsing. The two types of casing in most injection wells are 1) surface casing, the 

outer most casing that extends from the surface to the base of the lowermost USDW and 

2) long-string casing, which extends from the surface to or through the injection zone.

Cement: material used to support and seal the well casing to the rock formations 

exposed in the borehole. Cement also protects the casing from corrosion and prevents 

movement of injectate up the borehole. The composition of the cement may vary based 

on the well type and purpose; cement may contain latex, mineral blends, or epoxy.

Confining zone: a geologic formation, group of formations, or part of a formation 

stratigraphically overlying the injection zone(s) that acts as barrier to fluid movement. 

For Class VI wells operating under an injection depth waiver, confining zone means a 
Page 9 of 274

geologic formation, group of formations, or part of a formation stratigraphically 

overlying and underlying the injection zone(s).

Corrective action: the use of Director-approved methods to ensure that wells within 

the area of review do not serve as conduits for the movement of fluids into USDWs.

Corrosive: having the ability to wear away a material by chemical action. Carbon 

dioxide mixed with water forms carbonic acid, which can corrode well materials.

Dip: the angle between a planar feature, such as a sedimentary bed or a fault, and the 

horizontal plane. The dip of subsurface rock layers can provide clues as to whether 

injected fluids may be contained. 

Director: the person responsible for permitting, implementation, and compliance of 

the UIC program. For UIC programs administered by EPA, the Director is the EPA 

Regional Administrator or his/her delegatee; for UIC programs in Primacy States, the 

Director is the person responsible for permitting, implementation, and compliance of the 

State, Territorial, or Tribal UIC program.

Ductility: the ability of a material to sustain stress until it fractures. 

Enhanced Coal Bed Methane (ECBM) recovery: the process of injecting a gas (e.g., 

CO2) into coal, where it is adsorbed to the coal surface and methane is released. The 

methane can be captured and produced for economic purposes; when CO2 is injected, it 

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

Enhanced Oil or Gas Recovery (EOR/EGR): typically, the process of injecting a fluid 

(e.g., water, brine, or CO2) into an oil or gas bearing formation to recover residual oil or 

natural gas. The injected fluid thins (decreases the viscosity) and/or displaces extractable

oil and gas, which is then available for recovery. This is also used for secondary or 

tertiary recovery.

Deleted: small amounts of 

Comment [A2]: 

EPA deletion 11/12/10.

Deleted: known as

Comment [A3]: 

EPA deletion 11/12/10. 
Page 10 of 274

Flapper valve: a valve consisting of a hinged flapper that seals the valve orifice. In 

Class VI wells, flapper valves can engage to shut off the flow of the CO2 when 

acceptable operating parameters are exceeded.

Formation or geological formation: a layer of rock that is made up of a certain type of 

rock or a combination of types. 

Geologic sequestration (GS): the long-term containment of a gaseous, liquid or 

supercritical carbon dioxide stream in subsurface geologic formations. This term does not 

apply to CO2 capture or transport.

Geologic sequestration project: for the purpose of this regulation, an injection well or 

wells used to emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW; or, wells used for geologic sequestration of carbon dioxide that have 

been granted a waiver of the injection depth requirements pursuant to requirements at 

§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 

CO2 stream.

Injection zone: a geologic formation, group of formations, or part of a formation that 

is of sufficient areal extent, thickness, porosity, and permeability to receive CO2 through 

a well or wells associated with a geologic sequestration project.
Page 11 of 274

Lithology: the description of rocks, based on color, mineral composition and grain 

size.

Mechanical integrity (MI): The absence of significant leakage within the injection 

tubing, casing, or packer (known as internal mechanical integrity), or outside of the 

casing (known as external mechanical integrity). 

Mechanical Integrity Test: a test performed on a well to confirm that a well maintains 

internal and external mechanical integrity. MITs are a means of measuring the adequacy 

of the construction of an injection well and a way to detect problems within the well 

system.

Model: a representation or simulation of a phenomenon or process that is difficult to 

observe directly or that occurs over long time frames. Models that support GS can predict 

the flow of CO2 within the subsurface, accounting for the properties and fluid content of 

the subsurface formations and the effects of injection parameters.

Packer: a mechanical device that seals the outside of the tubing to the inside of the 

long string casing, isolating an annular space. 

Pinch-out: a situation where a formation thins to zero thickness.

Pore space: open spaces in rock or soil. These are filled with water or other fluids 

such as brine (i.e., salty fluid). CO2 injected into the subsurface can displace pre-existing 

fluids to occupy some of the pore spaces of the rocks in the injection zone.

Post-injection site care: appropriate monitoring and other actions (including 

corrective action) needed following cessation of injection to ensure that USDWs are not 

endangered, as required under §146.93.
Page 12 of 274

Pressure front: the zone of elevated pressure that is created by the injection of carbon 

dioxide into the subsurface. For GS projects, the pressure front of a CO2 plume refers to 

the zone where there is a pressure differential sufficient to cause the movement of 

injected fluids or formation fluids into a USDW.

Saline formations: subsurface geographically extensive sedimentary rock layers 

saturated with waters or brines that have a high total dissolved solids (TDS) content (i.e., 

over 10,000 mg/L TDS). 

Site closure: the point/time, as determined by the Director following the requirements 

under §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 (31.1o

C for CO2) and critical 

pressure (73.8 bar for CO2). Supercritical fluids have physical properties intermediate to 

those of gases and liquids. 

Total Dissolved Solids (TDS): the measurement, usually in mg/L, for the amount of 

all inorganic and organic substances suspended in liquid as molecules, ions, or granules. 

For injection operations, TDS typically refers to the saline (i.e., salt) content of watersaturated underground formations.

Transmissive fault or fracture: a fault or fracture that has sufficient permeability and 

vertical extent to allow fluids to move between formations.
Page 13 of 274

Trapping: the physical and geochemical processes by which injected CO2 is 

sequestered in the subsurface. Physical trapping occurs when buoyant CO2 rises in the 

formation until it reaches a layer that inhibits further upward migration or is immobilized 

in pore spaces due to capillary forces. Geochemical trapping occurs when chemical 

reactions between dissolved CO2 and minerals in the formation lead to the precipitation 

of solid carbonate minerals.

Underground Source of Drinking Water (USDW): an aquifer or portion of an aquifer 

that supplies any public water system or that contains a sufficient quantity of ground 

water to supply a public water system, and currently supplies drinking water for human 

consumption, or that contains fewer than 10,000 mg/l total dissolved solids and is not an 

exempted aquifer.

Viscosity: the property of a fluid or semi-fluid that offers resistance to flow. As a 

supercritical fluid, CO2 is less viscous than water and brine. 

Table of Contents

I. General Information

II. Background

A. Why is EPA Taking This Regulatory Action?

1. What is GS? 

2. Why is GS Under Consideration as a Climate Change Mitigation

Technology? 

3. What are the Unique Risks to USDWs Associated with GS? 

B. Under What Authority is This Rulemaking Promulgated? 

C. How Does This Rulemaking Relate to the Greenhouse Gas (GHG) Reporting 

Program?
Page 14 of 274

D. How Does This Rulemaking Relate to Other Federal Authorities and GS and 

CCS Activities?

E. What Steps Did EPA Take to Develop This Rulemaking? 

1. Developing Guidance for Experimental GS Projects

2. Conducting Research

a. Tracking the Results of CO2 GS Research Projects

b. Tracking State Regulatory Efforts

c. Conducting Technical Workshops on Issues Associated with 

CO2 GS

3. Conducting Stakeholder Coordination and Outreach

4. Proposed Rulemaking

5. Notice of Data Availability and Request for Comment

F. How Will EPA’s Adaptive Rulemaking Approach Incorporate Future 

Information and Research?

G. How Does This Action Affect UIC Program Implementation? 

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

III. What is EPA’s Final Regulatory Approach?

A. Site Characterization

B. Area of Review (AoR) and Corrective Action

1. AoR Requirements

2. Corrective Action Requirements

C. Injection Well Construction

D. Class VI Injection Depth Waivers and Use of Aquifer Exemptions for GS
Page 15 of 274

1. Proposed Rule

2. Notice of Data Availability and Request for Comment

3. Final Approach

E. Injection Well Operation

F. Testing and Monitoring

1. Testing and Monitoring Plan

2. CO2 Stream Analysis

3. Mechanical Integrity Testing (MIT)

4. Corrosion Monitoring

5. Ground Water/Geochemical Monitoring

6. Pressure Fall-Off Testing

7. CO2 Plume and Pressure Front Monitoring/Tracking

8. Surface Air/Soil Gas Monitoring

9. Additional Requirements

G. Recordkeeping and Reporting

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

2. How Must Information Be Submitted?

3. What are the Recordkeeping Requirements under This Rule?

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

1. Injection Well Plugging

2. Post-Injection Site Care (PISC)

3. Site Closure

I. Financial Responsibility
Page 16 of 274

J. Emergency and Remedial Response

K. Involving the Public in Permitting Decisions

L. Duration of a Class VI Permit

IV. Cost Analysis

A. National Benefits and Costs of the Rule

1. National Benefits Summary

a. Relative Risk Framework – Qualitative Analysis

b. Other Nonquantified Benefits

2. National Cost Summary

a. Cost of the Selected RA

b. Nonquantified Costs and Uncertainties in Cost Estimates

c. Supplementary Costs and Uncertainties in Cost Estimates

B. Comparison of Benefits and Costs of RAs Considered

1. Costs Relative to Benefits; Maximizing Net Social Benefits

2. Cost Effectiveness and Incremental Net Benefits

C. Conclusions

V. Statutory and Executive Order Review

VI. References

II. Background 

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

CO2 for the purpose of GS. The purpose of the rulemaking is to ensure that GS is 

conducted in a manner that protects USDWs from endangerment. GS refers to a suite of 

technologies that can be deployed to reduce CO2 emissions to the atmosphere and help 

mitigate climate change. Due to the large CO2 injection volumes anticipated at GS 
Page 17 of 274

projects, the relative buoyancy of CO2, its mobility within subsurface geologic 

formations, its corrosivity in the presence of water, and the potential presence of 

impurities in the captured CO2 stream, the Agency has determined that tailored 

requirements, modeled on the existing UIC regulatory framework, are necessary to 

manage the unique nature of CO2 injection for GS. This final rule applies to owners or 

operators of wells that will be used to inject CO2 into the subsurface for the purpose of 

GS. 

To support today’s final regulatory action, EPA proposed Federal Requirements Under 

the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic 

Sequestration (GS) Wells (73 FR 43492) on July 25, 2008; and the Agency published a 

supplemental publication, Federal Requirements Under the Underground Injection 

Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells; 

Notice of Data Availability and Request for Comment (74 FR 44802) on August 31, 2009. 

Final Class VI requirements are informed, in part, by comments and information 

submitted in response to these publications. 

Today’s rule defines a new class of injection well (Class VI), along with technical criteria 

that tailor the existing UIC regulatory framework to address the unique nature of CO2

injection for GS. It sets minimum technical criteria for Class VI wells to protect USDWs

from endangerment, including: 

• Site characterization that includes an assessment of the geologic, hydrogeologic, 

geochemical, and geomechanical properties of the proposed GS site to ensure that 

Class VI wells are located in suitable formations. 

• Computational modeling of the AoR for GS projects that accounts for the physical 

and chemical properties of the injected CO2 and is based on available site 

characterization, monitoring, and operational data. 

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

verify that the CO2 plume and the associated area of elevated pressure are moving as 

predicted within the subsurface.
Page 18 of 274

• Well construction using materials that can withstand contact with CO2 over the life of 

the GS project. 

• Robust monitoring of the CO2 stream, injection pressures, integrity of the injection 

well, ground water quality and geochemistry, and monitoring of the CO2 plume and 

position of the pressure front throughout injection.

• Comprehensive post-injection monitoring and site care following cessation of 

injection to show the position of the CO2 plume and the associated area of elevated 

pressure to demonstrate that neither pose an endangerment to USDWs.

• Financial responsibility requirements to ensure that funds will be available for all 

corrective action, injection well plugging, post-injection site care (PISC), site closure, 

and emergency and remedial response.

Today’s rule will help ensure consistency in permitting underground injection of CO2 at 

GS operations across the United States (US) and provide requirements to prevent 

endangerment of USDWs in anticipation of the potential role of carbon capture and 

storage (CCS) in mitigating climate change. Today’s action also briefly discusses the 

relationship between today’s rule and other Federal and State activities related to GS and 

CCS in Sections II.C and D, and E.2.b, and III.F.2.

A. Why is EPA Taking This Regulatory Action?

1. What is GS? 

GS is the process of injecting CO2 into deep subsurface rock formations for long-term 

storage. It is part of the process known as CCS. 

CO2 is first captured from fossil-fueled power plants or other emission sources. To 

transport captured CO2 for GS, operators typically compress CO2 to convert it from a 

gaseous state to a supercritical state (IPCC, 2005; IEA, 2008). CO2 exists as a 

supercritical fluid at high pressures, and in this state it exhibits properties of both a liquid 

and a gas. After capture and compression, the CO2 is delivered to the sequestration site, 

frequently by pipeline, or alternatively using tanker trucks or ships (WRI, 2007; IEA, 

2008).
Page 19 of 274

At the GS site, the CO2 is injected into deep subsurface rock formations through one or 

more wells, using technologies developed and refined by the oil, gas, and chemical 

manufacturing industries over the past several decades. EPA believes that many owners 

or operators will inject CO2 in a supercritical state to depths greater than 800 meters 

(2,645 feet) for the purpose of maximizing capacity and storage.

When injected into an appropriate receiving formation, CO2 is sequestered by a 

combination of trapping mechanisms, including physical and geochemical processes

(Benson, 2008). Physical trapping occurs when the relatively buoyant CO2 rises in the 

formation until it reaches a stratigraphic zone with low permeability (i.e., geologic 

confining system) that inhibits further upward migration. Physical trapping can also occur 

as residual CO2 is immobilized in formation pore spaces as disconnected droplets or 

bubbles at the trailing edge of the plume due to capillary forces. A portion of the CO2 will 

dissolve from the pure fluid phase into native ground water and hydrocarbons. 

Preferential sorption occurs when CO2 molecules attach to the surfaces of coal and 

certain organic-rich shales, displacing other molecules such as methane. Geochemical 

trapping occurs when chemical reactions between the dissolved CO2 and minerals in the 

formation lead to the precipitation of solid carbonate minerals (IPCC, 2005). The 

timeframe over which CO2 will be trapped by these mechanisms depends on properties of 

the receiving formation and the injected CO2 stream. 

The effectiveness of physical CO2 trapping is demonstrated by natural analogs in a range 

of geologic settings where CO2 has remained trapped for millions of years (Holloway et 

al., 2007). For example, CO2 has been trapped for more than 65 million years under the 

Pisgah Anticline, northeast of the Jackson Dome in Mississippi and Louisiana (IPCC, 

2005). Other natural CO2 sources include the following geologic domes: McElmo Dome, 

Sheep Mountain, and Bravo Dome in Colorado and New Mexico. 

Many of the injection and monitoring technologies that may be applicable to GS are 

commercially available today and will be more widely demonstrated over the next 10 to 

Deleted: It is expected that the CO2 will be 

injected at a depth greater than 800 meters (2,625 

feet) such that a sufficiently high pressure and 

temperature will be maintained to keep the CO2 in a 

supercritical state. 

Comment [A4]: OMB Environmental Branch 

edit. 10/26/10
Page 20 of 274

15 years (Dooley et al, 2009). The oil and natural gas industry in the United States has 

over 35 years of experience of injection and monitoring of CO2 in the deep subsurface for 

the purposes of enhancing oil and natural gas production. This experience provides a 

strong foundation for the injection and monitoring technologies that will be needed for 

commercial-scale CCS. US and international experience with enhanced recovery (ER)

and commercial CCS projects, as well as ongoing research, demonstration, and 

deployment programs throughout the world, provide critical experience and information 

to inform the safe injection of CO2. For additional information about these projects, see 

section II.E.

Although CCS is occurring now on a relatively small scale, it could play a larger role in 

mitigating greenhouse gas (GHG) emissions from a wide variety of stationary sources. 

According to the Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2007, 

stationary sources contributed 67 percent of the total CO2 emissions from fossil fuel 

combustion in 2007 (USEPA, 2008a). These sources represent a wide variety of sectors 

amenable to CO2 capture: electric power plants (existing and new), natural gas processing 

facilities, petroleum refineries, iron and steel foundries, ethylene plants, hydrogen 

production facilities, ammonia refineries, ethanol production facilities, ethylene oxide 

plants, and cement kilns. Furthermore, 95 percent of the 500 largest stationary sources are 

within 50 miles of a candidate GS reservoir (Dooley et al., 2008). Estimated GS capacity 

in the United States is over 3,500 Gigatons CO2 (Gt CO2) (DOE NETL, 2007), although 

the actual capacity may be lower once site-specific technical and economic 

considerations are addressed. Even if only a fraction of that geologic capacity is used, 

CCS would play a sizeable role in mitigating US GHG emissions. 

2. Why is GS Under Consideration as a Climate Change Mitigation Technology? 

Climate change is happening now, and the effects can be seen on every continent and in 

every ocean. While certain effects of climate change can be beneficial, particularly in the 

short term, current and future effects of climate change pose considerable risks to human 

health and the environment. There is now clear evidence that the Earth’s climate is 

warming (USEPA, 2010):

Comment [A5]: Edited 11/15 (citations check).

Deleted: is poised to

Comment [A6]: 9/20/10: OMB Environmental 

Branch comment.
Page 21 of 274

• 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 CO2 are expected unless energy producers 

reduce CO2 emissions to the atmosphere. For example, CCS would enable the continued 

use of coal in a manner that greatly reduces the associated CO2 emissions while other 

safe and affordable alternative energy sources are developed in the coming decades. The 

development and deployment of clean coal technologies including CCS will be a key to

achieving domestic emissions reductions.

GS is one of a portfolio of options that could be deployed to reduce CO2 emissions to the 

atmosphere and help to mitigate climate change. Other options include energy 

conservation, efficiency improvements, and the use of alternative fuels and renewable 

energy sources. Ensuring that GS is done in a manner that is protective of USDWs will 

ensure the safety and efficacy of CO2 injection for GS.

While predictions about large-scale availability and the rate of CCS project deployment 

are subject to uncertainty, EPA analyses of Congressional climate change legislative 

proposals (the American Power Act of 2010 and the American Clean Energy and 

Security Act H.R. 2454 of 2009, both in the 111th Congress) indicate that CCS has the 

potential to play a significant role in climate change mitigation scenarios. For example, 

Deleted: in the 111th Congress 

Deleted: 

Comment [A7]: EPA edit 11/12/10, for 

consistency.
Page 22 of 274

analysis of the American Power Act indicates that CCS technology could account for 10 

percent of CO2 emission reductions in 2050 (USEPA, 2010f). These results indicate that 

CCS could play an important role in achieving national greenhouse gas reduction goals. 

Today’s final rule provides minimum Federal requirements for the injection of CO2 to 

protect USDWs from endangerment as this key climate mitigation technology is 

developed and deployed. It clarifies requirements that apply to CO2 injection for GS, 

provides consistency in requirements across the US, and affords transparency about what 

requirements apply to owners or operators. 

3. What are the Unique Risks to USDWs Associated with GS? 

Large CO2 injection volumes associated with GS, the buoyant and mobile nature of the 

injectate, the potential presence of impurities in the CO2 stream, and its corrosivity in the

presence of water could pose risks to USDWs. The purpose of today’s Class VI 

requirements for GS is to ensure the protection of USDWs, recognizing that an 

improperly managed GS project has the potential to endanger USDWs. Proper siting, 

well construction, operation, and monitoring of GS projects are therefore necessary to 

reduce the risk of USDW contamination. 

It is expected that GS projects will inject large volumes of CO2. These volumes will be 

much larger than are typically injected in other well classes regulated through the UIC 

program, and could cause significant pressure increases in the subsurface. Supercritical or 

gaseous CO2 in the subsurface is buoyant, and thus would tend to flow upwards if it were 

to come into contact with a migration pathway, such as a fault, fracture, or improperly 

constructed or plugged well. However, the pressures induced by injection will also 

influence CO2 and mobilized fluids to flow away from the injection well in all directions, 

including laterally, upwards and downwards. When CO2 mixes with formation fluids, a 

percentage of it will dissolve. The resulting aqueous mixture of CO2 and water will sink 

due to a density differential between the mixture and the surrounding fluids. CO2 is also 

highly mobile in the subsurface (i.e., has a very low viscosity), and, in the presence of 

water, CO2 can be corrosive. These properties (of CO2), as well as the large volumes that 

Comment [A8]: Edited 11/15 (citations check). 

Citation fix.

Deleted: reference: EPA's June 2010 American 

Power Act analysis: 

http://www.epa.gov/climatechange/economics/econo

micanalyses.html#apa2010
Page 23 of 274

may be injected for GS result in several unique challenges for protection of USDWs in 

the vicinity of GS sites from endangerment.

While CO2 itself is not a drinking water contaminant, CO2 in the presence of water forms 

a weak acid, known as carbonic acid, that, in some instances, could cause leaching and 

mobilization of naturally-occurring metals or other contaminants from geologic 

formations into ground water (e.g., arsenic, lead, and organic compounds). Another 

potential risk to USDWs is the presence of impurities in the captured CO2 stream, which 

may include drinking water contaminants such as hydrogen sulfide or mercury. 

Additionally, pressures induced by injection may force native brines (naturally occurring 

salty water) into USDWs, causing degradation of water quality and affecting drinking 

water treatment processes. Research studies have shown that the potential migration of 

injected CO2 or formation fluids into a USDW could cause impairment through one or 

several of these processes (e.g., Birkholzer et al., 2008a). 

Today’s action addresses endangerment to USDWs by establishing new minimum

Federal requirements for the proper management of CO2 injection and storage in several 

program areas, including permitting, site characterization, AoR and corrective action, 

well construction, mechanical integrity testing (MIT), financial responsibility, 

monitoring, well plugging, PISC, and site closure. EPA believes that proper GS project 

management will appropriately mitigate potential risks of endangerment to USDWs 

posed by injection activities. 

B. Under What Authority is This Rulemaking Promulgated? 

Today’s rule is focused on USDW protection under the authority of Part C of SDWA

(SDWA, section 1421 et seq., 42 U.S.C. 300h et seq.). Part C of the SDWA requires EPA 

to establish minimum requirements for State1

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

UIC programs that regulate the subsurface 
Page 24 of 274

injection of fluids onshore and offshore under submerged lands within the territorial 

jurisdiction of States

2

.

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.” 

 2 The Submerged Lands Act and Territorial Submerged Lands Act define the scope of territorial 

jurisdiction of States and Territories respectively. 
Page 25 of 274

EPA promulgated administrative and permitting regulations, now codified in 40 CFR 

parts 144 and 146, on May 19, 1980 (45 FR 33290), and technical requirements, in 40 

CFR part 146, on June 24, 1980 (45 FR 42472). The regulations were subsequently 

amended on August 27, 1981 (46 FR 43156), February 3, 1982 (47 FR 4992), January 21, 

1983 (48 FR 2938), April 1, 1983 (48 FR 14146), May 11, 1984 (49 FR 20138), July 26, 

1988 (53 FR 28118), December 3, 1993 (58 FR 63890), June 10, 1994 (59 FR 29958), 

December 14, 1994 (59 FR 64339), June 29, 1995 (60 FR 33926), December 7, 1999 (64 

FR 68546), May 15, 2000 (65 FR 30886), June 7, 2002 (67 FR 39583), and November 

22, 2005 (70 FR 70513). 

Under the SDWA, the injection of any “fluid” must meet the requirements of the UIC 

program. A “fluid” is defined under 40 CFR 144.3 as any material or substance which 

flows or moves whether in a semisolid, liquid, sludge, gas or other form or state, and 

includes the injection of liquids, gases, and semisolids (i.e., slurries) into the subsurface. 

The types of fluids currently injected into wells subject to UIC requirements include: CO2

for the purposes of enhancing recovery of oil and natural gas, water that is stored to meet 

water supply demands in dry seasons, and wastes generated by industrial users. CO2 

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

C. How Does This Rulemaking Relate to the Greenhouse Gas (GHG) Reporting 

Program?

Today’s rulemaking under SDWA authority complements the CO2 Injection and GS 

Reporting rulemaking (subparts RR and UU) under the Greenhouse Gas Reporting 

Program’s Clean Air Act (CAA) authority developed by EPA’s Office of Air and 

Radiation (OAR).

The CAA defines EPA's responsibilities for protecting and improving the nation's air 

quality and the stratospheric ozone layer. The GHG Reporting Program requires reporting 

of GHG emissions and other relevant information from certain source categories in the 

US. The GHG Reporting Program, which became effective on December 29, 2009, 
Page 26 of 274

includes reporting requirements for facilities and suppliers in 32 subparts. For more 

detailed background information on the GHG Reporting Program, see the preamble to the 

final rule establishing the GHG Reporting Program (74 FR 56260, October 30, 2009).

In a separate action being finalized concurrently with this UIC Class VI rulemaking, EPA

is amending 40 CFR part 98, which provides the regulatory framework for the GHG

Reporting Program, to add reporting requirements covering facilities that conduct GS 

(subpart RR) and all other facilities that inject CO2 underground (subpart UU). This data 

will inform Agency policy decisions under CAA sections 111 and 112 related to the use 

of CCS for mitigating GHG emissions. In combination with data from other subparts of 

the GHG Reporting Program, data from subpart UU and subpart RR will allow EPA to 

track the flow of CO2 across the CCS system. EPA will be able to reconcile subpart RR 

data on CO2 received with CO2 supply data in order to understand the quantity of CO2

supply that is geologically sequestered. 

Owners or operators subject to today’s rule are required to report under subpart RR.

Subpart RR establishes reporting requirements for facilities that inject a CO2 stream for 

long-term containment into a subsurface geologic formation, including sub-seabed 

offshore formations. These facilities are required to develop and implement a site-specific 

Monitoring, Reporting, and Verification (MRV) plan which, once approved by EPA (in a 

process separate from the UIC permitting process), would be used to verify the amount of 

CO2 sequestered and to quantify emissions in the event that injected CO2 leaks to the 

surface. For more information on subpart RR, see 

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

UIC requirements and Subpart RR requirements: EPA designed the reporting 

requirements under subpart RR with consideration of the requirements for Class VI well 

owners or operators in subpart H of part 146 of today’s rule. Subpart RR builds on the

Class VI requirements outlined in today’s rule with the additional goals of verifying the 

amount of CO2 sequestered and collecting data on any CO2 surface emissions from GS 

facilities as identified under subpart RR of part 98. 

Deleted: PLACEHOLDER FOR 

MODIFICATION DEPENDING ON TIMING OF 

RULES

Deleted: 
Page 27 of 274

The Agency acknowledges that there are similar data elements that must be reported 

pursuant to requirements in this action and those required to be reported under subpart 

RR. Specifically, owners or operators subject to both regulations must report the amount 

(flow rate) of injected CO2. The Class VI and subpart RR rules differ, not only in purpose 

but in the specific requirements for the measurement unit and collection/reporting 

frequency. The UIC program Class VI rule requires that owners or operators report 

information on the CO2 stream to ensure appropriate well siting, construction, operation, 

monitoring, post-injection site care, site closure, and financial responsibility to ensure 

protection of USDWS. Under subpart RR, owners or operators must report the amount 

(flow rate) of injected CO2 for the mass balance equation that will be used to quantify the 

amount of CO2 sequestered by a facility. 

Table II-1. Comparison of Reporting Requirements under Subpart RR and Select 

UIC Class VI Requirements

Reporting Requirement Subpart RR UIC Class VI 

Quantity of CO2 transferred 

onsite

Yes N/A

Quantity (flow rate) of CO2

injected

Yes Yes

Fugitive and vented emissions 

from surface equipment

Yes N/A

Quantity of CO2 produced with 

oil or natural gas (ER)

Yes N/A

Percent of CO2 estimated to 

remain with the oil and gas 

(ER)

Yes N/A

Quantity of CO2 emitted from 

the subsurface

Yes N/A
Page 28 of 274

Quantity of CO2 sequestered in 

the subsurface

Yes N/A

Cumulative mass of CO2

sequestered in the subsurface

Yes N/A

Monitoring plan for detecting 

air emissions

Yes Yes1

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 CO2. EPA is pursuing ways to better integrate data management 

between the UIC and GHG Reporting Programs to ensure that data needs are harmonized 

and the burden to regulated entities is minimized. 

D. How Does This Rulemaking Relate to Other Federal Authorities and GS and 

CCS Activities?

While the SDWA provides EPA with the authority to develop regulations to protect 

USDWs from endangerment, it does not provide authority to develop regulations for all 

areas related to GS. EPA received a number of public comments on the proposal (73 FR 

43492, July 25, 2008) indicating that the Agency should further explore environmental 

and regulatory issues beyond the scope of the proposed SDWA requirements for 

underground injection of CO2 for GS. 

Comment [A9]: Added per OMB OIRA 

comment 10/29.
Page 29 of 274

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-pressoffice/presidential-memorandum-a-comprehensive-federal-strategy-carbon-capture-andstorage), the Agency continues to evaluate areas of potential applicability of other 

Federal environmental statutes including, but not limited to, the CAA (discussed in 

section II.C), the Resource Conservation and Recovery Act (RCRA; discussed in section 

III.F.2), the Comprehensive Environmental Response, Compensation, and Liability Act 

(CERCLA; discussed in section III.F.2), and the Marine Protection, Research and 

Sanctuaries Act (MPRSA; discussed in this section) to various aspects of GS and CCS. 

Additionally, EPA and the US Department of Energy (DOE) co-chaired the Interagency 

Task Force on Carbon Capture and Storage to develop a plan to overcome the barriers to 

the widespread, cost-effective deployment of CCS within 10 years, with a goal of 

bringing five to 10 commercial demonstration projects online by 2016. The Task Force’s 

report is available at http://www.whitehouse.gov/administration/eop/ceq/initiatives/ccs. 

This section clarifies the distinction between today’s rulemaking and a number of other 

Federal rulemakings and initiatives. 

National Environmental Protection Act (NEPA): The SDWA UIC program is exempt 

from performing an Environmental Impact Statement (EIS) under section 101(2)(C) and 

an alternatives analysis under section 101(2)(E) of NEPA under a functional equivalence 

analysis. See Western Nebraska Resources Council v. US EPA, 943 F.2d 867, 871-72 (8th

Cir. 1991) and EPA Associate General Counsel Opinion (August 20, 1979).

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

Implementation: Sub-seabed CO2 injection for GS may, in certain circumstances, be 

defined as ocean dumping and subject to regulation under the MPRSA. Application of the 

MPRSA would entail coordination of the permitting processes under the SDWA and 

MPRSA, pursuant to MPRSA sections 106(a) and (d). The substantive environmental 
Page 30 of 274

protection requirements of both statutes would need to be satisfied prior to the 

commencement of GS. The MPRSA was enacted in 1972 and implements the London 

Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other 

Matter (the “London Convention”). In 1996, the Protocol to the London Convention (the 

“London Protocol”) was established. The Protocol stipulates that sub-seabed GS may be 

approved provided that: 1) disposal is into a sub-seabed geologic formation; 2) the CO2

stream consists overwhelmingly of CO2, with only incidental associated substances 

derived from the source material and capture and sequestration process used; and, 3) no 

wastes or other matter are added for the purpose of disposal. The US has signed, but has 

not yet ratified, the Protocol. If the Protocol is ratified, and implementing legislation is 

enacted, EPA, in conjunction with other Federal agencies, will develop any necessary 

regulations for implementing the provisions relevant to sub-seabed GS. 

Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) Outer 

Continental Shelf Lands Act (OCSLA): BOEMRE, formerly the Minerals Management 

Service (MMS), an agency within the Department of the Interior, administers the 

OCSLA. As a result of recent OCSLA amendments by the Energy Policy Act of 2005, 

the OCSLA provides for the grant of leases, easements, or rights-of-way on the outer 

continental shelf to the extent that an activity “supports production, transportation, or 

transmission of energy from sources other than oil and gas” and complies with the other 

provisions of OCSLA section 8(p). Offshore geologic sequestration of CO2 on the outer 

continental shelf may be subject to requirements under the OCSLA. 

As indicated in the Report of the Interagency Task Force on Carbon Capture and Storage

(2010), ratification of the London Protocol and associated amendment of the MPRSA as 

well as amendment of the Outer Continental Shelf Lands Act (OCSLA) will ensure a 

comprehensive statutory framework for the storage of CO2 on the outer continental shelf.

Bureau of Land Management (BLM) Report to Congress: The BLM, another agency 

within the Department of Interior, was required by Section 714 of the Energy 

Independence and Security Act (EISA) of 2007 (P.L. 110-140, HR 6) to prepare a report 

Deleted: In 2008, EPA submitted to Congress 

proposed changes to the MPRSA to implement the 

London Protocol and subsequent amendments to the 

Protocol. Among the proposed changes was a 

provision for the regulation of sub-seabed GS under 

the MPRSA.

Comment [A10]: Edit made in response to OMB 

Environmental Branch comment.

Comment [A11]: Edit made in response to 

OMB-OIRA comment 11/01. 

Comment [A12]: Added per OMB 

Environmental Branch comment 10/26/10; Also 

provides clarity per OMB-OIRA comment.
Page 31 of 274

outlining a regulatory framework that could be applied to lands managed by the Bureau 

for natural resource development, chiefly oil and gas. With assistance from both EPA and 

the DOE, BLM submitted a Report to Congress titled “Framework for Geological Carbon 

Sequestration on Public Land” (BLM, 2009). This report affirms BLM’s role in 

appropriately managing Federal lands where GS injection projects may be sited. 

Additionally, the report makes recommendations regarding approaches for effective 

regulation of such activities under existing Federal authorities including the SDWA and 

UIC program requirements. 

United States Geological Survey (USGS) GS Capacity Methodology: USGS, another

agency within the Department of Interior and the primary Federal agency responsible for 

national geological research, has been an active participant with DOE and EPA at 

conferences and workshops on CCS. In 2008, in response to the EISA, USGS initiated 

development of a methodology for estimating the capacity to store CO2 in geologic 

formations of the US. While previous capacity estimates published by DOE/ National 

Energy Technology Laboratory (NETL) have been broad in scope (i.e., geologic basinwide), the USGS is focusing on small-scale, refined estimates. In 2009, USGS published 

a proposed, risk-based methodology for GS capacity estimation. After input from other 

agencies and stakeholders, USGS released a final report: A Probabilistic Assessment 

Methodology for the Evaluation of Geologic Carbon Dioxide Storage (USGS, 2010). The

report is available at http://pubs.usgs.gov/of/2010/1127/. USGS continues to work on 

capacity estimation as required under the EISA.

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

to the Energy Improvement and Extension Act of 2008, IRS, in consultation with EPA 

and DOE, issued guidance 2009-44 IRB (IRS, 2009) for taxpayers seeking to claim tax 

credits for capturing and sequestering CO2 from a qualified facility in the US. Under 

section 45Q of the Internal Revenue Code, a taxpayer who stores CO2 under the 

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

CO2 at ER projects; $20 per metric ton of qualified CO2 for non-ER projects). The 

taxpayer will be responsible for maintaining records for inspection by the IRS and tax 

Comment [A13]: Edited 11/15 (citations check).

Deleted: This report, Development of a 

Probabilistic Assessment Methodology for 

Evaluation of Carbon Dioxide Storage, is available 

at http://pubs.usgs.gov/of/2009/1035/ofr2009-

1035.pdf (USGS, 2009). 

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

Comment [A14]: Edit made to update outdated 

information. 
Page 32 of 274

credit amounts will be adjusted for inflation for any taxable year beginning after 2009. 

The Internal Revenue Service published IRS Notice 2009-83 (available at:

http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860) to provide guidance regarding 

eligibility for the section 45Q tax credit, computation of the section 45Q tax credit, 

reporting requirements for taxpayers claiming the section 45Q tax credit, and rules 

regarding adequate security measures for “secure geological storage of CO2.”

Following publication of today’s final Class VI requirements, and as clarified in the 

guidance, taxpayers claiming the section 45Q tax credit must follow the appropriate UIC 

requirements (e.g., Class II or Class VI). The guidance also clarifies that taxpayers 

claiming section 45Q tax credit must follow the GS monitoring, reporting, and 

verification procedures finalized in the CO2 Injection and GS Reporting Rule that is part 

of the GHG Reporting Program. 

General Accountability Office Reports on GS and CCS: The United States General 

Accountability Office (GAO) has prepared, or is in the process of preparing, several 

reports for Congressional requestors related to the GS of CO2. In September 2008, GAO 

(GAO-08-1080) completed a report related to assessing the application of CCS 

technologies entitled: Climate Change – Federal Actions Will Greatly Affect the Viability 

of Carbon Capture and Storage as a Key Mitigation Option (GAO, 2008). In September 

2010, GAO released a report entitled: Climate Change, A Coordinated Strategy Could 

Focus Federal Geoengineering Research and Inform Governance Efforts (GAO-10-903)

which describes innovative technologies that may alter climate change, details current 

research activities, and clarifies how coordination could inform subsequent climate 

science efforts. GAO initiated another report (GAO-10-675) focused on the methods by 

which coal-fired power plants may capture carbon emissions. The draft title of that study 

is: Coal Power Plants – Opportunities Exist for DOE to Provide Better Information on 

the Maturity of Key Technologies to Reduce Carbon Emissions (GAO, 2010). 

EPA will continue to coordinate internally and with other Federal agencies to promote 

consistency in existing and future GS and CCS initiatives.

Comment [A15]: Edited 11/15 (citations check).

Deleted: finalized 

Comment [A16]: Edit made by EPA to update 

outdated information and place in chronological 

order. 

Comment [A17]: Edited 11/15 (citations check).

Deleted: The final report, released in September 

2010, entitled: Climate Change, A Coordinated 

Strategy Could Focus Federal Geoengineering 

Research and Inform Governance Efforts (GAO-10-

903) describes innovative technologies that may alter 

climate change, details current research activities,

and clarifies how coordination could inform 

subsequent climate science efforts.

Comment [A18]: Edit made to update outdated 

information. 

Deleted: In May 2010, GAO initiated a study with 

a focus on Geoengineering Climate Change 

including the use of GS to ameliorate greenhouse gas 

impacts. The report will also assess innovative 

technologies that may alter climate change in a 

positive manner.¶
Page 33 of 274

E. What Steps Did EPA Take to Develop This Rulemaking? 

Today's final rule builds upon longstanding programmatic requirements for underground 

injection that have been in place since the 1980s and that are used to manage over 

800,000 injection wells nationwide. These programmatic requirements are designed to 

prevent fluid movement into USDWs by addressing the potential pathways through 

which injected fluids can migrate into USDWs and cause endangerment. 

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

how best to tailor existing UIC requirements to CO2 for GS. 

EPA has taken a number of steps in advance of today’s action including: 1) developing

guidance for experimental GS projects; 2) conducting research; 3) conducting stakeholder 

coordination and outreach; 4) issuing a proposed rulemaking and soliciting and reviewing 

public comment; and, 5) publishing a Notice of Data Availability (NODA) and Request 

for Comment to seek additional input on the rulemaking.

1. Developing Guidance for Experimental GS Projects

In 2007, EPA issued technical guidance to assist State and EPA Regional UIC programs 

in processing permit applications for pilot and other small scale experimental GS 

projects. The guidance was developed in cooperation with DOE and States, the Ground 

Water Protection Council (GWPC), the Interstate Oil and Gas Compact Commission 

(IOGCC), and other stakeholders. UIC Program Guidance # 83: Using the Class V 

Experimental Technology Well Classification for Pilot Carbon GS Projects (USEPA, 

2007) provides recommendations for permit writers regarding the use of the UIC Class V 

experimental technology well classification at demonstration GS projects while ensuring 

USDW protection. Program guidance #83 is available at: 

http://www.epa.gov/safewater/uic/wells_sequestration.html. EPA is preparing additional 

guidance for owners or operators and Directors regarding the use of Class V experimental 

technology wells for GS following promulgation of today’s rule. 
Page 34 of 274

2. Conducting Research

EPA participated in and supported research to inform today’s rulemaking including: 

supporting and tracking the development and results of national and international CO2 GS 

field and research projects; tracking GS-related State regulatory and legislative efforts; 

and conducting technical workshops on issues associated with CO2 GS. EPA described 

these research activities in detail in the proposed rule (July 2008) and the NODA and 

Request for Comment (August 2009). Additional information pertaining to these 

activities, which are summarized below, may be found in the rulemaking docket. 

a. Tracking the Results of CO2 GS Research Projects

To inform today’s rulemaking, EPA tracked the progress and results of national and 

international GS research projects. DOE leads field research on GS in the US in 

conjunction with the Regional Carbon Sequestration Partnerships (RCSPs). Currently, 

DOE’s NETL is developing and/or operating GS projects, a number of which have either 

completed injection or are in the process of injecting CO2. The seven RCSPs are 

conducting pilot and demonstration projects to study site characterization (including 

injection and confining formation information, core data and site selection information); 

well construction (well depth, construction materials, and proximity to USDWs); 

frequency and types of tests and monitoring conducted (on the well and on the project 

site); modeling and monitoring results; and injection operation (injection rates, pressures, 

and volumes, CO2 source and co-injectates). See section II.E.5 for more information on 

the status of these projects. 

Lawrence Berkeley National Laboratory (LBNL) research: EPA and DOE are jointly 

funding work by the LBNL to study potential impacts of CO2 injection on ground water 

aquifers and drinking water sources. The preliminary results have been used to inform 

today’s rulemaking and are described in detail in section II.E.5. 

In addition, EPA is funding an analysis by LBNL to integrate experimental and modeling 

information. LBNL will characterize ground water samples and aquifer mineralogies 

from select sites in the US and conduct controlled laboratory experiments to assess the 
Page 35 of 274

potential mobilization of hazardous constituents by dissolved CO2. These experiments 

will provide data that will be used to validate previous predictive modeling studies (of 

aquifer vulnerabilities to potential CO2 leaks) which may be applied to other GS sites in 

the future to assess the fate and migration of CO2-mobilized constituents in ground water. 

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

Agency scientists and engineers in targeted research to provide information to 

stakeholders and policy makers focused on areas of national environmental concern, 

including climate change and GS. In addition, ORD’s National Center for Environmental 

Research (NCER) provides extramural research grants for similar investigations through 

a competitive solicitation process. In the fall of 2009, NCER awarded six Science To 

Achieve Results (STAR) grants to recipients from major universities and institutions. The 

awards were granted to projects focused on Integrated Design, Modeling and Monitoring 

of GS of Anthropogenic CO2 to Safeguard Sources of Drinking Water. Work under the 

grants began in late 2009 and includes: evaluating potential impacts on drinking water 

aquifers of CO2-rich dissolved brines (Clemson University); reducing the hydrologic and 

geochemical uncertainties associated with CO2 sequestration in deep, saline reservoirs 

(University of Illinois-Urbana); assessing appropriate monitoring approaches at GS sites 

(University of Texas at Austin); integrating design, monitoring, and modeling of GS to 

assist in developing a practical methodology for characterizing risks to USDWs 

(University of Utah); conducting laboratory experiments on shallow aquifer systems to 

improve our understanding of geochemical and microbiological reactions under low 

pH/high CO2 stress (Columbia University); and, developing a set of computational tools 

to model CO2 and brine movement associated with GS (Princeton University).

International projects: EPA is tracking the progress of international GS efforts. The 

largest and longest-running commercial, large-scale projects in operation today include: 

the Sleipner Project in the Norwegian North Sea (operating since 1996); the Weyburn 

enhanced oil recovery (EOR) project in Saskatchewan, Canada (operating since 2000); 

the In Salah Gas Project in Algeria (operating since 2004); and Snohvit, also in offshore 

Norway in the Barents Sea (operating since 2008). Other projects EPA is tracking include 

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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 State’s regulatory efforts and approaches and sought input on State activities 

related to addressing GS in the proposed rule and NODA. At present, several States have 

published GS regulations, while others are investigating and developing strategies to 

address GS issues (e.g., management of multi-purpose injection wells in oil and gas 

reservoirs). EPA is tracking regulatory efforts in 18 States: Colorado, Illinois, Kansas, 

Kentucky, Louisiana, Michigan, Mississippi, Montana, New Mexico, New York, North 

Dakota, Oklahoma, Pennsylvania, Texas, Utah, Washington, West Virginia, and 

Wyoming. EPA is considering this information as it develops guidance on the primacy 

application and approval process for Class VI wells. Information about these State 

activities may be found in the docket for today’s rulemaking.

c. Conducting Technical Workshops on Issues Associated with CO2 GS 

EPA conducted a series of technical workshops with regulators, industry, utilities, and 

technical experts to identify and discuss questions relevant to the effective management 

of CO2 GS. The workshops included the following: Measurement, Monitoring, and 

Verification (in New Orleans, Louisiana on January 16, 2008); Geological Setting and 
Page 37 of 274

AoR Considerations for CO2 GS (in Washington, DC on July 10-11, 2007); Well 

Construction and MIT (in Albuquerque, New Mexico on March 14, 2007); a State 

Regulators’ Workshop on GS of CO2 (in collaboration with DOE in San Antonio, Texas 

on January 24, 2007); an International Symposium on Site Characterization for CO2

Geological Storage (co-sponsored with LBNL in Berkeley, California on March 20-22, 

2006); Risk Assessment for Geologic CO2 Storage (co-sponsored with the Ground Water 

Protection Council (GWPC) in Portland, Oregon on September 28-29, 2005); and 

Modeling and Reservoir Simulation for Geologic Carbon Storage (in Houston, Texas on 

April 6-7, 2005). Summaries of these workshops are available on EPA’s web site, at 

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

3. Conducting Stakeholder Coordination and Outreach

Throughout the rulemaking process, the Agency conducted public workshops and public 

hearings and consulted with specific groups. EPA representatives also attended meetings 

to explain the GS rulemaking effort to interested members of the public and stakeholder 

groups. Meeting information, notes, and summaries are available in the docket for this 

rulemaking.

Public stakeholder coordination: EPA held public meetings to discuss EPA’s rulemaking 

approach, and consulted with other stakeholder groups including non-governmental 

organizations (NGOs) to gain an understanding of stakeholder interests and concerns. As 

part of this outreach, EPA conducted two public stakeholder workshops with participants 

from industry, environmental groups, utilities, academia, States, and the general public. 

These workshops were held in December 2007 and February 2008. Workshop summaries 

are available on EPA’s web site, at

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

EPA also coordinated with GWPC, a State association that focuses on ensuring safe 

application of injection well technology and protecting ground water resources, and 

IOGCC, a chartered State association representing oil and gas producing States 

throughout the rulemaking process. Members of GWPC and IOGCC have specific 

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comment 10/29.

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comment 10/29.

Comment [A22]: 

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expertise regulating the injection of CO2 for the ER of oil and gas. EPA staff attended 

national meetings and calls of these organizations, as well as those held by technical and 

trade organizations, NGOs, States, and Tribal organizations to discuss the rulemaking 

process and GS-specific technical issues. 

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

November 2008, during the public comment period for the proposed rule, EPA met with 

NDWAC to discuss the proposed rule. At the meeting, EPA presented information about 

the rulemaking and responded to NDWAC questions and comments. NDWAC members 

indicated that they understood the role of GS as a climate mitigation tool and encouraged 

the Agency to continue to ensure the protection of USDWs. Since proposal publication, 

EPA has met with NDWAC to discuss the status of the rule and answer questions from 

NDWAC members. The notes of these meetings are in the rulemaking docket.

Consultations with States, Tribes, and Territories: EPA engaged States, Tribes, and 

Territories early and throughout the rulemaking process to promote open communication 

and solicit input and feedback on all aspects of the rule. 

In April of 2008, prior to publication of the proposed rule, the Agency sent background 

information about the rulemaking to all Federally-recognized Indian Tribes and invited 

participation in a dedicated GS consultation effort. EPA Regional Indian Coordinators 

(RICs), the National Indian Workgroup (NIWG), the National Tribal Caucus (NTC) and

the National Tribal Water Council (NTWC) contacts were also invited to participate in 

the consultation. EPA provided additional rulemaking updates after publication of the 

proposal with the above-mentioned groups as well as the National Water Program StateTribal 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 coregulators post-proposal. Summaries of the Tribal consultation conference calls are 

included in the docket for today’s rulemaking. 
Page 39 of 274

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 US Department of Health and 

Human Services during the rulemaking process. Prior to proposal publication and rule 

finalization, the Agency provided background information to HHS on the purpose and 

scope of the rule. In June of 2010, EPA met with HHS to discuss the GS rulemaking 

process as well as key elements of the proposed rule, the Notice of Data Availability and 

Request for Comment, and the final rule. During the June 2010 briefing, HHS 

participants asked about technical criteria for Class VI wells and monitoring technologies 

applicable to GS projects. The Agency addressed questions and comments and HHS 

certified that the EPA satisfied consultation obligations under the SDWA. The memo 

certifying this consultation is available in the docket for today’s rulemaking. 

4. Proposed Rulemaking

On July 25, 2008, EPA published the proposed Federal Requirements Under the 

Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic 

Sequestration (GS) Wells (73 FR 43492). The Agency proposed a new class of injection 

well (Class VI), along with technical criteria for permitting Class VI wells that tailored 

the existing UIC regulatory framework to address the unique nature of CO2 injection for 

GS, including:

• Site characterization requirements that would apply to owners or operators of Class 

VI wells and require submission of extensive geologic, hydrogeologic, and 

Comment [A23]: 9/20/10 Edit made to respond 

to OMB Environmental Branch comment/question. 
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geomechanical information on the proposed GS site to ensure that Class VI wells are 

located in suitable formations. EPA also proposed that owners or operators identify 

additional containment/confining zones, if required by the Director, to improve 

USDW protection. 

• Enhanced AoR and corrective action requirements (e.g., plugging abandoned wells) 

to delineate the AoR for GS projects using computational modeling that accounts for 

the physical and chemical properties of all phases of the injected CO2 stream. EPA 

also proposed that owners or operators periodically reevaluate the AoR around the 

injection well to incorporate monitoring and operational data and verify that the CO2

is moving as predicted within the subsurface.

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

with CO2 over the life of the GS project. 

• Multi-faceted monitoring of the CO2 stream, injection pressures, the integrity of the 

injection well, groundwater quality above the confining zone(s), and the position of 

the CO2 plume and the pressure front throughout injection.

• Comprehensive post-injection monitoring and site care until it can be demonstrated 

that movement of the plume and pressure front have ceased and the injectate does not 

pose a risk to USDWs. 

• Financial responsibility requirements to ensure that financial resources would be 

available for corrective action, injection well plugging, post-injection site care, and 

site closure, and emergency and remedial response.

Following publication of the proposed rule, EPA initiated a 120-day public comment 

period, which the Agency extended by 30 days to accommodate requests from interested 

parties. The public comment period for the proposed rule closed on December 24, 2008. 

EPA received approximately 400 unique submittals from 190 commenters, including late 

submissions. Commenters represented States; industry (including the oil and gas industry, 

electric utilities, and energy companies); environmental groups; and associations 

(including water organizations and CCS associations). 
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During the public comment period, the Agency held public hearings on the proposed rule

in Chicago, IL on September 30, 2008 and in Denver, CO on October 2, 2008. The two 

hearings collectively drew approximately 100 people representing non-governmental 

organizations, academia, industry, and other organizations. At the hearings, 29 people 

submitted oral comments. Transcripts of the public hearings are in the rulemaking docket 

(Docket ID Nos. EPA-HQ-OW-2008-0390-0185 and EPA-HQ-OW-2008-0390-0256). 

5. Notice of Data Availability and Request for Comment

Based on public comments received on the proposed rule, the Agency identified several 

topics on which it needed additional public comment. EPA published Federal 

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

Dioxide (CO2) Geologic Sequestration (GS) Wells; Notice of Data Availability and 

Request for Comment (74 FR 44802) on August 31, 2009, to describe additional topics 

and request comment. 

The NODA and Request for Comment presented new data and information from three 

DOE-sponsored RCSP projects including: 1) the Escatawpa, Mississippi project; 2) the 

Aneth Field, Paradox Basin project in Southeast Utah; and, 3) the Pump Canyon Site

project in New Mexico. Additional information on these projects and responses to 

comments received on the NODA and Request for Comment are available in the docket 

for this rulemaking. 

The NODA and Request for Comment also provided results of two GS-related modeling 

studies conducted by the LBNL. The first study (Birkholzer et al., 2008a) focused on the 

potential for GS to cause changes in ground water quality as a result of potential CO2

leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, 

mercury, lead, antimony, selenium, zinc, and uranium. Results from this model 

simulation suggest that if CO2 were to leak into a shallow aquifer, mobilization of lead 

and arsenic could occur, causing increases in the concentration of these trace elements in 

ground water and potential for drinking water standard exceedances. 
Page 42 of 274

The second study modeled a theoretical scenario of GS in a sedimentary basin to 

demonstrate the potential for basin-scale hydrologic impacts of CO2 storage (Birkholzer 

et al., 2008b). Model results indicate that basin-wide pressure influences may be large 

and that predicted pressure changes could move saline water upward into overlying 

aquifers if localized pathways, such as conductive faults, are present. This example 

illustrates the importance of basin-scale evaluation of reservoir pressures and far-field 

pressures resulting from CO2 injection. 

Additional information on LBNL’s research and responses to comments received on the 

NODA and Request for Comment are available in the docket for this rulemaking. 

The full publications on the LBNL research are also available on LBNL’s web site at 

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

Lastly, the NODA and Request for Comment presented an alternative to address public 

comments and concerns about the proposed injection depth requirements for Class VI 

wells. Section III.D of today’s action contains more information on this subject. 

Following publication of the NODA and Request for Comment, EPA initiated a 45-day 

public comment period, which closed on October 15, 2009. EPA received 67 unique 

submittals from 64 commenters, many of whom commented on the proposed rule. The 

Agency also held a public hearing in Chicago, IL on September 17, 2009. Six people, 

representing the oil and gas industry, electric utilities, water associations, and academia 

attended the hearing. Two attendees submitted oral comments at the hearing. A transcript 

of the public hearing is in the rulemaking docket (EPA-HQ-OW-2008-0390-391). 

F. How Will EPA’s Adaptive Rulemaking Approach Incorporate Future 

Information and Research? 

In the preamble to the proposed rule (73 FR 43492), EPA explained the need for and 

merits of using an adaptive approach to regulating injection of CO2 for GS at 40 CFR 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 
Page 43 of 274

VI permitting Agencies are able to meet current and future demand for Class VI permits. 

The proposal also clarified that, as the Agency reviewed public comments, it would 

continue to evaluate ongoing research and demonstration projects and gather other 

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

Many commenters strongly supported an adaptive, flexible approach and suggested that 

the Agency initially take a conservative approach in developing the UIC-GS 

requirements, with a provision for periodic review of the rule to allow EPA to incorporate 

operational experience as it is gained. These commenters also urged EPA not to wait until 

the completion of DOE’s pilot projects before finalizing the GS rule, expressing a need 

for early regulatory certainty.

Some commenters expressed concerns about an adaptive approach, stating that it could 

lead to regulatory uncertainty because modifications could be made after the initial 

regulations are promulgated. One commenter said that GS will not scale-up rapidly, 

leaving ample time to study and assess possible regulatory approaches. 

EPA agrees with commenters who supported an adaptive approach to the UIC 

rulemaking for GS. Additionally, the Agency believes that there is a need to have 

regulations in place during the earliest phases of GS deployment. Finalizing today’s 

requirements will allow early Class VI wells to be permitted in a manner that addresses 

the unique characteristics of CO2 injection for GS and allow early projects to demonstrate 

successful confinement of CO2 in a manner that is protective of USDWs. EPA also 

believes that an adaptive approach enables the Agency to make changes to the program as 

necessary to incorporate new research, data, and information about GS and associated 

technologies (e.g., modeling and well construction). This new information may increase 

protectiveness, streamline implementation, reduce costs, or otherwise inform the 

requirements for GS injection of CO2. The Agency plans, every six years, to review the 

rulemaking and data on GS projects to determine whether the appropriate amount and 

types of information and appropriate documentation are being collected, and to determine 

if modifications to the Class VI UIC requirements are appropriate or necessary. This time 

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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 

Deleted: must have available

Deleted: minimum

Comment [A25]: 

“the necessary” is an OMB-OIRA track change 

(11/08). 

Comment [A26]: 

Edited per OIRA track change edit 10/31.

11/04 – “must have” deleted to eliminate redundancy 

with first part of sentence in response to OMB OIRA 

comments. 

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Comment [A27]: Edited per OMB OIRA 

comment 10/29.
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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 
Page 46 of 274

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 
Page 47 of 274

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 

Deleted: acknowledges 

Comment [A28]: Edited per OMB OIRA 

comment 10/29.
Page 48 of 274

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 

[INSERT DATE 270 DAYS AFTER RULE PUBLICATION] 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 
Page 49 of 274

clear, nationally-consistent deadline will avoid potential confusion that may arise if some 

States have approved Class VI programs and others do not. EPA will publish a list of the 

States where the Federal Class VI requirements have become applicable in the Federal 

Register and update 40 CFR part 147. It is important to note that, although the Agency is 

not accepting extension requests, a State may, at any time in the future, apply for primacy 

for the new GS requirements following establishment of a Federal Class VI UIC 

program. If a State receives approval after the 270-day deadline (for a primacy 

application submitted either before or after the deadline), EPA will publish a subsequent 

notice of the approval as required by the SDWA; at that point, the State, rather than EPA, 

will implement the Class VI program. 

The Agency clarifies that States may not issue Class VI UIC permits until their Class VI 

UIC programs are approved. During the first 270-days and prior to EPA approval of a 

Class VI primacy application, States without existing SDWA section 1422 primacy

programs must direct all Class VI GS permit applications to the appropriate EPA Region. 

EPA Regions will issue permits using existing authorities and well classifications (e.g., 

Class I or Class V), as appropriate. 

States with existing UIC primacy for all non-Class VI well classes under section 1422 

that receive Class VI permit applications within the first 270 days after promulgation of 

the final rule may consider using existing authorities (e.g., Class I or Class V), as 

appropriate, to issue permits for CO2 injection for GS while EPA is evaluating their Class 

VI primacy application. EPA encourages States to issue permits that meet the

requirements for Class VI wells to ensure that Class V and Class I wells previously used 

for GS can be re-permitted as Class VI wells that meet the protective requirements of 

today’s final rule within one year of promulgation of the Class VI regulation, pursuant to 

requirements at §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 

Deleted: submits a primacy application after the 

270-day deadline and the application is approved

Comment [A29]: 

OMB-OIRA track changes (11/08). 
Page 50 of 274

States without Class VI programs must be directed to the appropriate EPA Region in 

order for a Class VI permit to be issued. In States where EPA directly implements the 

Class VI program, Class I permits for CO2 injection for GS may no longer be issued and 

Class V permits may only be issued to projects eligible for such permits (see discussion 

of the relationship between Class V and Class VI permits in Section II.H).

Streamlining the primacy approval process: In an effort to support States with the Class 

VI primacy application process and respond to comments received during the rulemaking 

process, today’s rule includes new regulatory language at §§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 

Comment [A30]: Edited per OIRA track change 

edit (minor text modification from suggested edit) 

10/31.

Deleted: i.e

Deleted: the 

Deleted: 's 7520

Deleted: ,

Comment [A31]: 

EPA edits for clarity. 11/12/10.

Comment [A32]: 

Edited with minor modification per OMB-OIRA 

track changes (11/08). 
Page 51 of 274

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 [INSERT DATE 365 DAYS AFTER DATE OF RULE 

PUBLICATION], 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 [INSERT DATE 365 DAYS AFTER DATE OF RULE 

PUBLICATION]. §145.23(f)(4) also requires the Director of a Class VI Program 

approved after [INSERT DATE 365 DAYS AFTER DATE OF RULE PUBLICATION], 

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 

Comment [A33]: 

Edited per OMB-OIRA comment 10/29.

Edits made here and to regulatory text in response to 

OMB-OIRA comments (11/08) and (11/11)
Page 52 of 274

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 CO2 injection for long-term storage presents several unique challenges that 

warrant the designation of a new well type. 

When EPA initially promulgated its UIC regulations in 1980, the Agency defined five 

classes of injection wells at 40 CFR 144.6, based on similarities in the fluids injected, 

construction, injection depth, design, injection practices, and operating techniques. These 

five well classes are still in use today and are described below.

• Class I wells inject industrial non-hazardous liquids, municipal wastewaters, or 

hazardous wastes beneath the lowermost USDW. These wells are among the deepest 

of the injection wells and are subject to technically sophisticated construction and 

operation requirements. 

• Class II wells inject fluids (e.g., CO2; brine) in connection with conventional oil or 

natural gas production, enhanced oil and gas production, and the storage of 

hydrocarbons that are liquid at standard temperature and pressure. 

Deleted: 14

Comment [A34]: 

Modified OMB-OIRA Track changes. 11/10

Deleted: submit a description of (and supporting 

information related to) any expansions to 

Deleted: s

Comment [A35]: Edited per OMB OIRA 

comment 10/29.

Deleted: , which the Director has identified and 

approved under §144.7(d

Comment [A36]: 

OMB-OIRA deletion “which the Director...” 

(11/10/10). 

Deleted: )

Comment [A37]: 

Updated in response to OMB comment (with 

associated regulatory edits due to redundancy 

between 145.23(f)(9) and (f)(14)). (11/08). 
Page 53 of 274

• 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 repermitted 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 

[INSERT DATE 365 DAYS AFTER DATE OF RULE PUBLICATION], pursuant to 

requirements at §146.81(c). The Agency anticipates that permit applications (e.g., Class I 

or Class V) developed for CO2 GS following publication of today’s rule will follow the 

Class VI requirements and be designed to facilitate efficient re-permitting as Class VI 

wells. Such forethought will allow new Class VI permits to be issued with minimal 

additional effort on the part of the owner or operator and the Director. Additional

information on Class V experimental technology wells is discussed in this section. For 

additional information on permitting authorities and UIC program implementation, see

section II.G.

Deleted: days after

Deleted: well owners or operators applying for 

Class VI well permits

Deleted: permit applications (e.g., for Class I or 

Class V) in a manner that 

Deleted: s

Comment [A38]: Edited per OIRA track change 

edit 10/31.

Deleted: Similarly, the Agency expects that 

previously permitted wells will use the year 

following rule promulgation to develop appropriate, 

tailored Class VI permits to re-permit their Class I 

(or Class V) wells. 

Comment [A39]: Deletion made in response to

OIRA comment 10/31.
Page 54 of 274

Class II CO2 injection wells designated for enhanced recovery: Enhanced oil recovery 

(EOR) and enhanced gas recovery (EGR) technologies, collectively referred to as 

enhanced recovery (ER), are used in oil and gas reservoirs to increase production. 

Injection of CO2 is one of several ER techniques that have successfully been used to 

boost production efficiency of oil and gas by re-pressurizing the reservoir, and in the case 

of oil, by also increasing mobility. Injection wells used for ER are regulated through the 

UIC Class II program. 

CO2 currently injected for ER in the US comes from both natural and anthropogenic 

sources, which provide 79 percent and 21 percent, respectively, of CO2 supply (DOE 

NETL, 2008). Natural CO2 sources consist of geologic domes in Colorado, New Mexico, 

and Mississippi. Anthropogenic sources of CO2 supplied for ER today include natural gas 

processing, ammonia and fertilizer production, and coal gasification facilities. 

Historically, CO2 purchases comprise about 33 to 68 percent of the cost of a CO2-ER 

project (EPRI, 1999). For this reason, CO2 injection volumes are carefully tracked at ER 

sites. CO2 recovered from production wells during ER is recycled (i.e., separated and reinjected), and at the conclusion of an ER project as much CO2 as is feasible is recovered 

and transported to other ER facilities for re-use. However, a certain amount of CO2

remains underground. Current Class II ER requirements do not require tracking and 

monitoring of the injectate; therefore, the migration and fate of the unrecovered CO2 is 

not documented.

As of 2008, there were 105 CO2-EOR projects within the US (Oil and Gas Journal, 

2008). The majority (58) of these projects are located in Texas, and the remaining 

projects are located in Mississippi, Wyoming, Michigan, Oklahoma, New Mexico, Utah, 

Louisiana, Kansas, and Colorado. CO2-EOR projects recovered 323,000 barrels of oil per 

day in 2008, 6.5 percent of total domestic oil production. A total of 6,121 CO2 injection 

wells among 105 projects were used to inject 51 million metric tons of CO2 (Oil and Gas 

Journal, 2008; EIA, 2009; DOE NETL, 2008). Compared to CO2-EOR, CO2-EGR 

remains largely in the development stage (e.g., Oldenburg et al., 2001). 

Formatted: Subscript

Comment [A40]: 

EPA edit. 11/12/10. 

Comment [A41]: Edited 11/15 (citations check).

Deleted: a

Comment [A42]: Edited 11/15 (citations check).

Deleted: NETL, 2008a
Page 55 of 274

Future deployment of CCS may fundamentally alter CO2-ER in the US. DOE anticipates 

that many early GS projects will be sited in depleted or active oil and gas reservoirs 

because the reservoirs have been previously characterized for hydrocarbon recovery and 

may have suitable infrastructure (e.g., wells, pipelines, etc.) in place. Additionally, oil 

and gas fields now considered to be “depleted” may resume operation because of 

increased availability and decreased cost of anthropogenic CO2.

EPA believes that if the business model for ER changes to focus on maximizing CO2

injection volumes and permanent storage, then the risk of endangerment to USDWs is 

likely to increase. This is because reservoir pressure within the injection zone will 

increase as CO2 injection volumes increase. Elevated reservoir pressure is a significant 

risk driver at GS sites, as it may cause unintended fluid movement and leakage into 

USDWs that may cause endangerment. Additionally, increasing reservoir pressure within 

the injection zone as a result of GS will stress the primary confining zone (i.e., geologic 

caprock) and well plugs to a greater degree than during traditional ER (e.g., Klusman, 

2003). Finally, active and abandoned well bores are much more numerous in oil and gas 

fields than other potential GS sites, and under certain circumstances could serve as

potential leakage pathways. For example, in typical productive oil and gas fields, a CO2

plume with a radius of about 5 km (3.1 miles) may come into contact with several 

hundred producing or abandoned wells (Celia et al., 2004).

EPA proposed that the Class VI GS requirements would not apply to Class II ER wells as 

long as any oil or gas production is occurring, but would apply only after the oil and gas 

reservoir is depleted. Under the proposed approach, Class II wells could be used for the 

injection of CO2, as long as oil production is simultaneously occurring from the same 

formation. The preamble to the proposal sought comment on the merits of this approach.

Some commenters agreed with the proposed approach while others suggested that the 

approach did not adequately address risks posed to USDWs by injection operations 

Comment [A43]: 9/20/10: OMB Environmental 

Branch comment.

Deleted: DOE expects that these early projects will 

be necessary to meet future GHG mitigation goals in 

the near-term. 
Page 56 of 274

transitioning from production to long-term storage of CO2. A majority of commenters 

requested that EPA develop specific criteria for this transition. 

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

injecting CO2 in oil and gas reservoirs for GS where there is an increased risk to USDWs 

compared to traditional Class II operations using CO2 should be required to obtain a 

Class VI permit, with some special consideration for the fact that they are transitioning 

from a well not originally designed to meet Class VI requirements. Additionally, EPA 

recognizes that further clarification is needed to sufficiently characterize the factors that 

lead to increased risks and warrant conversion from Class II to Class VI. 

Therefore, today’s rule clarifies that Class VI requirements apply to any CO2 injection 

project (regardless of formation type) when there is an increased risk to USDWs as 

compared to traditional Class II operations using CO2. Traditional ER projects are not 

impacted by this rulemaking and will continue operating under Class II permitting 

requirements. EPA recognizes that there may be some CO2 trapped in the subsurface at 

these operations; however, if there is no increased risk to USDWs, then these operations 

would continue to be permitted under Class II. 

EPA has developed specific, risk-based factors to be considered by the Director in 

making the determination to apply Class VI requirements to transitioning wells. EPA 

believes this approach provides the necessary, site-specific flexibility while providing 

appropriate protection of USDWs from endangerment. These risk-based factors for 

determining whether Class VI requirements apply are finalized in today’s rule at §144.19 

and include: 1) increase in reservoir pressure within the injection zone; 2) increase in CO2

injection rates; 3) decrease in reservoir production rates; 4) the distance between the 

injection zone and USDWs; 5) the suitability of the Class II AoR delineation; 6) the 

quality of abandoned well plugs within the AoR; 7) the owner’s or operator’s plan for 

recovery of CO2 at the cessation of injection; 8) the source and properties of injected 

CO2; and 9) any additional site-specific factors as determined by the Director. Any single 

factor may not necessarily result in a determination that a Class II owner or operator must 

Deleted: has 

Deleted: agrees with commenters 

Comment [A44]: 

EPA edit for clarity. 11/12/10

Comment [A45]: Edited per OMB OIRA 

comment 10/29.

Deleted: posed 

Comment [A46]: 

EPA edit for clarity. 11/12/10.

Deleted: increases and is greater than traditional 

ER projects

Comment [A47]: Edited per OMB OIRA 

comment 10/29.

Comment [A48]: 

OMB OIRA edit. 11/15/10

Comment [A49]: Edited per OMB OIRA 

comment 10/29.

Deleted: be an incidental amount of 

Deleted: criteria 

Comment [A50]: This paragraph edited (criteria 

to factors) per OMB OIRA comment 10/29.

Deleted: criteria

Deleted: criteria 

Deleted: criterion
Page 57 of 274

apply for a Class VI permit; rather, all factors must be evaluated comprehensively to 

inform a Director’s (or owners’ or operators’) decision. The Agency is also developing 

guidance to support Directors and owners or operators in evaluating these factors and

making the determination on whether to apply Class VI requirements. 

Owners and operators of Class II wells that are injecting carbon dioxide for the primary 

purpose of long-term storage into an oil and gas reservoir must apply for and obtain a 

Class VI permit where there is an increased risk to USDWs compared to traditional Class 

II operations using CO2. EPA expects that, in most cases, the ER owners or operators will 

use these same factors to evaluate whether there is an increased risk to USDWs. When an 

increased risk is identified, the owner or operator must notify the Director of their intent 

to seek a Class VI permit. Today’s rule clarifies that the Director has the discretion to 

make this determination in the absence of an owner or operator notification and, in doing 

so, require the owner or operator to apply for and obtain a Class VI permit in order to 

continue injection operations (§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 

Deleted: criteria 

Deleted: criteria 

Formatted: Subscript

Comment [A51]: 

EPA edit for clarity. 11/12/10

Deleted: because there is an increased risk to 

USDWs compared to traditional Class II operations

Comment [A52]: Edited per OMB OIRA 

comment 10/29.

Deleted: believes that requiring a well to 

Deleted: will not cause

Deleted: and is necessary to ensure USDW 

protection

Comment [A53]: Edited per OMB OIRA 

comment 10/29.
Page 58 of 274

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 CO2. 

Class V Experimental Technology Wells: Prior to finalization of the Class VI regulation, 

a number of CO2 injection projects were permitted as Class V experimental technology 

wells for the purpose of testing GS technology in the US. 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 

Deleted: criteria 

Comment [A54]: Edited per OMB OIRA 

comment 10/29.
Page 59 of 274

CO2 for the purpose of GS) to apply for Class VI permits within one year of rule 

promulgation and to comply with the requirements of today’s rule. However, EPA is 

allowing the constructed components of Class V experimental technology wells to be 

grandfathered into the Class VI permitting regime at the discretion of the Director and 

pursuant to requirements at §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 CO2 injection wells that are testing the injectivity or 

appropriateness of an individual formation (e.g., as a prelude to a commercial-scale 

operation) as Class V experimental technology wells. Such wells should be permitted as 

Class VI wells.

Other commenters suggested that owners or operators of wells injecting CO2 into basalts, 

coal seams, and salt domes should be able to seek a Class V experimental permit. EPA 

agrees that the Class V experimental technology well classification may be appropriate 

for these projects provided they are experimental in nature. EPA expects that, following 

today’s rule, a limited number of experimental injection projects testing GS technology 

will continue. EPA anticipates that these projects will be small-scale and involve limited 

CO2 volumes. However, if these projects become larger scale and are no longer 

experimental, they will need to be permitted as Class VI wells. The construction, 

operation or maintenance of any non-experimental Class V GS wells is prohibited 

(§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 

Deleted: EPA anticipates that Class V well owners 

or operators that plan to re-permit their wells as 

Class VI wells will initiate the permit application 

process following promulgation of today’s rule

Comment [A55]: Deletion made in response to 

OIRA comment 10/31.

Deleted: . 

Deleted: with these commenters and acknowledges 

Comment [A56]: Edited per OMB OIRA 

comment 10/29.
Page 60 of 274

and Directors in determining what constitutes a Class V experimental technology well for 

the purposes of testing GS technology. 

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

Recognizing that owners or operators of existing Class I, Class II, and Class V 

experimental technology wells may seek to change the purpose of their injection well,

EPA proposed to give the Director discretion to carry over or “grandfather” the 

construction requirements (e.g., permanent, cemented well components) provided he or 

she is able to make a determination that these wells would not endanger USDWs. EPA 

sought comment on this approach and how the proposed grandfathering provisions for 

existing wells may affect compliance with Class VI construction requirements.

Nearly all industry commenters favored grandfathering of Class I, II, and V well 

construction requirements for GS, indicating that most wells are built to appropriate 

specifications and would have sufficient mechanical integrity for GS in order to protect 

USDWs from endangerment. These commenters cited oil and gas industry experience 

with CO2 injection in the UIC Class II program and suggested that this experience 

demonstrates that construction requirements for Class II injection wells are sufficient to 

protect USDWs. Other commenters asserted that grandfathering Class II construction will 

expedite the transition of Class II ER projects to Class VI GS. 

Several commenters were concerned that the structural modifications that may be 

required for some existing Class II wells to comply with the proposed injection well 

construction requirements at §146.86 may actually compromise the integrity of those 

wells. One commenter also mentioned that pre-existing wells, including wells approved 

for sequestration as Class I and/or Class II wells, have not been constructed to the same 

standards. These existing wells penetrating the injection zone may, therefore, become 

potential threats to USDWs. 

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

injecting CO2 for ER and that many Class V experimental technology wells, including 
Page 61 of 274

those used in the RCSP’s projects, are specifically designed for injection of CO2 and are 

being constructed to Class I non-hazardous waste well specifications. In today’s final 

rule, at §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 CO2 for the purpose of GS. Today’s 

action includes requirements for the permitting, siting, construction, operation, financial 

responsibility, testing and monitoring, PISC, and site closure of Class VI injection wells 

that address the pathways through which USDWs may be endangered. These 

requirements are tailored from existing UIC program components to ensure that they are 

appropriate for the unique nature of injecting large volumes of CO2 for GS into a variety 

of geological formations to ensure that USDWs are not endangered. 

Today’s rule retains many of the requirements for Class VI wells that EPA proposed on 

July 25, 2008. However, based on a review of public comments on the proposed rule and 

the NODA and Request for Comment, EPA made several changes to the GS rule. These 

changes are highlighted as follows and are described in today’s publication. 
Page 62 of 274

• 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 CO2 injection 

transitions from ER (i.e., a Class II well) to long-term storage (i.e., Class VI) and the 

risk posed to USDWs increases and is greater than traditional ER projects injecting 

CO2, today’s rule at §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.

Comment [A57]: 

EPA edit for clarity 11/12/10.

Deleted: criteria 

Deleted: demonstrated 

Deleted: considered 

Comment [A58]: Edited per OMB OIRA 

comment 10/29.
Page 63 of 274

• 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 CO2 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 CO2 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.

Deleted: .

Deleted: T

Deleted: , t

Comment [A59]: 11/04 edit for ease of reading. 

Comment [A60]: Edited per OMB OIRA 

comment 10/29.

Deleted: use 
Page 64 of 274

EPA believes that these changes will result in a clearer, more protective approach to 

permitting GS projects across the US 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 US 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 

Deleted: s

Comment [A61]: Edited per OMB OIRA 

comment 10/29.
Page 65 of 274

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 CO2 so that the injection activities will not endanger 

USDWs. Today’s requirements for Class VI wells are based extensively on the longstanding 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 CO2, 

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 
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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. 
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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 US. The Agency 

encourages transparency in the permitting process and anticipates that State-State/StateTribal 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. 
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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 CO2 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 

CO2 is moving as predicted within the subsurface.

AoR modeling and reevaluation are important components of the overall proposed 

strategy to track the CO2 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 CO2 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 

Comment [A62]: Edited per OMB OIRA 

comment 10/29.

Deleted: storage operation 
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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 CO2 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 CO2 phases and areas of quantitative measures of elevated pressure 

should be included in the definition. 
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EPA evaluated all comments on the AoR definition, and determined that a performancebased 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 CO2 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 CO2 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 CO2, 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 
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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 CO2 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 CO2 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 CO2 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. 
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The majority of commenters agreed that AoR reevaluations are necessary, citing the large 

volumes of CO2 that may be injected, the uncertainty of CO2 movement in the 

subsurface, the need to incorporate monitoring data, and the lack of experience in 

tracking large volumes of CO2. 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 CO2 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 CO2 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 CO2 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 

CO2 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 
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consultation with the Director, would identify the wells that need corrective action to 

prevent the movement of CO2 or other fluids into or between USDWs. Owners or 

operators would perform corrective action to address deficiencies in any wells (regardless 

of ownership) that are identified as potential conduits for fluid movement into USDWs. 

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 CO2 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 CO2 exposure during the first years of injection as informed by sitecharacterization data and model predictions. Artificial penetrations in areas farther from 

the injection well would be addressed after injection has commenced, but prior to CO2

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.
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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 CO2 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 CO2 plume or pressure front. However, it is not 

appropriate to set a specific timeframe for completing corrective action because CO2

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 CO2 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 CO2, including its buoyancy relative to other fluids in the 

subsurface and the potential presence of impurities in captured CO2. In addition to 
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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 CO2 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 US. 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. 

Deleted: and, in turn, may promote acceptance of 

GS projects

Comment [A63]: 9/20/10: OMB Environmental 

Branch edit. 
Page 76 of 274

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 CO2 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 degradationresistant well construction materials, such as acid-resistant cements and corrosionresistant 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 
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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 

CO2 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 CO2 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 CO2 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 
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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 and packer 

in Class VI wells facilitate continuous monitoring of pressure in the annulus between the 

tubing and casing and effectively provide two barriers from USDWs. Additionally, 

tubing can be replaced relatively easily in the event that damage to the tubing is identified 

or a tubing diameter change is necessary. EPA agrees with commenters that the use of 

tubing and packer in accordance with specified requirements at §146.86(c) offers the best 

multiple-barrier protection of USDWs from endangerment and today’s final rule retains 

this requirement. 

Horizontal wells: In the proposed rule, EPA solicited comment on the merits of 

horizontal well drilling techniques for Class VI wells and the applicability of proposed 

well construction requirements to horizontal injection well design. Commenters strongly 

supported the use of horizontal well drilling techniques for Class VI wells. Many 

commenters cited the oil and gas industry’s extensive technical experience with 

horizontal injection well construction and the practical experience gained at GS pilot 

projects including the In Salah project in Algeria. Commenters also emphasized that 

horizontal well drilling helps to reduce surface impact by reducing the number of 

injection well heads required to achieve a given injection rate, which limits the number of 

potential leakage pathways into USDWs. Commenters stated that allowing the use of 

horizontal wells for GS would maximize CO2 injection volumes into a particular 

reservoir and increase the total effective GS CO2 storage capacity in the US.
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EPA agrees with commenters that horizontal well drilling techniques represent a potential 

and promising method for increasing efficiency of GS projects while simultaneously 

reducing impact and potential leakage pathways into USDWs. EPA agrees that using 

existing experience with horizontal well construction and use in conjunction with the 

Class VI requirements may help improve efficiency in GS operations while ensuring

protection of USDWs from endangerment. Therefore, the Agency will allow the use of 

horizontal wells for Class VI GS as long as the wells are constructed and implemented to 

meet the requirements under subpart H of part 146.

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

Today’s final rule includes requirements at §146.95 that allow owners or operators to 

seek a waiver from the Class VI injection depth requirements for GS to allow injection 

into non-USDW formations while ensuring that USDWs above and below the injection 

zone are protected from endangerment. The Agency anticipates that any issuance of 

waivers will be limited to circumstances where there are deep USDWs (74 FR 44802, 

August 31, 2009) and/or where the lack of a waiver of injection depth requirements 

would result in impractical or technically infeasible well construction, and where USDW 

protection is demonstrated and maintained through the life of the GS project. These 

requirements are designed to ensure that the owner or operator and the Director consider, 

on a site-specific basis, the implications, benefits, and challenges associated with GS, 

water availability, and USDW protection. Today’s final rule also establishes limited 

circumstances under which aquifer exemption expansions may be granted for owners or 

operators of Class II EOR/EGR wells transitioning to Class VI injection wells for GS. 

1. Proposed Rule

Injection depth requirements for GS: In the proposed rule, EPA defined Class VI 

injection wells as “wells used for GS (injection) of CO2 beneath the lowermost formation 

containing a USDW.” The proposed injection depth requirements (i.e., that injection is 

below the lowermost USDW) for Class VI wells are consistent with the siting and 

operational requirements for deep, technically sophisticated wells and are an important 

component of the UIC program. The basis for these requirements is the principle that 
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placing distance between the injection formation and USDWs will decrease risks to 

USDWs. In deep-well injection scenarios, the added depth and distance between the 

injection zone and overlying formations serve both as a buffer allowing for pressure 

dissipation and as a zone for monitoring that may detect any excursions (of the injectate) 

out of the injection zone. Additional depth and distance also allow CO2 trapping 

mechanisms, including physical trapping, dissolution of CO2 in native fluids and 

mineralization, to occur over time – thereby reducing risks that CO2 may migrate from 

the injection zone and endanger USDWs. Added depth also allows the potential for the 

presence of additional confining layers (between the injection zone and overlying 

formations/USDWs). 

The Agency acknowledged that the proposed injection depth requirements would 

preclude injection of CO2 into zones in between and above USDWs and may restrict the 

use of GS in areas of the country with deep USDWs, where well construction would be 

impractical or technically infeasible. As proposed, the definition would also have 

effectively precluded injection of CO2 into shallow formations such as coal seams and 

basalts. The Agency requested comment on alternative approaches that would allow 

injection between USDWs and/or above the lowermost USDW and thus potentially allow 

for more areas to be available for GS while continuing to prevent endangerment of 

USDWs. 

The Agency received comments in support of, and opposition to, the proposed injection 

depth requirements for Class VI wells. Commenters who supported the proposed 

requirements cited the importance of USDW protection, the integrity and importance of 

the long-standing deep well UIC requirements, and concerns about water availability and 

the future use of deep USDWs. Commenters also indicated that in the early years of GS 

deployment, injection depth limitations would be prudent. 

Those opposed to the proposed requirements supported allowing injection above and 

between USDWs. These commenters indicated that injection depth flexibility for GS is 

important to ensure that no parts of the country are excluded from GS activities and that 
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CCS deployment is not restricted. Other commenters encouraged injection depth 

flexibility because, they asserted, some Class II, Class III, and Class V operations already 

inject above the lowermost USDW without any potential for threats to underlying (or 

overlying) USDWs. 

Use of aquifer exemptions for GS: The UIC requirements at §§146.4 and 144.7 establish 

criteria for and afford the Director discretion to issue aquifer exemptions which, when 

approved, removes an aquifer from protection as a USDW, in accordance with the 

requirements of §144.7(b)(1). Generally, aquifer exemptions are granted for mineral or 

hydrocarbon exploitation by Class III solution mining wells, or by Class II oil and gasrelated wells, respectively, and when there is no reasonable expectation that the exempted 

aquifer will be used as a drinking water supply (see specific aquifer exemption criteria at 

§146.4). There are also limited numbers of aquifer exemptions for Class I industrial 

injection. Aquifer exemptions associated with Class II and Class III operations are 

generally limited in area (e.g., a quarter of a mile around the injection well-bore for Class 

II wells). EPA attempts to limit aquifer exemptions for injection operations to the 

circumstances where the necessary criteria at §146.4 are met and not, in general, for the 

purpose of creating additional capacity for the subsurface emplacement of fluids.

The proposed rule acknowledged that there may be situations where owners or operators 

may seek aquifer exemptions for GS and sought comment on whether aquifer exemptions 

should be allowed for the purpose of Class VI injection. EPA also requested comment on 

the conditions under which aquifer exemptions for GS should be approved. 

Some commenters encouraged the Agency to allow the use of aquifer exemptions for 

Class VI injection and indicated that the existing criteria at 40 CFR 146.4 and 40 CFR 

144.7 are appropriate for GS. However, a number of commenters requested that the 

Agency modify the aquifer exemption criteria to provide regulatory certainty and ensure 

that the criteria specifically apply to CO2 injection for GS. Other commenters requested 

that the Agency modify the definition of a USDW to reduce the need for aquifer 

exemptions (e.g., lowering the upper TDS limit from 10,000 mg/l TDS). Additionally, 
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commenters acknowledged that there was a particular interest in aquifer exemptions for 

Class II fields that may be used for GS in the future. 

Other commenters suggested that the Agency limit or prohibit aquifer exemptions for 

Class VI injection, citing the need to ensure protection of current and future drinking 

water resources. Furthermore, several commenters opposed to the use of aquifer 

exemptions suggested modifications to the definition of a USDW to enhance protection 

for formations in excess of 10,000 mg/l TDS. 

Injection formations for GS: In the preamble to the proposed rule, EPA discussed and 

sought comment on the range of target geologic formations used or under investigation 

for GS of CO2 (e.g., deep saline formations, depleted oil and gas reservoirs, unmineable 

coal seams, basalts, and other formations). The proposed rule also sought comment on 

whether the final rule should prohibit injection into any specific formation types that are 

located above the lowermost USDW. 

Most commenters encouraged EPA not to automatically exclude any potential injection 

formations for GS at this stage of deployment. Commenters suggested, in particular, that 

there is a sufficient technical basis and scientific evidence to allow GS in depleted oil and 

gas reservoirs and in saline formations, noting that there is consensus on how to inject 

into these formation types. 

Some commenters, including water associations, cautioned the Agency regarding 

injection into saline formations, citing concerns about the potential future need for these 

formations as drinking water sources. Other commenters suggested that basalts, salt 

domes, shales, coal seams, limestone formations, and fractured karst are not ready for 

commercial sequestration and suggested that additional research is needed into GS in 

these formation types. 

More detailed information on the comments is available in the NODA and Request for 

Comment and in the docket for this rulemaking. 
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2. Notice of Data Availability and Request for Comment

In response to comments received on the proposed injection depth requirements, the 

Agency published a NODA and Request for Comment to present additional information 

on an alternative for addressing injection depth in limited circumstances where there are 

deep USDWs and injection above and between USDWs would not endanger USDWs. 

Under the approach, the proposed Class VI injection depth requirements would remain 

unchanged but would allow an owner or operator seeking to inject into non-USDWs

above or between USDWs to apply for a waiver from the injection depth requirements. 

The waiver process, presented in the NODA and Request for Comment, would be 

informed by site-specific information and would be reviewed by both the UIC and Public 

Water System Supervision (PWSS) Directors to ensure appropriate siting of a GS project 

as well as consideration of water resource availability and demands. 

The NODA and Request for Comment sought comment on the merits of the injection 

depth waiver approach and whether the waiver process should apply only to saline 

formations and oil/gas reservoirs or to all formation types. Additionally, the Agency 

requested information on 1) locations in the US where injection depth is an issue; 2) data 

and information on the safety of injecting through/above/between USDWs; and, 3) 

strategies being considered by States, Tribes, and Regions to address competing resource 

issues. The Agency requested this information to enable a more comprehensive decision 

regarding the impacts of the proposed injection depth requirements and the need for 

waivers.

Comments on the waiver alternative presented in the NODA and Request for Comment: 

The Agency received comments both in support of and opposition to the injection depth 

waiver alternative discussed in the NODA and Request for Comment. 

Commenters supporting the waiver alternative presented in the NODA and Request for 

Comment acknowledged that the waiver approach is flexible, strikes the right balance 

between USDW protection and maximizing GS capacity, and would ensure a thorough 
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and scientifically based, site-specific assessment of the appropriateness of a waiver 

during the siting process. A number of commenters supportive of the waiver cited 

hydrocarbon storage, other injection operations, and production activities as evidence that 

GS into shallower geologic environments can be performed safely and successfully while 

ensuring USDW protection. 

There was limited opposition to the waiver alternative presented in the NODA and 

Request for Comment. Commenters who opposed the waiver approach maintained that 

all injection of CO2 for GS should be below the lowermost USDW and any new 

requirements should maximize protection of USDWs. However, some commenters who 

opposed the waiver process acknowledged the utility of the waiver, and urged the Agency 

to consider additional requirements for any wells that operate under injection depth 

waivers. The Agency did not receive any analytical or quantitative data in response to

publication of the NODA and Request for Comment.

The Agency also received comments on the waiver application and review process. 

Commenters questioned how the process would work and how waivers would apply to 

existing Class I, II, or V wells that may be re-permitted as Class VI wells in the future. 

Some commenters suggested that the waiver request should be part of the permit 

application process, while others felt that it should be a discrete submittal. Other 

commenters expressed concern about the nexus between the waiver process and aquifer 

exemptions. Some commenters who supported the waiver concept suggested that 

adoption of an injection depth waiver process should not be at the discretion of the 

individual UIC program Directors and that EPA should require all States to include a 

waiver process.

A number of commenters supporting the concept of the waiver of injection depth 

requirements indicated that they did not support the joint review of waiver information by 

both the UIC and PWSS Directors. These commenters believed that the joint review 

process as discussed in the NODA and Request for Comment was inefficient and 

duplicative, and could introduce confusion and lack of clarity about the role of each 

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Director. However, a number of commenters did support the principle of affording the 

PWSS Director a consultative role for increased transparency and to ensure consideration 

of public water supply needs in a potential GS project area when siting a Class VI well. 

Noting the unique nature of the waiver process and the belief that injection above 

USDWs may present additional questions relative to movement of CO2 in the subsurface, 

many commenters supported the Agency’s assertion that additional requirements should 

apply to waivered wells. These commenters suggested that additional regional, 

hydrologic studies be required when an injection depth waiver is considered. Other 

commenters encouraged EPA to enhance the site characterization requirements when a 

waiver is granted to 1) ensure the identification of appropriate upper and lower confining 

units, 2) include requirements for more comprehensive, site-specific monitoring (above 

and below the injection zone), and 3) ensure appropriate public notification prior to 

issuance of a waiver. A number of commenters also suggested that the Agency develop 

guidance to support the waiver application process, waiver evaluation, and decision 

making. 

Comments on the use of aquifer exemptions for GS: Comments submitted in response to 

the NODA were similar to and built upon those received on the proposal. Some 

commenters indicated that, in addition to allowing injection above and between USDWs 

(through the waiver process), aquifer exemptions should also be allowed for Class VI 

injection. A number of these commenters requested that the Agency modify 1) the aquifer 

exemption criteria to ensure that the criteria specifically apply to CO2 injection for GS

and 2) the USDW definition to limit protection for formations currently afforded 

protection under the SDWA (i.e., by reducing the 10,000 mg/l TDS threshold). These 

commenters added that Class II EOR/EGR operations injecting into exempted aquifers 

would need a mechanism to continue the aquifer exemptions if the well were to be repermitted as a GS operation. 

However, a number of commenters encouraged the Agency to limit or prohibit aquifer 

exemptions for Class VI injection, citing the need to ensure protection of current and 
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future drinking water resources. Furthermore, several of these commenters suggested 

modifications to the definition of a USDW to enhance protection for formations in excess 

of 10,000 mg/l TDS. 

Comments on injection formations for GS: Commenters submitted comments similar to 

those received on the proposal. Some commenters encouraged the Agency to limit GS 

injection to only deep saline formations and depleted reservoirs. These commenters cited 

a lack of information about the viability of basalts, salt domes, shales, and coal seams for 

GS. Other commenters suggested that the Agency allow injection into all formation types 

for GS. Commenters that supported flexibility in injection formation types indicated that 

proper site-characterization is critical, regardless of the injection formation type. They 

indicated that a decision to allow injection for GS should be made on a site-by-site basis 

and a prohibition based on formation types is not appropriate. 

3. Final Approach

In response to comments on the proposed injection depth requirements, the use of aquifer 

exemptions for GS, the range of potential injection formations for GS, the waiver process 

discussed in the NODA and Request for Comment, and concerns about USDW protection 

and national capacity for GS, today’s rule finalizes requirements at §146.95 that allow 

owners or operators to seek a waiver of the Class VI injection depth requirements for 

injection into non-USDW formations above and/or between USDWs. It establishes: 1) 

requirements specifying information that owners or operators must submit, and Directors 

must consider, in consultation with PWSS Directors; 2) procedures for public notice of a 

waiver application and for Director-Regional Administrator communication; 3) the 

waiver issuance process; and, 4) additional requirements that apply to owners or 

operators of Class VI wells granted a waiver of the injection depth requirements to ensure 

USDW protection above and below the injection zone. Today’s final rule also establishes 

limited circumstances under which expansions of aquifer exemptions may be granted for 

owners or operators of Class II EOR/EGR wells transitioning to Class VI injection for 

GS. Additionally, today’s rule does not categorically preclude or prohibit injection into 

any type of formation. 
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The Agency is finalizing these requirements to ensure USDW protection while providing 

flexibility to UIC program Directors and owners or operators who will undertake CO2

injection for GS. The Agency believes this approach: 1) responds to concerns about local 

and regional geologic storage capacity limitations imposed by the proposed injection 

depth requirements; 2) allows for a more site-specific assessment of injection depth for 

GS projects; 3) accommodates injection into different formation types; 4) allows for 

injection of CO2 for GS into non-USDWs above and/or between USDWs when 

appropriate and where it can be demonstrated that USDWs will be protected from 

endangerment; and 5) responds to concerns about the use of aquifer exemptions for GS. 

Finally, EPA’s approach to addressing injection depth variability through a waiver 

process responds to concerns about future drinking water resource availability and the 

need to ensure that high quality water remains available in sufficient quantities to supply 

drinking water needs. 

The final injection depth waiver requirements at §146.95 apply to all non-USDWs 

including: 1) formations that have salinities greater than 10,000 mg/l TDS and 2) all 

eligible previously exempted aquifers situated above and/or between USDWs. EPA 

anticipates that previously exempted aquifers will, in many cases, not be appropriate 

receiving formations for GS due to their location, size, lithologic properties, and previous 

injection operations; and, therefore, the Agency expects that few owners or operators will 

seek Class VI permits for GS injection into previously exempted aquifers. 

Injection depth waivers for GS: Today’s final rule requires an owner or operator seeking 

a Class VI waiver of the injection depth requirements to submit additional information to 

the Director to inform a comprehensive assessment of site-suitability for a Class VI well

to inject into a non-USDW above or between USDWs. The Agency believes that it is 

appropriate and reasonable that the owner or operator and the Director consider 

additional, specific information prior to waiver issuance in addition to the required Class 

VI permit information and the site characterization information collected (pursuant to 

requirements at §146.82(a) for the site-specific characterization of geologic, 
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hydrogeologic, geochemical, and geomechanical properties and §146.83 to determine the 

suitability of the proposed GS site).

In addition to submitting a Class VI permit application, the owner or operator must also 

submit a supplemental report (the GS Class VI injection depth waiver application report)

referenced at §146.82(d) and outlined at §146.95(a) with additional, specific information 

including: information about the injection zone; identification of confining units above 

and below the injection zone; tailored AoR modeling above and below the injection zone; 

a demonstration that well design is appropriate and protective of USDWs, in lieu of 

specific well construction requirements at §146.86; a description of how monitoring will 

be tailored for injection above/between USDWs; and information about public water 

supplies in the AoR. The purpose of the report is to ensure that the owner or operator 

collects appropriate information and demonstrates to the Director that the injection zone 

is suitable for GS and is confined by confining units above and below the injection zone;

that well construction, operation, and monitoring are tailored for the site; and, that 

USDWs are not and will not be endangered. This report, suggested by commenters on the 

NODA and Request for Comment, ensures that waiver information is discrete from the 

permit application as indicated at §146.82(d) and must be made available to the UIC 

Director, PWSS Directors, the Regional Administrator, and the public when the waiver is 

publicly noticed with the draft, Class VI permit application. 

EPA believes that, to be effective, a waiver of injection depth requirements should be 

granted only after the UIC program Director, the PWSS Director(s), and the public have 

evaluated information specific to the site and anticipated injection activity. In addition, 

the decision to waive injection depth requirements must be made using a clear and 

transparent public notification process. The requirements at §146.95(b) establish 

considerations that the UIC Director must assess when evaluating a waiver application in 

conjunction with the permit application for a Class VI GS project. These are designed to 

ensure that USDW protection, site-specific drinking water resource issues, and the use 

and impact of GS technologies are considered and documented. The requirements at 

§146.95(b)(2) also establish the manner in which the UIC Director will consult with the 
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PWSS Director(s) of States, Territories, and Tribes having jurisdiction over lands within 

the AoR of a well for which a waiver is sought to ensure that water system concerns are 

considered when evaluating a waiver application. The communication with the PWSS 

Director is consultative and does not constitute a final Agency decision. 

Under §146.95(c) and pursuant to requirements at §124.10, the public notification 

process for a waiver of injection depth requirements for a Class VI well must occur 

concurrently with the Class VI permit notification in order to ensure that all necessary 

information is disclosed to the public for notice and comment and that the public 

understands that the site, if permitted, would be operating under a waiver from the 

injection depth requirements. In addition, the rule at §146.95(c) requires the Director to 

provide the public with appropriate, site-specific and waiver-specific information to 

inform public comment. If the permitting authority receives comments on the injection 

depth waiver during the public comment period for both the waiver and the permit 

application, the Director must evaluate comments prior to approving the waiver and

issuing the Class VI permit. These requirements balance USDW protection and 

disclosure of PWSS information with the GS permit application process requirements. 

Today’s final regulations, at §146.95(d), require the Director to provide the Regional 

Administrator with the information collected during the waiver application and the public 

notice processes. Based on this information and pursuant to requirements at §146.95(d), 

the Regional Administrator will provide written concurrence or non-concurrence 

regarding waiver issuance. The requirements at §146.95(d)(1) afford the Regional 

Administrator discretion to request limited, additional information to support the waiver 

decision. The Regional Administrator also has the discretion to require re-initiation of the 

public notice and comment period if necessary. Today's rule at §146.95(d)(2) clarifies 

that Directors of State-approved programs shall not issue waivers without the written 

concurrence of the Regional Administrator. EPA believes Agency input is necessary in 

making injection depth waiver decisions and agrees with commenters who expressed 

interest in ensuring that multi-State boundary and water resource issues are addressed. 

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EPA also believes that Agency involvement in the waiver decision process will 

contribute to national consistency in waiver issuance. 

The requirements at §146.95(e) identify the information that EPA will maintain on its 

Web site to provide transparency and inform the public regarding GS injection depth 

waiver issuance throughout the US. 

Today’s rule finalizes additional requirements at §146.95(f) to address comments and 

provide clarity to owners or operators who receive and operate with a waiver of the Class 

VI injection depth requirements. These requirements are a supplement to all other 

applicable requirements finalized today (see §146.95(f)(1)). The additional requirements 

are designed to complement existing requirements by: 

• Building upon the site characterization and AoR delineation conducted during the 

waiver application process (at §146.95(a)),

• Supplementing specific requirements that are not applicable due to the fact that 

certain Class VI requirements (e.g., at §146.86) reference the “lowermost USDW,” 

• Expanding the monitoring requirements during operation and PISC to address 

protection of USDWs underlying and overlying the injection zone, and,

• Ensuring protection of USDWs above and below an injection zone when a Class VI 

well is issued a waiver of the injection depth requirements. 

The Agency believes that collection and assessment of site- and project-specific 

information is integral to the waiver process. The Agency is developing guidance to 

support owners or operators in assessing a GS project site and applying for a waiver of 

the Class VI injection depth requirements and to assist Directors in evaluating waiver 

applications.

Today’s final approach for injection depth waivers represents minimum Federal 

requirements. Adoption of the waiver process will remain at the discretion of individual 

UIC programs, since States may choose to develop requirements that are more stringent 

than the minimum Federal requirements provided in today’s rule. Furthermore, States, 
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Territories and Tribes may be prohibited by state law from allowing such a waiver 

process. Therefore, States, Territories, and Tribes seeking primacy for Class VI wells are 

not required to provide for injection depth waivers in their UIC regulations and may 

choose not to make this process available to owners or operators of Class VI wells under 

their jurisdiction. Although some commenters asked EPA to require that waivers be 

applied nationally, the Agency believes that the decision about whether a waiver program 

is appropriate in a specific State, Tribe, or Territory should be made by each program. 

This approach allows flexibility for individual program Directors to determine the 

appropriateness of allowing for waivers based on regional or State-specific conditions, 

such as the predominant geologic settings anticipated to be used for GS or other land uses 

in the State while ensuring maximum protection of USDWs from endangerment. UIC 

program Directors may adopt GS requirements that do not allow injection above or 

between USDWs if they determine this to be appropriate or if State law prohibits the 

injection depth waiver process. 

No waivers can be issued prior to the establishment of a Class VI UIC program in a State,

pursuant to the requirements at §145.21(see section II.E.2). This is designed to ensure 

that States determine whether a waiver process will be allowed as a part of their GS 

program.

Use of aquifer exemptions for GS: Today's rule allows for the expansion to the areal 

extent of existing aquifer exemptions for Class II EOR/EGR wells transitioning to Class 

VI injection for GS pursuant to requirements at §§146.4 and 144.7(d). Today’s final rule 

also precludes the issuance of new aquifer exemptions for Class VI wells. Aquifer 

exemptions will only be granted for projects that are transitioning from Class II 

EOR/EGR wells to Class VI, and are referred to as aquifer exemption expansions below. 

However, Class VI owners or operators granted expansions of existing Class II 

EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements 

for Class VI wells in today's rule, except where there are specific provisions for 

grandfathering of constructed wells pursuant to requirements at §146.81(c). 

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If an owner or operator applies for a Class VI permit to inject CO2 into a previously 

exempted aquifer (non-USDW) that is located above and/or between USDWs, the permit 

applicant must also apply for a waiver of the injection depth requirements pursuant to 

§146.95 to ensure that if a waiver is granted, USDWs above and below the injection zone 

are protected from endangerment. 

While the Agency developed the waiver process to address comments and concerns 

about: 1) current and future drinking water resources and 2) the use of climate mitigation 

technology at appropriate sites, the Agency acknowledges that there are limited 

circumstances where aquifer exemptions for GS may be warranted. The aquifer 

exemption requirements in today's final rule afford owners or operators an opportunity to 

assess and select a suitable GS site while also preserving USDWs (i.e., 

formations/aquifers afforded SDWA protection). EPA agrees with commenters who 

expressed concerns about USDW preservation and protection and believes that, in most 

cases, the injection depth waiver is a more appropriate option than aquifer exemptions for 

Class VI injection, and believes that aquifer exemption expansions for GS should be 

granted in limited circumstances. 

The aquifer exemption requirements and the injection depth waiver requirements serve 

different purposes. An aquifer exemption removes the injection formation from SDWA 

protection as a USDW and allows injection (i.e., permitted or rule authorized) into an 

exempted formation, while an injection depth waiver allows (Class VI) CO2 injection for 

GS above or between USDWs and ensures protection of USDWs above and below the 

injection zone (which may be an exempted aquifer). 

The Agency recognizes that a limited number of Class II EOR/EGR well owners or 

operators currently inject into exempted aquifers or exempted portions of aquifers and 

these owners or operators may transition to Class VI GS in the future (see section II.H). 

In response to commenters who believed that there is a need for aquifer exemptions in 

specific circumstances and in an effort to maintain USDW protection while providing 

flexibility to transitioning projects, today’s rule allows owners or operators of Class II 

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EOR/EGR operations injecting into exempted aquifers (or exempted portions of aquifers) 

to reapply for an aquifer exemption expansion for the re-permitted Class VI injection. 

For all Class II EOR/EGR aquifer exemption expansions for Class VI injection, public 

notice and opportunity for a public hearing is required under §144.7(b)(3). In addition, 

today’s rule requires that all such aquifer exemption expansion requests be treated as 

substantial program revisions under §145.32 and will require revision of part 147. 

Furthermore, if EPA directly implements the UIC program in a State, an aquifer 

exemption expansion requires a revision to the UIC program of the applicable State under 

part 147. 

The Agency acknowledges that the expansion of an existing aquifer exemption for a GS 

project will remove additional USDWs (or portions of USDWs) from SDWA protection, 

and that owners or operators of other classes of injection wells could apply for a permit to 

inject into these exempted aquifers. However, EPA clarifies that aquifer exemption 

expansions granted under today's rule will only be granted for the purpose of GS (and the 

injection will be subject to today's tailored requirements for Class VI wells). Any other 

uses of an exempted aquifer (e.g., for Class I through V injection) require a separate 

permit, are subject to existing UIC requirements, and must be approved by the UIC 

Director. The Agency anticipates that a UIC Director will (and encourages the UIC 

Director to) consider the following types of risks when evaluating additional injection 

activities into the AoR of a GS project: the number of artificial penetrations in the AoR, 

potential adverse geochemical interactions between previously injected CO2 and other 

injection fluids, and an increase in reservoir pressure as a result of multiple injectors and 

subsurface plume interaction. EPA believes that these factors would reduce the likelihood 

that exempted aquifers associated with GS injection will be used for other activities.

Additionally, the Agency recognizes that an owner or operator could, in theory, request 

multiple expansions to the areal extent of a previously exempted aquifer used for Class II 

EOR/EGR injection. However, due to the nature of Class VI operations including the 

permit application process, the AoR evaluation, and the development of site-specific 

Deleted: This modifies existing provisions that all 

aquifer exemption requests are either explicitly or 

implicitly approved by EPA pursuant to §144.7. 

Comment [A70]: Edited per OIRA comment

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plans, the Agency anticipates that an owner or operator will not be able to continually 

expand an aquifer exemption for a Class VI operation. Instead, the applicant should 

identify, up front, the predicted extent of the injected CO2 plume and any mobilized 

fluids that may result in degradation of water quality over the lifetime of the GS project 

to develop an appropriate aquifer exemption request. Identification of the areal extent of 

the expanded aquifer exemption must be informed by computational modeling of the site 

developed for delineation of the AoR, and be of sufficient size to cover any possible 

changes to the computational model that may arise during future reevaluation of the AoR 

over the life of the project.

Pursuant to requirements at §144.7(d)(2), the Director will comprehensively evaluate the 

permit application information in concert with the areal extent of the aquifer exemption 

expansion request. The purpose of these requirements is to ensure USDW protection 

while developing an exemption expansion that is commensurate with the Class VI 

injection project, for the life of the project, to reduce the potential need for additional 

expansions of a specific aquifer exemption for Class VI injection in the future. 

Furthermore, in the event that a Class VI owner or operator obtains evidence based on 

monitoring data collected at the GS site, as required by §146.90(g), that non-exempted, 

USDW portions of the aquifer (i.e., on the periphery of the exempted aquifer) may be 

endangered by the injection activity, the owner or operator must immediately cease 

injection and implement the Emergency and Remedial Response Plan approved by the 

Director pursuant to requirements at §146.94. Additionally, the Agency clarifies that such 

USDW endangerment is a violation of the UIC requirements and associated Class VI 

permit conditions (e.g., §144.12; §146.86, etc.).

Today's final approach is designed to ensure that the differences between traditional 

Class II EOR/EGR operations and Class VI operations are considered during the aquifer 

exemption application process and the Class VI permitting process. These differences 

include the anticipated large CO2 injection volumes associated with GS, the buoyant and 

mobile nature of the injectate, and its corrosivity in the presence of water. The Agency 

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believes that this process will encourage owners or operators and Directors to consider 

the use of alternative formations for GS, including non-USDW formations through the 

waiver process, prior to applying for or approving aquifer exemption expansions for 

Class II EOR/EGR wells transitioning to Class VI GS operations. See the discussion on 

injection depth waivers for GS for information on scenarios that will require the use of 

both aquifer exemptions and waivers in this section.

Injection formations for GS: In response to comments received on the proposal and the 

NODA and Request for Comment, today’s rule does not categorically preclude or 

prohibit injection into any type of formation. Instead, the requirements are designed to 

ensure protection of USDWs from endangerment through proper siting, well 

construction, operation, monitoring, and PISC at all sites selected for GS. 

EPA recognizes that some types of formations, such as coal seams and basalts, are 

typically shallow and above the lowermost USDW. EPA expects that injection wells 

conducting GS in these shallow formations will be permitted as Class VI wells and such 

wells will be issued waivers, provided that their owners or operators can meet all of the 

requirements for an injection depth waiver at §146.95 and demonstrate that such injection 

can be performed in a manner that protects USDWs. EPA adds that wells used to inject 

into these formation types or other formation types (e.g., salt domes and shales) for 

experimental purposes would be permitted as Class V experimental technology wells. See 

section II.H for additional information on the use of the Class V experimental technology 

well classification following finalization of today’s rulemaking. 

To facilitate experimental injection for GS and to increase understanding of injection into 

basalts, shales, and other formation types, 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. 

Adaptive approach: In the early stages of GS deployment, EPA will collect and review 

project data on GS projects, including information on any Class VI wells granted a 
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waiver of the injection depth requirements and any aquifer exemption expansions issued 

for Class II EOR/EGR wells transitioning to Class VI GS. Given the unique nature of the 

waiver of injection depth requirements, the Agency will further assess if the requirements 

provided in §146.95 are appropriately designed to evaluate waiver applications, issue 

waivers, and ensure protection of USDWs. The adaptive approach will also afford the 

Agency an opportunity to assess the manner in which waivers and expansions of existing 

Class II EOR/EGR aquifer exemptions for GS are issued across the US and evaluate the 

applicability of injection into all formation types. 

E. Injection Well Operation

Today’s final rule contains tailored requirements at §146.88 for the operation of Class VI

wells, including injection pressure limitations, use of down-hole shut-off systems, and 

annulus pressure requirements to ensure that injection of CO2 does not endanger USDWs.

The requirements for operation of Class VI injection wells are based on the existing 

requirements for Class I wells, with enhancements to account for the unique conditions 

that will occur during GS including buoyancy, corrosivity, and higher sustained pressures 

over a longer period of operation. 

Injection pressure limitations: EPA proposed that owners or operators limit injection 

pressure such that pressure in the injection zone does not exceed 90 percent of the 

fracture pressure of the injection zone, and that injection may not initiate new fractures or 

propagate existing fractures. Most commenters opposed an arbitrary pressure limit, and 

advocated setting pressure limitations on a site-specific basis. Today’s final rule retains 

the requirement that pressure in the injection zone must not exceed 90 percent of the 

fracture pressure of the injection zone (§146.88(a)). The calculated fracture pressure—

and therefore, the injection pressure limit—are based on site-specific geologic and 

geomechanical data collected during the site characterization process as advocated by 

commenters.
Page 97 of 274

Annulus pressure: EPA proposed that owners or operators fill the annulus with an 

approved non-corrosive fluid and maintain pressure on the annulus that exceeds the 

operating injection pressure. Many commenters disagreed with the requirement to 

maintain an annulus pressure greater than the injection pressure because they indicated 

that this could increase the potential for damage to the well. 

EPA acknowledges that, in some circumstances, maintaining an annulus pressure greater 

than the injection pressure could result in a greater chance for damage to the well or the 

formation. As a result, the final rule provides the Director discretion to adjust this 

requirement if maintaining an annulus pressure higher than the injection pressure may 

cause damage to the well or the formation. EPA changed the requirements in §146.88(c) 

to: “The owner or operator must maintain on the annulus a pressure that exceeds the 

operating injection pressure, unless the Director determines that such requirement might 

harm the integrity of the well or endanger USDWs.” 

Automatic down-hole shut-off devices: EPA proposed that owners or operators install and 

use alarms and automatic down-hole shut-off systems, in addition to the use of surface 

shut-off devices, to alert the owner or operator and shut-in the well in the event of a loss 

of mechanical integrity. Automatic down-hole shut-off devices are valves located in the 

well tubing (at a depth established based on the location of USDWs) that are set to close 

if triggered by changes in flow rate or other monitored parameters. Automatic surface 

shut-off valves are commonly used in the oil and gas industry to prevent further well 

complications in the case of a triggered event such as inadvertent well backflow during a 

workover. The Agency sought comment on the merits of requiring such devices.

Commenters, including representatives of water associations, supported the requirement 

to construct Class VI wells with automatic down-hole shut-off devices. These 

commenters suggested that automatic down-hole shut-off devices provide an additional 

barrier against upward migration of CO2 and serve as an additional level of protection 

when used in concert with surface shut-off devices. 

Deleted: formation 

Comment [A72]: Edited per OMB OIRA 

comment 10/29.
Page 98 of 274

Many industry commenters disagreed with the requirement to construct Class VI wells 

with automatic down-hole shut-off devices. These commenters indicated that down-hole 

shut-off devices are redundant of surface devices and unnecessary and would not provide 

additional protection to USDWs. Commenters suggested that these devices are more 

appropriate for offshore wells and that the likelihood of damage to surface wellheads is 

small. Other commenters stated that installation of automatic down-hole shut-off devices 

in new and pre-existing deep injection wells is complex and servicing of the devices 

necessitates removal of the tubing. Commenters also indicated that the use of such 

devices can complicate routine testing and well workovers, and that failure of such 

devices could damage the well. Several commenters suggested alternatives to automatic 

down-hole shut-off devices including: use of wireline retrievable plugs with landing 

nipples; and use of well materials designed to withstand the proposed injection pressures. 

EPA evaluated the range of comments on this topic and maintains that down-hole shutoff devices are an important barrier against endangerment of USDWs from the escape of 

CO2. While stakeholders commented that automatic down-hole shut-off devices are 

primarily used in offshore oil and gas production applications, they are currently used in 

other situations where loss of well integrity could result in damage to the well or harm to 

humans (e.g., near high-density population areas, or in onshore acid gas injection; IEA, 

2003). While commenters indicated that down-hole monitoring is more difficult, or 

impractical with an automatic down-hole shut-off device in place, EPA has identified 

examples of documented logging techniques, including ultrasonic and temperature logs, 

that can be performed with an automatic down-hole device emplaced (Julian et al., 2007; 

Somaschini et al., 2009). They are also used in high pressure, high temperature onshore 

wells and in permafrost areas.

EPA recognizes that, in limited circumstances, the sudden closing of an automatic shutoff valve could cause damage to a well, and that some of these devices may make well 

maintenance and operation more challenging. Additionally, EPA recognizes that well 

complications may increase as the frequency of routine or unexpected down-hole device 

maintenance workovers increases. However, the buoyant nature of CO2 and the elevated 
Page 99 of 274

injection pressures associated with GS increase the likelihood of an uncontrolled flow of 

CO2 out of the well. If CO2 does begin to flow back up an injection well, it will rapidly 

cool and expand as it moves toward the surface and can result in a stream of solid CO2 

which can cause damage to the wellhead and other well instrumentation; such damage 

has been documented in CO2 ER wells (Skinner, 2003; Duncan et al., 2009). Automatic 

shut-off devices can help prevent such occurrences.

After evaluating the risks and benefits of down-hole shut-off systems and considering 

additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells. Instead, the final rule, at §146.88(e)(2), requires that owners or 

operators of onshore Class VI wells install automatic surface shut-off devices, and 

affords Director's discretion to mandate automatic down-hole shut-off devices in onshore 

situations that may warrant their use. EPA believes that requiring automatic surface shutoff devices instead of down-hole devices provides more flexibility to owners or operators 

when performing required mechanical integrity tests. Additionally, this requirement 

addresses concerns about risks associated with routine well workovers that may be 

complicated by the presence of down-hole devices while still maintaining USDW 

protection. 

Today’s rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for 

Class VI wells located in the offshore submerged lands within the jurisdiction of a State 

UIC program. The Agency believes that the unique construction and operational 

conditions for offshore Class VI wells, including isolation from shorelines and the need 

to construct wells through the water column and the subsurface, may delay response time 

in the event of well difficulties. These conditions merit requiring automatic down-hole 

shut-off devices for offshore wells in the submerged lands of a State. 

In the event of onshore or offshore well complications, an automatic surface or downhole shut-off device will immediately shut-in the well to cease injection (limiting CO2

volume associated with the event), isolate the injectate, and minimizes the risk of 

subsurface fluid movement and associated problems that may endanger USDWs. EPA 

Comment [A73]: Edited 11/15 (citations check).

Deleted: 8
Page 100 of 274

believes that requiring the installation of automatic surface shut-off devices for onshore 

wells (and affording Director's discretion to require down-hole devices where necessary) 

and automatic down-hole shut-off devices for offshore wells in submerged lands within 

the jurisdiction of a State ensures that proper precautions are taken to prevent subsurface 

fluid movement and ensure protection of USDWs, human health, and the environment.

Well stimulation: In the proposed rule, EPA sought comment on whether well stimulation 

or fracturing to enhance formation injectivity is appropriate and should be allowed for 

Class VI wells. EPA also requested submittal of information from commenters to better 

qualify the use of hydraulic fracturing for well stimulation in specific geologic settings 

and various lithologies. Well owners or operators often use stimulation techniques, 

including intentionally creating new or propagating existing fractures in the injection 

zone on wells that have experienced decreased oil and gas production. Additionally, 

increasing the number and size of fractures surrounding the injection zone can enhance or 

increase the injectivity of the formation. However, if fractures extend to the confining 

layer, USDWs can be endangered. 

Some commenters stated that while stimulation using a range of techniques including 

hydraulic fracturing is not appropriate in all geologic settings it should be allowed for 

Class VI wells. Commenters supported the requirement that hydraulic fracturing only be 

allowed during well stimulation, noting that ER operations have successfully employed 

hydraulic fracturing to increase well injectivity without damaging the confining layer. 

These commenters thought that enhancing injectivity through stimulation would allow 

injection to occur with fewer injection wells and therefore fewer penetrations of the 

confining layer. 

Many commenters indicated that the Director should be able to determine, based on sitespecific information, whether stimulation techniques would pose a risk to the confining 

layer. Some commenters proposed considerations for determining whether stimulation, 

including hydraulic fracturing, is appropriate in a given situation and acknowledged that 

tools exist for owners or operators and Directors to manage the safe use of well 
Page 101 of 274

stimulation practices. These tools include use of monitoring programs or computer 

simulations in conjunction with stimulation activities to determine if stimulation is 

negatively impacting confining layers. Others suggested that open-hole injection zones 

and multiple injection points can also aid in increasing well injectivity. 

A water association commented that activities such as hydraulic fracturing should not be 

allowed under any circumstances in order to prevent fracturing of the confining layer and 

the opening of pathways for fluid migration into a USDW. 

EPA agrees with commenters that well stimulation may be appropriate in situations 

where it is determined that it will increase well injectivity and provide better performance 

for some projects. However, EPA believes that protection of USDWs from endangerment 

is critical and the primary purpose of UIC regulations pursuant to SDWA. In order to 

allow appropriate well stimulation while protecting confining layers and USDWs, EPA 

intends to allow stimulation only at the discretion of the Director. The Director is in the 

best position to determine if well stimulation techniques, including but not limited to 

hydraulic fracturing, are appropriate in a given situation. EPA has added a requirement at 

§146.91(d)(2) that the owner or operator must notify the Director before any stimulation 

activities are undertaken. Such notice will provide the Director an additional opportunity 

to review stimulation plans, assess the description of stimulation fluids to be used, 

determine that stimulation will not interfere with containment, assess plan 

appropriateness, and potentially witness the stimulation activity. Although the plan will 

already have been approved by the Director as part of the permit application process and 

incorporated into the permit, this notification requirement gives the Director an 

opportunity to reassess the proposed stimulation activities in light of any new 

information. In order to preserve the integrity of the confining layer, EPA is retaining the 

prohibition against fracturing the confining layer at any time and adds that fracturing 

should not be allowed except during well stimulation. EPA clarifies that under no 

circumstances may stimulation endanger USDWs.

Comment [A74]: 

OMB-OIRA comment/edit. (11/08). 

Comment [A75]: 

EPA edit 11/12/10. 
Page 102 of 274

Tracers: In the proposed rule, EPA sought comment on the use of tracers in GS 

operations. Tracers are inert compounds added to or naturally occurring in the injection 

fluid, which can be easily detected through monitoring wells or through surface 

monitoring techniques. Detection of the tracer would indicate a leak of the injection fluid 

from the injection zone. Many types of tracers are available, including perfluorocarbons, 

SF6, noble gases, and stable isotopes such 18O and 14C. 

Some commenters supported the use of tracers in Class VI injection wells, maintaining 

that tracers are a useful method for detecting CO2 leaks. Many commenters suggested 

that tracers should not be required, but should be allowed at the discretion of the Director. 

Other commenters thought that owners or operators should be allowed to decide whether 

to use tracers. 

Most commenters asserted that tracers were unnecessary and that better methods for 

tracking CO2 movement were available. These commenters cited a variety of reasons, 

including that tracers were expensive, burdensome, and untested; that detection of a 

tracer at the surface would do nothing to protect USDWs from endangerment; and that 

some tracers may have health risks or can contribute to climate change. EPA received 

comments on specific tracers, such as perfluorocarbons (which have been proven in other 

applications), radioactive tracers (which have been used successfully in the oil and gas 

industry, but only with a limited radius), and the use of CO2 itself (which can act as a 

tracer). 

EPA agrees that tracers can be a useful tool in some circumstances, but recognizes that 

some factors (e.g., the potential to contribute GHGs to the atmosphere, cost, and 

difficulties associated with monitoring for tracers) may make other methods of tracking 

CO2 movement more practical. Therefore, today’s rule does not require use of tracers for 

Class VI wells. However, EPA does believe that tracers may be valuable in some cases, 

and will retain Director’s discretion to require the use of tracers and to determine the type 

of tracer to be used if the Director determines that their use will increase USDW 

protection from endangerment. 
Page 103 of 274

F. Testing and Monitoring 

Today’s final rule at §146.90 requires owners or operators of Class VI wells to develop 

and implement a comprehensive testing and monitoring plan for their projects that 

includes injectate monitoring, corrosion monitoring of the well’s tubular, mechanical, and 

cement components, pressure fall-off testing, ground water quality monitoring, CO2

plume and pressure front tracking, and, at the Director’s discretion, surface air and soil 

gas monitoring (SDWA section 1421 et al). The rule also requires MIT to verify proper 

well construction, operation, and maintenance. 

Monitoring associated with injection projects is an important component of the UIC 

program and is required to ensure that USDWs are not endangered. Monitoring data can 

be used to verify that the injectate is safely confined in the target formation, minimize 

costs, maintain the efficiency of the storage operation, confirm that injection zone 

pressure changes follow predictions, and serve as inputs for AoR modeling. Monitoring 

results will provide information about site performance when compared against baseline 

information (collected during the site characterization phase) or when compared to 

previous monitoring results. In conjunction with careful site selection and AoR

delineation, monitoring is critical to the successful operation, PISC, and site closure of a 

GS project. 

Today’s monitoring requirements are based on existing UIC regulations, tailored to 

address the needs and challenges posed by GS projects. For example, supercritical CO2 is 

different from many Class I injectates in physical properties and chemical composition. 

Also, many GS projects are anticipated to be “large-scale,” with large volumes of CO2

injected over long project life-spans. In the proposed rule, EPA sought comment on the 

testing and monitoring plan, MIT, the use of pressure fall-off testing, the types and 

amounts of ground water quality monitoring, pressure front tracking, geophysical 

methods, and surface air and soil gas monitoring. 
Page 104 of 274

The testing and monitoring requirements for Class VI wells at §146.90 incorporate

elements of pre-existing UIC requirements for monitoring and testing, tailored and 

augmented as appropriate for GS projects. EPA recognizes that much will be learned 

about monitoring and testing technologies and their application in various geologic 

settings in the early phases of GS deployment. Therefore, the Agency will evaluate 

monitoring data from early GS projects as part of the Agency’s adaptive rulemaking 

approach (See section II.F). The Agency is developing guidance to support testing and 

monitoring at GS sites. 

1. Testing and Monitoring Plan

EPA proposed that owners or operators of Class VI wells submit monitoring plans with 

their permit applications. These plans would be tailored to the GS project and be 

implemented upon Director approval, and, at a minimum, include procedures and 

frequencies for analysis of the chemical and physical characteristics of the CO2 stream; 

MIT (internal and external); corrosion monitoring; determination of the position of the 

CO2 plume and area of elevated pressure; monitoring of geochemical changes in the 

subsurface; and, at the discretion of the Director, surface air and soil gas monitoring for 

CO2 fluctuations, and any additional tests necessary to ensure USDW protection from 

endangerment. 

EPA sought comment on the testing and monitoring plan. Commenters recommended 

that the plan be reevaluated concurrently with AoR reevaluations. Commenters agreed 

that the plan should be site-specific and flexible to allow the use of varied monitoring and 

testing technologies. The Agency acknowledges the importance of flexibility and today’s 

rule maintains a testing and monitoring plan requirement that will allow for site 

specificity and selection of the most appropriate monitoring technologies. The Agency 

also acknowledges the importance of agreement between site-characterization data, AoR 

information, and monitoring and testing information. 

The final rule retains the requirement to develop and implement a testing and monitoring 

plan and requires that the approved plan be incorporated into the Class VI permit. 

Deleted: ,

Deleted: s

Comment [A76]: Edited per OMB OIRA 

comment 10/29.
Page 105 of 274

Owners or operators must also periodically review the testing and monitoring plan to 

incorporate operational and monitoring data and the most recent AoR reevaluation 

(§146.90(j)). This review must take place within one year of an AoR reevaluation, 

following significant changes to the facility, or when required by the Director. The 

iterative process by which this and other required plans are reviewed throughout the life 

of a project will promote an ongoing dialogue between the owner or operator 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 to address situations 

where there is a change in the AoR or other circumstances change, while adding little 

burden if the AoR reevaluation confirms that the plan is appropriate as written. The 

Agency is developing guidance that describes the contents of the project plans required in 

the GS rule, including the testing and monitoring plan.

2. CO2 Stream Analysis

Injectate analysis provides information on the chemical composition and physical 

characteristics of the injectate. Analysis of the CO2 stream for GS projects will provide 

information about any impurities that may be present and whether such impurities might 

alter the corrosivity of the injectate down-hole. Such information is necessary to inform 

well construction and the project-specific testing and monitoring plan, and enable the 

owner or operator to optimize well operating parameters while ensuring compliance with 

the Class VI permit. The proposed rule required that analysis of the CO2 stream be 

conducted prior to commencing injection and throughout injection operations at an 

appropriate frequency based on the CO2 source and the likelihood of variability in the 

injectate composition. Commenters supported the need for analysis of the CO2 stream. 

The final rule retains the requirement that owners or operators need to characterize their 

CO2 stream as part of their UIC permit application (§146.82(a)(7)), and throughout the 

operational life of the injection facility (§146.90(a)). The details of the sampling process 

and frequency must be described in the Director-approved, site/project-specific testing 

and monitoring plan.

Deleted: if 

Comment [A77]: Edited per OMB OIRA 

comment 10/29.
Page 106 of 274

Resource Conservation and Recovery Act (RCRA) Applicability to CO2 Streams: EPA 

received public comment asserting that the proposed UIC Class VI requirements were 

unclear as to whether the CO2 stream would be a RCRA hazardous waste, and left 

uncertain the type of permit needed. Many commenters stated that a CO2 stream should 

not be treated as a RCRA hazardous waste on the grounds that it is neither a listed 

hazardous waste nor does it exhibit a hazardous characteristic. Other commenters 

asserted that CO2 in the presence of water could exhibit the RCRA corrosivity 

characteristic. Additionally, commenters indicated that analytic procedures used under 

RCRA (in particular, the toxicity characteristic leaching procedure (TCLP)) cannot be 

applied to supercritical CO2 streams and that the Class VI regulations would better ensure 

the proper management of a CO2 injectate. EPA did not receive any new data on CO2

stream characterization in the public comments.

In general, subtitle C of RCRA establishes a “cradle to grave” regulatory scheme over 

certain “solid wastes” which are also “hazardous wastes.” RCRA defines solid waste as, 

among other things, discarded material, including solid, liquid, semisolid, or contained 

gaseous material. EPA has further defined the term solid waste for purposes of its 

hazardous waste regulations. To be considered a hazardous waste, a material must first be 

classified as a solid waste under the regulations (40 CFR 261.2). Under EPA’s 

regulations at 40 CFR 262.11, generators of solid waste are required to determine 

whether their wastes are hazardous wastes. A solid waste is a hazardous waste if it 

exhibits any of four characteristics of a hazardous waste (i.e., ignitability, corrosivity, 

reactivity, or toxicity) under 40 CFR 261.20-.24, or is a listed waste under 40 CFR 

261.30-.33 (these include various used chemical products, by-products from specific 

industries, or unused commercial products). 

A CO2 stream is not itself a listed RCRA hazardous waste. EPA has reviewed estimates 

of CO2 injectate quality, which were based upon information such as the quality of flue 

gas from the burning of fossil fuels, existing flue gas emission controls (e.g., electrostatic 

precipitators and scrubbers), and data from applied CO2 capture technology. These 

estimates indicate that captured CO2 could contain some impurities. These estimates also 

Deleted: A CO2 stream injected for purposes of 

GS is a RCRA solid waste, as it has been discarded. 

Additionally, EPA agrees that a CO2 stream is not 

itself a listed RCRA hazardous waste. The CO2

stream would be a hazardous waste if it exhibits any 

of the ignitability, corrosivity, reactivity or toxicity 

characteristics (40 CFR 261.20-.24) or is a listed 

waste (40 CFR 261.30-.33).

Comment [A78]: EPA edit made to simplify 

discussion. 

OMB-OIRA edit (deletion of period) (11/08). 
Page 107 of 274

indicate that the types of impurities and their concentrations would likely vary by facility, 

coal composition, plant operating conditions, and pollutant removal and carbon capture 

technologies. 

Under this final rule, owners or operators will need to determine whether the CO2 stream 

is hazardous under EPA’s RCRA regulations, and if so, any injection of the CO2 stream 

may only occur in a Class I hazardous waste injection well. Conversely, Class VI wells 

cannot be used for the co-injection of RCRA hazardous wastes (i.e., hazardous wastes 

that are injected along with the CO2 stream). 

EPA supports the use of CO2 capture technologies that minimize impurities in the CO2

stream. As a result of the public comments received on the proposed Class VI rule related 

to various RCRA applicability issues, EPA initiated a rulemaking separate from today’s 

final UIC Class VI rule. The RCRA proposed rule will examine the issue of RCRA 

applicability to CO2 streams being geologically sequestered, including the possible option 

of a conditional exemption from the RCRA requirements for CO2 GS in Class VI wells 

(see RIN 2050-AG60, EPA Semiannual Regulatory Agenda, Spring 2010, EPA-230-Z10-001). EPA will consider comments received on the Class VI rule during the

development of the RCRA proposal. The Agency clarifies that commenters who wish to 

submit comments on the RCRA proposal must do so during the comment period for that 

rule. Today’s rule does not itself change applicable RCRA regulations.

Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA)

Applicability to CO2 Streams: EPA received a range of comments regarding CERCLA 

liability and GS. Some commenters suggested that the Agency allow for a GS exemption 

under CERCLA, while others requested that the rule specify that injectate intrusion into a 

USDW is not considered a CERCLA release and that the SDWA provides enough civil 

and criminal enforcement authority to address any environmental contamination that 

might result from GS. Other commenters supported maximizing protection under 

CERCLA by writing Class VI GS permits as broadly as possible so that “unauthorized 

releases” are avoided. 

Deleted: proposed 

Comment [A79]: 

OMB-OIRA deletion of “proposed” (11/08). 

Comment [A80]: EPA edits made to clarify and 

update information and address OMB-OIRA 

comments/questions. 

Deleted: At the same time, the Agency agrees that 

any requirements for the CO2 stream should be 

clearly identified. EPA has begun to examine issues 

of RCRA regulation for CO2 streams, including 

options such as a conditional exemption from the 

RCRA requirements for CO2 GS. If appropriate, 

EPA will address these issues in a separate action

from today’s final UIC rule. 
Page 108 of 274

CERCLA, more commonly known as Superfund, is the law that provides broad Federal

authority to clean up releases or threatened releases of hazardous substances that may 

endanger human health or the environment. CERCLA references four other 

environmental laws to designate more than 800 substances as hazardous and to identify 

many more as potentially hazardous due to their characteristics pursuant to RCRA. 

CERCLA authorizes EPA to clean up sites contaminated with hazardous substances and 

seek compensation from responsible parties or compel responsible parties to perform 

cleanups themselves.

CO2 itself is not listed as a hazardous substance under CERCLA. However, the CO2

stream may contain a listed hazardous substance (such as mercury) or may mobilize 

substances in the subsurface that could react with ground water to produce listed 

hazardous substances (such as sulfuric acid). Whether such substances may result in 

CERCLA liability from a GS facility depends entirely on the composition of the specific 

CO2 stream and the environmental media in which it is stored (e.g., soil or ground water). 

CERCLA exempts from liability under CERCLA section 107, 42 U.S.C. 9607, certain 

“Federally permitted releases” (FPR) as defined in CERCLA, 42 U.S.C. 9601(10), which 

would include the permitted injectate stream as long as it is injected and behaves in 

accordance with the permit requirements. Class VI permits will need to be carefully 

structured to ensure that they prevent potential releases from the well, which are outside 

the scope of the Class VI permit and thus not considered federally permitted releases. 

The UIC program Director has authority under the SDWA to address potential 

compliance issues (e.g., potential releases that may endanger USDWs) resulting from 

injection violations in the unlikely event that an emergency or remedial response (at 

§146.94) is necessary. Although EPA anticipates that the need for emergency or remedial 

actions at GS sites will be rare, today’s rule requires that emergency and remedial 

response plans be developed and updated to address such events (in accordance with the 

remedial response requirements at §146.94) and that owners or operators demonstrate 

Comment [A81]: Edit made per OMB-OIRA 

comment (10/29)

Comment [A82]: Edit made per OMB-OIRA 

comment (10/29)
Page 109 of 274

that financial resources are set aside to implement the plans if necessary (pursuant to the 

financial responsibility requirements at §146.85).

3. Mechanical Integrity Testing (MIT)

Injection well MIT is a critical component of the UIC program’s requirements designed 

to ensure USDW protection from endangerment. Testing and monitoring the integrity of 

an injection well at an appropriate frequency throughout the injection operation, in 

conjunction with corrosion monitoring of well materials, can verify that the injection 

system is operating as intended or provide notice that there may be a loss of containment 

that may lead to endangerment of USDWs. Routine MITs enable owners or operators to 

ensure that well integrity is maintained from construction throughout the life of the 

injection project. UIC regulations for other deep-well classes require injection well 

owners or operators to demonstrate both internal and external mechanical integrity. 

Internal MIT: Internal mechanical integrity (MI) is an absence of significant leakage in 

the injection tubing, casing, or packer. Loss of internal MI is usually due to corrosion or 

mechanical failure of the injection well’s tubular and mechanical components. Typically, 

internal MI is demonstrated with an annual pressure test of the annular space between the 

injection tubing and long-string casing. 

For Class VI wells, EPA proposed that owners or operators perform an initial annulus 

pressure test and then continuously monitor injection pressure, injection rate, injected 

volume, pressure on the annulus between the tubing and long-stem casing, and annulus 

fluid during injection. EPA sought comment on the appropriate frequency of internal 

MIT and the practicality of continuous testing to measure internal MI. Commenters’ 

suggestions on the appropriate frequency varied and some believed that the proposed

requirement for continuous monitoring seemed excessive and/or impractical.

Today’s rule at §146.89 retains the requirements for continuous monitoring to 

demonstrate internal MI presented in the proposed rule. This is driven by concerns that 

the potential corrosivity of CO2 in the presence of water and the anticipated high 
Page 110 of 274

pressures and volumes of injectate could compromise the integrity of the well. 

Continuous monitoring to demonstrate internal MI for Class VI wells is essential because 

it allows for the immediate identification of corrosion-related mechanical integrity 

problems or problems due to temperature and pressure effects associated with injection of 

supercritical CO2. Furthermore, the technologies used for continuous monitoring are

currently available and widely used. 

External MIT: External well MI is demonstrated by establishing the absence of 

significant fluid movement along the outside of the casing, generally between the cement 

and the well structure, and between the cement and the well-bore. Failure of an external 

MIT can indicate improper cementing or degradation of the cement that was emplaced to 

fill and seal the annular space between the outside of the casing and the well-bore. This 

type of failure can lead to movement of injected fluids out of intended injection zones 

and toward USDWs. 

EPA proposed annual external MIT using a tracer survey, a temperature or noise log, a 

casing inspection log, or any other test the Director requires. EPA sought comment on the 

appropriate frequency and types of MITs for Class VI wells. In general, commenters 

requested flexibility in methods and timing of testing, with some suggesting a five-year 

frequency for external MIT. 

Because GS is a new technology and there are a number of unknowns associated with the 

long-term effects of injecting large volumes of CO2, today’s rule requires owners or 

operators of CO2 injection wells to demonstrate external MI at least once annually during 

injection operations using a tracer survey or a temperature or noise log (§146.89(c)). This 

increase in required testing frequency relative to other injection well classes ensures the 

protection of USDWs from endangerment given the potential corrosive effects of CO2 (in 

the presence of water) on well components (steel casing and cement) and the buoyant 

nature of supercritical CO2 relative to formation brines, which could enable it to migrate 

up a compromised wellbore. The Director may also authorize an alternate test of external 

mechanical integrity with the approval of EPA (§146.89(e)). Comment [A83]: Edited per OMB OIRA 

comment 10/29.
Page 111 of 274

In addition, the final rule is modified from the proposal to allow the Director discretion to 

require use of casing inspection logs to determine the presence or absence of any casing 

corrosion at §146.89(d). To ensure the appropriate application of this test and to afford 

flexibility to owners or operators and Directors, the final rule requires that the frequency 

of this test be established based on site-specific and well-specific conditions and 

incorporated into the testing and monitoring plan if the Director requires such testing. 

This modification is made to clarify that such logs, while not used to directly assess 

mechanical integrity, may be used to measure for corrosion of the long-string casing and 

thus may serve as a useful predictor of potential mechanical integrity problems in the 

future. 

4. Corrosion Monitoring

Existing UIC Class I deep well operating requirements allow the Director discretion to 

require corrosion monitoring and control where corrosive fluids are injected. Corrosion 

monitoring can provide early warning of well material corrosion that could compromise 

the well’s MI. Given the potential for corrosion of well components if they are in contact 

with water saturated with CO2 or CO2 in the presence of water, corrosion monitoring is 

included as a routine part of Class VI well testing. EPA proposed quarterly monitoring 

using coupons, routing the CO2 injectate through a loop of well material, or an alternative 

method proposed by the Director. 

Some commenters believed that such testing was unnecessary given that well materials 

will need to be constructed with materials compatible with the injectate. EPA notes, 

however, that the long-term effects of CO2 on cement and other well components are not 

yet completely understood. Given the anticipated long life-span of a Class VI well and 

the difficulties that would be associated with a corrosion-related well failure, EPA 

believes that quarterly corrosion monitoring is justified and retains the requirement in the 

final rule (at §146.90(c)). 

5. Ground Water/Geochemical Monitoring

Deleted: ,

Comment [A84]: Edited per OMB OIRA 

comment 10/29; 11/04 - comma deleted. 
Page 112 of 274

Ground water and geochemical monitoring are important monitoring techniques that 

ensure protection of USDWs from endangerment, preserve water quality, and allow for 

timely detection of any leakage of CO2 or displaced formation fluids out of the target 

formation and/or through the confining layer. Periodically analyzing ground water quality 

(e.g., salinity, pH, and aqueous and pure-phase CO2) above the confining layer can reveal 

geochemical changes that result from leaching or mobilization of heavy metals and 

organic compounds, or fluid displacement. 

EPA proposed periodic monitoring of the ground water quality and geochemical changes 

above the confining zone and sought comment on the types and frequencies of 

monitoring to be performed. The Agency agrees with commenters who support a flexible 

monitoring regime, and believes that the amounts and types of monitoring should be site 

specific. 

Some commenters expressed concern that monitoring wells penetrating the confining 

layer could become conduits for fluid movement. EPA clarifies that direct geochemical 

monitoring is not required in the target formation itself, although sampling via wells in 

the target formation may be desirable in some circumstances, e.g., to perform 

geochemical monitoring in wells used for direct pressure monitoring to meet 

requirements of §146.90(g). Furthermore, EPA believes that the benefits of direct 

monitoring using wells outweigh the risks of unintended fluid migration. Monitoring 

wells provide important information that confirms injectate confinement. Careful siting 

and appropriate construction of monitoring wells are critical to effective monitoring and 

can minimize the potential that monitoring wells serve as conduits for fluid movement. 

The final rule, at §146.90(d), retains the requirement for direct ground water quality 

monitoring as specified in the site-specific monitoring plan. Such monitoring is required 

above the confining zone (and below the lower confining zone for waivered wells

pursuant to requirements at §146.95(f)). The number, placement, and depth of monitoring 

wells will be site-specific and will be based on information collected during baseline site 

characterization. Ground water and geochemical monitoring results, when compared to 
Page 113 of 274

baseline site characterization data, previous monitoring results, and operational 

parameters will enable owners or operators and Directors to assess project performance, 

confirm that the injectate, formation fluids, and the injection operation are not impacting 

overlying (and underlying, for wells operating under injection depth waivers) formations, 

identify formation fluid changes, inform modifications to the monitoring plan, and ensure 

USDW protection from endangerment. 

6. Pressure Fall-Off Testing

Pressure fall-off tests are designed to determine if reservoir pressures are tracking 

predicted pressures and modeling inputs. The results of pressure fall-off tests will 

confirm site characterization information, inform AoR reevaluations, and verify that 

projects are operating properly and the injection zone is responding as predicted. 

EPA proposed that owners or operators perform pressure fall-off testing at least once 

every five years and requested comment on the use and frequency of these tests. Some 

commenters expressed support for the tests, and suggested frequencies of annually to

every five years. Some commenters expressed opposition to the tests stating that they are 

not necessary and the information they provide is not unique and may be obtained from 

other tests.

The Agency believes that pressure fall-off testing provides valuable information and that 

a five-year frequency is appropriate. The final rule, at §146.90(f), retains the requirement 

for testing at least once every five years. EPA believes that this frequency will allow for 

pressure tracking in the injection formation. It will also help to verify that the operation is 

responding as modeled/predicted and allow the owner or operator to take appropriate 

action (e.g., recalibration of the AoR model) in the event that the monitoring results do 

not match expectations. 

7. CO2 Plume and Pressure Front Monitoring/Tracking

Monitoring the movement of the CO2 and the pressure front are necessary to identify 

potential risks to USDWs posed by injection activities, verify predictions of plume 
Page 114 of 274

movement, provide inputs for modeling, identify needed corrective actions, and target 

other monitoring activities. The proposed rule required tracking of the plume and 

pressure front by direct pressure monitoring via monitoring wells in the first formation 

overlying the confining zone or by using indirect geophysical techniques such as seismic 

profiling, electrical, gravity, and electromagnetic surveys. 

EPA sought comment on the requirement to track the CO2 plume and pressure front and 

the appropriate technologies and geophysical methods that can be used for such 

monitoring. Commenters focused on appropriate testing frequency and technologies, 

expressing concerns about cost and the belief that the requirements were too stringent and 

might negatively affect public opinion. With respect to direct monitoring of pressure, 

some commenters supported the proposed approach, while others believed the use of 

monitoring wells would be costly and difficult. Some commenters supported indirect 

(i.e., geophysical) monitoring of the plume, while others expressed concerns that seismic 

methods may not be effective in all settings. 

In consideration of all public comments, today’s final rule at §146.90 requires Class VI 

well owners or operators to perform monitoring to track the extent of the CO2 plume and 

pressure front. The owner or operator must use direct methods to monitor for pressure 

changes in the injection zone. Indirect methods (e.g., seismic, electrical, gravity, or 

electromagnetic surveys and/or down-hole CO2 detection tools) are required unless the 

Director determines, based on site-specific geology that such methods are not appropriate 

(§146.90(g)). 

The purpose of monitoring in the injection zone (§146.90(g)(1)) is to track the 

development and movement of the pressure front and CO2 plume. This will support an 

understanding of site performance and verify predictive modeling. Pressure monitoring 

within the injection zone is necessary because any such monitoring above the confining 

zone would not detect movement of the pressure front unless a breach of the confining 

zone occurs. EPA believes that monitoring using wells in the injection zone (i.e., that 

penetrate the confining zone) can be safely performed if the wells are constructed to 
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prevent flow between the injection zone and USDWs or other layers above the confining 

zone. Such construction technologies exist and have been used in the oil and gas industry 

for years. EPA believes that the benefits of monitoring in the injection formation 

outweigh the manageable risk of those monitoring wells serving as conduits for fluid 

movement. EPA adds that owners or operators may consider performing additional 

pressure monitoring in wells that are above the confining zone (e.g., in the same wells 

used to perform ground water quality monitoring required at §146.90(d)) to provide 

additional verification that no pressure changes are occurring above the confining zone 

due to CO2 leakage or displacement of native fluids. An appropriate monitoring regimen 

will enhance public confidence in GS. EPA disagrees that the use of monitoring wells to 

track the plume and pressure front will be too costly and believes that the benefits 

outweigh the costs.

Additionally, §146.90(g)(2) requires owners or operators to track the position of the CO2

plume using indirect methods (e.g., seismic, electrical, gravity, or electromagnetic 

surveys and/or down-hole CO2 detection tools), unless the Director determines based on 

site-specific geology, that such methods are not appropriate. EPA is affording Director’s 

discretion regarding the use of geophysical techniques at some sites because the Agency 

recognizes that geophysical methods are not appropriate in all geologic settings. For 

example, geophysical methods are difficult to execute in areas that are structurally and 

topographically complex or where lithologies have limited contrast in density, porosity, 

permeability, and other physical properties. EPA clarifies that this determination will be 

made by the Director based on the site-specific geologic information submitted by the 

owner or operator with their permit application. However, because the use of geophysical 

methods can yield valuable information about the extent of the CO2 plume and pressure 

front, EPA is requiring their use unless they are determined not to be appropriate. 

EPA believes that this approach – requiring direct pressure monitoring at all sites and the 

use of indirect geophysical or down-hole techniques except where the Director 

determines that such methods are not appropriate based on site-specific information –

provides owners or operators the flexibility to develop a site-specific monitoring plan, 
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ensures that direct monitoring is available to track the movement of the CO2 and validate 

models, and recognizes that indirect techniques may not be appropriate in all situations. 

8. Surface Air/Soil Gas Monitoring

EPA proposed that Directors have discretion to require surface air and/or soil gas 

monitoring at GS sites. Surface air and soil gas monitoring can be used to monitor the 

flux of CO2 out of the subsurface, with elevation of CO2 levels above background levels 

indicating potential leakage and USDW endangerment. While deep subsurface well 

monitoring forms the primary basis for detecting threats to USDWs, knowledge of leaks 

to shallow USDWs is of critical importance because these USDWs are more likely to 

serve public water supplies than deeper formations. If leakage to a USDW should occur, 

near-surface and surface monitoring may assist owners or operators in identifying the 

general location of the leak and what USDWs may have been impacted by the leak, and 

initiating targeted emergency and remedial response actions. 

EPA sought comment on the use of surface air and soil gas monitoring technologies to 

ensure USDW protection. Commenters that supported the use of surface air and soil gas 

monitoring technologies stressed the importance of USDW protection and noted that this 

monitoring can provide a potential indication that a leak into a USDW has occurred and 

may need to be remediated. These commenters suggested that such monitoring should be 

site-specific and that any data collected must be compared against baseline data 

(collected prior to commencing an injection project). Those who opposed the proposed 

surface air and soil gas monitoring requirements questioned the applicability of surface 

air and soil gas technologies to USDW protection, and expressed concerns about the 

potential for false positives, uncertainty and variability in measurements, and the negative 

impact that this requirement may have on public perception of GS. Some commenters 

also believed that requiring such monitoring would be outside the scope of SDWA 

authority. 

The Agency agrees that surface air and soil gas monitoring, when coupled with 

subsurface monitoring, may be appropriate at some GS projects to ensure USDW 
Page 117 of 274

protection and agrees that baseline information is needed for this type of monitoring.

EPA also acknowledges that surface air and soil gas measurements are subject to 

variability and may not be suitable for all settings as a method to ensure USDW 

protection. However, EPA does not believe that this should entirely preclude their use. 

The decision to use surface monitoring and the selection of monitoring methods will be 

site-specific (e.g., may be influenced by geology; injection depth; and operational 

conditions) and must be based on potential risks to USDWs within the AoR. EPA also 

believes that appropriately selected surface monitoring technologies will not negatively 

influence public opinion, but could help to assure the public that GS projects are being 

appropriately operated and monitored. Used in conjunction with deep subsurface 

monitoring, as required at §146.90, and as part of a multi-barrier approach to protecting 

USDWs from endangerment, surface air and soil gas monitoring are within the scope of 

SDWA’s general authority (SDWA sections 1421 et al). Furthermore, where deployed, 

such monitoring will increase USDW protection, enable immediate notification of the 

UIC Director in the case of potential USDW endangerment, and facilitate remedial 

action.

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring 

at the discretion of the Director as a means of identifying leaks that may pose a risk to 

USDWs and informing emergency notification of a Class VI owner or operator and UIC 

Director in the event of a USDW endangerment, pursuant to requirements at §146.91(c).

Since proposal of the Class VI UIC requirements (73 FR 43492, July 25, 2008), EPA 

proposed, and is finalizing concurrently with this rulemaking, GS reporting requirements 

under the GHG Reporting Program (subpart RR). Subpart RR is being promulgated under 

authority of the CAA and builds on UIC requirements with the additional goals of 

verifying the amount of CO2 sequestered and collecting data on any CO2 surface 

emissions. If a Director requires surface air/soil gas monitoring pursuant to requirements 

at §146.90(h) and an owner or operator demonstrates that monitoring employed under 

§§98.440 to 98.449 of subpart RR meets the requirements at §146.90(h)(3), the Director 

must approve the use of monitoring employed under subpart RR. 
Page 118 of 274

The Agency recognizes that there may be unique circumstances wherein the UIC Director 

requires the use of surface air/soil gas monitoring other than monitoring deployed under 

subpart RR due to site-specific considerations. For example, a UIC Director may identify 

a sensitive USDW such as a sole source aquifer, as defined at 40 CFR 149, in the AoR of 

a GS project. He or she may determine that the most appropriate method of enhancing 

protection of such resources is to require the owner or operator to deploy an array of soil 

gas probes, pursuant to §146.90(h), around the sole source aquifer at specified depths and 

lateral spacing, with specified sampling and reporting frequencies, to ensure USDW 

protection. Such monitoring might not be necessary under Subpart RR, where the primary 

purpose of surface air and soil gas monitoring is to verify the amount of CO2 sequestered 

and collect data on any CO2 surface emissions.

EPA believes that the requirements of these two rules complement one another by 

concurrently ensuring USDW protection, as appropriate, and requiring reporting of CO2

surface emissions under subpart RR. Subpart RR is discussed further in section II.C.

9. Additional Requirements

EPA recognizes that monitoring and testing technologies used at GS sites will vary and 

be project-specific, influenced by both geologic conditions and project characteristics. At 

certain sites additional monitoring may be needed. Furthermore, EPA acknowledges that 

the science and technology behind subsurface monitoring and testing will continue to 

develop, and new methods may emerge to provide additional monitoring options. 

Therefore, the final rule (at §146.90(i)) allows the Director discretion to require 

additional monitoring where appropriate. For example, a Director may require a Class VI 

owner or operator to conduct ground water quality monitoring in additional formations or 

zones or require the use of multiple indirect geophysical methods for plume and pressure 

front tracking if he or she determines it is necessary based on review of project-specific 

information submitted.

Comment [A85]: 

OMB-OIRA track change, modified by EPA (11/08). 

Deleted: ¶
Page 119 of 274

The final rule, at §146.90(k), requires owners or operators to submit a quality assurance 

and surveillance plan (QASP) for all testing and monitoring requirements. A QASP 

ensures that all aspects of monitoring and testing are verifiable, including the 

technologies, methodologies, frequencies, and procedures involved. Each QASP will be 

unique to a given GS project, informed by site-specific details, monitoring technologies 

selected, and will be updated as the project evolves in concert with the testing and 

monitoring plan. 

G. Recordkeeping and Reporting 

Pursuant to §1445(a)(1) of the SDWA, today’s final rule at §146.91 requires owners or 

operators of Class VI wells to submit the results of required periodic testing and 

monitoring associated with the GS project. Furthermore, today’s rule at §146.91(e) also 

requires that all required reports, submittals, and notifications under subpart H be 

submitted to EPA in an electronic format. This requirement applies to owners or 

operators in Class VI primacy States and those in States where EPA implements the Class 

VI program, pursuant to §147.1. All Directors will have access to the data through the 

EPA electronic data system. 

EPA expects that the Class VI permit application process will be an iterative process,

during which the owner or operator must submit information to the Director to inform 

permitting decisions and permit issuance. During this process, the Director is responsible 

for reviewing and approving the required information. The Agency is requiring that 

owners or operators submit information in an electronic format to facilitate accessibility 

and transferability; however, if an owner or operator cannot submit the required data 

using EPA’s electronic reporting system, EPA expects the Director to seek EPA’s 

approval regarding an alternate reporting format. Following EPA’s approval of a nonelectronic submittal format, an alternate reporting procedure may be allowed.

The electronic reporting requirement is designed to facilitate programmatic activities by 

providing Directors with information needed to ensure compliance with UIC Class VI 

permits, while also ensuring that GS projects are operating properly, are in compliance 

Deleted: coordinate with EPA regarding when

Deleted: is necessary

Comment [A86]: Edited per OIRA comments 

10/31.

Deleted: s

Deleted: are

Deleted: provide the 

Deleted: the i

Comment [A87]: Edited per OIRA comment

10/31.
Page 120 of 274

with their permit conditions, and are sufficiently protective of USDWs. The information 

compiled under §146.91 may be used as evidence of a permit violation. 

Use of EPA’s electronic reporting system will also allow EPA to access data related to

Class VI program implementation and facilitate coordination between EPA and coregulators. EPA plans to use the data and information submitted by owners or operators 

to periodically evaluate the effectiveness of the GS program, enabling the Agency to 

make changes to the Class VI program as necessary to incorporate new research, data, 

and information about GS and associated technologies.

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

Today’s rule identifies the technical information and reports that Class VI owners or 

operators must submit to the Director to obtain a Class VI permit to construct, operate, 

monitor, and close a Class VI well. The information submitted as a demonstration, to the 

Director, must be in the appropriate format and level of detail necessary to support 

permitting and project-specific decisions by the Director to ensure USDW protection. 

The final decision regarding the appropriateness and acceptability of all owner or 

operator submissions rests with the Director.

Class VI Permit Application Information: Today’s rule requires owners or operators to 

submit, pursuant to the requirements at §146.91(e), information to the Director to support 

Class VI permit applications (this information is enumerated at §146.82). This 

information includes site characterization information on the stratigraphy, geologic 

structure, and hydrogeologic properties of the site; a demonstration that the applicant has 

met financial responsibility requirements; proposed construction, operating, and testing 

procedures; and AoR/ corrective action, testing and monitoring, well plugging, PISC and 

site closure, and emergency and remedial response plans. The specific requirements for 

the content of this information are discussed in other sections of this preamble.

Operational and Monitoring Reports: Today’s rule, at §146.91, requires owners or 

operators to submit project monitoring and operational data at varying intervals, 

Deleted: improve

Deleted: ’

Deleted: understanding of

Comment [A88]: 

OMB-OIRA modified track change (11/08) and

(11/10)
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including semi-annually and prior to or following specific events (e.g., 30 day

notifications and 24 hour emergency notifications). 

EPA proposed that operating data be reported semi-annually. EPA also proposed that 

monitoring data be submitted semi-annually in certain circumstances. Several 

commenters asked that the Director have discretion to authorize reporting less frequently 

than semi-annually, while other commenters suggested monthly or quarterly reporting. 

EPA is retaining the semi-annual reporting requirement for operating data and some 

monitoring data in the final rule (§146.91(a)). However, permitting authorities may 

choose to require more frequent reporting. 

The final rule also requires owners or operators to report the results of mechanical 

integrity tests, any other injection well testing required by the Director, and any well 

workovers within 30 days (§146.91(b)), as proposed. 

Today’s final rule consolidates notification requirements and clarifies the manner in 

which the data must be reported. Owners or operators must notify the Director in writing 

30 days prior to any planned well workover, stimulation, or test of the injection well 

(§146.91(d)). This notification affords the Director an opportunity to evaluate the planned 

activity in the context of new information received since permit approval and correspond 

with the owner or operator, if necessary, regarding any suggested modifications to the 

planned activity or to place additional conditions on the planned activity if necessary. 

EPA clarifies that a response by the Director following 30-day notification is not required

if the Director has no further concerns regarding the activity. The final rule also requires 

owners or operators to notify the Director within 24 hours of obtaining any evidence that 

the injected CO2 stream and associated pressure front may cause an endangerment to a 

USDW, any noncompliance with a permit condition, or of an event (such as malfunction 

of the injection system or triggering of a down-hole automatic shut-off system) that may 

endanger USDWs, or any release of carbon dioxide to the atmosphere or biosphere

detected through any required soil/air monitoring (§146.91(c)). 

Deleted: ,

Comment [A89]: 

OMB-OIRA track change (11/08). 

Deleted: ,

Deleted: semi-annually, 

Deleted: s

Deleted: , 

Deleted: s

Comment [A90]: Edited per OIRA comment and 

associated track change edit 10/31.

Deleted: incorporated into the 

Deleted: explicitly 

Comment [A91]: 

OMB-OIRA edit in response to comment (11/08). 

Minor clarifying edits to text in response to OMBOIRA comment (11/10).
Page 122 of 274

Area of review reevaluations and plan amendments: Today’s final rule requires owners 

or operators to electronically submit AoR reevaluation information and all plan 

amendments, pursuant to §146.84, at a minimum of every five years. 

Annual report: In addition to the recordkeeping and reporting requirements, EPA sought 

comment on requiring submittal of an annual report throughout the duration of a GS 

project. Most commenters did not support annual reports. 

Today’s final rule does not include a requirement for an annual report. EPA recognizes 

the concerns expressed by commenters about the burden associated with an annual report, 

and believes that the reporting required at §146.91(a) in conjunction with the AoR 

reevaluations and associated plan updates, which are required no less frequently than 

every five years, will facilitate a continuous dialogue between owners or operators and 

the permitting authority, provide evidence of compliance with the Class VI permit, and 

ensure protection to USDWs. 

2. How Must Information Be Submitted?

Electronic Reporting: Recognizing that much of the data generated during Class VI site 

characterization, operation, testing and monitoring, mechanical integrity testing, and 

during the post-injection site care period will be generated in electronic format, EPA 

proposed that owners or operators report data in an electronic format acceptable to the 

Director (§146.91). EPA also proposed that the Director have discretion to accept data in 

other formats, if appropriate. EPA sought comment on electronic data submissions and 

the concept of providing Directors discretion to accept other data formats. See section 

II.C for additional information on mandatory reporting of greenhouse gases under the 

Clean Air Act.

Most commenters supported the concept of requiring data to be submitted electronically. 

Commenters also recognized that there may be a need to accept data in other formats. 

Several commenters expressed concern about whether States would have the capabilities 

to accept electronic data submissions from owners or operators.
Page 123 of 274

In light of the prevalent use of electronic data, the expectation that Class VI wells will be 

used into the future, that the capability to send and receive electronic data will improve 

over time, and that today, information generated during GS site characterization, 

operation, monitoring, and testing is generated in electronic formats, the final rule 

requires that owners or operators submit data in an electronic format. 

Acknowledging that some States may have to develop electronic data systems to receive 

electronic information from the owner or operator, and that many States which already 

have electronic data systems will have to make changes to accommodate a new class of 

UIC well (Class VI), EPA believes that it is prudent to provide assistance by developing a 

central framework for the electronic system that will be used by States to gather and track 

owner or operator data. This will enable owners or operators to submit data without 

having to wait for a State to develop a system. It will also provide for standardized 

submissions across the country and enable States to focus State resources on reviewing 

and approving permit applications rather than building or upgrading separate, 

independent databases for GS information.

EPA recognizes that there may be some circumstances where it may be necessary to 

collect data in other formats, e.g., for historical data, etc. Therefore, the Agency is 

providing for the Director to allow submission of data in alternative formats on a case-bycase basis. EPA expects that decisions to allow submission of data in formats other than 

electronic will be based on the inability or inefficiency of converting data to electronic 

formats, rather than the ability of the State to accept electronic data.

3. What are the Recordkeeping Requirements under This Rule?

Today’s final rule requires that owners or operators retain most operational monitoring 

data as required under §146.91 for 10 years after the data are collected. In addition, the 

rule requires that owners or operators retain certain data until 10 years after site closure. 

This recordkeeping timeframe, which is longer than requirements for other injection well 

classes, is appropriate and tailored to the longer life-spans of GS projects. 
Page 124 of 274

The proposed rule did not include any requirements for operational data recordkeeping. 

However, existing UIC requirements at 40 CFR 144.51(j), which apply to all permitted 

injection wells require retention of certain operational data and permit application data 

for three years and retention of injectate quality data throughout the life of the project and 

for three years after injection well plugging. Commenters requested clarity on the 

recordkeeping requirements for Class VI well owners or operators, particularly related to 

well plugging and site closure reports.

Today’s final rule clarifies the recordkeeping requirements for Class VI well owners or 

operators. These include the requirements at 40 CFR 144.51(j) and the Class VI-specific 

recordkeeping requirements in today’s rule at §146.91(f). Class VI well owners or 

operators must retain data collected to support permit applications and data on the CO2

stream until 10 years after site closure. Owners or operators must retain monitoring data 

collected under the testing and monitoring requirements at §146.90(b-i) for 10 years after 

it is collected. Today’s rule allows the Director authority to require the owner or operator 

to retain specific operational monitoring data for a longer duration of time 

(§146.91(f)(5)). Well plugging reports, PISC data, and site closure reports must be kept 

for 10 years after site closure (§§146.92(d), 146.93(f), and 146.93(h)).

EPA believes that longer record retention timeframes are appropriate for Class VI wells 

to ensure that all necessary data are available to support AoR reevaluations, updates to 

the various plans which will occur at least every five years, and non-endangerment 

demonstrations during PISC. In addition, extended retention periods will ensure that data 

are available should any project-specific questions or concerns arise following site 

closure. These data will also support EPA’s review of project data as part of the adaptive 

rulemaking approach.

Class VI compliance: Today’s final Class VI rule includes requirements for permitting, 

siting, construction, operation, financial responsibility, testing and monitoring, PISC, and 

site closure of Class VI injection wells to ensure that USDWs are not endangered. SiteDeleted: 4

Deleted: e

Deleted: g

Comment [A92]: Edit made to correspond to 

final PISC changes made in response to OMB-OIRA 

communication (11/12).
Page 125 of 274

specific information collected during the site characterization process and periodically 

updated throughout the life of the project is incorporated into the GS project plans and 

used to establish permit conditions. This information establishes the manner in which an 

owner or operator must construct, operate, monitor, report on, and close a Class VI GS 

project – the conditions the owner or operator must meet to ensure compliance. Pursuant 

to requirements at 40 CFR 144.8, an owner or operator’s failure to comply with the sitespecific permit conditions, failure to complete construction elements, failure to complete 

or provide compliance schedules or monitoring reports, failure to submit complete 

reports, and any action that causes USDW endangerment during the life of the GS project 

are considered instances of noncompliance and will result in a violation of the permit 

under SDWA section 1423. Additionally, EPA may use this information as evidence of 

an imminent and substantial endangerment of a USDW, which may require remedial

action under SDWA section 1431. 

Data and information gathered through information requests, semi-annual and 30-day 

reporting, and other project records will provide information to demonstrate and confirm 

that a Class VI project is in compliance. Information reported within 24 hours as required 

under §146.91(c), including, but not limited to: evidence that the injected CO2 stream or 

associated pressure front may cause an endangerment to a USDW; triggering of a shutoff system; or failure to maintain mechanical integrity is used to inform the Director of 

any evidence indicating that an owner or operator of a Class VI well has violated a permit 

condition or caused endangerment to USDWs. 

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

Today’s final action, at §146.92 requires owners or operators of Class VI wells to plug 

injection and monitoring wells in a manner that protects USDWs. The final rule, at 

§146.93, also contains tailored requirements for extended, comprehensive post-injection 

monitoring and site care of GS projects following cessation of injection until it can be 

demonstrated that movement of the CO2 plume and pressure front no longer pose a risk

of endangerment to USDWs. 

Deleted: 

Deleted: An owner or operator that fails to reestablish operation within the established permit 

conditions within 45 days is also considered 

noncompliant, pursuant to the requirements at 40 

CFR 144.8.

Comment [A93]: Edit made in response to 

OMB-OIRA comment (11/01). 

Deleted: 
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Proper plugging of injection and monitoring wells is a long-standing requirement in the 

UIC program designed to ensure that injection wells do not serve as conduits for fluid 

movement following cessation of injection and site closure in order to ensure protection 

of USDWs. PISC, which is unique to GS, is necessary to ensure that site monitoring 

continues until the injectate and any mobilized fluids do not pose a risk to USDWs.

1. Injection Well Plugging

EPA proposed that, after injection ceases at a GS project, the injection well must be 

plugged in order to ensure that the well itself does not become a conduit for fluid 

movement into USDWs. Well plugging activities include flushing the well with a buffer 

fluid, testing the external mechanical integrity of the well, and emplacing cement into the 

well in a manner that will prevent fluid movement that may endanger USDWs. In the 

proposed rule, EPA did not specify the types of materials or tests that must be used 

during well plugging, acknowledging that there are a variety of methods that are 

appropriate and new materials and tests may become available in the future. However, all 

plugging materials must be compatible with the injectate (i.e., such that plugging 

materials would not degrade over time). EPA sought comment on the injection well 

plugging activities identified in the proposed rule. 

Most commenters supported EPA’s proposed approach regarding well plugging. Because 

the injection well plugging requirements provide appropriate protection of USDWs while 

allowing owners or operators flexibility in meeting the well plugging requirements by 

allowing them to choose from available materials and tests to carry out the requirements,

EPA retains the requirements as proposed in today’s rule at §146.92. The owners or 

operators must prepare and comply with a Director-approved injection well plugging plan 

submitted with their permit application (§146.92(b)). The approved injection well 

plugging plan will be incorporated into the Class VI permit. The Agency is developing 

guidance that describes the contents of the project plans required in the GS rule, 

including the injection well plugging plan. 

Comment [A94]: Edited per OMB OIRA 

comment 10/29.
Page 127 of 274

Owners or operators must submit a notice of intent to plug at least 60 days prior to 

plugging the well. At this time, if any changes have been made to the original well 

plugging plan (e.g., based on operational and monitoring data or data collected during 

AoR reevaluations), the owner or operator must submit a revised injection well plugging 

plan (§146.92(c)). Any amendments to the injection well plugging plan must be 

incorporated into the permit following public notice and comment and approval by the 

Director. EPA envisions that owners or operators will take into account similar 

considerations that guide updates to other project plans, e.g., the testing and monitoring 

plan, as they update the injection well plugging plan. However, EPA is not requiring 

formal periodic review and updates to the injection well plugging plan throughout the 

injection phase because it is not expected that changes to this plan will be implemented 

until the point at which the injection well is to be plugged. EPA also encourages an 

ongoing dialogue between owners or operators and Directors regarding planned well 

plugging activities. Finally, owners or operators must submit, to the Director, a plugging 

report within 60 days after plugging. The Agency is developing guidance on injection 

well plugging, PISC, and site closure that addresses performing well plugging activities.

2. Post-Injection Site Care (PISC)

Today’s final rule at §146.93 incorporates a PISC period, specific to Class VI wells. 

PISC is the period after CO2 injection ceases—but prior to site closure – during which the 

owner or operator must continue monitoring to ensure USDW protection from 

endangerment. 

PISC and site closure plan submittal and updates: EPA proposed that owners or 

operators would prepare, update, and comply with a Director-approved PISC and site 

closure plan that would describe the anticipated PISC monitoring activities and 

frequency. 

EPA sought comment on the PISC and site closure plan requirements. Most commenters 

supported the requirement for PISC monitoring and the proposed approach regarding 

submittal, revision, and implementation of a PISC and site closure plan. Many 
Page 128 of 274

commenters agreed that a PISC monitoring plan is a necessary and important part of the 

permitting process. These commenters supported the option to amend the plan. However, 

they contended that, upon cessation of injection, if evaluation of monitoring and 

modeling results indicates that the project is performing as expected, an owner or 

operator should not have to submit amendments to the plan. 

Today’s final regulation retains the PISC and site closure plan requirements (§146.93)

with an additional requirement at §146.93(a)(2)(v) that the owner or operator include the 

duration of the PISC timeframe, and the demonstration of any alternative PISC timeframe 

pursuant to requirements at §146.93(c) as part of the plan. The requirement to maintain 

and implement the approved PISC and site closure plan is directly enforceable regardless 

of whether the requirement is a condition of the Class VI permit. The PISC and site 

closure plan will serve to clarify PISC requirements and procedures prior to 

commencement of a project. 

Upon cessation of injection, today’s rule requires that owners or operators of Class VI 

wells either submit an amended PISC and site closure plan or demonstrate to the Director 

through monitoring data and modeling results that no amendment to the plan is needed 

(§146.93(a)(3)). Any amendments to the PISC and site closure plan would be 

incorporated into the permit once they are approved by the Director. EPA envisions that 

owners or operators would take into account similar considerations that guide updates to 

other project plans, e.g., the testing and monitoring plan, as they update the PISC and site 

closure plan. EPA also encourages an ongoing dialogue between owners or operators and 

Directors regarding planned PISC and site closure activities. The Agency is developing 

guidance that describes the content of the project plans required in the GS rule, including 

the PISC and site closure plan.

PISC timeframe: EPA proposed that during PISC, owners or operators of Class VI wells 

would be required to periodically monitor the site and track the position of the CO2

plume and pressure front to ensure USDWs are not endangered. The proposed rule 

identified a default PISC timeframe of 50 years following the cessation of injection. This 

Deleted: as proposed

Comment [A95]: Added 11/11 per OIRA 

discussion.

Deleted: However, EPA is not requiring formal 

periodic review and updates to the PISC and site 

closure plan throughout the injection phase because 

it is not expected that changes to this plan would be 

implemented until cessation of injection activities. 

Comment [A96]: Change made 11/11 per OIRA 

discussion.
Page 129 of 274

timeframe was based on a review of research studies, industry reports, and existing 

environmental programs. In order to support site-specific flexibility, the proposed rule 

stipulated that the PISC timeframe could be shortened by the Director after cessation of 

injection if the owner or operator could demonstrate that USDWs would not be 

endangered prior to 50 years. Similarly, if after 50 years the Director determined that 

USDWs may still become endangered by the CO2 plume and/or pressure front, he or she 

could lengthen the PISC timeframe. EPA sought comment on the proposed PISC

timeframe and whether the timeframe should be adjusted. 

Most industry commenters supported reducing the default PISC timeframe, stating that 

the 50-year default timeframe in the proposal would make GS prohibitively expensive, 

and is not warranted based on the probable timeframes of CO2 trapping. Commenters 

suggested that the PISC timeframe should be specific to the characteristics of a project, 

including the predicted extent of the CO2 plume and the area of elevated pressure, 

geologic factors, modeled predictions of CO2 trapping, and subsurface geochemical 

reactions and that the PISC period be established on a case-by-case basis as a part of the 

permitting process. Other commenters supported the proposed 50-year PISC period and 

indicated that the risks of GS to USDWs are still unclear, and thus a conservative PISC 

monitoring time period should be implemented. Other commenters asserted that a 

combination of a fixed timeframe and a performance standard would strike a good 

balance and is preferable to relying on only one approach. 

EPA evaluated comments advocating for a shorter timeframe, including suggestions of 10 

and 30 years. However, EPA has not obtained any data from commenters or identified 

other research that contradict EPA’s initial analysis and supports a default timeframe 

shorter than 50 years. EPA acknowledges the merits of a performance-based approach for 

the PISC timeframe, recognizing the variety of site conditions that will affect the 

appropriate PISC timeframe. EPA believes that the Director will be in the best position to 

make a site-specific determination allowing for the PISC timeframe to be modified while 

ensuring USDWs are not endangered.

Comment [A97]: Added 11/11 per OIRA 

discussion.

Comment [A98]: Added 11/11 per OIRA 

discussion.
Page 130 of 274

Therefore, in response to comments, EPA retains the proposed default 50-year PISC 

timeframe. However, today’s final rule affords flexibility regarding the duration of the 

PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC 

timeframe during the PISC period based on site-specific data, pursuant to requirements at 

§146.93(b); and, (2) affording the Director discretion to approve a Class VI well owner or 

operator to demonstrate, based on substantial data during the permitting process, that an 

alternative PISC timeframe is appropriate if it ensures non-endangerment of USDWs 

pursuant to requirements at §146.93(c).

EPA clarifies that owners or operators of all GS sites (i.e., those commencing injection 

using the 50-year default PISC or those demonstrating an alternative PISC timeframe 

pursuant to requirements at §146.93(c)) must continue monitoring until they submit, for 

Director review and approval, a demonstration based on monitoring and other sitespecific data that no additional monitoring is needed to ensure that the GS project does 

not pose an endangerment to USDWs. If a demonstration cannot be made that the GS 

project no longer poses a risk of endangerment to USDWs, or the Director does not 

approve the demonstration, the owner or operator must submit a plan to the Director to 

continue post-injection site care until such a demonstration can be made and approved by 

the Director. 

Today’s final rule at §146.93(c), affords the Director discretion to approve a 

demonstration during the permitting process (per requirements at §146.82(a)(18)) that an 

alternative post-injection site care timeframe, other than the 50 year default, is 

appropriate. The demonstration must be based on substantial evidence and site-specific 

data and information compiled and analyzed during the permitting process and must 

satisfy the Director, in consultation with EPA that USDWs will be protected from 

endangerment from GS activities.

Today’s final rule at §146.93(c)(1) specifies what the Director, in consultation with EPA, 

must consider and what the demonstration of an alternative PISC timeframe must be 

based on: the results of site-specific computational modeling of the AoR (performed 

Comment [A99]: Added 11/11 per OIRA 

discussion.
Page 131 of 274

pursuant to §146.84) and information that supports the PISC and site closure plan 

development required at §146.93(a), including the predicted timeframe for pressure 

decline within the injection zone and any other zones; the predicted rate of CO2 plume 

migration and timeframe for the cessation of migration; site-specific chemical processes 

that will result in CO2 trapping (e.g., by capillary trapping, dissolution, and 

mineralization); the predicted rate of CO2 trapping; and laboratory analyses, research 

studies, and/or field or site-specific studies to verify the information on trapping. The 

demonstration must also be based on consideration and documentation of a 

characterization of the confining zone(s), e.g., thickness, integrity, and the absence of 

transmissive faults, fractures, and micro-fractures (based on information collected per 

§146.82(a)(3)); the presence of potential conduits for fluid movement near the injection 

well (per §146.84(c)(2)); the quality of wells and well plugs in wells within the AoR (per 

§146.84(c)(3)); the distance between the injection zone and the nearest USDWs above 

and/or below the injection zone (based on data collected per §146.82(a)(5)); and any 

additional site-specific factors required by the Director.

The demonstration of an alternative PISC timeframe must meet criteria set forth at 

§146.93(c)(2) to ensure that the data and models on which the demonstration is based are 

accurate, appropriate to site-specific circumstances, based on the best available 

information, calibrated where sufficient data are available, and reproducible. This 

demonstration must be submitted as part of the permit application pursuant to 

§146.82(a)(18); the duration of the alternative PISC timeframe and the associated 

demonstration must be included in the PISC and site closure plan pursuant to 

§146.93(a)(2)(iv); and, must be incorporated in the permit as part of the PISC and site 

closure plan as required at §146.82(c)(9). 

Over the lifetime of the project, owners or operators must periodically reevaluate the 

AoR regardless of the PISC timeframe approved by the Director. This may also result in 

periodic reevaluations and updates as needed to the PISC and site closure plan (per 

§146.93(a)(4)). These reevaluations provide opportunities for the owner or operator and 

the Director to review and validate the data on which the alternative demonstration is 
Page 132 of 274

based, along with operational and monitoring data, to determine whether modifications to 

the alternative PISC timeframe are needed, and to make changes to the PISC plan as 

appropriate. Regardless of whether the PISC and site closure plan is modified during the 

injection period or not, the rule requires at §146.93(a)(3) that upon cessation of injection, 

owners or operators must either submit an amended plan or demonstration to the Director 

through monitoring data and modeling results that no amendment to the plan is needed. 

Today’s final rule also retains the proposed approach affording the Director discretion, 

during the PISC period, to shorten the PISC timeframe if the owners or operators can 

demonstrate that there is substantial evidence that the GS project no longer poses a risk of 

endangerment to USDWs (§146.93(b)). Likewise, the Director may lengthen the PISC 

timeframe if, after 50 years, USDWs still may become endangered. 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility 

to adjust the timeframe during the permitting process where substantial data exists to 

demonstrate that an alternative timeframe would be protective of USDWs, or based on 

data collected during the PISC period, is appropriate to address the range of sites where 

GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW 

protection. The Agency is developing guidance on injection well plugging, PISC, and site 

closure.

3. Site Closure

EPA proposed that, following a determination under §146.93 that the site no longer poses 

a risk of endangerment to USDWs, the Director would approve site closure and the 

owner or operator would be required to properly close site operations. EPA proposed site 

closure activities similar to those for other well classes. These include plugging all 

monitoring wells; submitting a site closure report; and recording a notation on the deed to 

the facility property or other documents that the land has been used to sequester CO2. Site 

closure would proceed according to the approved PISC and site closure plan. Today’s 

final regulation retains these closure requirements (at §146.93(d) through (h)).

Deleted: EPA retains the proposed hybrid 

approach of a default 50-year timeframe, while 

allowing the Director discretionEPA retains the 

proposed hybrid approach of a default 50-year 

timeframe, while allowing the Director discretion

Comment [A100]: Added 11/11 per OIRA 

discussion.

Deleted: c

Deleted: g

Comment [A101]: Change made 11/11 per 

OIRA discussion.
Page 133 of 274

The site closure report will provide documentation of injection and monitoring well 

plugging; copies of notifications to State and local authorities that may have authority 

over future drilling activities in the region; and records reflecting the nature, composition, 

and volume of the injected CO2 stream. The purpose of this report will be to provide 

information to potential, future users and authorities of the land surface and subsurface 

pore space regarding the operation. Well plugging reports, PISC data, including, if 

appropriate, data and information used to develop the alternative PISC timeframe, and 

site closure reports must be kept for 10 years after site closure (or longer at the Director’s 

discretion), pursuant to the requirements at §§146.91(f),146.93(f), and 146.93(h). See 

section III.G for more about the recordkeeping requirements in today’s rule.

I. Financial Responsibility 

Today’s rule finalizes regulations at §146.85 to require that owners or operators 

demonstrate and maintain financial responsibility as approved by the Director for 

performing corrective action on wells in the AoR, injection well plugging, PISC and site 

closure, and emergency and remedial response. 

The purpose of these financial responsibility requirements is to ensure that owners or 

operators have the resources to carry out activities related to closing and remediating GS 

sites if needed during injection or after wells are plugged but before site closure is 

approved so that they do not endanger USDWs. The end result is ensuring that all the GS 

injection sites are cared for and maintained appropriately and that there is no gap in 

coverage throughout injection and post-injection site care and site closure. 

EPA's Proposed Approach: Financial assurance for wells under the UIC program is 

typically demonstrated through two broad categories of financial instruments: 1) third 

party instruments, including surety bond, financial guarantee bond or performance bond, 

letters of credit (the above third party instruments must also establish a standby trust 

fund), and an irrevocable trust fund; and 2) self-insurance instruments, including the 

corporate financial test and the corporate guarantee. In the preamble to the proposed rule, 

Comment [A102]: Added 11/11 per OIRA 

discussion.

Deleted: §146.93(e)

Deleted: §146.93(g).

Comment [A103]: Change made 11/11 per 

OIRA discussion.
Page 134 of 274

EPA described these instruments and sought comment on the need to adjust financial 

responsibility instruments for GS projects and the need for additional financial 

responsibility instruments. The Agency also sought comment on allowing separate 

financial demonstrations for injection well plugging and PISC (i.e., a demonstration 

submitted prior to well plugging and the beginning of the post-injection site care period 

rather than with the permit application).

Summary of Public Comments and Other Input: Commenters identified strengths and 

weaknesses of the various financial responsibility instruments and expressed concerns 

about the risk of bank failures and corporate insolvency, which could leave financial 

obligations unfunded. Some commenters supported the use of self insurance (i.e., a 

financial test and a corporate guarantee) as a mechanism to demonstrate financial 

responsibility for GS projects, but expressed concerns that companies that have passed 

financial tests can fail, and also that the current tangible net worth requirement of $10 

million is not adequate for GS projects. Generally, commenters supported allowing 

separate financial demonstrations for injection well plugging and PISC. Many 

commenters expressed concern about the potential high cost and long time frames 

involved with GS projects. They believed that financial assurance would be difficult to 

obtain, particularly throughout the duration of the PISC period and that it may discourage 

investment in GS. 

Commenters also expressed a need for regulatory certainty to help inform financial 

responsibility requirements for well owners or operators. They suggested that EPA 

specify the acceptability of various financial responsibility instruments and that States 

needed guidance including information on what instruments they should approve in order 

to avoid approving financial assurance that did not meet the Federal requirements or that 

was financially inadvisable. Other commenters suggested that the proposed rule left too 

much discretion to the Director, possibly causing operators to run a higher risk of having 

their instrument rejected. Other commenters suggested that the rule provide flexibility to 

owners or operators in the choice of financial instruments, while allowing the Director 

discretion to assess instruments in the context of operational and site-specific factors, 
Page 135 of 274

including the level of risk over time, when approving financial responsibility for each 

project. 

Many commenters addressed the use of a pay-in period for trust funds. Some commenters 

expressed concern that an initial three-year pay-in period would increase upfront costs, 

while others suggested that an initial pay-in period could help lower financial risk. A 

commenter suggested that the duration of the pay-in period could coincide with the 

estimated project risk. 

In addition to evaluating public comments, EPA worked with members of the public, 

academia, industry, regulatory agencies, and financial experts to address the unique 

financial responsibility issues associated with GS projects. In April and May of 2009, 

EPA held webinars for the public and industry stakeholders to gather information to 

inform the financial responsibility requirements and guidance. The webinars facilitated 

information sharing among stakeholders on financial instruments that could be used to 

meet the financial responsibility requirements for GS projects. Approximately 100 

webinar participants, representing a range of organizations with interest in and unique 

perspectives on financial responsibility, attended the workshop series which focused on 

the strengths and weaknesses of various financial instruments and their applicability for 

various injection activities. The material presented during the webinars and summaries of 

participant discussions can be found in the docket for today’s rulemaking. 

EPA is also aware of recent published literature on the topic of financial responsibility for 

GS. In particular, the World Resources Institute (WRI) and CCS Regulatory Project 

(affiliated with Carnegie Mellon University, Department of Engineering and Public 

Policy) have published research on climate change technologies and policy issues. These 

and other resources are informing EPA's financial responsibility guidance. These reports 

can be found in the docket for today’s rulemaking. 

To supplement publicly available literature and public comments, EPA reevaluated the 

current minimum Tangible Net Worth (TNW) requirement of $10 million used in the 
Page 136 of 274

Class I regulations and will recommend a TNW threshold for Class VI wells in guidance. 

EPA guidance on TNW for GS will help ensure that the risk borne by the public from a 

self-insured owner or operator is no greater than the riskiest scenario where independent 

third-party instruments are used. The financial responsibility guidance will also include a 

recommended cost estimation methodology to assist owners or operators of Class VI 

wells. The guidance will provide examples of cost considerations and activities that may 

need to be performed to satisfy the requirements of today’s rule. A draft of this guidance 

will be posted on EPA’s web site at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm for a 30-day public 

comment period concurrent with or shortly after publication of today’s final rule.

EPA solicited input from the Environmental Financial Advisory Board (EFAB) to 

develop recommendations on financial responsibility for Class VI wells absent any 

constraints under the SDWA. EFAB made several recommendations that support the 

financial responsibility requirements in today’s final rule. EFAB agreed that both self 

insurance and third-party insurance should be made available to responsible parties. They 

also supported the requirement that third-party providers, such as insurers, pass financial 

strength requirements, the use of credit ratings to demonstrate financial strength, and that 

the owner or operator notify the Director in the event of bankruptcy. EFAB also agreed 

that financial responsibility requirements be linked to cost estimates, with regular updates 

to both cost estimates and financial responsibility demonstrations. Additionally, EFAB 

specifically recommended:

• The use of standardized language for financial instruments. Although EFAB did not 

recommend the use of standardized policy language for insurance, they did suggest

that procedures be adopted so that the Director can specifically agree to limitations 

contained in the insurance policy or specifically reject such limitations during the 

review process;

• That the owner or operator be required to notify the Director by certified mail of any 

proceeding under Title 11 (Bankruptcy), US Code, within 10 business days after the 

Deleted: s

Deleted: s

Deleted: www. 

Deleted: the 

Comment [A104]: 

OMB-OIRA edit 11/12/10
Page 137 of 274

commencement of the proceeding; that owners or operators be deemed to not possess 

the required financial responsibility in the event of bankruptcy, insolvency, or a 

suspension or revocation of the license or charter of the third party when using letters 

of credit, surety bonds, or insurance policies or loss of authority of the third party to 

act as a trustee when using a trust fund; 

• That because the RCRA financial mechanisms, which are largely used in the SDWA 

Class I program, were developed based on hazardous waste facility owner’s or 

operator’s considerations, there may be differences in the owner or operator profiles 

for proposed GS facilities that warrant additional assurance mechanisms. Thus, the 

Agency should consider adding a new category of financial assurance to the Class VI 

program that provides the Agency with the flexibility to approve the “functional 

equivalent” to the established RCRA financial assurance tests; and

• That EPA consider the use of rate-based financing, a new category of instrument that 

would provide the Director with the flexibility to approve instruments that are 

functionally equivalent to existing qualifying instruments.

Today's Final Approach: Today’s final regulation retains the substantive requirements

that owners or operators of Class VI wells demonstrate and maintain financial 

responsibility to cover the cost of corrective action, injection well plugging, PISC and 

site closure, and emergency and remedial response. In response to public comments EPA 

requested in the proposed rule and other input, this final regulation at §146.85, modifies 

the proposed requirements to provide clarity on acceptable instruments to enhance 

enforceability of the requirements, and to set reporting timeframes to provide consistency 

with other EPA regulations. Specifically, EPA has clarified the financial responsibility 

requirements by: 

1) Describing “qualifying instruments” to cover the cost of corrective action, injection 

well plugging, PISC and site closure, and emergency and remedial response in a 

manner that prevents endangerment of USDWs. 

Formatted: No underline

Comment [A105]: 

Edited per OMB-OIRA track change (11/10)

Deleted: of the third party 

Comment [A106]: 

Edited per OMB-OIRA track change (11/10)

Deleted: letters of credit, surety bonds, or 

insurance policies

Comment [A107]: 

OMB-OIRA edit (11/15/10). 

Deleted: ,

Comment [A108]: Edited per OMB OIRA 

comment 10/29.
Page 138 of 274

2) Adding language clarifying that the financial responsibility instrument is directly

enforceable regardless of whether the requirement is a condition of the permit. 

3) Requiring submission of annual inflationary updates and specifying a 60-day 

timeframe after notification by the Director for the submission of written updates of 

adjustments to the cost estimate. 

4) Requiring owners or operators to notify the Director no later than 10 days after filing 

for bankruptcy. 

5) Requiring an owner or operator or its guarantor using self insurance to demonstrate 

financial responsibility for GS to meet a Tangible Net Worth of an amount approved 

by the Director; have both a net working capital and a tangible net worth of at least 

six times the sum of the current well plugging, post-injection site care and site closure 

cost; have assets located in the US amounting to at least 90 percent of total assets or 

at least six times the sum of the current well plugging, post-injection site care and site 

closure cost; submit annual report of bond rating and financial information; and 

either: 1) Pass a bond rating test issued by one or both of the nationally recognized 

bond rating agencies, Standard & Poor’s and Moody’s for which the bond’s rating 

must be one of the four highest categories (i.e., AAA, AA, A, or BBB for Standard & 

Poor’s or Aaa, Aa, A, or Baa for Moody’s)); or, 2) Meet all of the following five 

financial ratio thresholds:

• A ratio of total liabilities to net worth less than 2.0; 

• A ratio of current assets to current liabilities greater than 1.5; 

• A ratio of the sum of net income plus depreciation, depletion, and amortization to 

total liabilities greater than 0.1; 

• A ratio of current assets minus current liabilities to total assets greater than -0.1; 

and

• A net profit (revenues minus expenses) greater than 0.

These financial responsibility requirements are not made to duplicate existing financial 

responsibility regulations, but are tailored to the unique characteristics and requirements 

of GS. Considering the potential high costs associated with large-scale deployment of GS 
Page 139 of 274

projects, EPA would like to ensure that adequate and continuous financial responsibility 

mechanisms are in place throughout the life of each GS project and that the cost 

associated with operation of GS projects is not passed along to the public. EPA also 

believes that having stringent self-insurance requirements in addition to an annual 

evaluation of the financial instrument minimizes the potential for a financial institution 

(that has passed the test) to be likely to undergo financial difficulties that can hinder the 

financial responsibility demonstration for a GS project.

EPA's final approach for financial responsibility for Class VI wells: EPA does not have 

authority under SDWA to be the direct or indirect beneficiary of a trust fund under this 

statute for the purpose of establishing financial responsibility for GS projects. EPA must 

comply with the Miscellaneous Receipts Act, 31 U.S.C. §3302. Standby trust funds are 

not stand-alone financial instruments that can be used by an owner or operator to 

demonstrate financial responsibility. Standby trusts must be used with certain types of 

financial responsibility instruments to enable EPA to be party to the financial 

responsibility agreement without EPA being the beneficiary of any funds. Use of standby 

trust funds must be accompanied by other financial responsibility instruments (e.g., 

surety bonds, letters of credit, or escrow accounts) to provide a location to place funds if 

needed. The final rule, at §146.85(a)(1), identifies the following qualifying financial 

instruments for Class VI wells, all of which must be sufficient to address endangerment 

of USDWs. Standby trusts are not needed for options 1, 4, and 5.

1) Trust Funds: If using a trust fund, owners or operators are required to set aside funds

with a third party trustee sufficient to cover estimated costs. During the financial 

responsibility demonstration, the owner or operator may be required to deposit the 

required amount of money into the trust prior to the start of injection or during the “payin period” if authorized by the Director. 

2) Surety Bond: Owners or operators may use a payment surety bond or a performance 

surety bond to guarantee that financial responsibility will be fulfilled. In case of operator 

default, a payment surety bond funds a standby trust fund in the amount equal to the face 

value of the bond and sufficient to cover estimated costs, and a performance surety bond 

Comment [A109]: 

OMB-OIRA track change (11/10). 

Deleted: S

Deleted: used along with

Comment [A110]: Edited per OIRA comment; 

10/31.

Comment [A111]: 

OMB-OIRA track change (11/10). 

Comment [A112]: Edited per OMB OIRA 

comment 10/29.
Page 140 of 274

guarantees performance of the specific activity or payment of an amount equivalent to the 

estimated costs into a standby trust fund.

3) Letter of Credit: A letter of credit is a credit document, issued by a financial 

institution, guaranteeing that a specific amount of money will be available to a designated 

party under certain conditions. In case of operator default, letters of credit fund standby 

trust funds in an amount sufficient to cover estimated costs.

4) Insurance: The owner or operator may obtain an insurance policy to cover the 

estimated costs of GS activities requiring financial responsibility. This insurance policy 

must be obtained from a third party to decrease the possibility of failure (i.e., non-captive 

insurer).

5) Self Insurance (i.e., Financial Test and Corporate Guarantee): Owners or operators 

may self insure through a financial test provided certain conditions are met. The owner or 

operator needs to pass a financial test to demonstrate profitability, with a margin 

sufficient to cover contingencies and unknown obligations, and stability. If the owner or 

operator meets corporate financial test criteria, this is an indication that the owner or 

operator can guarantee its ability to satisfy financial obligations based solely on the 

strength of the company’s financial condition. An owner or operator who is not able to 

meet corporate financial test criteria may arrange a corporate guarantee by demonstrating 

that its corporate parent meets the financial test requirements on its behalf. The parent’s 

demonstration that it meets the financial test requirement is insufficient if it has not also 

guaranteed to fulfill the obligations for the owner or operator.

6) Escrow Account: Owners or operators may deposit money to an escrow account to 

cover financial responsibility requirements. This account must segregate funds sufficient 

to cover estimated costs for GS financial responsibility from other accounts and uses. 

7) Other instrument (s) satisfactory to the Director: In addition to these instruments, EPA 

anticipates that new instruments that may be tailored to meet GS needs may emerge, and 

Deleted: for the

Comment [A113]: Edited per OIRA comment 

10/31.

OMB-OIRA modification to previous text (11/10).
Page 141 of 274

may be determined appropriate for use by the Director for the purpose of financial 

responsibility demonstrations. 

The final rule specifies that the qualifying financial responsibility instrument must 

include protective conditions of coverage, including, but not limited to: cancellation, 

renewal, and continuation provisions; specifications on when the provider becomes liable 

in case of cancellation if there is a failure to renew with a new qualifying financial 

instrument; and requirements for the provider to meet a minimum credit rating, minimum 

capitalization, and ability to pass the bond rating when applicable. This clarification was 

made in direct response to issues raised by commenters for numerous instruments, and 

also to make sure that there is no gap in coverage if a financial instrument fails. 

Today’s rule, at §146.85(c), requires the owner or operator to have a detailed written 

estimate, in current dollars, of the cost of: performing corrective action on wells in the 

AoR, plugging the injection well(s), PISC and site closure, and emergency and remedial 

response. A cost estimate must be prepared separately for each of these activities and be 

based on the costs to the owner or operator of hiring a third party (who is neither a parent 

nor a subsidiary of the owner or operator) to perform the activities. EPA recommends 

that owners or operators take the following into account when determining the cost 

estimate for GS projects:

1) Performing corrective action on wells in the AoR. This includes conducting 

corrective action on deficient wells in the AoR during the initial AoR, under a phased 

corrective action approach; and for newly-identified deficient wells in subsequent 

AoR re-evaluations. See section III.B for more details on the AoR and corrective 

action plan requirements.

2) Plugging the injection well(s). This includes performing a final external MIT and 

plugging the wells in a manner that considers the well depth, the number of plugs and

the amount of cement needed, the composition of the captured CO2, and the types of 

subsurface formations. See section III.H for more details on plugging requirements.

Deleted: comprise 

Comment [A114]: Edited per OMB OIRA 

comment 10/29.

Comment [A115]: Edited per OIRA comment

10/31.
Page 142 of 274

3) Post-injection site care and closure. This includes all needed monitoring and site care 

until it can be demonstrated that the site no longer poses an endangerment to USDWs. 

See section III.H for more details on post-injection site care and site closure 

requirements.

4) Emergency and remedial response. This includes the cost to perform any necessary 

responses or remediation to address potential USDW endangerment. See section III.J 

for more details on the emergency and remedial response requirements.

Owners or operators have the flexibility to choose from a variety of financial instruments 

to meet their financial responsibility obligations. Owners or operators may use one or 

multiple financial responsibility instruments for well plugging and PISC (§146.85(a)(6)). 

However, EPA will not allow for a separate financial responsibility demonstration for 

well plugging and PISC (i.e., a demonstration submitted prior to well plugging and the 

beginning of the PISC period rather than with the permit application). A demonstration of 

financial responsibility for all phases of the GS project will be required prior to the 

issuance of a Class VI permit (§146.85(a)(5)(i)). 

EPA adds that under today’s final rulemaking at §146.85(a), the Director will only 

approve instruments determined to be sufficient to address endangerment of USDWs, and 

has the discretion to disapprove of instruments that he/she determines may not be 

sufficient based on the following:

1) The financial instrument is not determined to be a qualifying instrument;

2) The financial instrument is not sufficient to cover the cost to properly plug and 

abandon, remediate, and manage wells;

3) The financial instrument is not sufficient to address endangerment of USDWs; or 

4) The financial instrument does not include required conditions of coverage to facilitate 

enforceability and prevent gaps in coverage for the life of the GS project.

Comment [A116]: Edited per OMB OIRA 

comment 10/29.

Deleted: comprise 
Page 143 of 274

EPA has added language, at §146.85(b), that a financial responsibility instrument is 

directly enforceable regardless of whether the requirement is a condition of the permit. 

EPA also specifies circumstances under which an owner or operator may be released 

from a financial instrument, including that the owner or operator has completed the GS 

project activity for which the financial instrument was required and has fulfilled all 

financial obligations as determined by the Director, or has submitted a replacement 

financial instrument and received written approval from the Director accepting the new 

financial instrument and releasing the owner or operator from the previous financial 

instrument. The Director’s determination of completion of a GS project activity may be 

sustained by a professional engineer’s report on completion. The Director must notify the 

owner or operator in writing that the owner or operator is no longer required to maintain 

financial responsibility for the project or activity. This clarification was added to address 

unforeseen situations where EPA may need to directly enforce the financial responsibility 

provisions should the permit inadequately provide protection of USDWs from 

endangerment. 

This rule, at §146.85(c), also requires that the owner or operator adjust the cost estimates 

to address amendments to the AoR and corrective action plan (§146.84), the injection 

well plugging plan (§146.92), the PISC and site closure plan (§146.93), and the 

emergency and remedial response plan (§146.94). Within 60 days after the Director has 

approved any modifications to the plan(s), the owner or operator must review and update 

the cost estimate for well plugging, PISC and site closure, and emergency and remedial 

response to account for any amendments if the change in the plan increases the cost. The 

revised cost estimate must also be adjusted for inflation as specified at §146.85(c)(2). 

Any changes to the approved cost estimate must be approved by the Director. 

Today’s rule does not allow a separate demonstration for financial responsibility 

requirements (i.e., a demonstration submitted prior to well plugging and the beginning of 

the post-injection site care period rather than with the permit application). Although the 

owner or operator may use a financial instrument or a combination of financial 

instruments for the purpose of financial responsibility for specific phases of the GS 
Page 144 of 274

project, the demonstration of financial responsibility must be done for the overall GS 

project at the time of permit application. However, today’s rule, at §146.85(a)(6) provides 

that, prior to obtaining a Class VI permit, an owner or operator may demonstrate financial 

responsibility by using one or multiple qualifying financial instruments for specific GS 

activities, thereby realizing greater flexibility and cost savings from this regulation. In the 

event that the owner or operator combines more than one instrument for a specific GS 

activity (e.g., well plugging), such combination must be limited to instruments that are 

not based on financial strength or performance (i.e., self insurance or performance bond), 

for example trust funds, surety bonds guaranteeing payment into a trust fund, letters of 

credit, escrow account, and insurance. In this case, it is the combination of instruments, 

rather than the single instrument, which must provide financial responsibility for an 

amount at least equal to the current cost estimate. EPA also notes that today’s rule 

requires the Director to approve the use and length of pay-in-periods for trust funds or 

escrow accounts. EPA understands that in some cases a short pay-in period (e.g., threeyears or less) will provide some financial flexibility for owners or operators while 

balancing financial risk.

EPA has further clarified financial responsibility requirements by requiring owners or 

operators or a guarantor to notify the Director no later than 10 days after filing for 

bankruptcy, at §146.85(d). This requirement is added in direct response to commenters 

who addressed the necessity of adequate financial responsibility requirements, even in the 

event of operator bankruptcy. EPA is adding this requirement in order to avoid a gap in 

coverage in the event that an instrument fails. This timeframe is consistent with the 

current US bankruptcy code. In the event that the third party files for bankruptcy, today’s 

rule requires that the owner or operator establish alternative financial assurance within 

sixty (60) days.

Today’s rule, at §146.85(e), also requires the owner or operator to adjust cost estimates if 

the Director has reason to believe that the most recent demonstration is no longer 

adequate to cover the cost of the identified activities. This clarification is made in direct 

response to commenters who stressed the importance of accurate cost estimates. The 
Page 145 of 274

Agency is developing guidance, which will provide direction to the Director for when a 

demonstration may no longer be adequate to cover the GS activities.

As a Federal agency, EPA is working to create a nationally consistent financial 

responsibility program for GS activities while providing permitting authorities an 

appropriate level of flexibility. EPA is developing guidance on financial responsibility for 

owners or operators of Class VI wells to assist owners or operators in evaluating the 

financial responsibility requirements for Class VI wells and to assist Directors in 

evaluating financial responsibility demonstrations. The guidance will describe financial 

responsibility options, demonstrations, types of financial instruments for Class VI wells 

as well as how to estimate the costs to support accurate financial responsibility 

demonstrations specific to the needs of a GS project. 

Long-term liability and stewardship for GS projects under the SDWA: EPA received a 

range of comments from stakeholders regarding liability following site closure. Many 

commenters suggested that, after a GS site is closed, liability should be transferred to the 

State or Federal government or to a publicly- or industry-funded entity based on a series 

of rationales (e.g., the need for certainty; the potential for high cost; insurance and legal 

concerns). EPA also received comments from those who disagreed with the assertion that 

a public entity should bear liability following site closure based on the belief that, if 

owners or operators face potential liability following site closure, they would use 

precaution in their operations to avoid risks and potential environmental damage. 

Additionally, many commenters encouraged EPA to consider other State or Federal laws 

under which liability transfers may be accomplished as models for GS liability transfer. 

Under SDWA authority, owners or operators of injection wells must ensure protection of 

USDWs from endangerment and are subject to liability for enforcement under the Act. 

The final rule requires that an owner or operator must conduct monitoring as specified in 

the Director-approved PISC and site closure plan following the cessation of injection 

until the owner or operator can demonstrate to the Director that the geologic 
Page 146 of 274

sequestration project no longer poses an endangerment to USDWs. For additional 

information about the PISC and site closure requirements, see section III.H of this action. 

Once an owner or operator has met all regulatory requirements under part 146 for Class 

VI wells and the Director has approved site closure pursuant to requirements at §146.93, 

the owner or operator will generally no longer be subject to enforcement under section 

1423 of SDWA for noncompliance with UIC regulatory requirements. However, an 

owner or operator may be held liable for regulatory noncompliance under certain 

circumstances even after site closure is approved under §146.93, under section 1423 of 

the SDWA for violating §144.12, such as where the owner or operator provided 

erroneous data to support approval of site closure.

Additionally, an owner or operator may always be subject to an order the Administrator 

deems necessary to protect the health of persons under section 1431 of the SDWA after 

site closure if there is fluid migration that causes or threatens imminent and substantial 

endangerment to a USDW. For example, the Administrator may issue a SDWA section 

1431 order if a well may present an imminent and substantial endangerment to the health 

of persons, and the State and local authorities have not acted to protect the health of such 

persons. The order may include commencing a civil action for appropriate relief. If the 

owner or operator fails to comply with the order, they may be subject to a civil penalty 

for each day in which such violation occur or failure to comply continues. 

Furthermore, after site closure, an owner or operator may, depending on the fact scenario, 

remain liable under tort and other remedies, or under other Statutes including, but not 

limited to, Clean Air Act, 42 U.S.C. §§7401-7671; CERCLA, 42 U.S.C. §9601-9675; and

RCRA, 42 U.S.C. §6901-6992. 

EPA acknowledges stakeholder interest in liability and long-term stewardship in the 

context of development and deployment of GS technology, however, under current 

SDWA provisions EPA does not have authority to transfer liability from one entity (i.e., 

owner or operator) to another.
Page 147 of 274

J. Emergency and Remedial Response

Today’s rule at §146.94 requires Class VI well owners or operators to develop and 

maintain an emergency and remedial response plan that describes actions to be taken to 

address events that may cause endangerment to a USDW during the construction, 

operation, and PISC periods of a GS project. Owners or operators must also periodically 

update the emergency and remedial response plan to incorporate changes to the AoR or 

other significant changes to the project. Today’s requirements will support expeditious 

and appropriate response to protect USDWs from endangerment in the unlikely event of 

an emergency. 

Developing emergency and remedial response plans: EPA proposed that owners or 

operators submit an emergency and remedial response plan to the Director as part of the 

Class VI permit application. The plan would describe measures that would be taken in the 

event of adverse conditions at the well, such as a loss of mechanical integrity, the 

opening of faults or fractures within the AoR, or if movement of injection or formation 

fluids caused an endangerment to a USDW. Commenters were supportive of including an 

emergency and remedial response plan as part of the Class VI permit, and some 

commenters suggested that the plan should be risk based. EPA agrees that advanced 

planning for emergency and remedial response is an important part of ensuring protection 

of USDWs at GS sites from endangerment, and today’s rule retains the requirement for 

an emergency and remedial response plan (§146.94(a)), and also requires that the 

approved emergency and remedial response plan be incorporated into the Class VI 

permit. The purpose of the emergency and remedial response plan is to ensure that 

owners or operators comprehensively plan, in advance, what actions would be necessary 

in the unlikely event of an emergency. The plan will also ensure that operators know 

what entities and individuals must be notified and what actions might need to be taken to 

expeditiously mitigate any emergency situations and protect USDWs from endangerment. 

The Agency is developing guidance that describes the contents of the project plans 

required in the GS rule, including the emergency and remedial response plan. The docket 

for today's rulemaking includes brief research papers that discuss remedial technologies 
Page 148 of 274

available to address potential impacts of CO2 on water resources (USEPA, 2010b) and 

remedial technologies that may be used to seal faults and fractures at GS sites (USEPA, 

2010c).

EPA agrees with commenters that the emergency and remedial response plan should be 

site-specific and “risk-based.” EPA expects that each emergency and remedial response 

plan will be tailored to the site, and today’s rule provides flexibility to the owner or 

operator to design a site-specific plan that meets the requirements of §146.94(a). Rather 

than requiring specific information in the emergency and remedial response plan that may 

not be relevant to all GS projects, the plan allows such information to be determined on a 

site-specific basis. The details of an emergency and remedial response plan may be 

influenced by a variety of factors including: geology, USDW depth, and injection depth; 

the presence, depth, and age of artificial penetrations; proposed operating conditions and 

properties of the CO2; and activities in the AoR (e.g., the presence of population centers, 

land uses, and public water supplies). The Director will evaluate the proposed emergency 

and remedial response plan for a GS project in the context of all information submitted 

with the permit application (e.g., site characterization information, AoR evaluation data, 

and well construction, monitoring, and operational information) to ensure that the plan is 

appropriately comprehensive to address potential emergencies. 

Implementing the emergency and remedial response plan: EPA also proposed several 

steps that the owner or operator would need to follow if he or she obtained evidence that 

the injectate and associated pressure front may endanger a USDW. Most comments 

requesting clarity on this requirement recommended that EPA establish triggers during 

the initial permitting phase and identify appropriate mitigation options. 

EPA disagrees with commenters that it is appropriate or useful to identify specific 

triggers or response actions in the rule that would apply to all sites. EPA believes that 

decisions about responses should be made through consultation between owners or 

operators and Directors because each response action will be site- and event-specific. The 

purpose of the emergency and remedial response requirements in today’s rule is to ensure 
Page 149 of 274

that a plan is in place for the owner or operator to take appropriate action (e.g., cease 

injection) in the unlikely event of an emergency or USDW endangerment. The plan also 

facilitates a dialogue between the owner or operator and the Director to expedite the 

necessary and appropriate response based on steps identified in advance.

Today’s rule at §146.94(b) requires that, if an owner or operator obtains evidence of 

endangerment to a USDW, he or she must: 1) immediately cease injection; 2) take all 

steps reasonably necessary to identify and characterize any release; 3) notify the Director 

within 24 hours; and, 4) implement the approved emergency and remedial response plan.

Emergency and remedial response plan updates: Two water associations recommended 

that the emergency and remedial response plan be reviewed and updated throughout the 

course of a GS project. EPA agrees with these commenters and today’s rule includes a 

requirement that owners or operators must periodically review the emergency and 

remedial response plan to incorporate operational and monitoring data and the most 

recent AoR reevaluation at §146.94(d). This review must take place within one year of an 

AoR reevaluation, following significant changes to the facility, or when required by the 

Director. 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 Directors and ensure that owners or operators are complying with the 

conditions of their Class VI permits. Tying emergency and remedial response plan 

reviews to the AoR reevaluation frequency is appropriate to ensure that reviews of the 

plans are conducted on a defined schedule that ensures there will be appropriate revisions 

to the plan if there is a change in the AoR or other relevant circumstances change, while 

adding little burden if the AoR reevaluation confirms that the plan is appropriate as 

written. 

K. Involving the Public in Permitting Decisions

Public input and participation in GS projects has a number of benefits, including: 1) 

providing citizens with access to decision-making processes that may affect them; 2) 

educating the community about a GS project; 3) ensuring that the public receives 

Comment [A117]: OMB OIRA edit (11/01)
Page 150 of 274

adequate information about the proposed GS project; and 4) allowing the permitting 

authority and owners or operators to become aware of public viewpoints, preferences and 

environmental justice concerns and ensuring these concerns are considered by decisionmaking officials. 

GS of CO2 is a new technology that is unfamiliar to most people and maximizing the 

public’s understanding of the technology can result in more meaningful public input and 

constructive participation as new GS projects are proposed and developed. Early and 

frequent public involvement through education and information exchange is critical to the 

success of GS and can provide early insight into how the local community and 

surrounding communities perceive potential environmental, economic, or health effects 

associated with a specific GS project. Owners or operators can increase the likelihood of 

success by integrating social, economic, and cultural concerns of the community into the 

permit decision-making process.

In the proposed rule, EPA sought comment on: 1) the appropriateness of adopting 

existing public participation requirements at 40 CFR parts 25 and 124 for GS; 2) the need 

for additional public participation requirements to reflect availability of new information 

technology to disseminate and gather information; and 3) ways to enhance the public 

participation process. 

Nearly all commenters agreed that early and frequent public education and participation 

would enhance public acceptance of GS projects. Several commenters supported 

adopting the existing public participation requirements used for other injection well 

classes. Many commenters favored requiring the use of new information technology to

improve public notification and involvement on GS projects and permitting.

Today’s final approach adopts the existing UIC public participation requirements at 40 

CFR part 25 and the permitting decision procedures at 40 CFR part 124. EPA encourages 

owners or operators and permitting agencies to involve the public by providing them 

information about the Class VI permit (and any requests for a waiver of the injection 
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depth requirements or an expansion of the areal extent of an aquifer exemption) as early 

in the process as possible. Under 40 CFR parts 25 and 124, permitting authorities must 

provide public notice of pending actions via newspaper advertisements, postings, 

mailings, or e-mails to interested parties; hold public hearings if requested; solicit and 

respond to public comment; and involve a broad range of stakeholders. 

EPA expects that there will be higher levels of public interest in GS projects than for 

other injection activities. The Agency believes that encouraging public participation will 

help permitting authorities understand public concerns about GS projects and will afford 

the public an opportunity to gain a clearer understanding of the nature and safety of GS 

projects and technologies. To address comments about stakeholder participation, EPA is 

amending the requirements for public notice of permit actions and public comment period 

at §124.10 to clarify that public notice of Class VI permitting activities must be given to 

State and local oil and gas regulatory agencies, State agencies regulating mineral 

exploration and recovery, the Director of the PWSS program in the State, and all agencies 

that have jurisdiction to oversee wells in the State in addition to the general public.

EPA agrees with commenters that the use of new forms of information technology can 

improve public participation and understanding of GS projects. EPA recognizes the 

importance of social media as a public outreach tool. Social media, which are primarily 

Internet and mobile based technologies for disseminating and discussing information, can 

help provide accessibility and transparency to a wide audience. EPA encourages permit 

applicants and permitting authorities to use the Internet and other forms of social media 

to explain potential GS projects; describe GS technologies; and post information on the 

latest developments related to a GS project including schedules for hearings, briefings 

and other opportunities for involvement. 

L. Duration of a Class VI Permit

Today’s rule establishes that Class VI permits are issued for the life of the GS project, 

including the PISC period (§144.36). In lieu of the periodic permit reissuance required 

for most other deep-well classes, owners or operators of Class VI wells must periodically 

reevaluate the AoR and prepare and implement a series of plans for AoR and corrective 

Comment [A118]: 9/20/10: OMB Environmental 

Branch edit. 

Deleted: Some social media tools that may be 

useful for sharing information on GS projects 

include blogs, social networks, podcasts, and 

webcasts. 
Page 152 of 274

action, testing and monitoring, injection well plugging, PISC and site closure, and

emergency and remedial response. These plans must be reevaluated by the owner or 

operator throughout the life of the project to foster a continuing dialogue between the 

owner or operator and the Director, and afford opportunities for public input as needed

and ensure compliance with the Class VI permit.

EPA proposed that Class VI injection well permits be issued for up to the operating life 

of the facility, including the PISC period. In the preamble to the proposed rule, EPA 

explained that, in lieu of permit renewals for Class VI wells, owners or operators must 

periodically re-evaluate the AoR, at least every 10 years. In existing UIC program

regulations, permit duration varies by injection well class: permits for Class I and Class V 

wells are effective for up to 10 years; while Class II and III permits may be issued for the 

operating life of the facility, but are subject to a review by the permitting authority at 

least once every five years. 

EPA sought comment on the proposed permit duration for Class VI wells, the 

appropriateness of GS project plans, and the merits of updating the AoR and corrective 

action plan in place of permit reissuance. Many commenters supported EPA’s proposal to 

issue permits for the life of a GS project, stating that the requirements for periodic 

reevaluation of the AoR and corrective action plan would make a five-or ten-year permit 

review process unnecessary and that a lifetime permit would provide operational 

continuity. Some commenters suggested that other plans (e.g., the testing and monitoring 

plan) should also be periodically reviewed throughout the life of the project. Other 

commenters disagreed with EPA’s proposed permit duration for Class VI wells, believing 

that the proposed level and frequency of interaction (i.e., every 10 years) between the 

primacy agency and owner or operator would not be sufficient to justify a permit for the 

operating life of the project. Comments both in favor of and opposition to lifetime 

permits stressed the importance of incorporating new information, the value of permit 

review and modification, and the need for a transparent process. 
Page 153 of 274

EPA agrees with commenters regarding the need for continuous interaction between 

permitting authorities and owners or operators of GS projects. Today’s rule retains the 

requirement that Class VI permits are issued for the lifetime of the project (§144.36). It 

also requires owners or operators to review and update the AoR and corrective action 

plan, the testing and monitoring plan, and the emergency and remedial response plan 

throughout the life of the project (§146.84(e), §146.90(j), and §146.94(d)). 

Today’s rule requires owners or operators to review each plan as required by part 146 and 

either identify necessary amendments to the plan or demonstrate to the satisfaction of the 

Director that no amendment is needed. These reviews must be performed within one year 

of an AoR reevaluation, following any significant changes to the facility (e.g., the 

addition of monitoring or injection wells), or when required by the Director. In no case 

can reviews occur less often than once every five years. This review frequency is 

necessary to ensure that reviews of the plans are conducted on a defined schedule or 

when there is a change in the AoR or other significant change, while adding little burden 

if an AoR reevaluation confirms that the plans are appropriate as written. (EPA also 

revised the AoR reevaluation frequency from 10 years to five years; see section III.B.)

EPA is not requiring formal periodic review and updates to the injection well plugging 

plan and PISC and site closure plan throughout the injection phase because it is not 

expected that changes to these plans would be implemented until injection operations 

cease. However, today’s rule at §§146.92 and 146.93 does require that owners or 

operators identify any needed changes to these plans at the cessation of injection 

operations. 

Because the approved plans required by today’s rule will be incorporated into the Class 

VI permit, today’s rule establishes permit modification requirements tailored for Class VI 

permits (e.g., associated with plan updates and other project changes). These 

requirements state that any changes to the plans will trigger a permit modification 

pursuant to §144.39(a)(5). 

Comment [A119]: OMB-OIRA edit (11/01).
Page 154 of 274

These modifications invoke part 124 public participation requirements. The Director, 

through consultation with the owner or operator, may choose to provide public notice of 

permit modifications as they occur or concurrent with the five year permit review 

schedule at §144.36 (e.g., the Director may notice multiple modifications at once, every 

five years). Minor changes to the plans (e.g., correction of typographical errors) that may 

result in a permit modification pursuant to requirements at §144.41 for minor 

modifications of permits will not require public notification. If any of the plans are 

changed because of significant changes they will be considered by the Director to be 

major modifications under §144.39. 

Periodic review and revision of required plans and the ongoing dialogue between owners 

or operators and Directors will address many of the comments in support of periodic 

permit renewal, without the associated time and expense of rewriting the entire permit. 

Instead, today’s final approach requires a close level of interaction between owners or 

operators and Directors. It requires permits to be informed with continually updated 

information, focuses resources on key issues, and provides for public transparency and 

involvement when needed. Periodic reevaluation of the AoR, along with reviews and 

updates to the plans, will provide an equivalent level of review and attention to address 

potential risks, while focusing time and resources on the most important components of 

GS operations. 

The iterative reviews and revisions of the various rule-required plans and the underlying 

computational models will also provide numerous opportunities for technical 

reassessments of the project. These reviews will ensure that the owner or operator and the 

Director have current knowledge of how the CO2 plume and pressure front are behaving 

and afford them time to assess the information and react appropriately to ensure 

protection of USDWs. 

Transfer of permits: Today’s final rule does not allow for automatic transfer of a Class VI 

permit to a new owner or operator (§144.38(b)). Given the unique nature of GS and the 

importance of interaction between GS project owners or operators and permitting 
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authorities, the Agency believes that the Director should have an opportunity to review 

the permit and determine whether any changes are necessary at the time of the permit 

transfer, pursuant to requirements at §144.38(a). If information about the GS project and 

existing permit conditions are determined to be adequate, the permit review and transfer 

may entail a minimal amount of new information and administrative effort. 

Area permits: Today’s rule does not allow area permits for Class VI wells 

(§144.33(a)(5)). Individual well permits are essential to ensure that every Class VI well is 

constructed, operated, monitored, plugged, and abandoned in a manner that protects 

USDWs from endangerment. Individual permitting of wells maximizes opportunities for 

the public to provide input on each well as it is brought into service. This also ensures 

that existing wells that are converted or re-permitted from other well classes (e.g., Class 

II EOR/EGR wells converted to Class VI) are 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).

While area permits allow for some administrative efficiency, this efficiency can also be 

achieved through appropriately executed plans for Class VI wells. For example, an owner 

or operator under §146.84(c)(1) must delineate the projected lateral and vertical 

movement of the CO2 plume and formation fluids from the commencement of injection 

activities until injection ceases. This delineation should account for any future wells that 

the owner or operator plans to construct in the AoR to ensure that the Director can 

consider all anticipated injection and resultant pressure changes when evaluating the plan 

and setting permit conditions. Similarly, testing and monitoring plans should account for 

future injection wells to ensure that ground water monitoring and CO2 plume and 

pressure front tracking are planned appropriately. Through this iterative planning and 

submission process, owners or operators and Directors can accomplish multiple 

efficiencies: permits to construct Class VI wells can be submitted and reviewed either 

separately or simultaneously, and common, static components of the project can be 

identified and incorporated into future permit applications, which would facilitate 
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submittal of data by the owner or operator and review and approval by the Director of 

future wells in the same field.

Owners or operators and permitting authorities may also achieve economies of scale by 

conducting the public process (e.g., noticing wells; holding hearings) for several Class VI 

permits simultaneously. This may improve efficiency and public understanding of how 

multiple wells may interact in a given GS site. EPA also believes that requiring separate 

permit applications for each well will ensure that the public has an opportunity to provide 

input on each well in the field as it is constructed or brought online. 

As part of the EPA’s adaptive rulemaking approach, the Agency will collect information 

on early GS projects and may consider the use of area permits in the future.

IV. Cost Analysis

Today’s rulemaking finalizes regulations for the protection of USDWs, but it does not 

require entities to sequester CO2. The costs and benefits associated with protection of 

USDWs from endangerment are the focus of this rule; however, those associated with the 

mitigation of climate change are not directly attributable to this rulemaking. 

To calculate the costs and benefits of compliance for the final GS Rule, EPA selected the 

existing UIC program Class I industrial waste disposal well category as the baseline for 

costs and benefits. EPA used this baseline to determine the incremental costs of today’s 

rule, based on the fact that permits issued to early pilot projects included requirements 

similar to those for Class I industrial wells.

The incremental costs of the rule include elements such as geologic site characterization, 

well construction and operation, monitoring equipment and procedures, well plugging, 

and post-injection site care (monitoring). The benefits of this rulemaking include the 

decreased risk of endangerment to USDWs and potentially a corresponding decrease in 

health-related risks associated with contaminated USDWs.
Page 157 of 274

The scope of the GS Rule Cost Analysis includes the full range of activities associated 

with an injection project, from the end of the CO2 pipeline at the GS site to the 

underground injection and monitoring, as it occurs during the timeframe of the analysis. 

The scope of the cost analysis does not include capturing or purifying the CO2, nor does 

it include transporting the CO2 to the GS site. Some costs as highlighted in this section 

have changed from the proposed rule based on cost updates or public comments received. 

The timeframe of the cost analysis was extended from 25 years in the proposed rule to 50 

years for the final rule. Although twice as long as the timeframes commonly used in 

drinking water-related cost analyses, EPA believes that 50 years reflects the fact that the 

full lifecycle of GS projects is expected to be well beyond 25 years while avoiding the 

extreme amount of uncertainty involved in projecting an analysis across multiple 

generations. Costs attributed to this rule are inclusive of GS projects begun during the 50 

years of the analysis, and all cost elements that occur during the 50-year timeframe are 

discounted to present year values. The number of GS projects projected to be 

implemented over the timeframe of the cost analysis (29) includes pilot projects and other 

projects associated with regulations that are in place today.3

 EPA consulted directly with 

DOE and Regional Partnerships and searched publicly available data to inform the 

estimated number of projects. Again, EPA emphasizes that the rule does not require 

anyone to undertake GS.

EPA recognizes that basing the analysis on 29 projects (consisting of pilot projects and 

other projects) expected on the basis of regulations in place today omits the incremental 

costs of applying these requirements to additional projects that may result from future 

changes in climate policy and that a much larger number of affected projects (and thus 

higher costs) could result from such policy changes. EPA has thus conducted several 

sensitivity analyses to provide perspective on the incremental costs of the rule under 

possible future climate policy scenarios. These are summarized in Section IV.A.2.b of 

 3 Note that although pilot projects are conducted on a small scale, they are considered geologic 

sequestration demonstration projects for a given site, not Class V experimental technology well projects.
Page 158 of 274

this preamble and discussed in greater detail in Cost Analysis for this rule (see EPA, 

2010d).

This section of the Preamble summarizes the results of the cost analysis conducted for 

this rule. For details, see the Cost Analysis for the Final GS Rule, which is included in the 

rule docket.

A. National Benefits and Costs of the Rule4

1. National Benefits Summary

This section summarizes the risk (and benefit) tradeoffs between compliance with 

existing requirements and with the regulatory alternative (RA) selected for the final rule.

The Cost Analysis includes a more comprehensive evaluation of risk and benefit 

tradeoffs for all of the RAs considered for the final rule (see Chapter 2 of the Cost 

Analysis for a description of each of the RAs). These evaluations in the Cost Analysis 

include a nonquantitative analysis of the relative risks of contamination to USDWs for 

the RAs under consideration. The expected change in risk based on promulgation of the 

selected RA and the potential nonquantified benefits of compliance with this RA are also 

discussed. 

a. Relative Risk Framework—Qualitative Analysis

Table IV-1 below presents the projected directional change in risk of the selected RA 

relative to the baseline. As detailed in Chapter 5 in the Cost Analysis, the term “baseline” 

in the exhibit refers to risks as they exist under the current UIC program regulations for 

Class I industrial wells. The terms “decrease” and “increase” indicates the change in risk 

relative to this baseline. The Agency has used best professional judgment to qualitatively 

assess the relative risk associated with each RA. This assessment was made with 

contributions from a wide range of injection well and hydrogeological experts, ranging 

from scientists and well owners or operators to administrators and regulatory experts. 

 4 Although both estimated costs and benefits are discussed in detail, the final policy decisions regarding this 

rulemaking are not premised solely on a cost/benefit basis.

Comment [A120]: OMB-OIRA edit – (11/03); 

minor modification to first sentence for clarity. 

Deleted: during the regulatory development 

process and public comment

Deleted: E

Comment [A121]: OMB-OIRA edits (11/03). 

Deleted: estimated relative risks 

Deleted: for compliance with the rule 

Comment [A122]: OMB-OIRA edits (11/03). 

Comment [A123]: 

Edits made in response to OMB-OIRA comment. 

(11/10).
Page 159 of 274

Table IV-1. Relative Risk of Regulatory Components for Selected RA versus the 

Current Regulations 5

Requirements

Direction of Change 

in Risk for Selected 

RA

(Relative to Baseline)

1. Geologic Characterization

Baseline 

Identify a geologic system consisting of a receiving zone; trapping mechanism; and 

confining system to allow injection at planned rates and volumes. 

Provide maps and cross sections of local and regional geology, AoR, and USDWs; 

characterize the overburden and subsurface; and provide information on fractures, 

stress, rock strength, and in-situ fluid pressures within cap rock and storage reservoir. 

Incremental Requirements under RA3

Perform detailed assessment of geologic, hydrogeologic, geochemical and 

geomechanical properties of proposed site. 

Identify additional zones above the confining zone that will impede vertical fluid 

movement (at Director’s discretion). 

Collect seismic history data; identify and evaluate faults and fractures.

Decrease

2. Area Of Review (AoR) Study and Corrective Action

 5 The activity baseline used for costing purposes in this analysis is based on the UIC program Class I 

industrial waste disposal well category because of the similarity of early CO2 sequestration permits to the 

permits from that well class.

Comment [A124]: Table modified in response to 

OMB-OIRA comment (11/03). 

Deleted: Relative Risk of Regulatory 

Components for Selected RA versus the Current 

Regulations
Page 160 of 274

Requirements

Direction of Change 

in Risk for Selected 

RA

(Relative to Baseline)

Baseline 

The AoR determined as either a 1⁄4 mile radius or by mathematical formula. Identify all 

wells in the AoR that penetrate the injection zone and provide a description of each; 

identify the status of corrective action for wells in the AoR; and remediate those posing 

a risk to USDWs.

Incremental Requirements under RA3

Define the AoR using sophisticated computational models based on site specific data 

that accounts for multiphase flow and the buoyancy of CO2. 

Perform corrective action using materials that are compatible with CO2. 

Periodically reevaluate the AoR over the life of the injection project.

Decrease

3. Injection Well Construction

Baseline 

The well must be cased and cemented to prevent movement of fluids into or between 

USDWs and to withstand the injected materials at the anticipated pressure, 

temperature and other operational conditions. Wells must be constructed to inject 

below the lowermost USDW.

Incremental Requirements under RA3

Construct and cement wells with casing, tubing, and packer that meet API or ASTM 

International standards and are compatible with CO2.

Cemented surface casing (base of the lowermost USDW to surface) and long string 

casing (cemented from injection zone to surface) must be compatible with fluids with 

which they may be expected to come into contact. 

(A waiver of the Class VI requirement that projects inject below the lowermost USDW 

may be permitted in limited cases.)

Decrease (enhanced 

well construction 

requirements); 

Increase (A waiver to 

inject above the 

lowermost USDW in 

limited cases)

4. Well Operation

Baseline 

Limit injection pressure to avoid initiating new fractures or propagating existing 

fractures in the confining zone adjacent to the USDWs. 

Incremental Requirements under RA3

Limit injection pressure to less than the fracture pressure of the injection formation in 

any portion of the area defined by the anticipated pressure front. Equip injection wells 

with down-hole shut-off systems.

Decrease

5. Mechanical Integrity Testing (MIT)

Comment [A125]: 

Edits made in response to OMB-OIRA comment. 

(11/10)

Comment [A126]: 

OMB-OIRA comment. 11/10

Deleted: Injection must be below the 

lowermost USDW. 
Page 161 of 274

Requirements

Direction of Change 

in Risk for Selected 

RA

(Relative to Baseline)

Baseline 

Demonstrate internal mechanical integrity, and conduct a pressure fall-off test every 5 

years.

Incremental Requirements under RA3

Continuously monitor injection pressure, flow rate, injected volumes, and pressure on 

the annulus between the tubing and the long string casing. Demonstrate external 

mechanical integrity annually, and conduct casing inspection logs at the discretion of 

the Director.

Decrease

6. Monitoring

Baseline 

Monitor the nature of injected fluids at a frequency sufficient to yield data 

representative of their characteristics. Conduct ground water monitoring within the AoR

(Director’s discretion). Report semi-annually on the characteristics of injection fluids, 

injection pressure, injection flow rate, injection volume and annular pressure, and on 

the results of MITs and groundwater monitoring.

Incremental Requirements under RA3

Develop, implement, and periodically review a Testing and Monitoring plan for the site. 

Monitor injectate; corrosion of the well’s tubular, mechanical and cement components. 

Conduct pressure fall-off testing; CO2 plume and pressure front tracking; and ground 

water quality monitoring. 

Report operating and monitoring results twice per year in operating reports, unless the 

monthly MIT or other periodic tests revealed operations were somehow compromised, 

in which case 24 hour notification is required.

Decrease 

7. Well Plugging and Post-Injection Site Care (PISC)

Baseline 

Ensure that the well is in a state of static equilibrium and plugged using approved 

methods. Plugs shall be tagged and tested. Conduct PISC monitoring to confirm that 

CO2 movement is limited to intended zones.

Incremental Requirements under RA3

Flush the well with a buffer fluid, determine bottom-hole reservoir pressure, and 

perform a final external MIT. Develop and implement a plan to conduct PISC 

monitoring, (which may include pressure monitoring, geophysical monitoring, and 

geochemical monitoring in and above the injection zone and the USDW). Following the 

PISC monitoring (50 years), perform a non-endangerment demonstration to ensure no 

threat to USDWs and that no further monitoring is necessary.

Decrease

8. Financial Responsibility
Page 162 of 274

Requirements

Direction of Change 

in Risk for Selected 

RA

(Relative to Baseline)

Baseline 

Demonstrate and maintain financial responsibility and resources to plug and abandon

the injection well.

Incremental Requirements under RA3

Demonstrate and maintain financial responsibility for all needed corrective action, 

emergency and remedial response, and PISC and closure. Adjust the cost estimates 

for these activities periodically to account for inflation and other conditions that may 

affect costs.

Decrease

9. Emergency and Remedial Response

Baseline 

No specific requirement under Baseline.

Incremental Requirements under RA3

Develop and periodically review an emergency and remedial response plan that 

describes actions to be taken to address events that may cause an endangerment to a 

USDW during construction, operation and PISC.

Decrease

Overall Decrease

Note: Chapters 2 and 4 of the GS rule Cost Analysis provide detail on the components of the 

regulatory alternatives considered in this analysis and on the direction of change in risk 

associated with them, respectively..

In considering the benefits of the GS rule, the direction of change in risk compared to the 

baseline regulatory scenario was assessed for each component of the four RAs 

considered. An overall assessment for each alternative as a whole requires consideration 

of the relative importance of the risk being mitigated by each component of the rule.

As shown in Table IV-1, EPA estimates that under the selected alternative, RA3, risk will 

decrease relative to the baseline for each of the nine components assessed. 

b. Other Nonquantified Benefits 

Finalization of this rule will result in direct benefits, that is, protection of USDWs as is 

required of EPA under SDWA; and indirect benefits, which are those protections 

Deleted: ¶

Baseline ...
Page 163 of 274

afforded to entities as a by-product of protecting USDWs. Indirect benefits are described 

in Chapter 4 of the GS Rule Cost Analysis. They include mitigation of potential risk to 

surface ecology and to human health through exposure to elevated concentrations of CO2. 

Potential benefits from any climate change mitigation are not included in the assessment.

2. National Cost Summary

a. Cost of the Selected RA

EPA estimated the incremental one-time, capital, and operations and maintenance 

(O&M) costs associated with today’s rulemaking. As Table IV-2 shows, the total 

annualized incremental cost associated with the selected RA is $38.1 million (as 

compared to $15.0 million for the proposed rule) and $31.7 million (as compared to 

$15.6 million in the proposed rule), using a 3-percent and 7-percent discount rate, 

respectively. These costs are in addition to the baseline costs that would be incurred if GS 

activities were instead subject to the current rules for UIC Class I industrial wells. As can 

be seen from Table IV-2, today’s rule increases the costs of complying with UIC 

regulations for these wells from approximately a baseline total of $70.2 million ($32.3 

million in the proposed rule) to $108.3 million ($47.3 million in the proposed rule) in 

annualized terms using a 3-percent discount rate, which is an increase of 54 percent. EPA 

believes these increased costs are needed to ensure the protection of UDWSs from 

endangerment. The details of the costs associated with each RA are presented in the Cost 

Analysis, along with a discussion of how EPA derived these estimates (EPA, 2010d).

Comment [A127]: Cost numbers modified in 

response to OMB comments and subsequent model 

rerun. Oct/Nov. 2010

Deleted: 34.0

Deleted: 28.2

Deleted: 71.3

Deleted: 105.3

Deleted: 48 
Page 164 of 274

Table IV-2. Annualized Incremental Costs of Selected RA 

for Initial Baseline1 of 29 Projects (2008$, $million)

Regulatory 

Alternative One-Time Costs Capital Costs O&M Costs Total

RA0 $ 10.0 $ 15.5 $ 44.8 $ 70.2

RA3 $ 16.6 $ 21.5 $ 70.2 $ 108.3

RA3 Incremental $ 6.6 $ 6.0 $ 25.4 $ 38.1

RA0 $ 11.2 $ 16.5 $ 30.4 $ 58.1

RA3 $ 18.2 $ 23.5 $ 48.1 $ 89.8

RA3 Incremental $ 7.0 $ 7.0 $ 17.7 $ 31.7

Notes: 

2) Detail may not add due to rounding.

1) Depending on the RA, it is estimated that 25-26 of the 29 baseline projects (25.1 under RA0 and 26.4 

under RA3) will successfully deploy over the 50 year period of analysis. Annualized one-time, capital, and 

O&M costs are based on the number of successfully deployed projects.

7 Percent Discount Rate

3 Percent Discount Rate

Table IV-3 presents a breakout of the annualized incremental costs of the selected RA by 

rule component using a 3-percent discount rate:

• Monitoring activities account for approximately 49 percent of the incremental 

regulatory costs. Most of this cost is for the construction, operation, and maintenance 

of corrosion-resistant monitoring wells. This cost includes tracking of the plume and 

pressure front as well as the cost of incorporating monitoring results into fluid-flow 

models that are used to reevaluate the AoR. These activities are a key component of 

decreasing risk associated with GS because they facilitate early detection of 

unacceptable movement of CO2 or formation fluids. 

• The next largest cost component of the selected RA is injection well operation, which 

accounts for approximately 22 percent of the total incremental cost. This component 

ensures that the wells operate within established parameters in the permit to prevent 

unacceptable fluid movement. 

• Mechanical integrity testing accounts for approximately 6.8 percent of the cost. 

Continuous pressure monitoring is a key component of decreasing risk because it 

provides an early warning that a CO2 leak may have occurred and allows the owner or 

operator to prevent compromises to well integrity. 

Deleted: ¶

Deleted: 48 

Deleted: 27

Deleted: 7.6
Page 165 of 274

• Construction of Class VI wells using the corrosion-resistant design and materials 

necessary to withstand exposure to CO2 accounts for approximately 3.2 percent of the 

incremental cost of the selected RA.

• Geologic site characterization, which ensures that the site geology is safe and 

appropriate for GS, accounts for approximately 12.1 percent of the incremental cost 

of the selected RA. Costs for this component were determined using a site selection 

factor that accounts for the expense of characterizing multiple sites prior to finding an 

appropriate site. 

• Well plugging and post-injection site care activities, which ensure that the injection 

well is properly closed and that the geologic sequestration project no longer poses a 

risk to USDWs, account for approximately 5.7 percent of the total incremental cost of 

RA 3.

• AoR activities, which include modeling the AoR and remediating wells in the AoR, 

account for approximately 1.0 percent of the total incremental cost of RA3. 

Table IV-3. Annualized Incremental Rule Costs of Selected RA for Initial Baseline 

of 29 Projects by Rule Component 

(2008$, $million)

Geologic Site 

Characterization Monitoring

Injection Well 

Construction

Area of 

Review

Well 

Operation MIT

Well Plugging 

and PostInjection Site 

Care1

Financial 

Responsibility2

Permitting 

Authority 

Admin TOTAL

Baseline $6.7 $3.4 $16.2 $1.1 $41.8 $0.2 $0.6 $0.0 $0.3 $70.2

Alternative 3 $11.3 $22.0 $17.4 $1.5 $50.3 $2.7 $2.8 $0.0 $0.4 $108.3

Alt 3 Incremental $4.6 $18.6 $1.2 $0.4 $8.5 $2.6 $2.2 $0.0 $0.1 $38.1

Alt 3 as % of Total 12.1% 49% 3.2% 1.0% 22% 6.8% 5.7% 0.0% 0.3% 100%

Baseline $8.3 $2.9 $17.0 $1.0 $28.2 $0.1 $0.2 $0.0 $0.3 $58.1

Alternative 3 $14.1 $18.7 $18.4 $1.3 $34.2 $1.7 $1.0 $0.0 $0.4 $89.8

Alt 3 Incremental $5.7 $15.8 $1.4 $0.3 $5.9 $1.6 $0.8 $0.0 $0.2 $31.7

Alt 3 as % of Total 18% 50% 4.3% 1.1% 19% 5.1% 2.4% 0.0% 0.5% 100%

Notes:

3) Detail may not add due to rounding.

7 Percent Discount Rate

Regulatory 

Alternative

Rule Component

3 Percent Discount Rate

2) Costs related to demonstration of Financial Responsibility are less than $100,000 in annualized terms.

1) With the exception of the two pilot saline projects in the baseline, the GS Rule Cost Model does not capture the full PISC period for projects under the 

baseline and RA3, and because these costs mostly occur near (or after) the end of the 50 year period of analysis they are also significantly influenced by 

the discount rate.

b. Nonquantified Costs and Uncertainties in Cost Estimates

Deleted: 3.5

Deleted: 7.8

Deleted: 4.2

Deleted: 1.1

Comment [A128]: 

Footnote modified in response to OMB-OIRA 

comment (11/10)
Page 166 of 274

Should this rule somehow impede GS from happening, then the opportunity costs of not 

capturing the benefits associated with GS could be attributed to this regulation; however, 

the Agency has tried to develop a rule that balances risk with practicability, site specific 

flexibility and economic considerations and believes the probability of such impedance is 

low. This rule ensures protection of USDWs from endangerment associated with GS 

activities while also providing regulatory certainty to industry and permitting authorities 

and an increased understanding of GS through public participation and outreach. Thus, 

EPA believes the rule will not impede GS from happening and has not quantified such 

risk.

Uncertainties in the analysis are inherent in some of the basic assumptions as well as 

some detailed cost items. Uncertainties related to economic trends, the future rate of CCS 

deployment, and GS implementation choices may affect three basic assumptions on 

which the analysis is based: 1) the estimated number of projects that will be affected by 

the GS rule; 2) the labor rates applied; and 3) the estimated number of monitoring wells 

to be constructed per square mile of the AoR to adequately monitor in a given geologic 

setting. 

First, the number of projects that will deploy from 2011 through 2060 may be 

significantly underestimated in this analysis given the uncertainty in future deployment of 

this technology. The current baseline assumption is that 29 projects (changed from 22 

projects in the proposed rule) will deploy during the 50-year period (changed from 25 

years in the proposed rule), as described in Chapter 3 of the Cost Analysis. To address the 

uncertainty inherent in projecting the GS baseline, the final rule cost analysis also 

presents sensitivity analyses that considers 5 and 54 projects as the lower and upper 

bound project numbers to be consistent with the Mandatory Reporting of Greenhouse 

Gases: injection and Geologic Sequestration of CO2 rule (Subpart RR). EPA developed 

this rule simultaneously with Subpart RR to ensure coordination of requirements and 

costs between the two rules. The sensitivity analysis numbers (5 and 54 projects) are 

based on projected deployment highlighted in the presidential memorandum establishing 

Deleted: The purpose of this rule is to mitigate any 

potential risk caused by GS injection activities to the 

quality, and indirectly the quantity, of current and 

potential future USDWs. Furthermore, the rule 

creates requirements that are intended to provide 

additional safeguards. In the rare case where this rule 

is non-implementable and results in contamination of 

a USDW, the cost of clean-up or finding an 

alternative source of drinking water could be 

attributable to this rule. Based on data from States 

regarding implementation of the UIC program and 

current research, EPA considers the likelihood of 

this occurring very small and has not quantified this 

risk.¶

¶

Comment [A129]: Deletion made in response to 

OMB-OIRA comment.

Deleted: very 

Comment [A130]: Edit made in response to 

OMB-OIRA comment.

Deleted: the alternative deployment scenarios of 

50 percent more or 50 percent fewer projects. This 

Deleted: is

Deleted: in 
Page 167 of 274

the CCS Task Force and an EPA legislative analysis model of deployment under the 

American Power Act, respectively.

Second, the labor rate adopted for each of the labor categories for owners or operators 

described in Section 5.2.1 of the Cost Analysis (i.e., geoscientist, mining and geological 

engineer) may be underestimated. The labor rates used in the Cost Analysis are based on 

current industry costs; therefore, the level and pace of price responses as the level of GS 

deployment increases represents a potentially uncertain component in the cost estimates. 

The practice of CO2 injection represents an activity that, although already practiced 

widely in some contexts (i.e., ER), has the potential to expand rapidly in the coming 

years. This expansion may be exponential under certain climate legislative scenarios, 

which may lead to shortages in labor and equipment in the short term and result in rapid 

cost escalation for many of the cost components discussed in the Cost Analysis. 

However, based on current research, potential increases in costs due to increased 

deployment rates and an associated rise in demand for labor or services in the field are 

not expected to cause a rapid, wide-scale increase in deployment. To address the potential 

underestimate of laobr rates in the event that rapid deployment does drive up costs, EPA 

conducted sensitivyt analyses using labor rates that were 50% higher than those used in 

the primary anlysis. EPA found that the 50% increase in industry labor rates results in 

annualized incremental rule costs of $38.6 million based on a 3 percent discount rate, an 

approximately 1% increase in costs from the primary analysis.

Third, for the purpose of estimating national costs, the Agency assumes one monitoring 

well above the injection zone per two square miles of AoR; for monitoring wells into the 

injection zone, the Agency assumes one monitoring well per four square miles. EPA 

assumes monitoring wells into the injection zone will also be used to sample above the 

injection zone. However, the Agency recognizes that operators and primacy agency 

Directors may choose more or fewer monitoring wells depending on project site 

characteristics. Because the monitoring wells and associated costs represent a significant 

component of the cost analysis, the Agency acknowledges that this factor may be 

significant in the overall uncertainty of the cost analysis. To address this source of 

Deleted: is not intended to consider future 

legislative scenarios, the costs of which would not be 

attributed to this rule. Instead the 50 percent estimate 

is a large, round estimate that could reasonably be 

expected to represent a worst case scenario for the 

potential difference between the baseline information 

developed with DOE and actual deployment under 

the GS Rule in the context of existing legislation. 

Comment [A131]: Section updated in response 

to discussions between EPA and OMB-OIRA 

regarding sensitivity analyses. 

Deleted: GS

Comment [A132]: 

EPA edit 11/12/10 for clarity. 

Deleted: is expected 

Deleted: 

Comment [A133]: Paragraph modified in 

response to OMB-OIRA comment. (11/03)

Comment [A134]: 

Edit in response to OMB-OIRA track changes and 

comment.

Deleted: ¶

Deleted: this chapter. (Anecdotal evidence based 

on discussions with industry representatives suggests 

that there may already be labor shortages developing 

in some critical disciplines.) Because the cost 

analyses presented in this chapter are based on 

current industry costs, the level and pace of price 

responses as the level of GS deployment increases 

represent a highly uncertain component in the cost 

estimates presented in this chapter. ¶

¶
Page 168 of 274

uncertainty, the Agency conducted sensitivity analyses based on alternative estimates of 

25 percent more and 25 percent fewer monitoring wells than the number assumed for the 

primary analysis. These analyses resulted in annualized incremental rule costs of 

approximately $43.1 million and $33.0 million respectively, a 13 percent increase or 

decrease from the primary analysis results of $38.1 million at a 3 percent discount rate.

Additional uncertainties correspond more directly to specific assumptions made in 

constructing the cost model. If the assumptions for such items are incorrect, there may be 

significant cost implications outside of the general price level uncertainties discussed 

above. These cost items are described in Section 5.9.2 of the Cost Analysis. 

EPA requested and received comments on the cost analysis presented in the preamble of 

the proposed rule. One commenter expressed concern that EPA overstated risks to 

USDWs, which may discourage investment in CCS. EPA notes that the risks have been 

discussed as low, based on the rule requirements and the redundancy in those 

requirements. One commenter requested that costs be estimated for a range of projects, 

rather than only the number of projects estimated in the cost analysis. EPA notes that the 

cost analysis for the final rule presents sensitivity analyses that consider 5 and 54 projects 

as the lower and upper bound number of projects deployed which is comparable with the 

Subpart RR analysis. The sensitivity analyses are intended to further explore the 

implications of alternative climate policy scenarios.

EPA received comments on the proposal cost analysis section that suggested that various 

estimated costs were too high, too low, or absent. EPA clarifies that cost estimates are 

presented in incremental terms. For this reason, costs may seem lower or less 

comprehensive than expected. However, EPA increased some costs, such as labor rates, 

in response to comments. Using industry survey data from the American Association of 

Petroleum Geologists and the Society for Petroleum Engineers, as presented in the Cost 

Analysis, EPA increased the estimated labor rates significantly from the Bureau of Labor 

Statistics estimates used in the analysis for the proposed rule. The updated rates 

(weighted by 1.6 for overhead) in the analysis for the final rule are $110.62 and $107.23 

Comment [A135]: 

Edit in response to OMB-OIRA track changes and 

comment.

Deleted: ¶

Deleted: ¶

Deleted: (as for the proposal) 

Deleted: a

Deleted: is

Deleted: s

Deleted: a 50-percent increase and a 50-percent 

decrease in this estimated baseline number of 

projects

Deleted: s

Deleted: is is

Deleted: intented

Comment [A136]: Modification in response to 

OMB-OIRA comment (11/03). 
Page 169 of 274

in 2008$ for engineers and geologists, respectively. These correspond approximately to 

annual salaries of $143,800 and $139,400 and represent an approximately 115 percent 

and a one percent increase, respectively, for engineers and geologists from the proposed 

rule analysis. For more details please see the Cost Analysis for the Final GS Rule 

(USEPA, 2010d).

Lastly, many commenters believed that an assumption of three monitoring wells per GS 

injection well was too high or too low a ratio, or should be modeled for a range of values. 

EPA changed the algorithm for calculating the number of monitoring wells to be based 

on the AoR, instead of the number of injection wells. For a representative saline project 

of approximately 23.3 square miles, EPA assumed 12 monitoring wells (six above the 

injection zone, and six into the injection zone), which EPA understands will be an 

overestimate in some cases and an underestimate in others. Because EPA recognizes the 

inherent uncertainty in this assumption, the cost analysis for the proposed rule presented 

and for the final rule presents a sensitivity analysis based on alternative estimates of 25 

percent more and 25 percent fewer monitoring wells than the number assumed for the 

primary analysis.

c. Supplementary Cost and Uncertainties in Cost Estimates 

To better establish the context in which to evaluate the cost analysis for this rule, EPA

considers three types of costs that are not accounted for explicitly for this rule: 1) costs 

that are incurred beyond the 50-year timeframe of the analysis, 2) costs that could arise 

due to a higher rate of deployment of CCS in the future in response to climate change 

legislation, and 3) overall costs of CCS and their relationship to the proportion of such 

costs attributable to the requirements. Because GS is in the early phase of development, 

and given the significant interest in research, development, and eventual 

commercialization of CCS, EPA provides a preliminary discussion of the potential 

significance of these costs below.

Deleted: the proportion 

Deleted: overall 

Deleted: costs

Comment [A137]: OMB-OIRA comment/edit 

(10/29).

Deleted: impact 

Comment [A138]: OMB-OIRA comment/edit 

(11/01). 
Page 170 of 274

The cost analysis for this rule estimates costs that EPA anticipates will be incurred during 

a 50-year timeframe beginning with rule promulgation.

6

 When analyzing costs for a 

commercial-size saline formation sequestration project that begins in year one of the cost 

analysis, EPA assumes that the first year is a pre-construction and construction period, 

followed by 40 years of injection and then either 10, 50, or 100 years of PISC as 

indicated in the cost analysis for the RAs considered. Given the 50-year timeframe 

(changed from 25 years in the proposed rule) of the analysis, the first nine years (changed 

from four years in proposed rule) of the PISC period would be captured in the cost 

analysis for a project beginning in year one, and fewer or no years of PISC for a project 

beginning later in the 50-year analytical timeframe would be included. EPA estimates 

that the incremental present value sequestration costs above the baseline costs incurred 

for one representative large deep saline project within the 50-year timeframe of the cost 

analysis are approximately $1.26/metric tonne CO2. These costs over the full lifetime of 

the sequestration project are estimated to be $1.40/metric tonne CO2. Thus the 50-year 

timeframe (changed from 25 years in proposed rule) captures approximately 90 percent 

(changed from 75 percent in the proposed rule) of the present value lifetime incremental 

costs associated with implementing this rule. EPA notes, however, that the longer time 

horizon over which costs are estimated inherently introduces increasing amounts of 

uncertainty into those estimates, and that the relatively low percentage share of these 

costs as a fraction of the total costs is significantly influenced by the long horizon 

(greater than 50 years) over which they are discounted.

The cost analysis assumes that Class VI well owners or operators will inject 

approximately 1.0 billion metric tons (or 1.0 Petagram, Pg) of CO2 cumulatively over the 

next 50 years.

7

 The start years of these projects, for both pilot and large-scale saline, are 

staggered over the first seven years of the period of analysis.8

 6 A detailed discussion of the timeframe over which the costs of the final requirements were estimated can be found in 

the Cost Analysis. The 50 years of costs are calculated in terms of their present value (2008$) and then annualized over 

a 25- year period for a more consistent comparison to other regulations.

 Based on the assumed 

deployment schedule, the analysis captures the full injection periods for approximately 10 

7 A more detailed discussion of these projects can be found in the Cost Analysis. 8 A detailed table of the scheduled deployment of projects assumed in the baseline over the 50-year timeframe can be 

found in Exhibit 3.1 of the Cost Analysis.

Deleted: 20

Deleted: 09

Deleted: 91

Comment [A139]: 

OMB-OIRA track change. 11/10

Deleted: though a

Deleted: are

Comment [A140]: 

Modified OMB-OIRA track changes 11/10 and 

11/12.

Deleted: .¶
Page 171 of 274

large scale saline projects (with an injection period of 40 years) and 2 pilot saline projects 

(with an injection period of four years), and for 14 ER projects (with an assumed 

injection period of 10 years), which are in oil and gas reservoirs. The analysis assumes 

that 10 percent of projects initiated will include waiver applications, and that 50 percent 

of those applications will be approved, while the other 50 percent of waiver applicants 

are removed from the baseline. The analysis also assumes that five percent of project 

permits for the initial baseline estimate of 29 projects will not be approved for geological 

or mechanical reasons.9 While the baseline injection amount represents a significant step 

towards demonstrating the feasibility of CCS on an annual basis, it represents a small 

amount of current CO2 emissions in the United States (approximately one percent).

The US fleet of 1,493 coal-fired power generators emits 1.932 Pg CO2 equivalent per 

year. The technical or economic viability of retrofitting these or other industrial facilities 

with CCS is not the subject of this rulemaking. However, if some percentage of these 

facilities undertook CCS and used GS, they (or the owner or operator of the Class VI

injection wells) would be subject to the UIC requirements. For example, if 25 percent of 

these facilities undertook CCS (assuming a 90 percent capture rate and the incremental 

rule costs outlined in Table IV-4) the annualized incremental sequestration costs 

associated with meeting the Class VI requirements would be on the order of $546 

million. Similarly, if 100 percent of these plants undertook CCS, the annualized

incremental costs would be on the order of $2.2 billion, although it is unlikely that all 

coal plants would deploy CCS simultaneously. These preliminary cost estimates 

represent the annualized incremental cost of meeting the additional sequestration 

requirements in the rule, which would be incurred over the lifetime of the sequestration 

projects, assuming that all sequestration projects begin in the same year. These cost 

estimates were not generated from a full economic analysis or included in the cost 

analysis for this rule, due to the uncertainty of what percentage, if any, of such facilities 

will deploy CCS in the future. However, based on current research, the uncertainty in 

 9 Of the 29 projects that compose the initial baseline, a total of 10 percent, or approximately 3 projects, will not be 

approved based on their permit or waiver applications; costs for compiling the applications and reviewing them are 

included in the cost analysis, but no further costs are incurred for those projects that do not get approved. EPA 

recognizes that this may omit opportunity costs of projects that do not go forward.

Deleted: sequestration 

Comment [A141]: OMB-OIRA edit (11/01).

Deleted: 474 

Comment [A142]: OMB-OIRA edit (11/01).

Deleted: 1.9
Page 172 of 274

labor or service costs is not likely to contribute significantly as a rapid, wide-scale 

increase in deployment is not expected

, capital and labor cost trends, and the shape of the 

10. Therefore, the cost estimates presented 

represent a sensitivity analysis of the potential costs, assuming that 25 percent or 100 

percent of all plants undertake CCS beginning in the same year, and do not take into 

consideration CCS deployment rates and project-specific costs. Actual annualized costs 

incurred as CCS deploys in the future could be higher or lower, depending on a number 

of factors, including deployment rates

learning curve among industry and State/Federal operators.

Based on current literature, sequestration costs are expected to be a small component of 

total CCS project costs. Table IV-4 shows example total annualized CCS project costs 

broken down by capture, transportation, and sequestration components. The largest 

component of total CCS project costs is the cost of capturing CO2 ($42.90/metric tonne 

CO2 for capture from an integrated gasification combined cycle power plant12). 

Transportation costs vary widely depending on the distance from emission source to 

sequestration site, but EPA uses a long-term average estimate of $4.60/metric tonne 

CO2.

13 EPA estimates total sequestration costs for a commercial-size deep saline project 

to be approximately $3.80/ metric tonne CO2, of which approximately $1.40/metric tonne

CO2 is attributable to complying with requirements of this rule (including PISC). Based 

on the project costs outlined in Table IV-4, the requirements amount to approximately 2.7

percent of the total CCS project costs.

 10 Potential increase in costs due to increased deployment rates and an associated rise in demand for labor or services in 

the field were considered in terms of the uncertainty this contributes to the analysis results. However, a rapid wide scale 

increase in deployment is not expected, according to the Joint Global Change Research Institute (Dooley, 2010), 

therefore the uncertainty in labor or services costs does not contribute significantly to the uncertainty in this cost 

analysis. 

12 Cost and Performance Baseline for Fossil Energy Plants, Vol. 1, DOE/NETL-2007/1281, May 2007. 13 Costs of capture from the “Strategic Analysis of the Global Status of Carbon Capture and Storage Report 2: 

Economic assessment of carbon capture and storage technologies. Final Report,” 2009, Worley Parsons for Global CCS 

Institute. Costs of transport from “Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and 

Challenges,” Feb. 2009, INGAA Foundation.

Deleted: 

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Comment [A143]: OMB-OIRA edit (11/01).

Comment [A144]: Edits made in response to 

OMB-OIRA comment (11/03). 

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Table IV-4. Example Total Annualized CCS Project Costs

Cost over lifetime of project 

($/metric tonne)

Percentage of Total CCS 

Project Cost (%)

Capture (IGCC plant) $ 42.90 83.6%

Transportation Estimate $ 4.60 9.0%

Baseline Sequestration $ 2.40 4.7%

Incremental Final Rule 

Sequestration 

Requirements $ 1.40 2.7%

Total CCS Project Cost $ 51.30 100%

Notes:

1) Detail may not add due to rounding.

2) Transportation cost estimates are based on a distance of 150 miles.

Example Total CCS Project Costs (including capture at an IGCC plant, 

transportation, and deep saline reservoir at commercial scale sequestration)

B. Comparison of Benefits and Costs of RAs Considered

1. Costs Relative to Benefits; Maximizing Net Social Benefits

EPA developed a relative risk analysis in place of a comparison of quantified benefits (a 

direct numerical comparison of costs to benefits) because GS is a new technology and 

data collection on the potential effects of GS on USDWs are ongoing. Costs can only be 

compared to qualitative relative risks as discussed in section IV.A.1. 

Compared to the baseline, RA3 provides greater protection to USDWs because it is 

specifically tailored to GS injection activities. The current regulatory requirements do not 

specifically consider the injection of a buoyant, corrosive (in the presence of water) fluid. 

In particular, RA3 includes increased monitoring requirements that provide the amount of 

protection the Agency estimates is necessary for USDWs. As described in section IV.A. 

(National Benefits and Costs of the Rule), monitoring requirements account for 49

percent of the incremental regulatory costs, of which 74 percent is incurred for the 

construction, operation, and maintenance of monitoring wells, and the other 26 percent 

for tracking of the plume and pressure front through complex modeling at a minimum of 

every five years for all operators and for monitoring for CO2 leakage. Public awareness 

of these protective measures would be expected to enhance public acceptance of GS.

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EPA also compared RA1 and RA2 to the baseline (discussed in the proposed rule of July 

2008). RA1 does not contain specific requirements but requires operators to meet a 

performance standard regarding protection of USDWs. RA2 is similar to the Class II UIC 

requirements, with some additional construction and PISC requirements. See the Cost 

Analysis (USEPA, 2010d) for a more detailed description. RA1 and RA2 do not provide 

the specific safeguards against CO2 migration that RA3 does because of a significantly 

greater amount of discretion allowed to Directors and operators for interpreting 

requirements, and less stringent requirements for some compliance activities. Only RA3 

and RA4 require the periodic complex modeling exercise for tracking the plume, for 

example. RA4 provides greater safeguards against CO2 migration, but at a much higher 

cost.

2. Cost Effectiveness and Incremental Net Benefits

RA1 and RA2 provide lower costs than RA3 but at increased levels of risk to USDWs. 

Although RA4 has more stringent requirements, EPA does not believe that the increased 

requirements and the increased costs are necessary to provide protection to USDWs. 

Therefore EPA believes that RA3 is the most appropriate alternative. 

C. Conclusions

RA3 provides a high level of protection to USDWs overlying and underlying GS CO2

injection zones. It does so at lower costs than the more stringent RA4 while providing 

significantly more protection than RA1 or RA2. Therefore EPA has selected RA3 for the 

final GS Rule. 

V. Statutory and Executive Order Review 

A. Executive Order 12866: Regulatory Planning and Review 

Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is a 

“significant regulatory action.” Accordingly, EPA submitted this action to the Office of 

Management and Budget (OMB) for review under EO 12866 and any changes made in 

response to OMB recommendations have been documented in the docket for this action.

Deleted: "

Deleted: ,

Deleted: because this action will raise novel legal 

or policy issues.

Comment [A145]: OMB-OIRA edit (10/27).
Page 175 of 274

B. Paperwork Reduction Act (PRA)

The information collection requirements in this rule will be submitted for approval to the 

Office of Management and Budget (OMB) under the Paperwork Reduction Act (PRA), 

44 U.S.C. 3501 et seq. The information collection requirements are not enforceable until 

OMB approves them. 

The information collected as a result of this rule will allow EPA and State permitting 

authorities to review geologic information about a proposed injection project to evaluate 

its suitability for safe and effective GS. It also allows the Agency to fulfill the 

requirements of the UIC program to verify throughout the life of the injection project that 

protective requirements are in place and that USDWs are protected. The collection 

requirements are mandatory under the SDWA (42 U.S.C. 300h et seq.). 

For the first three years after publication of the final rule in the Federal Register, the 

major information requirements apply to a total of 38 respondents, for an average of 12.6

respondents per year. The total incremental burden (for owners or operators, permitting

authorities, and the Agency) associated with the change in moving from the information 

requirements of the UIC program for Class I non-hazardous wells (baseline) to the 

selected alternative under the GS Rule over the three years covered by the Information 

Collection Request (ICR) for the Geologic Sequestration Rule is 53,740 hours, for an 

average of 17,913 hours per year. The total incremental reporting and recordkeeping cost 

over the three year clearance period is $36.9 million, for an average of $12.3 million per 

year (simple average over three years). The average burden per response (i.e., the amount 

of time needed for each activity that requires a collection of information) is 423 hours; 

the average cost per response is $290,695. The collection requirements are mandatory 

under SDWA (42 U.S.C. 3501 et seq.). Details on the calculation of the rule information 

collection burden and costs can be found in the ICR (USEPA, 2010e) and Chapter 5 of 

the Cost Analysis (USEPA, 2010d). A summary of the burden and costs of the collection 

is presented in Exhibit V-1. 

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Comment [A146]: Modified OMB-OIRA edit

(11/03). 

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Exhibit V-1 Average Annual Net Change Burden and Costs for the GS ICR

Annual Labor 

Cost

Annual 

Capital Cost

Annual O&M 

Cost

Total Annual 

Cost

Owners or 

Operators 1.0 1,549 $ 204,574 $ 5,827,027 $ 5,454,346 $ 11,485,946 6.9 

Permitting 

Authorities 10.7 11,241 $ 555,763 $ - $ - $ 555,763 23.6 

Agency 1.0 5,123 $ 256,880 $ - $ - $ 256,880 11.7 

Total 12.6 17,913 $ 1,017,217 $ 5,827,027 $ 5,454,346 $ 12,298,589 42.3 

Source: 

Information Collection Request for the Geologic Sequestration Rule (USEPA, 2010c).

Notes:

1) Detail may not add exactly to total due to independent rounding.

2) “Annual Burden Hours” reflects an annual average for all project types over the 3-year ICR period.

Annual 

Responses

Respondent 

Type

Annual 

Respondents

Annual 

Burden 

Hours

Cost

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The 

OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. In 

addition, EPA is amending the table in 40 CFR part 9 of currently approved OMB control 

numbers for various regulations to list the regulatory citations for the information 

requirements contained in this final rule.

C. Regulatory Flexibility Act (RFA) 

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare regulatory 

flexibility analysis of any rule subject to notice and comment rulemaking requirements 

under the Administrative Procedures Act or any other statute unless the agency certifies 

that the rule will not have a significant economic impact on a substantial number of small 

entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts of today’s rule on small entities, small entity is 

defined as: (1) a small business primarily engaged in the generation, transmission, and/or 

distribution of electric energy for sale as defined by North American Industry 

Classification System (NAICS) codes 221111, 221112, 221113, 221119, 221121, 221122 

with total electric output for the preceding fiscal year that did not exceed 4 million 

megawatt hours; (2) a small business primarily engaged in petroleum production as 

defined by NAICS code 324110 with fewer than 1,500 employees and less than 125,000 
Page 177 of 274

barrels per calendar day in total Operable Atmospheric Crude Oil Distillation capacity, as 

specified for government procurement purposes (capacity includes owned or leased 

facilities as well as facilities under a processing agreement or an arrangement such as an 

exchange agreement or a throughput); (3) a small governmental jurisdiction that is a 

government of a city, county, town, school district or special district with a population of 

less than 50,000; and (4) a small organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its field. The small entity 

definitions for commercial operations focus on the electricity and oil and gas sectors 

because these are the sectors most likely to deploy GS.

After considering the economic impacts of today’s final rule on small entities, I certify

that this action will not have a significant economic impact on a substantial number of 

small entities. This rule does not impose any requirements on small entities. 

Furthermore, GS is a technologically complex activity, the cost of which is anticipated to 

be prohibitive to small entities. Therefore it is anticipated small entities would not elect to 

sequester CO2 via injection wells, and thus the rule will not have any impact on them. 

D. Unfunded Mandates Reform Act (UMRA) 

This rule does not contain a Federal mandate that may result in expenditures of $100 

million or more for State, local, and tribal governments, in the aggregate, or the private 

sector in any one year. The total annual incremental costs estimated for the 

implementation of this rule are well under $100 million, resulting in expenditures for the 

entity groupings required under an UMRA analysis that also fall far below the $100 

million per year threshold. Thus, this rule is not subject to the requirements of sections 

202 or 205 of UMRA.

This rule is also not subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or uniquely affect small 

Comment [A147]: OMB-OIRA edit (11/01). 

Comment [A148]: OMB-OIRA deletion and 

comment (11/01)

Deleted: GS is a voluntary action that would only 

be undertaken by a small entity if GS were in its 

interest compared to other alternatives it may have. 
Page 178 of 274

governments. Government responsibilities for oversight and implementation of this rule 

reside with State or Federal agencies and not with small governments.

E. Executive Order 13132: Federalism

Under section 6(b) of Executive Order 13132, EPA may not issue an action that has 

federalism implications, that imposes substantial direct compliance costs, and that is not 

required by statute, unless the Federal government provides the funds necessary to pay 

the direct compliance costs incurred by State and Local governments, or EPA consults 

with State and Local officials early in the process of developing the proposed action. In 

addition, under section 6(c) of Executive Order 13132, EPA may not issue an action that 

has federalism implications and that preempts State law, unless the Agency consults with 

State and Local officials early in the process of developing the proposed action. 

 

EPA concluded that today’s action does not have federalism implications. This rule will 

not impose substantial direct compliance costs on State or Local governments, nor does 

EPA anticipate that it will preempt State law. Thus, the requirements of sections 6(b) and 

6(c) of the Executive Order do not apply to this action. 

Consistent with EPA policy, EPA nonetheless consulted with representatives of State and 

local governments early in the process of developing the proposed action to permit them 

to have meaningful and timely input into its development. Representatives included the 

National Governors’ Association, the National Conference of State Legislatures, the 

Council of State Governments, the National League of Cities, the US Conference of 

Mayors, the National Association of Counties, the International City/County 

Management Association, the National Association of Towns and Townships, and the 

County Executives of America. In the spirit of Executive Order 13132, and consistent 

with EPA policy to promote communications between EPA and State and local 

governments, EPA specifically solicited comment on the proposed action from State and 

local officials. See section II of the Preamble for more details on consultation with State 

and local officials. 
Page 179 of 274

F. Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments

Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) EPA may not 

issue a regulation that has Tribal implications, that imposes substantial direct compliance 

costs, and that is not required by statute, unless the Federal government provides the 

funds necessary to pay the direct compliance costs incurred by Tribal governments, or 

EPA consults with Tribal officials early in the process of developing the proposed 

regulation and develops a Tribal summary impact statement. 

EPA has concluded that this action may have Tribal implications. However, it will 

neither impose substantial direct compliance costs on Tribal governments, nor preempt 

Tribal law. Indian Tribes may voluntarily apply for primary enforcement responsibility to 

regulate the UIC program in lands under their jurisdiction (See section II.G for more 

details on primacy). Currently, two Tribes have received primacy for the UIC program

under section 1425 of the SDWA since the publication of the proposed rule. EPA is 

responsible for implementing the UIC program in the event that States or Tribes do not 

seek primary enforcement responsibility. EPA clarifies that regardless of whether Tribes 

have UIC program primacy, the rule protects USDWs from contamination and therefore 

protects all populations from adverse health effects related to potential USDW

contamination. 
Page 180 of 274

EPA consulted with Tribal officials early in the process of developing this regulation to 

permit them to have meaningful and timely input into its development. A summary of the 

Tribal consultation calls are included in the docket for the GS rulemaking. See section 

II.E.3 for more information on the details of the Tribal consultation process. 

As required by section 7(a), EPA’s Tribal Consultation Official has certified that the 

requirements of the Executive Order have been met in a meaningful and timely manner. 

A copy of the certification is included in the docket for this action.

G. Executive Order 13045: Protection of Children from Environmental Health 

Risks and Safety Risks

This action is not subject to EO 13045 (62 FR 19885, April 23, 1997) because it is not 

economically significant as defined by EO 12866 and because the Agency does not 

believe the environmental health risks or safety risks addressed by this action present a 

disproportionate risk to children. Today’s rule does not require or provide incentive for 

firms to engage in GS, however, it does protect USDWs from potential negative impacts 

from GS of CO2 should a firm decide to undertake such a project. Health and risk 

assessments related to GS of CO2 and its effects on humans and the environment are 

presented in the Vulnerability Evaluation Framework for Geologic Sequestration of 

Carbon Dioxide (USEPA, 2008b). Additionally, EPA notes that it is funding and 

monitoring research related to the potential for USDW contamination associated with GS 

projects. Much of this research focuses on potential exceedances of drinking water 

standards (as suggested), which were developed by EPA and take into account impacts on 

children. Please see section II of this Preamble for more details on this research.

H. Executive Order 13211: Actions that Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a “significant energy action” as defined in Executive Order 13211 (66 

FR 28355 (May 22, 2001)), because it is not likely to have a significant adverse effect on 

the supply, distribution, or use of energy. The higher degree of regulatory certainty and 
Page 181 of 274

clarity in the permitting process may, in fact, have a positive effect on the energy sector. 

Specifically, if climate change legislation that imposes caps or taxes on CO2 emissions is 

passed in the future, energy generation firms and other CO2 producing industries will 

have an economic incentive to reduce emissions, and this rule will provide regulatory 

certainty in determining how best to meet any new requirements (for example, by 

maintaining or increasing production while staying within the emissions cap or avoiding 

some carbon taxes). The rule may allow some firms to extend the life of their existing 

capital investment in plant machinery or plant processes. 

I. National Technology Transfer and Advancement Act 

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(NTTAA), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use 

voluntary consensus standards in its regulatory activities unless to do so would be 

inconsistent with applicable law or otherwise impractical. Voluntary consensus standards 

are technical standards (e.g., materials specifications, test methods, sampling procedures, 

and business practices) that are developed or adopted by voluntary consensus standards 

bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the 

Agency decides not to use available and applicable voluntary consensus standards. 

This rulemaking involves environmental monitoring or measurement. Consistent with the 

Agency’s Performance Based Measurement System (PBMS), EPA has decided not to 

require the use of specific, prescribed analytic methods. Rather, the rule will allow the 

use of any method that meets the performance criteria. The PBMS approach is intended 

to be more flexible and cost-effective for the regulated community; it is also intended to 

encourage innovation in analytical technology and improved data quality. While EPA is 

not precluding the use of any method, whether it constitutes a voluntary consensus 

standard or not, as long as it meets the performance criteria specified, the PBMS 

approach is fully consistent with the use of voluntary consensus standards, as such 

standards are generally designed to address the same types of criteria required by PBMS. 

Deleted: to maximize operations 

Comment [A149]: OMB-OIRA edit (11/01).

Comment [A150]: OMB-OIRA edits (11/03). 
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J. Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations

Executive Order 12898 (59 FR 7629; February 16, 1994) establishes Federal executive 

policy on environmental justice. Its main provision directs Federal agencies, to the 

greatest extent practicable and permitted by law, to make environmental justice part of 

their mission by identifying and addressing, as appropriate, disproportionately high and 

adverse human health or environmental effects of their programs, policies, and activities 

on minority populations and low-income populations in the United States. 

EPA has determined that this final rule will not have disproportionately high and adverse 

human health or environmental effects on minority or low-income populations because it 

increases the level of environmental protection for all affected populations.

Existing electric power generation plants that burn fossil fuels may be more prevalent in 

areas with higher percentages of people who are minorities or have lower incomes on 

average, but it is hard to predict where new plants with CCS will be built. EPA is 

developing guidance for UIC Directors that places emphasis on considering the potential 

impact of any Class VI permits on communities (such as minority and low income 

populations) when evaluating Class VI injection well permit applications, as well as 

provides suggestions and tools for targeted outreach to ensure more meaningful public 

input and participation from the most affected communities during the permit evaluation 

and approval process. 

This rule does not require that GS be undertaken; but does require that if it is undertaken, 

operators will conduct the activity in such a way as to protect USDWs from 

endangerment caused by CO2. Additionally, this rule will ensure that all areas of the 

United States are subject to the same minimum Federal requirements for protection of 

USDWs from endangerment from GS. Additional detail regarding the potential risk of 

the rule is presented in the Vulnerability Evaluation Framework for Geologic 

Sequestration of Carbon Dioxide (USEPA, 2008b). 

K. Congressional Review Act
Page 183 of 274

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business 

Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may 

take effect, the agency promulgating the rule must submit a rule report, which includes a 

copy of the rule, to each House of the Congress and to the Comptroller General of the 

United States prior to publication of the rule in the Federal Register. A Major rule cannot 

take effect until 60 days after it is published in the Federal Register. This action is not a 

“major rule” as defined by 5 U.S.C. 804(2). This rule will be effective [INSERT DATE 

30 DAYS AFTER DATE OF PUBLICATION]. 

VI. References

Benson. 2008. Multi-Phase Flow and Trapping of CO2 in Saline Aquifers. Sally M. 

Benson, SPE, Stanford University. Copyright 2008, Offshore Technology Conference.

Birkholzer, J., T. Apps, L. Zheng, Y. Zhang, T. Xu, and C-F. Tsang. 2008a. Research 

Project on CO2 Geological Storage and Groundwater Resources: Water Quality Effects 

Caused by CO2 Intrusion into Shallow Groundwater. LBNL paper #LBNL-1251E. 

http://repositories.cdlib.org/lbnl/LBNL-1251E.

Birkholzer, J., Zhou, Q., Zhang, K., Jordan, P., Rutqvist, J., and C.F. Tsang. 2008b. 

Research Project on CO2 Geological Storage and Groundwater Resources: Large-Scale 

Hydrological Evaluation and Modeling of the Impact on Groundwater Systems. NETL 

Project Annual Report, October 1, 2007 to September 30, 2008.

BLM. 2009. Framework for Geological Carbon Sequestration on Public Land.

Celia, M.A., S. Bachu, J.M. Nordbotten, S.E. Gasda, and H.K. Dahle. 2004. Quantitative 

Estimation of CO2 Leakage from Geological Storage: Analytical Models, Numerical 

Models, and Data Needs. p. 663–671. In M. Wilson et al. (ed.) Proc. Int. Conf. on 

Greenhouse Gas Control Technologies, 7th, Vancouver, BC, Canada. 5–9 Sept. 2004. 

Vol. 1. Elsevier Science, Amsterdam.

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Comment [A151]: OMB Comment (OIRA) –

10/27/10

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Deleted: ¶

Deleted: e

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check).
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DOE NETL. 2007. Carbon Sequestration Atlas of the U.S. and Canada. U.S. Department 

of Energy, Office of Fossil Energy, National Energy Technology Laboratory. March

2007.

DOE NETL. 2008. Carbon Sequestration Atlas of the United States and Canada (Atlas 

II). Second Edition. National Energy Technology Laboratory, Pittsburgh, PA, USA. 

Dooley, J.J., R.T. Dahowski, C.L. Davidson. 2008. On the Long-Term Average Cost of 

CO2 Transport and Storage, Pacific Northwest National Laboratory, PNNL-17389.

Dooley, J., C. Davidson, and R. Dahowski. 2009. An Assessment of the Commercial 

Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. Joint 

Global Change Research Institute. Pacific Northwest National Laboratory. PNNL-18520. 

Duncan, I.J., J.P. Nicot, and J.W. Choi. 2009. Risk Assessment for Future CO2

Sequestration Projects Based on CO2 Enhanced Oil Recovery in the U.S. Energy 

Procedia 1(1): 2037-2042.

Energy Information Administration (EIA). 2009. Annual Energy Review, 2008. 

EPRI. 1999. Enhanced Oil Recovery Scoping Study. Report TR-113836.

GAO. 2008. Climate Change – Federal Actions Will Greatly Affect the Viability of 

Carbon Capture and Storage as a Key Mitigation Option. GAO-08-1080.

GAO. 2010. Climate Change: A Coordinated Strategy Could Focus Federal 

Geoengineering Research and Inform Governance Efforts. GAO-10-903.

Holloway, S., J. Pearce, V. Hards, T. Ohsumi, and J. Gale. 2007. Natural Emissions of 

CO2 from the Geosphere and their Bearing on the Geological Storage of Carbon Dioxide. 

Energy 32: 1194-1201.

Comment [A153]: Edited 11/15 (citations 

check).

Comment [A154]: Edited 11/15 (citations 

check).

Deleted: ,

Comment [A155]: Edited 11/15 (citations 

check).

Deleted: a

Deleted: 8

Formatted: Subscript

Comment [A156]: Edited 11/15 (citations 

check).

Deleted: 

Comment [A157]: Edited 11/15 (citations 

check).

Deleted: 08

Formatted: Font: Not Italic

Comment [A158]: Edited 11/15 (citations 

check).

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Formatted: Font: Not Italic
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IEA. 2003. Acid Gas Injection: A Study of Existing Operations. Phase 1: Final Report.

IEA. 2008. CO2 Capture and Storage: A Key Abatement Option. Energy Technology 

Analysis. Paris: IEA/OECD, 2008. 

IPCC. 2005. IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared by 

Working Group III of the Intergovernmental Panel on Climate Change. Metz, B., O. 

Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.). New York: Cambridge 

University Press.

IRS. 2009. Internal Revenue Service (IRS) Guidance for Tax Incentives for GS Projects 

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

Julian, J.Y., G.E. King, J.E. Johns, J.K. Sack, and D.B. Robertson. 2007. Detecting UltraSmall Leaks with Ultrasonic Leak Detection-Case Histories from the North Slope, 

Alaska. Presented at International Oil Conference and Exhibition, 27-30 June, Veracruz, 

Mexico. Society of Petroleum Engineers. Paper Number 108906-MS.

Klusman, R. W. 2003. Evaluation of Leakage Potential from a Carbon Dioxide 

EOR/Sequestration Project. Energy Conversion and Management 44: 1921-1940.

Oldenburg, C.M., K. Pruess, and S.M. Benson. 2001. Process Modeling of CO2 Injection 

into Natural Gas Reservoirs for Carbon Sequestration and Enhanced Gas Recovery.

Energy and Fuels 15: 293-298.

Oil and Gas Journal. 2008. Enhanced Oil Recovery Survey. April 21, 2008, p. 41-59.

Schnaar, G., and D.C. Digiulio. 2009. Computational Modeling of the Geologic 

Sequestration of Carbon Dioxide. Vadose Zone J. 8: 389–403.

Deleted: k

Deleted: a

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check).

Comment [A160]: IPCC 2007 removed 11/15 

(citations check). Not cited in the preamble.

Deleted: ¶

Deleted: IPCC. 2007. Climate Change 2007: 

Synthesis Report: Summary for Policymakers. 

Intergovernmental Panel on Climate Change.¶

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check).

Deleted: ,

Comment [A162]: Edited 11/15 (citations 

check).

Comment [A163]: Edited 11/15 (citations 

check).

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gas reservoirs for carbon sequestration and enhanced 

gas recovery. Energy and Fuels, 15: 293-298

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Skinner, L. 2003. CO2 Blowouts: An Emerging Problem. World Oil. 224(1). 

Somaschini, G., J. Lovell, H. Abdullah, B. Chariyev, P. Singh, and F. Arachman. 2009. 

Subsea Deployment of Instrumented Sand Screens in High-Rate Gas Wells. Presented at 

SPE Annual Technical Conference and Exhibition, 4-7 October 2009, New Orleans, 

Louisiana. Society of Petroleum Engineers. Paper Number 125047-MS.

USEPA. 2001. Class I Underground Injection Control Program: Study of the Risks 

Associated with Class I Underground Injection Wells. 

USEPA. 2007. Using the Class V Experimental Technology Well Classification for Pilot 

Carbon Geologic Sequestration Projects – Underground Injection Control Program

Guidance (UICPG # 83). March 2007.

USEPA. 2008a. Climate Change – Climate Economics. Economic Analyses. Updated 

May 7, 2008. http://www.epa.gov/climatechange/economics/economicanalyses.html.

USEPA. 2008b. Vulnerability Evaluation Framework for Geologic Sequestration of 

Carbon Dioxide.

USEPA. 2010. Climate Change Science Facts. 430-10-F-002.

USEPA. 2010a. International Geologic Sequestration Efforts: An Overview of the 

Sleipner, Weyburn, and In Salah Projects and Summary of International Regulatory 

Developments. 816-R10-011.

USEPA. 2010b. Drinking Water Treatment Considerations: Water Quality, Carbon 

Dioxide Concentration, and Geologic Sequestration Projects. 816-R10-014.

USEPA. 2010c. Technologies Available to Address Induced Faults and Fractures: 

Considerations for GS Sites. 816-R10-0018.

Comment [A167]: Edited 11/15 (citations 

check).

Deleted: SPE, 

Deleted: p

Comment [A168]: Edited 11/15 (citations 

check).

Comment [A169]: Edited 11/15 (citations 

check).

Comment [A170]: Edited 11/15 (citations 

check). See note below under USEPA 2010f.

Deleted: USEPA. 2010. EPA's June 2010 

American Power Act analysis: 

http://www.epa.gov/climatechange/economics/econo

micanalyses.html#apa2010¶

¶

Comment [A171]: Edited 11/15 (citations 

check).

Deleted: International GS Efforts: A look at the 

Sleipner, Weyburn, and In Salah Projects and other 

International Regulatory Developments

Comment [A172]: Edited 11/15 (citations 

check).

Deleted: Potential Impacts of Leaking Sequestered 

Carbon Dioxide on Water Treatment

Comment [A173]: Edited 11/15 (citations 

check).

Deleted: Characterization of Faults and Fractures 

for GS Operations: Possible Induced Changes

Formatted: Not Highlight
Page 187 of 274

USEPA. 2010d. Cost Analysis for the Federal Requirements Under the Underground 

Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS 

Rule). 816-R10-013. 

USEPA. 2010e. Information Collection Request for the Federal Requirements Under the

Underground Injection Control Program for Carbon Dioxide Geologic Sequestration. 

816-R10-012.

USEPA. 2010f. EPA’s June 2010 American Power Act Analysis.

http://www.epa.gov/climatechange/economics/economicanalyses.html#apa2010.

USGS. 2010. A Probabilistic Assessment Methodology for the Evaluation of Geologic 

Carbon Dioxide Storage. http://pubs.usgs.gov/of/2010/1127/.

WRI. 2007. J. Logan, J. Venezia, and K. Larsen. Issue Brief: Opportunities and 

Challenges for Carbon Capture and Sequestration. WRI Issue Brief, No. 1. World 

Resources Institute. October 2007. Washington, DC.

Comment [A174]: Edited 11/15 (citations 

check).

Deleted: T

Comment [A175]: Edited 11/15 (citations check) 

– moved and added period.

Deleted: USGS. 

Formatted: Font: Not Italic

Deleted: F

Formatted: Font: Not Italic

Deleted: T

Formatted: Font: Not Italic

Comment [A176]: Edited 11/15 (citations 

check).

Formatted: Font: Not Italic

Formatted: No underline

Comment [A177]: Edited 11/15 (citations 

check).

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

Formatted: No underline

Comment [A178]: Updated in preamble. 

Deleted: 2009. GS Capacity Methodology

http://pubs.usgs.gov/of/2009/1035/ofr2009-1035.pdf. ¶

Deleted: ,

Comment [A179]: Edited 11/15 (citations 

check).
Page 188 of 274

List of Subjects 

40 CFR Part 124

Environmental protection, Administrative practice and procedure, Air pollution control, 

Hazardous waste, Indians-lands, Reporting and recordkeeping requirements, Water 

pollution control, Water supply.

40 CFR Part 144

Environmental protection, Administrative practice and procedure, Confidential business 

information, Hazardous waste, Indians-lands, Reporting and recordkeeping requirements, 

Surety bonds, Water supply. 

40 CFR Part 145

Environmental protection, Confidential business information, Indian-lands, 

Intergovernmental relations, Penalties, Reporting and recordkeeping requirements, Water 

supply.

40 CFR Part 146 

Environmental protection, Hazardous waste, Indian-lands, Reporting and record keeping 

requirements, Water supply.
Page 189 of 274

[Federal Requirements Under the Underground Injection Control (UIC) Program 

for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells, Page 189 of 274]

40 CFR Part 147

Environmental protection, Indian-lands, Intergovernmental relations, Penalties, Reporting 

and record keeping requirements, Water supply.

Dated:

Lisa P. Jackson,

Administrator.

For the reasons set forth in the preamble, title 40 chapter I of the Code of Federal 

Regulations is amended as follows:

PART 124—PROCEDURES FOR DECISION MAKING

1. The Authority citation for part 124 continues to read as follows: 

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

Safe Drinking Water Act, 42 U.S.C. 300f et seq.; Clean Water Act, 33 U.S.C. 1251 et 

seq.; Clean Air Act, 42 U.S.C. 7401 et seq.

Subpart A—General Program Requirements

Deleted: 0

Deleted: 59

Comment [A180]: Formatting edits made by 

EPA for compliance with Federal Register 

requirements. These were not recommended by 

OMB-OIRA unless otherwise indicated. 
Page 190 of 274

2. Section 124.10 is amended by revising paragraph (c) introductory text and by adding 

paragraph (c)(1)(xi) to read as follows:

§ 124.10 Public notice of permit actions and public comment period.

* * * * *

(c) Methods (applicable to State programs, see 40 CFR 123.25 (NPDES), 145.11 (UIC), 

233.23 (404), and 271.14 (RCRA)). Public notice of activities described in paragraph 

(a)(1) of this section shall be given by the following methods:

(1) * * *

(xi) For Class VI injection well UIC permits, mailing or emailing a notice to State 

and local oil and gas regulatory agencies and State agencies regulating mineral 

exploration and recovery, the Director of the Public Water Supply Supervision 

program in the State, and all agencies that oversee injection wells in the State.

*****

PART 144—UNDERGROUND INJECTION CONTROL PROGRAM

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

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

Conservation and Recovery Act, 42 U.S.C. 6901 et seq.

Subpart A —General Provisions
Page 191 of 274

4. Section 144.1 is amended by adding paragraph (f)(1)(viii) and by revising paragraph 

(g) introductory text to read as follows.

§144.1 Purpose and scope of part 144.

* * * * *

(f) ***

(1) ***

(viii) Subpart H of part 146 sets forth requirements for owners or operators of 

Class VI injection wells.

* * * * *

(g) Scope of the permit or rule requirement. The UIC permit program regulates 

underground injection by six classes of wells (see definition of ‘‘well injection,’’ §144.3). 

The six classes of wells are set forth in §144.6. All owners or operators of these injection 

wells must be authorized either by permit or rule by the Director. In carrying out the 

mandate of the SDWA, this subpart provides that no injection shall be authorized by 

permit or rule if it results in the movement of fluid containing any contaminant into 

underground sources of drinking water (USDWs –see §144.3 for definition), if the 

presence of that contaminant may cause a violation of any primary drinking water 

regulation under 40 CFR part 141 or may adversely affect the health of persons 

(§144.12). Existing Class IV wells which inject hazardous waste directly into an 

underground source of drinking water are to be eliminated over a period of six months 

and new such Class IV wells are to be prohibited (§144.13). For Class V wells, if 

remedial action appears necessary, a permit may be required (§144.25) or the Director 

Deleted: 
Page 192 of 274

must require remedial action or closure by order (§144.6(c)). During UIC program 

development, the Director may identify aquifers and portions of aquifers which are actual 

or potential sources of drinking water. This will provide an aid to the Director in carrying 

out his or her duty to protect all USDWs. An aquifer is a USDW if it fits the definition 

under §144.3, even if it has not been “identified.” The Director may also designate 

“exempted aquifers” using the criteria in 40 CFR 146.4 of this chapter. Such aquifers are 

those which would otherwise qualify as “underground sources of drinking water” to be 

protected, but which have no real potential to be used as drinking water sources. 

Therefore, they are not USDWs. No aquifer is an exempted aquifer until it has been 

affirmatively designated under the procedures at §144.7. Aquifers which do not fit the 

definition of “underground source of drinking water” are not “exempted aquifers.” They 

are simply not subject to the special protection afforded USDWs. During initial Class VI 

program development, the Director shall not expand the areal extent of an existing Class 

II enhanced oil recovery or enhanced gas recovery aquifer exemption for Class VI 

injection wells and EPA shall not approve a program that applies for aquifer exemption 

expansions of Class II-Class VI exemptions as part of the program description. All Class 

II to Class VI aquifer exemption expansions previously issued by EPA must be 

incorporated into the Class VI program descriptions pursuant to requirements at 

§145.23(f)(9).***

* * * * *

5. Section 144.3 is amended by adding in alphabetic order “geologic sequestration” to 

read as follows:

Deleted: §

Comment [A181]: Deletion made in response to 

OMB-OIRA (see track changes below).

Deleted: , except that the Director may not expand 

the areal extent of an existing Class II enhanced oil 

recovery or enhanced gas recovery aquifer 

exemption for Class VI injection wells during initial 

program development and EPA may not approve a 

program with expanded Class II-Class VI 

exemptions. 

Deleted: may

Deleted: may

Deleted: with

Deleted: expanded 

Deleted: ) and must be issued pursuant to 

requirements at §§146.4 and 144.7.

Deleted: 

Comment [A182]: 

Edit made in response to OMB-OIRA comment

(11/12/10) and (11/15/10). 
Page 193 of 274

§144.3 Definitions

*****

Geologic sequestration means the long-term containment of a gaseous, liquid, or 

supercritical carbon dioxide stream in subsurface geologic formations. This term does not 

apply to carbon dioxide capture or transport.

*****

6. Section 144.6 is amended by revising paragraph (e) and adding paragraph (f) to read as 

follows:

§144.6 Classification of wells.

* * * * *

(e) Class V. Injection wells not included in Class I, II, III, IV, or VI. Specific 

types of Class V injection wells are described in §144.81.

(f) Class VI. Wells that are not experimental in nature that are used for geologic 

sequestration of carbon dioxide 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 of this 

chapter; or, wells used for geologic sequestration of carbon dioxide that have received an 

expansion to the areal extent of an existing Class II enhanced oil recovery or enhanced 

gas recovery aquifer exemption pursuant to §§146.4 of this chapter and 144.7(d).

.
Page 194 of 274

7. Section 144.7 is amended as follows: 

a. Revising paragraph (a); 

b. Revising paragraph (b); and

c. Adding paragraph (d) as follows:

§144.7 Identification of underground sources of drinking water and exempted 

aquifers

(a) The Director may identify (by narrative description, illustrations, maps, or 

other means) and shall protect as underground sources of drinking water, all aquifers and 

parts of aquifers which meet the definition of “underground source of drinking water” in 

§144.3, except to the extent there is an applicable aquifer exemption under paragraph (b) 

of this section or an expansion to the areal extent of an existing Class II enhanced oil 

recovery or enhanced gas recovery aquifer exemption for the exclusive purpose of Class 

VI injection for geologic sequestration under paragraph (d) of this section. Other than 

EPA approved aquifer exemption expansions that meet the criteria set forth in §146.4(d)

of this chapter, new aquifer exemptions shall not be issued for Class VI injection wells. 

Even if an aquifer has not been specifically identified by the Director, it is an 

underground source of drinking water if it meets the definition in §144.3.

(b)(1) The Director may identify (by narrative description, illustrations, maps, or 

other means) and describe in geographic and/or geometric terms (such as vertical and 

lateral limits and gradient) which are clear and definite, all aquifers or parts thereof which 

the Director proposes to designate as exempted aquifers using the criteria in §146.4 of 

this chapter.

Deleted: No exempted aquifer may be used for 

Class VI injection unless the owner or operator 

and/or Director requests, and EPA approves, a 

request to expand an existing Class II enhanced oil 

recovery or enhanced gas recovery(EOR/EGR)

aquifer exemption for a Class VI well in accordance 

with the criteria set forth in §146.4(d) of this chapter

and the requirements in paragraph (d) of this section. 

Comment [A183]: 

Edits in response to OMB-OIRA comment. 

11/12/10
Page 195 of 274

(2) No designation of an exempted aquifer submitted as part of a UIC program shall be 

final until approved by the Administrator as part of a UIC program. No designation of an 

expansion to the areal extent of a Class II enhanced oil recovery or enhanced gas 

recovery aquifer exemption for the exclusive purpose of Class VI injection for geologic 

sequestration shall be final until approved by the Administrator as a revision to the 

applicable Federal UIC program under part 147 or as a substantial revision of an 

approved State UIC program in accordance with §145.32 of this chapter. ***

* * * * *

(d) Expansion to the Areal Extent of Existing Class II Aquifer Exemptions for 

Class VI Wells. Owners or operators of Class II enhanced oil recovery or enhanced gas 

recovery wells may request that the Director approve an expansion to the areal extent of 

an aquifer exemption already in place for a Class II enhanced oil recovery or enhanced 

gas recovery well for the exclusive purpose of Class VI injection for geologic 

sequestration. Such requests must be treated as a revision to the applicable Federal UIC 

program under part 147 or as a substantial program revision to an approved State UIC 

program under §145.32 of this chapter and will not be final until approved by EPA. 

(1) The owner or operator of a Class II enhanced oil recovery or enhanced gas 

recovery well that requests an expansion of the areal extent of an existing aquifer 

exemption for the exclusive purpose of Class VI injection for geologic 

sequestration must define (by narrative description, illustrations, maps, or other 

means) and describe in geographic and/or geometric terms (such as vertical and 

lateral limits and gradient) that are clear and definite, all aquifers or parts thereof 

Deleted: 

Comment [A184]: 9/20/10: EPA edit made for 

consistency with other references to Class II wells 

for AE’s
Page 196 of 274

that are requested to be designated as exempted using the criteria in §146.4 of this 

chapter.

(2) In evaluating a request to expand the areal extent of an aquifer exemption of a 

Class II enhanced oil recovery or enhanced gas recovery well for the purpose of 

Class VI injection, the Director must determine that the request meets the criteria 

for exemptions in §146.4. In making the determination, the Director shall 

consider:

(i) Current and potential future use of the USDWs to be exempted as drinking 

water resources;

(ii) The predicted extent of the injected carbon dioxide plume, and any mobilized 

fluids that may result in degradation of water quality, over the lifetime of the GS 

project, as informed by computational modeling performed pursuant to 

§146.84(c)(1), in order to ensure that the proposed injection operation will not at 

any time endanger USDWs including non-exempted portions of the injection 

formation;

(iii) Whether the areal extent of the expanded aquifer exemption is of sufficient 

size to account for any possible revisions to the computational model during 

reevaluation of the area of review, pursuant to §146.84(e); and

(iv) Any information submitted to support a waiver request made by the owner or 

operator under §146.95, if appropriate.

8. Section 144.8 is amended by adding paragraph (b)(2)(iii) to read as follows:

Deleted: 

Deleted: 

Comment [A185]: Edits made in response to 

OMB Environmental Branch comment. 

Deleted: ¶
Page 197 of 274

§ 144.8 Noncompliance and program reporting by the Director. 

* * * * *

(b) ***

(2) ***

(iii) All Class VI program reports shall be consistent with reporting requirements 

set forth in §146.91 of this chapter.

* * * * *

Subpart B —General Program Requirements

9. Section 144.12 is amended by revising the first sentence in paragraph (b) to read as 

follows:

§ 144.12 Prohibition of movement of fluid into underground sources of drinking 

water.

* * * * *

(b) For Class I, II, III, and VI wells, if any water quality monitoring of an underground 

source of drinking water indicates the movement of any contaminant into the 

underground source of drinking water, except as authorized under part 146, the Director 

shall prescribe such additional requirements for construction, corrective action, operation, 

monitoring, or reporting (including closure of the injection well) as are necessary to 

prevent such movement. ***

* * * * *

Deleted: 
Page 198 of 274

10. Section 144.15 is added to read as follows:

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

The construction, operation or maintenance of any non-experimental Class V 

geologic sequestration well is prohibited.

11. Section 144.18 is added to read as follows:

§144.18 Requirements for Class VI wells. 

Owners or operators of Class VI wells must obtain a permit. Class VI wells 

cannot be authorized by rule to inject carbon dioxide.

12. Section 144.19 is added to read as follows:

§ 144.19 Transitioning from Class II to Class VI.

(a) Owners or operators that are injecting carbon dioxide for the primary purpose of longterm storage into an oil and gas reservoir must apply for and obtain a Class VI geologic 

sequestration permit when there is an increased risk to USDWs compared to Class II 

operations. In determining if there is an increased risk to USDWs, the owner or operator 

must consider the factors specified in §144.19(b).

Deleted: 

Deleted: 

Comment [A186]: 

EPA added dash for consistency with other text. 

11/15/10

Deleted: should

Comment [A187]: 

OMB-OIRA track changes (11/11) with minor 

modification
Page 199 of 274

(b) The Director shall determine when there is an increased risk to USDWs compared to 

Class II operations and a Class VI permit is required. In order to make this determination 

the Director must consider the following:

(1) Increase in reservoir pressure within the injection zone(s);

(2) Increase in carbon dioxide injection rates;

(3) Decrease in reservoir production rates;

(4) Distance between the injection zone(s) and USDWs;

(5) Suitability of the Class II area of review delineation; 

(6) Quality of abandoned well plugs within the area of review;

(7) The owner’s or operator’s plan for recovery of carbon dioxide at the cessation of 

injection;

(8) The source and properties of injected carbon dioxide; and

(9) Any additional site-specific factors as determined by the Director.

13. Section 144.22 is amended by revising paragraph (b) to read as follows:

§ 144.22 Existing Class II enhanced recovery and hydrocarbon storage wells. 

*****

(b) Duration of well authorization by rule. Well authorization under this section expires 

upon the effective date of a permit issued pursuant to §§144.19, 144.25, 144.31, 144.33 

or 144.34; after plugging and abandonment in accordance with an approved plugging and 

abandonment plan pursuant to §§144.28(c) and 146.10 of this chapter; and upon 

Deleted: criteria
Page 200 of 274

submission of a plugging and abandonment report pursuant to §144.28(k); or upon 

conversion in compliance with §144.28(j). 

* * * * *

Subpart D—Authorization by Permit

14. Section 144.31 is amended by revising paragraph (e) introductory text to read as 

follows:

§ 144.31 Application for a permit; authorization by permit.

*****

(e) Information requirements. All applicants for Class I, II, III, and V permits shall 

provide the following information to the Director, using the application form provided by 

the Director. Applicants for Class VI permits shall follow the criteria provided in §146.82

of this chapter.

* * * * *

15. Section 144.33 is amended by revising paragraph (a)(4) and adding paragraph (a)(5).

§ 144.33 Area permits. 

(a) ***

(4) Used to inject other than hazardous waste; and

(5) Other than Class VI wells. 

* * * * *
Page 201 of 274

16. Section 144.36 is amended by revising paragraph (a) to read as follows:

§144.36 Duration of permits.

(a) Permits for Class I and V wells shall be effective for a fixed term not to exceed 10 

years. UIC permits for Class II and III wells shall be issued for a period up to the 

operating life of the facility. UIC permits for Class VI wells shall be issued for the 

operating life of the facility and the post-injection site care period. The Director shall 

review each issued Class II, III, and VI well UIC permit at least once every 5 years to 

determine whether it should be modified, revoked and reissued, terminated or a minor 

modification made as provided in §§144.39, 144.40, or 144.41.

* * * * *

17. Section 144.38 is amended by revising paragraph (b) introductory text to read as 

follows:

§ 144.38 Transfer of permits.

* * * * *

(b) Automatic transfers. As an alternative to transfers under paragraph (a) of this section, 

any UIC permit for a well not injecting hazardous waste or injecting carbon dioxide for 

geologic sequestration may be automatically transferred to a new permittee if: 

* * * * *

Deleted: 
Page 202 of 274

18. Section 144.39 is amended as follows:

a. Revising the second sentence in paragraph (a) introductory text;

b. Revising the second sentence in paragraph (a)(3) introductory text; and 

c. Adding a new paragraph (a)(5) to read as follows:

§144.39 Modification or revocation and reissuance of permits.

* * * * *

(a) *** For Class I hazardous waste injection wells, Class II, Class III or Class VI wells 

the following may be causes for revocation and reissuance as well as modification; and 

for all other wells the following may be cause for revocation or reissuance as well as 

modification when the permittee requests or agrees. ***

*****

(3) *** Permits other than for Class I hazardous waste injection wells, Class II, 

Class III or Class VI wells may be modified during their permit terms for this 

cause only as follows: ***

*****

(5) Basis for modification of Class VI permits. Additionally, for Class VI wells, 

whenever the Director determines that permit changes are necessary based on:

(i) Area of review reevaluations under §146.84(e)(1) of this chapter;

(ii) Any amendments to the testing and monitoring plan under §146.90(j) of this 

chapter; 
Page 203 of 274

(iii) Any amendments to the injection well plugging plan under §146.92(c) of this 

chapter;

(iv) Any amendments to the post-injection site care and site closure plan under 

§146.93(a)(3) of this chapter; 

(v) Any amendments to the emergency and remedial response plan under 

§146.94(d) of this chapter; or

(vi) A review of monitoring and/or testing results conducted in accordance with 

permit requirements.

* * * * *

19. Section 144.41 is amended by adding a new paragraph (h) to read as follows:

§ 144.41 Minor modifications of permits.

* * * * *

(h) Amend a Class VI injection well testing and monitoring plan, plugging plan, postinjection site care and site closure plan, or emergency and remedial response plan where 

the modifications merely clarify or correct the plan, as determined by the Director. 

Subpart E—Permit Conditions

20. Section 144.51 is amended to read as follows:

a. Adding a new paragraph (j)(4); 

b. Revising paragraph (o); and 

Deleted: 
Page 204 of 274

c. Revising the first two sentences in paragraph (q)(1) and the first sentence in 

paragraph (q)(2). 

§ 144.51 Conditions applicable to all permits.

*****

(j) ***

(4) Owners or operators of Class VI wells shall retain records as specified in subpart H 

of part 146, including §§146.84(g), 146.91(f), 146.92(d), 146.93(f), and 146.93(h) of this 

chapter.

*****

(o) A Class I, II or III permit shall include and a Class V permit may include conditions 

which meet the applicable requirements of §146.10 of this chapter to ensure that plugging 

and abandonment of the well will not allow the movement of fluids into or between 

USDWs. Where the plan meets the requirements of §146.10 of this chapter, the Director

shall incorporate the plan into the permit as a permit condition. Where the Director's 

review of an application indicates that the permittee's plan is inadequate, the Director 

may require the applicant to revise the plan, prescribe conditions meeting the 

requirements of this paragraph, or deny the permit. A Class VI permit shall include 

conditions which meet the requirements set forth in §146.92 of this chapter. Where the 

plan meets the requirements of §146.92 of this chapter, the Director shall incorporate it 

into the permit as a permit condition. For purposes of this paragraph, temporary or 

intermittent cessation of injection operations is not abandonment. 

*****

Deleted: e

Deleted: g

Comment [A188]: 

Edits made to conform with regulatory changes at 

146.93 (in response to OMB comments). 
Page 205 of 274

(q) ***

(1) The owner or operator of a Class I, II, III or VI well permitted under this part 

shall establish mechanical integrity prior to commencing injection or on a 

schedule determined by the Director. Thereafter the owner or operator of Class I, 

II, and III wells must maintain mechanical integrity as defined in §146.8 of this 

chapter and the owner or operator of Class VI wells must maintain mechanical 

integrity as defined in §146.89 of this chapter. ***

(2) When the Director determines that a Class I, II, III or VI well lacks 

mechanical integrity pursuant to §§146.8 or 146.89 of this chapter for Class VI of this 

chapter, he/she shall give written notice of his/her determination to the owner or operator. 

***

* * * * *

21. Section 144.52 is amended as follows:

a. By revising paragraph (a) introductory text;

b. Revising paragraph (a)(2);

c. Revising paragraphs (a)(7)(i)(A) and (a)(7)(ii); and,

d. Revising paragraph (a)(8).

§ 144.52 Establishing permit conditions. 

(a) In addition to conditions required in §144.51, the Director shall establish conditions, 

as required on a case-by-case basis under §144.36 (duration of permits), §144.53(a) 

(schedules of compliance), §144.54 (monitoring), and for EPA permits only §144.53(b) 
Page 206 of 274

(alternate schedules of compliance), and §144.4 (considerations under Federal law). 

Permits for owners or operators of hazardous waste injection wells shall include 

conditions meeting the requirements of §144.14 (requirements for wells injecting 

hazardous waste), paragraphs (a)(7) and (a)(9) of this section, and subpart G of part 146. 

Permits for owners or operators of Class VI injection wells shall include conditions 

meeting the requirements of subpart H of part 146. Permits for other wells shall contain 

the following requirements, when applicable. 

*****

(2) Corrective action as set forth in §§144.55, 146.7, and 146.84 of this chapter.

*****

(7) ***

(i) ***

(A) The well has been plugged and abandoned in accordance with an approved 

plugging and abandonment plan pursuant to §§144.51(o), 146.10, and 146.92 of 

this chapter, and submitted a plugging and abandonment report pursuant to 

§144.51(p); or 

*****

(ii) The permittee shall show evidence of such financial responsibility to the 

Director by the submission of a surety bond, or other adequate assurance, such as 

a financial statement or other materials acceptable to the Director. For EPA 

administered programs, the Regional Administrator may on a periodic basis 

require the holder of a lifetime permit to submit an estimate of the resources 

needed to plug and abandon the well revised to reflect inflation of such costs, and 
Page 207 of 274

a revised demonstration of financial responsibility, if necessary. The owner or 

operator of a well injecting hazardous waste must comply with the financial 

responsibility requirements of subpart F of this part. For Class VI wells, the 

permittee shall show evidence of such financial responsibility to the Director by 

the submission of a qualifying instrument (see §146.85(a) of this chapter), such as 

a financial statement or other materials acceptable to the Director. The owner or 

operator of a Class VI well must comply with the financial responsibility 

requirements set forth in §146.85 of this chapter.

(8) Mechanical integrity. A permit for any Class I, II, III or VI well or injection 

project which lacks mechanical integrity shall include, and for any Class V well 

may include, a condition prohibiting injection operations until the permittee 

shows to the satisfaction of the Director under §§146.8, or 146.89 for Class VI,

that the well has mechanical integrity.

* * * * *

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

22. Section 144.80 is amended by revising the first sentence in paragraph (e) and by 

adding paragraph (f) to read as follows:

§144.80 What is a Class V injection well?

* * * * *

(e) Class V. Injection wells not included in Class I, II, III, IV or VI. *** 
Page 208 of 274

(f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath the 

lowermost formation containing a USDW, except those wells that are experimental in 

nature; 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 of this 

chapter; or, wells used for geologic sequestration of carbon dioxide that have received an 

expansion to the areal extent of a existing Class II enhanced oil recovery or enhanced gas 

recovery aquifer exemption pursuant to §§146.4 of this chapter and 144.7(d).

PART 145—STATE UIC PROGRAM REQUIREMENTS

23. The authority citation for part 145 continues to read as follows:

Authority: 42 U.S.C. 300f et seq.

Subpart A—General Program Requirements

24. Section 145.1 is amended by adding paragraph (i) to read as follows:

§ 145.1 Purpose and scope.

* * * * *

(i) States seeking primary enforcement responsibility for Class VI wells must submit a 

primacy application in accordance with subpart C of this part and meet all requirements 

of this part. States may apply for primary enforcement responsibility for Class VI wells 

independently of other injection well classes. 
Page 209 of 274

Subpart C—State Program Submissions

25. Section 145.21 is amended by adding paragraph (h) to read as follows:

§145.21 General requirements for program approvals.

* * * * *

(h) To establish a Federal UIC Class VI program in States not seeking full UIC primary 

enforcement responsibility approval, pursuant to the SDWA section 1422(c), States shall, 

by [INSERT DATE 270 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], submit to the Administrator a new or revised State UIC program complying 

with §§145.22 or 145.32 of this part. Beginning on [INSERT DATE 270 DAYS AFTER 

DATE OF PUBLICATION IN THE FEDERAL REGISTER] the requirements of subpart 

H of part 146 will be applicable and enforceable by EPA in each State that has not 

received approval of a new Class VI program application under section 1422 of the Safe 

Drinking Water Act or a revision of its UIC program under section 1422 of the Safe 

Drinking Water Act to incorporate subpart H of part 146. Following [INSERT DATE 270 

DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER], EPA will 

publish a list of the States where subpart H of part 146 has become applicable.

26. Section 145.22 is amended by revising paragraphs (a) introductory text and (a)(5) to 

read as follows:

§ 145.22 Elements of a program submission.
Page 210 of 274

(a) Any State that seeks to administer a program under this part shall submit to the 

Administrator at least three copies of a program submission. For Class VI programs, the 

entire submission can be sent electronically. The submission shall contain the following:

*****

(5) Copies of all applicable State statutes and regulations, including those 

governing State administrative procedures;

*****

27. Section 145.23 is amended as follows: 

a. By revising the introductory text; 

b. Revising paragraph (c);

c. Revising paragraph (d);

d. Revising paragraphs (f)(1), (f)(2), (f)(3), (f)(4), (f)(9); and,

e. Adding paragraphs (f)(13) to read as follows:

§ 145.23 Program description.

Any State that seeks to administer a program under this part shall submit a description of 

the program it proposes to administer in lieu of the Federal program under State law or 

under an interstate compact. For Class VI programs, the entire submission can be sent 

electronically. The program description shall include:

*****

(c) A description of applicable State procedures, including permitting procedures and any 

State administrative or judicial review procedures.

Deleted: 

Deleted: 

Deleted: 

Deleted: 

Deleted: 

Deleted: and (f)(14) 

Comment [A189]: 

EPA citation check – 11/12/10.
Page 211 of 274

(d) Copies of the permit form(s), application form(s), reporting form(s), and manifest 

format the State intends to employ in its program. Forms used by States need not be 

identical to the forms used by EPA but should require the same basic information. The 

State need not provide copies of uniform national forms it intends to use but should note 

its intention to use such forms. For Class VI programs, submit copies of the current forms 

in use by the State, if any.

*****

(f) ***

(1) A schedule for issuing permits within five years after program approval to all 

injection wells within the State which are required to have permits under this part 

and 40 CFR part 144. For Class VI programs, a schedule for issuing permits 

within two years after program approval;

(2) The priorities (according to criteria set forth in §146.9 of this chapter) for 

issuing permits, including the number of permits in each class of injection well 

which will be issued each year during the first five years of program operation. 

For Class VI programs, include the priorities for issuing permits and the number 

of permits which will be issued during the first two years of program operation;

(3) A description of how the Director will implement the mechanical integrity 

testing requirements of §146.8 of this chapter, or, for Class VI wells, the 

mechanical integrity testing requirements of §146.89 of this chapter, including the 

frequency of testing that will be required and the number of tests that will be 

reviewed by the Director each year; 
Page 212 of 274

(4) A description of the procedure whereby the Director will notify owners or

operators of injection wells of the requirement that they apply for and obtain a 

permit. The notification required by this paragraph shall require applications to be 

filed as soon as possible, but not later than four years after program approval for 

all injection wells requiring a permit. For Class VI programs approved before 

[INSERT DATE 365 DAYS AFTER PUBLICATION], a description of the 

procedure whereby the Director will notify 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 [INSERT DATE 365 DAYS AFTER PUBLICATION]. For Class VI 

programs approved following [INSERT DATE 365 DAYS AFTER 

PUBLICATION], a description of the procedure whereby the Director will notify 

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 previously permitted by EPA that they must 

apply for a Class VI permit pursuant to requirements at §146.81(c) within one 

year of Class VI program approval;

*****

(9) A description of aquifers, or parts thereof, which the Director has identified 

under §144.7(b) as exempted aquifers, and a summary of supporting data. For 

Deleted: 

Deleted: For Class VI programs, 

Deleted: must

Comment [A190]: 

OMB-OIRA edit/update. 11/15/10

Deleted: must 

Deleted: existing Class VI wells permitted by EPA 

or 

Deleted: that will continue injection of carbon 

dioxide for the purpose of GS 

Deleted: the Director must notify owners or 

operators of any existing Class VI wells or 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 Class VI rule 

promulgation [INSERT DATE 365 DAYS AFTER 

PUBLICATION] or one year after Class VI program 

approval, whichever comes firstthis paragraph shall 

require applications to be filed as soon as possible, 

but not later than one year after program approval

Comment [A191]: Added per OMB OIRA 

comment and edits 10/29; 11/08; and 11/12.

Deleted: and a summary of supporting data
Page 213 of 274

Class VI programs only, States must incorporate information related to any EPA 

approved exemptions expanding the areal extent of existing aquifer exemptions 

for Class II enhanced oil recovery or enhanced gas recovery wells transitioning to 

Class VI injection for geologic sequestration pursuant to requirements at 

§§146.4(d) and 144.7(d), including a summary of supporting data and the specific 

location of the aquifer exemption expansions. Other than expansions of the areal 

extent of Class II enhanced oil recovery or enhanced gas recovery well aquifer 

exemptions for Class VI injection, new aquifer exemptions shall not be issued for 

Class VI wells or injection activities;

*****

(13) For Class VI programs, a description of the procedure whereby the Director 

must notify, in writing, any States, Tribes, and Territories of any permit 

applications for geologic sequestration of carbon dioxide wherein the area of 

review crosses State, Tribal, or Territory boundaries, resulting in the need for 

trans-boundary coordination related to an injection operation. 

28. Section 145.32 is amended by adding a sentence at the end of paragraph (b)(2) to read 

as follows

§ 145.32 Procedures for revision of State programs.

*****

(b) ***

Comment [A192]: 

OMB-OIRA edit 11/15/10. 

Deleted: including exemptions expanding the areal 

extent of existing aquifer exemptions for Class II 

EOR/EGR wells transitioning to Class VI injection 

for GS pursuant to requirements at §§146.4 and 

144.7(d),. and a summary of supporting data. Other 

than expansions of the areal extent of Class II 

enhanced oil recovery or enhanced gas recovery well 

aquifer exemptions for Class VI injection, nNew 

aquifer exemptions shall not be issued for Class VI 

wells or injection activities, and Class VI wells 

cannot inject into previously exempted aquifers;

Comment [A193]: Edits made in response to 

OMB-OIRA comment (11/01) and (11/08)

Comment [A194]: Deleted in response to OMBOIRA comment (11/08)

Deleted: (14) For Class VI programs only, a 

description of any expansions to the areal extent of 

an existing Class II enhanced oil recovery or 

enhanced gas recovery aquifer exemption, which the 

Director has identified and approved under §144.7(d) 

of this chapter and a summary of supporting data. ¶
Page 214 of 274

(2) *** All requests for expansions to the areal extent of Class II enhanced oil recovery 

or enhanced gas recovery aquifer exemptions for Class VI wells must be treated as 

substantial program revisions.

*****

PART 146—UNDERGROUND INJECTION CONTROL PROGRAM: CRITERIA 

AND STANDARDS

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

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

Conservation and Recovery Act, 42 U.S.C. 6901 et seq.

30. Section 146.4 is amended by revising the introductory text and adding paragraph (d) 

to read as follows:

§ 146.4 Criteria for exempted aquifers.

An aquifer or a portion thereof which meets the criteria for an “underground source of 

drinking water” in §146.3 may be determined under §144.7 of this chapter to be an 

“exempted aquifer” for Class I-V wells if it meets the criteria in paragraphs (a) through 

(c) of this section. Class VI wells must meet the criteria under paragraph (d) of this 

section:

*****
Page 215 of 274

(d) The areal extent of an aquifer exemption for a Class II enhanced oil recovery or 

enhanced gas recovery well may be expanded for the exclusive purpose of Class VI 

injection for geologic sequestration under §144.7(d) of this chapter if it meets the 

following criteria:

(1) It does not currently serve as a source of drinking water; and

(2) The total dissolved solids content of the ground water is more than 3,000 mg/l 

and less than 10,000 mg/l; and

(3) It is not reasonably expected to supply a public water system.

31. Section 146.5 is amended by revising the first sentence in paragraph (e) introductory 

text and by adding paragraph (f) to read as follows:

§146.5 Classification of injection wells.

* * * * *

(e) Class V. Injection wells not included in Class I, II, III, IV or VI. *** 

* * * * *

(f) Class VI. Wells that are not experimental in nature that are used for geologic 

sequestration of carbon dioxide 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 enhanced oil recovery or enhanced gas recovery 

aquifer exemption pursuant to §§146.4 of this chapter and 144.7(d).

Deleted: 0

Deleted: 

Deleted: .
Page 216 of 274

32. Subpart H is added to read as follows:

Subpart H—Criteria and Standards Applicable to Class VI Wells

Sec.

146.81 Applicability.

146.82 Required Class VI permit information.

146.83 Minimum criteria for siting.

146.84 Area of review and corrective action.

146.85 Financial responsibility.

146.86 Injection well construction requirements.

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

146.88 Injection well operating requirements.

146.89 Mechanical integrity.

146.90 Testing and monitoring requirements.

146.91 Reporting requirements.

146.92 Injection well plugging.

146.93 Post-injection site care and site closure.

146.94 Emergency and remedial response.

146.95 Class VI injection depth waiver requirements. 

Subpart H—Criteria and Standards Applicable to Class VI Wells

§146.81 Applicability.

Deleted: 1
Page 217 of 274

(a) This subpart establishes criteria and standards for underground injection control 

programs to regulate any Class VI carbon dioxide geologic sequestration injection wells.

(b) This subpart applies to any wells used to inject carbon dioxide specifically for the 

purpose of geologic sequestration, i.e., the long-term containment of a gaseous, liquid, or 

supercritical carbon dioxide stream in subsurface geologic formations. 

(c) This subpart also applies to owners or operators of permit- or rule-authorized Class I, 

Class II, or Class V experimental carbon dioxide injection projects who seek to apply for 

a Class VI geologic sequestration permit for their well or wells. Owners or operators 

seeking to convert existing Class I, Class II, or Class V experimental wells to Class VI 

geologic sequestration wells must demonstrate to the Director that the wells were 

engineered and constructed to meet the requirements at §146.86(a) and ensure protection 

of USDWs, in lieu of requirements at §§146.86(b) and 146.87(a). By [INSERT DATE 

365 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER],

owners or operators of either 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 must apply for a Class VI permit. A converted well must still meet all other 

requirements under part 146.

(d) Definitions. The following definitions apply to this subpart. To the extent that these 

definitions conflict with those in §§144.3 or 146.3 of this chapter these definitions govern

for Class VI wells:

Area of review means the region surrounding the geologic sequestration project 

where USDWs may be endangered by the injection activity. The area of review is 

Comment [A195]: 

EPA edit 11/12/10.
Page 218 of 274

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.

Carbon dioxide plume means the extent underground, in three dimensions, of an 

injected carbon dioxide stream.

Carbon dioxide stream means carbon dioxide that has been captured from an 

emission source (e.g., a power plant), plus incidental associated substances 

derived from the source materials and the capture process, and any substances 

added to the stream to enable or improve the injection process. This subpart does 

not apply to any carbon dioxide stream that meets the definition of a hazardous 

waste under 40 CFR part 261. 

Confining zone means a geologic formation, group of formations, or part of a 

formation stratigraphically overlying the injection zone(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 means 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 underground sources of drinking water (USDW). 

Geologic sequestration means the long-term containment of a gaseous, liquid, or 

supercritical carbon dioxide stream in subsurface geologic formations. This term 

does not apply to carbon dioxide capture or transport.
Page 219 of 274

Geologic sequestration project means 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 enhanced oil recovery or 

enhanced gas recovery aquifer exemption pursuant to §§146.4 of this chapter 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.

Injection zone means a geologic formation, group of formations, or part of a 

formation that is of sufficient areal extent, thickness, porosity, and permeability to 

receive carbon dioxide through a well or wells associated with a geologic 

sequestration project.

Post-injection site care means appropriate monitoring and other actions 

(including corrective action) needed following cessation of injection to ensure that 

USDWs are not endangered, as required under §146.93.

Pressure front means the zone of elevated pressure that is created by the injection 

of carbon dioxide into the subsurface. For the purposes of this subpart, the 

pressure front of a carbon dioxide plume refers to a zone where there is a pressure 

differential sufficient to cause the movement of injected fluids or formation fluids 

into a USDW.
Page 220 of 274

Site closure means the point/time, as determined by the Director following the 

requirements under §146.93, at which the owner or operator of a geologic 

sequestration site is released from post-injection site care responsibilities. 

Transmissive fault or fracture means a fault or fracture that has sufficient 

permeability and vertical extent to allow fluids to move between formations.

§146.82 Required Class VI permit information.

This section sets forth the information which must be considered by the Director in 

authorizing Class VI wells. For converted Class I, Class II, or Class V experimental 

wells, certain maps, cross-sections, tabulations of wells within the area of review and 

other data may be included in the application by reference provided they are current, 

readily available to the Director, and sufficiently identified to be retrieved. In cases where 

EPA issues the permit, all the information in this section must be submitted to the 

Regional Administrator.

(a) Prior to the issuance of a permit for the construction of a new Class VI well or the 

conversion of an existing Class I, Class II, or Class V well to a Class VI well, the owner 

or operator shall submit, pursuant to §146.91(e), and the Director shall consider the 

following:

(1) Information required in §144.31 (e)(1) through (6) of this chapter;

(2) A map showing the injection well for which a permit is sought and the 

applicable area of review consistent with §146.84. Within the area of review, the 

map must show the number or name, and location of all injection wells, producing 

wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, 
Page 221 of 274

State- or EPA-approved subsurface cleanup sites, surface bodies of water, springs, 

mines (surface and subsurface), quarries, water wells, other pertinent surface 

features including structures intended for human occupancy, State, Tribal, and 

Territory boundaries, and roads. The map should also show faults, if known or 

suspected. Only information of public record is required to be included on this 

map;

(3) Information on the geologic structure and hydrogeologic properties of the 

proposed storage site and overlying formations, including:

(i) Maps and cross sections of the area of review;

(ii) The location, orientation, and properties of known or suspected faults 

and fractures that may transect the confining zone(s) in the area of review 

and a determination that they would not interfere with containment;

(iii) Data on the depth, areal extent, thickness, mineralogy, porosity, 

permeability, and capillary pressure of the injection and confining zone(s); 

including geology/facies changes based on field data which may include 

geologic cores, outcrop data, seismic surveys, well logs, and names and 

lithologic descriptions; 

(iv) Geomechanical information on fractures, stress, ductility, rock 

strength, and in situ fluid pressures within the confining zone(s); 

(v) Information on the seismic history including the presence and depth of 

seismic sources and a determination that the seismicity would not interfere 

with containment; and
Page 222 of 274

(vi) Geologic and topographic maps and cross sections illustrating 

regional geology, hydrogeology, and the geologic structure of the local 

area.

(4) A tabulation of all wells within the area of review which penetrate the 

injection or confining zone(s). Such data must include a description of each well's 

type, construction, date drilled, location, depth, record of plugging and/or 

completion, and any additional information the Director may require;

(5) Maps and stratigraphic cross sections indicating the general vertical and lateral 

limits of all USDWs, water wells and springs within the area of review, their 

positions relative to the injection zone(s), and the direction of water movement, 

where known;

(6) Baseline geochemical data on subsurface formations, including all USDWs in 

the area of review; 

(7) Proposed operating data for the proposed geologic sequestration site:

(i) Average and maximum daily rate and volume and/or mass and total 

anticipated volume and/or mass of the carbon dioxide stream;

(ii) Average and maximum injection pressure; 

(iii) The source(s) of the carbon dioxide stream; and

(iv) An analysis of the chemical and physical characteristics of the carbon 

dioxide stream.
Page 223 of 274

(8) Proposed pre-operational formation testing program to obtain an analysis of 

the chemical and physical characteristics of the injection zone(s) and confining 

zone(s) and that meets the requirements at §146.87;

(9) Proposed stimulation program, a description of stimulation fluids to be used

and a determination that stimulation will not interfere with containment;

(10) Proposed procedure to outline steps necessary to conduct injection operation;

(11) Schematics or other appropriate drawings of the surface and subsurface 

construction details of the well;

(12) Injection well construction procedures that meet the requirements of 

§146.86;

(13) Proposed area of review and corrective action plan that meets the 

requirements under §146.84;

(14) A demonstration, satisfactory to the Director, that the applicant has met the 

financial responsibility requirements under §146.85;

(15) Proposed testing and monitoring plan required by §146.90;

(16) Proposed injection well plugging plan required by §146.92(b);

(17) Proposed post-injection site care and site closure plan required by 

§146.93(a);

(18) At the Director’s discretion, a demonstration of an alternative post-injection 

site care timeframe required by §146.93(c);

(19) Proposed emergency and remedial response plan required by §146.94(a); 

Comment [A196]: Insertion (and subsequent 

renumbering) 11/11based on OIRA discussion

Deleted: and
Page 224 of 274

(20) A list of contacts, submitted to the Director, for those States, Tribes, and 

Territories identified to be within the area of review of the Class VI project based 

on information provided in paragraph (a)(2) of this section; and

(21) Any other information requested by the Director. 

(b) The Director shall notify, in writing, any States, Tribes, or Territories within the area 

of review of the Class VI project based on information provided in paragraphs (a)(2) and 

(a)(20) of this section of the permit application and pursuant to the requirements at 

§145.23(f)(13) of this chapter.

(c) Prior to granting approval for the operation of a Class VI well, the Director shall 

consider the following information:

(1) The final area of review based on modeling, using data obtained during 

logging and testing of the well and the formation as required by paragraphs (c)(2), 

(3), (4), (6), (7), and (10) of this section; 

(2) Any relevant updates, based on data obtained during logging and testing of the 

well and the formation as required by paragraphs (c)(3), (4), (6), (7), and (10) of 

this section, to the information on the geologic structure and hydrogeologic 

properties of the proposed storage site and overlying formations, submitted to 

satisfy the requirements of paragraph (a)(3) of this section; 

(3) Information on the compatibility of the carbon dioxide stream with fluids in 

the injection zone(s) and minerals in both the injection and the confining zone(s), 

based on the results of the formation testing program, and with the materials used 

to construct the well; 

Deleted: 19

Deleted: 0

Deleted: 19

Comment [A197]: 

EPA citation checks.
Page 225 of 274

(4) The results of the formation testing program required at paragraph (a)(8) of 

this section;

(5) Final injection well construction procedures that meet the requirements of 

§146.86;

(6) The status of corrective action on wells in the area of review; 

(7) All available logging and testing program data on the well required by 

§146.87;

(8) A demonstration of mechanical integrity pursuant to §146.89;

(9) Any updates to the proposed area of review and corrective action plan, testing 

and monitoring plan, injection well plugging plan, post-injection site care and site 

closure plan, or the emergency and remedial response plan submitted under 

paragraph (a) of this section, which are necessary to address new information 

collected during logging and testing of the well and the formation as required by 

all paragraphs of this section, and any updates to the alternative post-injection site 

care timeframe demonstration submitted under paragraph (a) of this section, 

which are necessary to address new information collected during the logging and 

testing of the well and the formation as required by all paragraphs of this section; 

and

(10) Any other information requested by the Director.

(d) Owners or operators seeking a waiver of the requirement to inject below the 

lowermost USDW must also refer to §146.95 and submit a supplemental report, as 

required at §146.95(a). The supplemental report is not part of the permit application. 

Comment [A198]: Added 11/11 based on OIRA

discussion.
Page 226 of 274

§146.83 Minimum criteria for siting.

(a) Owners or operators of Class VI wells must demonstrate to the satisfaction of the 

Director that the wells will be sited in areas with a suitable geologic system. The owners 

or operators must demonstrate that the geologic system comprises: 

(1) An injection zone(s) of sufficient areal extent, thickness, porosity, and 

permeability to receive the total anticipated volume of the carbon dioxide stream;

(2) Confining zone(s) free of transmissive faults or fractures and of sufficient 

areal extent and integrity to contain the injected carbon dioxide stream and 

displaced formation fluids and allow injection at proposed maximum pressures 

and volumes without initiating or propagating fractures in the confining zone(s).

(b) The Director may require owners or operators of Class VI wells to identify and 

characterize additional zones that will impede vertical fluid movement, are free of faults 

and fractures that may interfere with containment, allow for pressure dissipation, and 

provide additional opportunities for monitoring, mitigation, and remediation. 

§146.84 Area of review and corrective action. 

(a) The area of review is 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 is based on available site 

characterization, monitoring, and operational data. 
Page 227 of 274

(b) The owner or operator of a Class VI well must prepare, maintain, and comply with a 

plan to delineate the area of review for a proposed geologic sequestration project, 

periodically reevaluate the delineation, and perform corrective action that meets the 

requirements of this section and is acceptable to the Director. The requirement to 

maintain and implement an approved plan is directly enforceable regardless of whether 

the requirement is a condition of the permit. As a part of the permit application for 

approval by the Director, the owner or operator must submit an area of review and 

corrective action plan that includes the following information:

(1) The method for delineating the area of review that meets the requirements of 

paragraph (c) of this section, including the model to be used, assumptions that 

will be made, and the site characterization data on which the model will be based; 

(2) A description of:

(i) The minimum fixed frequency, not to exceed five years, at which the 

owner or operator proposes to reevaluate the area of review;

(ii) The monitoring and operational conditions that would warrant a 

reevaluation of the area of review prior to the next scheduled reevaluation 

as determined by the minimum fixed frequency established in paragraph 

(b)(2)(i) of this section.

(iii) How monitoring and operational data (e.g., injection rate and 

pressure) will be used to inform an area of review reevaluation; and

(iv) How corrective action will be conducted to meet the requirements of 

paragraph (d) of this section, including what corrective action will be 

performed prior to injection and what, if any, portions of the area of 
Page 228 of 274

review will have corrective action addressed on a phased basis and how 

the phasing will be determined; how corrective action will be adjusted if 

there are changes in the area of review; and how site access will be 

guaranteed for future corrective action.

(c) Owners or operators of Class VI wells must perform the following actions to 

delineate the area of review and identify all wells that require corrective action:

(1) Predict, using existing site characterization, monitoring and operational data,

and computational modeling, the projected lateral and vertical migration of the 

carbon dioxide plume and formation fluids in the subsurface from the 

commencement of injection activities until the plume movement ceases, until 

pressure differentials sufficient to cause the movement of injected fluids or 

formation fluids into a USDW are no longer present, or until the end of a fixed 

time period as determined by the Director. The model must:

(i) Be based on detailed geologic data collected to characterize the 

injection zone(s), confining zone(s) and any additional zones; and 

anticipated operating data, including injection pressures, rates, and total 

volumes over the proposed life of the geologic sequestration project;

(ii) Take into account any geologic heterogeneities, other discontinuities, 

data quality, and their possible impact on model predictions; and

(iii) Consider potential migration through faults, fractures, and artificial 

penetrations.

(2) Using methods approved by the Director, identify all penetrations, including 

active and abandoned wells and underground mines, in the area of review that 
Page 229 of 274

may penetrate the confining zone(s). Provide a description of each well’s type, 

construction, date drilled, location, depth, record of plugging and/or completion, 

and any additional information the Director may require; and 

(3) Determine which abandoned wells in the area of review have been plugged in 

a manner that prevents the movement of carbon dioxide or other fluids that may 

endanger USDWs, including use of materials compatible with the carbon dioxide 

stream.

(d) Owners or operators of Class VI wells must perform corrective action on all wells in 

the area of review that are determined to need corrective action, using methods designed 

to prevent the movement of fluid into or between USDWs, including use of materials 

compatible with the carbon dioxide stream, where appropriate. 

(e) At the minimum fixed frequency, not to exceed five years, as specified in the area of 

review and corrective action plan, or when monitoring and operational conditions 

warrant, owners or operators must: 

(1) Reevaluate the area of review in the same manner specified in paragraph 

(c)(1) of this section;

(2) Identify all wells in the reevaluated area of review that require corrective 

action in the same manner specified in paragraph (c) of this section; 

(3) Perform corrective action on wells requiring corrective action in the 

reevaluated area of review in the same manner specified in paragraph (d) of 

this section; and

(4) Submit an amended area of review and corrective action plan or demonstrate 

to the Director through monitoring data and modeling results that no 
Page 230 of 274

amendment to the area of review and corrective action plan is needed. Any 

amendments to the area of review and corrective action plan must be approved 

by the Director, must be incorporated into the permit, and are subject to the 

permit modification requirements at §§144.39 or 144.41 of this chapter, as 

appropriate.

(f) The emergency and remedial response plan (as required by §146.94) and the

demonstration of financial responsibility (as described by §146.85) must account for the 

area of review delineated as specified in paragraph (c)(1) of this section or the most 

recently evaluated area of review delineated under paragraph (e) of this section, 

regardless of whether or not corrective action in the area of review is phased.

(g) All modeling inputs and data used to support area of review reevaluations under 

paragraph (e) of this section shall be retained for 10 years.

§146.85 Financial responsibility. 

(a) The owner or operator must demonstrate and maintain financial responsibility as 

determined by the Director that meets the following conditions:

(1) The financial responsibility instrument(s) used must be from the following list 

of qualifying instruments: 

(i) Trust Funds

(ii) Surety Bonds

(iii) Letter of Credit

(iv) Insurance
Page 231 of 274

(v) Self Insurance (i.e., Financial Test and Corporate Guarantee)

(vi) Escrow Account

(vii) Any other instrument(s) satisfactory to the Director

(2) The qualifying instrument(s) must be sufficient to cover the cost of:

(i) Corrective action (that meets the requirements of §146.84);

(ii) Injection well plugging (that meets the requirements of §146.92);

(iii) Post injection site care and site closure (that meets the requirements of 

§146.93); and 

(iv) Emergency and remedial response (that meets the requirements of 

§146.94).

(3) The financial responsibility instrument(s) must be sufficient to address 

endangerment of underground sources of drinking water. 

(4) The qualifying financial responsibility instrument(s) must comprise protective 

conditions of coverage.

(i) Protective conditions of coverage must include at a minimum 

cancellation, renewal, and continuation provisions, specifications on when 

the provider becomes liable following a notice of cancellation if there is a 

failure to renew with a new qualifying financial instrument, and 

requirements for the provider to meet a minimum rating, minimum 

capitalization, and ability to pass the bond rating when applicable. 

(A) Cancellation – for purposes of this part, an owner or operator must 

provide that their financial mechanism may not cancel, terminate or fail to 

renew except for failure to pay such financial instrument. If there is a 

Deleted: in case 

Comment [A199]: 

OMB-OIRA edit 11/15/10. 
Page 232 of 274

failure to pay the financial instrument, the financial institution may elect to 

cancel, terminate, or fail to renew the instrument by sending notice by 

certified mail to the owner or operator and the Director. The cancellation 

must not be final for 120 days after receipt of cancellation notice. The 

owner or operator must provide an alternate financial responsibility 

demonstration within 60 days of notice of cancellation, and if an alternate 

financial responsibility demonstration is not acceptable (or possible), any 

funds from the instrument being cancelled must be released within 60 days 

of notification by the Director.

(B) Renewal – for purposes of this part, owners or operators must renew 

all financial instruments, if an instrument expires, for the entire term of the 

geologic sequestration project. The instrument may be automatically 

renewed as long as the owner or operator has the option of renewal at the 

face amount of the expiring instrument. The automatic renewal of the 

instrument must, at a minimum, provide the holder with the option of 

renewal at the face amount of the expiring financial instrument. 

(C) Cancellation, termination, or failure to renew may not occur and the 

financial instrument will remain in full force and effect in the event that on 

or before the date of expiration: the Director deems the facility abandoned; 

or the permit is terminated or revoked or a new permit is denied; or 

closure is ordered by the Director or a U.S. district court or other court of 

competent jurisdiction; or the owner or operator is named as debtor in a 

Deleted: should 

Comment [A200]: 

Edit made in response to OMB-OIRA comment 

(11/12).
Page 233 of 274

voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. 

Code; or the amount due is paid.

(5) The qualifying financial responsibility instrument(s) must be approved by the 

Director. 

(i) The Director shall consider and approve the financial responsibility 

demonstration for all the phases of the geologic sequestration project prior to 

issue a Class VI permit (§146.82).

(ii) The owner or operator must provide any updated information related 

to their financial responsibility instrument(s) on an annual basis and if there are 

any changes, the Director must evaluate, within a reasonable time, the financial 

responsibility demonstration to confirm that the instrument(s) used remain 

adequate for use. The owner or operator must maintain financial responsibility 

requirements regardless of the status of the Director’s review of the financial 

responsibility demonstration.

(iii) The Director may disapprove the use of a financial instrument if he 

determines that it is not sufficient to meet the requirements of this section.

(6) The owner or operator may demonstrate financial responsibility by using one 

or multiple qualifying financial instruments for specific phases of the geologic 

sequestration project. 

(i) In the event that the owner or operator combines more than one 

instrument for a specific geologic sequestration phase (e.g., well plugging), such 

combination must be limited to instruments that are not based on financial 

strength or performance (i.e., self insurance or performance bond), for example 

Deleted: d

Comment [A201]: 

OMB-OIRA reg. edits. (11/11)
Page 234 of 274

trust funds, surety bonds guaranteeing payment into a trust fund, letters of credit, 

escrow account, and insurance. In this case, it is the combination of mechanisms, 

rather than the single mechanism, which must provide financial responsibility for 

an amount at least equal to the current cost estimate. 

(ii) When using a third-party instrument to demonstrate financial 

responsibility, the owner or operator must provide a proof that the third-party 

providers either have passed financial strength requirements based on credit 

ratings; or has met a minimum rating, minimum capitalization, and ability to pass 

the bond rating when applicable.

(iii) An owner or operator using certain types of third party instruments

must establish a standby trust to enable EPA to be party to the financial 

responsibility agreement without EPA being the beneficiary of any funds. The 

standby trust fund must be used along with other financial responsibility 

instruments (e.g., surety bonds, letters of credit, or escrow accounts) to provide a 

location to place funds if needed.

(iv) An owner or operator may deposit money to an escrow account to 

cover financial responsibility requirements; this account must segregate funds 

sufficient to cover estimated costs for Class VI (geologic sequestration) financial 

responsibility from other accounts and uses. 

(v) An owner or operator or its guarantor may use self insurance to 

demonstrate financial responsibility for geologic sequestration projects. In order 

to satisfy this requirement the owner or operator must meet a Tangible Net Worth 

of an amount approved by the Director, have a Net working capital and tangible 

Deleted: a

Deleted: s

Comment [A202]: 

Edits made in response to OMB-OIRA comment. 

(11/12)
Page 235 of 274

net worth each at least six times the sum of the current well plugging, post 

injection site care and site closure cost, have assets located in the United States 

amounting to at least 90 percent of total assets or at least six times the sum of the 

current well plugging, post injection site care and site closure cost, and must 

submit a report of its bond rating and financial information annually. In addition 

the owner or operator must either: have a bond rating test of AAA, AA, A, or 

BBB as issued by Standard & Poor’s or Aaa, Aa, A, or Baa as issued by Moody’s; 

or meet all of the following five financial ratio thresholds: a ratio of total 

liabilities to net worth less than 2.0; a ratio of current assets to current liabilities 

greater than 1.5; a ratio of the sum of net income plus depreciation, depletion, and 

amortization to total liabilities greater than 0.1; a ratio of current assets minus 

current liabilities to total assets greater than -0.1; and a net profit (revenues minus 

expenses) greater than 0.

(vi) An owner or operator who is not able to meet corporate financial test 

criteria may arrange a corporate guarantee by demonstrating that its corporate 

parent meets the financial test requirements on its behalf. The parent’s 

demonstration that it meets the financial test requirement is insufficient if it has 

not also guaranteed to fulfill the obligations for the owner or operator. 

(vii) An owner or operator may obtain an insurance policy to cover the 

estimated costs of geologic sequestration activities requiring financial 

responsibility. This insurance policy must be obtained from a third party provider.

(b) The requirement to maintain adequate financial responsibility and resources is 

directly enforceable regardless of whether the requirement is a condition of the permit. 
Page 236 of 274

(1) The owner or operator must maintain financial responsibility and resources 

until:

(i) The Director receives and approves the completed post-injection site 

care and site closure plan; and 

(ii) The Director approves site closure.

(2) The owner or operator may be released from a financial instrument in the 

following circumstances:

(i) The owner or operator has completed the phase of the geologic 

sequestration project for which the financial instrument was required and has 

fulfilled all its financial obligations as determined by the Director, including 

obtaining financial responsibility for the next phase of the GS project, if required; 

or

(ii) The owner or operator has submitted a replacement financial 

instrument and received written approval from the Director accepting the new 

financial instrument and releasing the owner or operator from the previous 

financial instrument. 

(c) The owner or operator must have a detailed written estimate, in current dollars, of the 

cost of performing corrective action on wells in the area of review, plugging the injection 

well(s), post-injection site care and site closure, and emergency and remedial response. 

(1) The cost estimate must be performed for each phase separately and must be 

based on the costs to the regulatory agency of hiring a third party to perform the 

required activities. A third party is a party who is not within the corporate 

structure of the owner or operator. 
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(2) During the active life of the geologic sequestration project, the owner or 

operator must adjust the cost estimate for inflation within 60 days prior to the 

anniversary date of the establishment of the financial instrument(s) used to 

comply with paragraph (a) of this section and provide this adjustment to the 

Director. The owner or operator must also provide to the Director written updates 

of adjustments to the cost estimate within 60 days of any amendments to the area 

of review and corrective action plan (§146.84), the injection well plugging plan 

(§146.92), the post-injection site care and site closure plan (§146.93), and the 

emergency and remedial response plan (§146.94). 

(3) The Director must approve any decrease or increase to the initial cost estimate. 

During the active life of the geologic sequestration project, the owner or operator 

must revise the cost estimate no later than 60 days after the Director has approved 

the request to modify the area of review and corrective action plan (§146.84), the 

injection well plugging plan (§146.92), the post-injection site care and site closure 

plan (§146.93), and the emergency and response plan (§146.94), if the change in 

the plan increases the cost. If the change to the plans decreases the cost, any 

withdrawal of funds must be approved by the Director. Any decrease to the value 

of the financial assurance instrument must first be approved by the Director. The 

revised cost estimate must be adjusted for inflation as specified at paragraph 

(c)(2) of this section. 

(4) Whenever the current cost estimate increases to an amount greater than the 

face amount of a financial instrument currently in use, the owner or operator, 

within 60 days after the increase, must either cause the face amount to be 

Deleted: s

Comment [A203]: 

Edit made in response to OMB-OIRA comment 

(11/12) and (11/15).
Page 238 of 274

increased to an amount at least equal to the current cost estimate and submit 

evidence of such increase to the Director, or obtain other financial responsibility 

instruments to cover the increase. Whenever the current cost estimate decreases, 

the face amount of the financial assurance instrument may be reduced to the 

amount of the current cost estimate only after the owner or operator has received 

written approval from the Director. 

(d) The owner or operator must notify the Director by certified mail of adverse financial 

conditions such as bankruptcy that may affect the ability to carry out injection well 

plugging and post-injection site care and site closure. 

(1) In the event that the owner or operator or the third party provider of a financial 

responsibility instrument is going through a bankruptcy, the owner or operator 

must notify the Director by certified mail of the commencement of a voluntary or 

involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the 

owner or operator as debtor, within 10 days after commencement of the 

proceeding. 

(2) A guarantor of a corporate guarantee must make such a notification to the 

Director if he/she is named as debtor, as required under the terms of the corporate 

guarantee.

(3) An owner or operator who fulfills the requirements of paragraph (a) of this 

section by obtaining a trust fund, surety bond, letter of credit, escrow account, or 

insurance policy will be deemed to be without the required financial assurance in 

the event of bankruptcy of the trustee or issuing institution, or a suspension or 

revocation of the authority of the trustee institution to act as trustee of the 
Page 239 of 274

institution issuing the trust fund, surety bond, letter of credit, escrow account, or 

insurance policy. The owner or operator must establish other financial assurance 

within 60 days after such an event.

(e) The owner or operator must provide an adjustment of the cost estimate to the Director 

within 60 days of notification by the Director, if the Director determines during the 

annual evaluation of the qualifying financial responsibility instrument(s) that the most 

recent demonstration is no longer adequate to cover the cost of corrective action (as 

required by §146.84), injection well plugging (as required by §146.92), post-injection site 

care and site closure (as required by §146.93), and emergency and remedial response (as 

required by §146.94).

(f) The Director must approve the use and length of pay-in-periods for trust funds or 

escrow accounts. 

§146.86 Injection well construction requirements. 

(a) General. The owner or operator must ensure that all Class VI wells are constructed 

and completed to:

(1) Prevent the movement of fluids into or between USDWs or into any 

unauthorized zones;

(2) Permit the use of appropriate testing devices and workover tools; and

(3) Permit continuous monitoring of the annulus space between the injection 

tubing and long string casing.

(b) Casing and Cementing of Class VI Wells.
Page 240 of 274

(1) Casing and cement or other materials used in the construction of each Class 

VI well must have sufficient structural strength and be designed for the life of the 

geologic sequestration project. All well materials must be compatible with fluids 

with which the materials may be expected to come into contact and must meet or 

exceed standards developed for such materials by the American Petroleum 

Institute, ASTM International, or comparable standards acceptable to the Director. 

The casing and cementing program must be designed to prevent the movement of 

fluids into or between USDWs. In order to allow the Director to determine and 

specify casing and cementing requirements, the owner or operator must provide 

the following information:

(i) Depth to the injection zone(s);

(ii) Injection pressure, external pressure, internal pressure, and axial 

loading;

(iii) Hole size;

(iv) Size and grade of all casing strings (wall thickness, external diameter, 

nominal weight, length, joint specification, and construction material);

(v) Corrosiveness of the carbon dioxide stream and formation fluids;

(vi) Down-hole temperatures;

(vii) Lithology of injection and confining zone(s);

(viii) Type or grade of cement and cement additives; and

(ix) Quantity, chemical composition, and temperature of the carbon 

dioxide stream.
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(2) Surface casing must extend through the base of the lowermost USDW and be 

cemented to the surface through the use of a single or multiple strings of casing 

and cement. 

(3) At least one long string casing, using a sufficient number of centralizers, must 

extend to the injection zone and must be cemented by circulating cement to the 

surface in one or more stages. 

(4) Circulation of cement may be accomplished by staging. The Director may 

approve an alternative method of cementing in cases where the cement cannot be 

recirculated to the surface, provided the owner or operator can demonstrate by 

using logs that the cement does not allow fluid movement behind the well bore.

(5) Cement and cement additives must be compatible with the carbon dioxide 

stream and formation fluids and of sufficient quality and quantity to maintain 

integrity over the design life of the geologic sequestration project. The integrity 

and location of the cement shall be verified using technology capable of 

evaluating cement quality radially and identifying the location of channels to 

ensure that USDWs are not endangered.

(c) Tubing and packer.

(1) Tubing and packer materials used in the construction of each Class VI well 

must be compatible with fluids with which the materials may be expected to come 

into contact and must meet or exceed standards developed for such materials by 

the American Petroleum Institute, ASTM International, or comparable standards 

acceptable to the Director.
Page 242 of 274

(2) All owners or operators of Class VI wells must inject fluids through tubing 

with a packer set at a depth opposite a cemented interval at the location approved 

by the Director.

(3) In order for the Director to determine and specify requirements for tubing and 

packer, the owner or operator must submit the following information:

(i) Depth of setting;

(ii) Characteristics of the carbon dioxide stream (chemical content, 

corrosiveness, temperature, and density) and formation fluids;

(iii) Maximum proposed injection pressure;

(iv) Maximum proposed annular pressure;

(v) Proposed injection rate (intermittent or continuous) and volume and/or 

mass of the carbon dioxide stream;

(vi) Size of tubing and casing; and

(vii) Tubing tensile, burst, and collapse strengths.

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

(a) During the drilling and construction of a Class VI injection well, the owner or 

operator must run appropriate logs, surveys and tests to determine or verify the depth, 

thickness, porosity, permeability, and lithology of, and the salinity of any formation 

fluids in all relevant geologic formations to ensure conformance with the injection well 

construction requirements under §146.86 and to establish accurate baseline data against 

which future measurements may be compared. The owner or operator must submit to the 

Director a descriptive report prepared by a knowledgeable log analyst that includes an 
Page 243 of 274

interpretation of the results of such logs and tests. At a minimum, such logs and tests 

must include:

(1) Deviation checks during drilling on all holes constructed by drilling a pilot 

hole which is enlarged by reaming or another method. Such checks must be at 

sufficiently frequent intervals to determine the location of the borehole and to 

ensure that vertical avenues for fluid movement in the form of diverging holes are 

not created during drilling; and

(2) Before and upon installation of the surface casing:

(i) Resistivity, spontaneous potential, and caliper logs before the casing is 

installed; and

(ii) A cement bond and variable density log to evaluate cement quality 

radially, and a temperature log after the casing is set and cemented.

(3) Before and upon installation of the long string casing:

(i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, 

fracture finder logs, and any other logs the Director requires for the given 

geology before the casing is installed; and

(ii) A cement bond and variable density log, and a temperature log after 

the casing is set and cemented.

(4) A series of tests designed to demonstrate the internal and external mechanical 

integrity of injection wells, which may include:

(i) A pressure test with liquid or gas;

(ii) A tracer survey such as oxygen-activation logging;

(iii) A temperature or noise log;
Page 244 of 274

(iv) A casing inspection log; and

(5) Any alternative methods that provide equivalent or better information and that 

are required by and/or approved of by the Director. 

(b) The owner or operator must take whole cores or sidewall cores of the injection zone 

and confining system and formation fluid samples from the injection zone(s), and must 

submit to the Director a detailed report prepared by a log analyst that includes: well log 

analyses (including well logs), core analyses, and formation fluid sample information.

The Director may accept information on cores from nearby wells if the owner or operator 

can demonstrate that core retrieval is not possible and that such cores are representative 

of conditions at the well. The Director may require the owner or operator to core other 

formations in the borehole.

(c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir 

pressure, and static fluid level of the injection zone(s).

(d) At a minimum, the owner or operator must determine or calculate the following 

information concerning the injection and confining zone(s):

(1) Fracture pressure;

(2) Other physical and chemical characteristics of the injection and confining 

zone(s); and

(3) Physical and chemical characteristics of the formation fluids in the injection 

zone(s).

(e) Upon completion, but prior to operation, the owner or operator must conduct the 

following tests to verify hydrogeologic characteristics of the injection zone(s):

(1) A pressure fall-off test; and,
Page 245 of 274

(2) A pump test; or

(3) Injectivity tests.

(f) The owner or operator must provide the Director with the opportunity to witness all 

logging and testing by this subpart. The owner or operator must submit a schedule of 

such activities to the Director 30 days prior to conducting the first test and submit any 

changes to the schedule 30 days prior to the next scheduled test.

§146.88 Injection well operating requirements.

(a) Except during stimulation, the owner or operator must ensure that injection pressure 

does not exceed 90 percent of the fracture pressure of the injection zone(s) so as to ensure 

that the injection does not initiate new fractures or propagate existing fractures in the 

injection zone(s). In no case may injection pressure initiate fractures in the confining 

zone(s) or cause the movement of injection or formation fluids that endangers a USDW. 

Pursuant to requirements at §146.82(a)(9), all stimulation programs must be approved by 

the Director as part of the permit application and incorporated into the permit.

(b) Injection between the outermost casing protecting USDWs and the well bore is 

prohibited.

(c) The owner or operator must fill the annulus between the tubing and the long string 

casing with a non-corrosive fluid approved by the Director. The owner or operator must 

maintain on the annulus a pressure that exceeds the operating injection pressure, unless 

the Director determines that such requirement might harm the integrity of the well or 

endanger USDWs. 

Deleted: .¶

Comment [A204]: Edit made in response to 

OMB-OIRA comment 10/31 and 11/12. 
Page 246 of 274

(d) Other than during periods of well workover (maintenance) approved by the Director 

in which the sealed tubing-casing annulus is disassembled for maintenance or corrective 

procedures, the owner or operator must maintain mechanical integrity of the injection 

well at all times.

(e) The owner or operator must install and use:

(1) Continuous recording devices to monitor: the injection pressure; the rate, 

volume and/or mass, and temperature of the carbon dioxide stream; and the 

pressure on the annulus between the tubing and the long string casing and annulus 

fluid volume; and

(2) Alarms and automatic surface shut-off systems or, at the discretion of the 

Director, down-hole shut-off systems (e.g., automatic shut-off, check valves) for 

onshore wells or, other mechanical devices that provide equivalent protection; and

(3) Alarms and automatic down-hole shut-off systems for wells located offshore 

but within State territorial waters, designed to alert the operator and shut-in the 

well when operating parameters such as annulus pressure, injection rate, or other 

parameters diverge beyond permitted ranges and/or gradients specified in the 

permit.

(f) If a shutdown (i.e., down-hole or at the surface) is triggered or a loss of mechanical 

integrity is discovered, the owner or operator must immediately investigate and identify 

as expeditiously as possible the cause of the shutoff. If, upon such investigation, the well 

appears to be lacking mechanical integrity, or if monitoring required under paragraph (e) 

of this section otherwise indicates that the well may be lacking mechanical integrity, the 

owner or operator must:
Page 247 of 274

(1) Immediately cease injection;

(2) Take all steps reasonably necessary to determine whether there may have been 

a release of the injected carbon dioxide stream or formation fluids into any 

unauthorized zone;

(3) Notify the Director within 24 hours;

(4) Restore and demonstrate mechanical integrity to the satisfaction of the 

Director prior to resuming injection; and

(5) Notify the Director when injection can be expected to resume.

§146.89 Mechanical integrity.

(a) A Class VI well has mechanical integrity if:

(1) There is no significant leak in the casing, tubing, or packer; and

(2) There is no significant fluid movement into a USDW through channels 

adjacent to the injection well bore.

(b) To evaluate the absence of significant leaks under paragraph (a)(1) of this section, owners 

or operators must, following an initial annulus pressure test, continuously monitor injection 

pressure, rate, injected volumes; pressure on the annulus between tubing and long-string 

casing; and annulus fluid volume as specified in §146.88 (e); 

Deleted: ¶
Page 248 of 274

(c) At least once per year, the owner or operator must use one of the following methods 

to determine the absence of significant fluid movement under paragraph (a)(2) of this 

section:

(1) An approved tracer survey such as an oxygen-activation log; or

(2) A temperature or noise log.

(d) If required by the Director, at a frequency specified in the testing and monitoring plan 

required at §146.90, the owner or operator must run a casing inspection log to determine 

the presence or absence of corrosion in the long-string casing. 

(e) The Director may require any other test to evaluate mechanical integrity under 

paragraphs (a)(1) or (a)(2) of this section. Also, the Director may allow the use of a test 

to demonstrate mechanical integrity other than those listed above with the written 

approval of the Administrator. To obtain approval for a new mechanical integrity test, the 

Director must submit a written request to the Administrator setting forth the proposed test 

and all technical data supporting its use. The Administrator may approve the request if he 

or she determines that it will reliably demonstrate the mechanical integrity of wells for 

which its use is proposed. Any alternate method approved by the Administrator will be 

published in the Federal Register and may be used in all States in accordance with 

applicable State law unless its use is restricted at the time of approval by the

Administrator. 

(f) In conducting and evaluating the tests enumerated in this section or others to be 

allowed by the Director, the owner or operator and the Director must apply methods and 
Page 249 of 274

standards generally accepted in the industry. When the owner or operator reports the 

results of mechanical integrity tests to the Director, he/she shall include a description of 

the test(s) and the method(s) used. In making his/her evaluation, the Director must review 

monitoring and other test data submitted since the previous evaluation.

(g) The Director may require additional or alternative tests if the results presented by the 

owner or operator under paragraphs (a) through (d) of this section are not satisfactory to 

the Director to demonstrate that there is no significant leak in the casing, tubing, or 

packer, or to demonstrate that there is no significant movement of fluid into a USDW 

resulting from the injection activity as stated in paragraphs (a)(1) and (2) of this section.

§146.90 Testing and monitoring requirements. 

The owner or operator of a Class VI well must prepare, maintain, and comply with a 

testing and monitoring plan to verify that the geologic sequestration project is operating 

as permitted and is not endangering USDWs. The requirement to maintain and implement 

an approved plan is directly enforceable regardless of whether the requirement is a 

condition of the permit. The testing and monitoring plan must be submitted with the 

permit application, for Director approval, and must include a description of how the 

owner or operator will meet the requirements of this section, including accessing sites for 

all necessary monitoring and testing during the life of the project. Testing and monitoring 

associated with geologic sequestration projects must, at a minimum, include:

(a) Analysis of the carbon dioxide stream with sufficient frequency to yield data 

representative of its chemical and physical characteristics; 

Deleted: 
Page 250 of 274

(b) Installation and use, except during well workovers as defined in §146.88(d), of 

continuous recording devices to monitor injection pressure, rate, and volume; the 

pressure on the annulus between the tubing and the long string casing; and the annulus 

fluid volume added;

(c) Corrosion monitoring of the well materials for loss of mass, thickness, cracking, 

pitting, and other signs of corrosion, which must be performed on a quarterly basis to 

ensure that the well components meet the minimum standards for material strength and 

performance set forth in §146.86(b), by:

(1) Analyzing coupons of the well construction materials placed in contact with 

the carbon dioxide stream; or

(2) Routing the carbon dioxide stream through a loop constructed with the 

material used in the well and inspecting the materials in the loop; or

(3) Using an alternative method approved by the Director;

(d) Periodic monitoring of the ground water quality and geochemical changes above the 

confining zone(s) that may be a result of carbon dioxide movement through the confining 

zone(s) or additional identified zones including: 

(1) The location and number of monitoring wells based on specific information 

about the geologic sequestration project, including injection rate and volume, 

geology, the presence of artificial penetrations, and other factors; and

Comment [A205]: 

OMB-OIRA regulatory edits. (11/11).
Page 251 of 274

(2) The monitoring frequency and spatial distribution of monitoring wells based 

on baseline geochemical data that has been collected under §146.82(a)(6) and on 

any modeling results in the area of review evaluation required by §146.84(c).

(e) A demonstration of external mechanical integrity pursuant to §146.89(c) at least once 

per year until the injection well is plugged; and, if required by the Director, a casing 

inspection log pursuant to requirements at §146.89(d) at a frequency established in the 

testing and monitoring plan; 

(f) A pressure fall-off test at least once every five years unless more frequent testing is 

required by the Director based on site-specific information;

(g) Testing and monitoring to track the extent of the carbon dioxide plume and the 

presence or absence of elevated pressure (e.g., the pressure front) by using:

(1) Direct methods in the injection zone(s); and,

(2) Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys 

and/or down-hole carbon dioxide detection tools), unless the Director determines, 

based on site-specific geology, that such methods are not appropriate;

(h) The Director may require surface air monitoring and/or soil gas monitoring to detect 

movement of carbon dioxide that could endanger a USDW. 

(1) Design of Class VI surface air and/or soil gas monitoring must be based on 

potential risks to USDWs within the area of review;
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(2) The monitoring frequency and spatial distribution of surface air monitoring 

and/or soil gas monitoring must be decided using baseline data, and the 

monitoring plan must describe how the proposed monitoring will yield useful 

information on the area of review delineation and/or compliance with standards 

under §144.12 of this chapter;

(3) If an owner or operator demonstrates that monitoring employed under 

§§98.440 to 98.449 of this chapter (Clean Air Act, 42 U.S.C. 7401 et seq.) 

accomplishes the goals of (h)(1) and (2) of this section, and meets the 

requirements pursuant to §146.91(c)(5), a Director that requires surface air/soil 

gas monitoring must approve the use of monitoring employed under §§98.440 to 

98.449 of this chapter. Compliance with §§98.440 to 98.449 of this chapter 

pursuant to this provision is considered a condition of the Class VI permit;

(i) Any additional monitoring, as required by the Director, necessary to support, upgrade, 

and improve computational modeling of the area of review evaluation required under 

§146.84(c) and to determine compliance with standards under §144.12 of this chapter; 

(j) The owner or operator shall periodically review the testing and monitoring plan to 

incorporate monitoring data collected under this subpart, operational data collected under 

§146.88, and the most recent area of review reevaluation performed under §146.84(e). In 

no case shall the owner or operator review the testing and monitoring plan less often than 

once every five years. Based on this review, the owner or operator shall submit an 

amended testing and monitoring plan or demonstrate to the Director that no amendment 

to the testing and monitoring plan is needed. Any amendments to the testing and 
Page 253 of 274

monitoring plan must be approved by the Director, must be incorporated into the permit, 

and are subject to the permit modification requirements at §§144.39 or 144.41 of this 

chapter, as appropriate. Amended plans or demonstrations shall be submitted to the 

Director as follows:

(1) Within one year of an area of review reevaluation; 

(2) Following any significant changes to the facility, such as addition of 

monitoring wells or newly permitted injection wells within the area of review, on 

a schedule determined by the Director; or 

(3) When required by the Director.

(k) A quality assurance and surveillance plan for all testing and monitoring requirements. 

§146.91 Reporting requirements.

The owner or operator must, at a minimum, provide, as specified in paragraph (e) of this 

section, the following reports to the Director, for each permitted Class VI well:

(a) Semi-annual reports containing:

(1) Any changes to the physical, chemical, and other relevant characteristics of 

the carbon dioxide stream from the proposed operating data;

(2) Monthly average, maximum, and minimum values for injection pressure, flow 

rate and volume, and annular pressure; 

Deleted: injection or 

Comment [A206]: 

OMB-OIRA comment/edit. 11/15/10. 
Page 254 of 274

(3) A description of any event that exceeds operating parameters for annulus 

pressure or injection pressure specified in the permit;

(4) A description of any event which triggers a shut-off device required pursuant 

to §146.88(e) and the response taken;

(5) The monthly volume and/or mass of the carbon dioxide stream injected over 

the reporting period and the volume injected cumulatively over the life of the 

project;

(6) Monthly annulus fluid volume added; and 

(7) The results of monitoring prescribed under §146.90.

(b) Report, within 30 days, the results of:

(1) Periodic tests of mechanical integrity;

(2) Any well workover; and,

(3) Any other test of the injection well conducted by the permittee if required by 

the Director.

(c) Report, within 24 hours:

(1) Any evidence that the injected carbon dioxide stream or associated pressure 

front may cause an endangerment to a USDW; 

Deleted: of
Page 255 of 274

(2) Any noncompliance with a permit condition, or malfunction of the injection 

system, which may cause fluid migration into or between USDWs;

(3) Any triggering of a shut-off system (i.e., down-hole or at the surface);

(4) Any failure to maintain mechanical integrity; or.

(5) Pursuant to compliance with the requirement at §146.90(h) for surface air/soil 

gas monitoring or other monitoring technologies, if required by the Director, any 

release of carbon dioxide to the atmosphere or biosphere. 

(d) Owners or operators must notify the Director in writing 30 days in advance of:

(1) Any planned well workover; 

(2) Any planned stimulation activities, other than stimulation for formation testing 

conducted under §146.82; and

(3) Any other planned test of the injection well conducted by the permittee. 

(e) Regardless of whether a State has primary enforcement responsibility, owners or 

operators must submit all required reports, submittals, and notifications under subpart H 

of this part to EPA in an electronic format approved by EPA.

(f) Records shall be retained by the owner or operator as follows:

(1) All data collected under §146.82 for Class VI permit applications shall be 

retained throughout the life of the geologic sequestration project and for 10 years 

following site closure.
Page 256 of 274

(2) Data on the nature and composition of all injected fluids collected pursuant to 

§146.90(a) shall be retained until 10 years after site closure. The Director may 

require the owner or operator to deliver the records to the Director at the 

conclusion of the retention period. 

(3) Monitoring data collected pursuant to §146.90(b) through (i) shall be retained 

for 10 years after it is collected.

(4) Well plugging reports, post-injection site care data, including, if appropriate, 

data and information used to develop the demonstration of the alternative postinjection site care timeframe, and the site closure report collected pursuant to 

requirements at §§146.93(f) and (h) shall be retained for 10 years following site 

closure.

(5) The Director has authority to require the owner or operator to retain any 

records required in this subpart for longer than 10 years after site closure.

§146.92 Injection well plugging.

(a) Prior to the well plugging, the owner or operator must flush each Class VI injection 

well with a buffer fluid, determine bottomhole reservoir pressure, and perform a final 

external mechanical integrity test. 

(b) Well Plugging Plan. The owner or operator of a Class VI well must prepare, maintain, 

and comply with a plan that is acceptable to the Director. The requirement to maintain 

and implement an approved plan is directly enforceable regardless of whether the 

requirement is a condition of the permit. The well plugging plan must be submitted as 

part of the permit application and must include the following information:

Comment [A207]: Inserted 11/11 based on 

OIRA discussion.
Page 257 of 274

(1) Appropriate tests or measures for determining bottomhole reservoir pressure;

(2) Appropriate testing methods to ensure external mechanical integrity as 

specified in §146.89;

(3) The type and number of plugs to be used;

(4) The placement of each plug, including the elevation of the top and bottom of 

each plug;

(5) The type, grade, and quantity of material to be used in plugging. The material 

must be compatible with the carbon dioxide stream; and

(6) The method of placement of the plugs.

(c) Notice of intent to plug. The owner or operator must notify the Director in writing 

pursuant to §146.91(e), at least 60 days before plugging of a well. At this time, if any 

changes have been made to the original well plugging plan, the owner or operator must 

also provide the revised well plugging plan. The Director may allow for a shorter notice 

period. Any amendments to the injection well plugging plan must be approved by the 

Director, must be incorporated into the permit, and are subject to the permit modification 

requirements at §§144.39 or 144.41 of this chapter, as appropriate. 

(d) Plugging report. Within 60 days after plugging, the owner or operator must submit,

pursuant to §146.91(e), a plugging report to the Director. The report must be certified as 

accurate by the owner or operator and by the person who performed the plugging 

operation (if other than the owner or operator.) The owner or operator shall retain the 

well plugging report for 10 years following site closure.

§146.93 Post-injection site care and site closure.
Page 258 of 274

(a) The owner or operator of a Class VI well must prepare, maintain, and comply with a 

plan for post-injection site care and site closure that meets the requirements of paragraph 

(a)(2) of this section and is acceptable to the Director. The requirement to maintain and 

implement an approved plan is directly enforceable regardless of whether the requirement 

is a condition of the permit.

(1) The owner or operator must submit the post-injection site care and site closure 

plan as a part of the permit application to be approved by the Director. 

(2) The post-injection site care and site closure plan must include the following 

information:

(i) The pressure differential between pre-injection and predicted postinjection pressures in the injection zone(s);

(ii) The predicted position of the carbon dioxide plume and associated 

pressure front at site closure as demonstrated in the area of review 

evaluation required under §146.84(c)(1); 

(iii) A description of post-injection monitoring location, methods, and 

proposed frequency; 

(iv) A proposed schedule for submitting post-injection site care 

monitoring results to the Director pursuant to §146.91(e); and, 

Deleted: and

Comment [A208]: Deleted 11/11 to 

accommodate insertion below per OIRA discussion.
Page 259 of 274

(v) The duration of the post-injection site care timeframe and, if approved 

by the Director, the demonstration of the alternative post-injection site 

care timeframe that ensures non-endangerment of USDWs.

(3) Upon cessation of injection, owners or operators of Class VI wells must either 

submit an amended post-injection site care and site closure plan or demonstrate to 

the Director through monitoring data and modeling results that no amendment to 

the plan is needed. Any amendments to the post-injection site care and site closure 

plan must be approved by the Director, be incorporated into the permit, and are 

subject to the permit modification requirements at §§144.39 or 144.41 of this 

chapter, as appropriate.

(4) At any time during the life of the geologic sequestration project, the owner or 

operator may modify and resubmit the post-injection site care and site closure 

plan for the Director’s approval within 30 days of such change. 

(b) The owner or operator shall monitor the site following the cessation of injection to

show the position of the carbon dioxide plume and pressure front and demonstrate that 

USDWs are not being endangered. 

(1) Following the cessation of injection, the owner or operator shall continue to 

conduct monitoring as specified in the Director-approved post-injection site care 

and site closure plan for at least 50 years or for the duration of the alternative 

timeframe approved by the Director pursuant to requirements in paragraph (c) of 

this section, unless he/she makes a demonstration under (b)(2) of this section. The

Comment [A209]: Inserted 11/11 per OIRA

discussion.

Deleted: (1) The

Comment [A210]: Added 11/11 per OIRA 

discussion.

Deleted: The 

Deleted: following

Deleted: cessation

Comment [A211]: Added 11/11 per OIRA 

discussion.

Deleted: injection,following the cessation of 

injection

Deleted: . At the Director’s discretion,

Comment [A212]: 

EPA deletion for consistency with other text; and 

subsequent addition at end of paragraph per OMBOIRA 11/12. 

Deleted: t
Page 260 of 274

monitoring must continue until the geologic sequestration project no longer poses 

an endangerment to USDWs and the demonstration under (b)(2) of this section is 

submitted and approved by the Director. 

(2) If the owner or operator can demonstrate to the satisfaction of the Director 

before 50 years or prior to the end of the approved alternative timeframe based on 

monitoring and other site-specific data, that the geologic sequestration project no 

longer poses an endangerment to USDWs, the Director may approve an 

amendment to the post-injection site care and site closure plan to reduce the 

frequency of monitoring or may authorize site closure before the end of the 50-

year period or prior to the end of the approved alternative timeframe, where he or 

she has substantial evidence that the geologic sequestration project no longer 

poses a risk of endangerment to USDWs.

(3) Prior to authorization for site closure, the owner or operator must submit to the 

Director for review and approval a demonstration, based on monitoring and other 

site-specific data, that no additional monitoring is needed to ensure that the 

geologic sequestration project does not pose an endangerment to USDWs. 

(4) If the demonstration in paragraph (b)(3) of this section cannot be made (i.e., 

additional monitoring is needed to ensure that the geologic sequestration project 

does not pose an endangerment to USDWs) at the end of the 50-year period or at 

the end of the approved alternative timeframe, or if the Director does not approve 

the demonstration, the owner or operator must submit to the Director a plan to 

Comment [A213]: 

Added per OMB-OIRA comment. (11/12)

Deleted: ,

Comment [A214]: Added 11/11 per OIRA

discussion.

Comment [A215]: Added 11/11 per OIRA 

discussion.

Comment [A216]: Added 11/11 per OIRA 

discussion.

Comment [A217]: Added 11/11 per OIRA 

discussion.
Page 261 of 274

continue post-injection site care until a demonstration can be made and approved 

by the Director. 

(c) Demonstration of alternative post-injection site care timeframe. At the Director’s 

discretion, the Director may approve, in consultation with EPA, an alternative postinjection site care timeframe other than the 50 year default, if an owner or operator can 

demonstrate during the permitting process that an alternative post-injection site care 

timeframe is appropriate and ensures non-endangerment of USDWs. The demonstration 

must be based on significant, site-specific data and information including all data and 

information collected pursuant to §§146.82 and 146.83, and must contain substantial 

evidence that the geologic sequestration project will no longer pose a risk of 

endangerment to USDWs at the end of the alternative post-injection site care timeframe.

(1) A demonstration of an alternative post-injection site care timeframe must include 

consideration and documentation of:

(i) The results of computational modeling performed pursuant to delineation of 

the area of review under §146.84;

(ii) The predicted timeframe for pressure decline within the injection zone, and 

any other zones, such that formation fluids may not be forced into any USDWs; 

and/or the timeframe for pressure decline to pre-injection pressures;

(iii) The predicted rate of carbon dioxide plume migration within the injection 

zone, and the predicted timeframe for the cessation of migration;

Comment [A218]: Added 11/11 per OIRA 

discussion.

Comment [A219]: Added 11/11 per OIRA 

discussion.
Page 262 of 274

(iv) A description of the site-specific processes that will result in carbon dioxide 

trapping including immobilization by capillary trapping, dissolution, and 

mineralization at the site;

(v) The predicted rate of carbon dioxide trapping in the immobile capillary phase, 

dissolved phase, and/or mineral phase;

(vi) The results of laboratory analyses, research studies, and/or field or sitespecific studies to verify the information required in paragraphs (iv) and (v) of 

this section; 

(vii) A characterization of the confining zone(s) including a demonstration that it 

is free of transmissive faults, fractures, and micro-fractures and of appropriate 

thickness, permeability, and integrity to impede fluid (e.g., carbon dioxide, 

formation fluids) movement; 

(viii) The presence of potential conduits for fluid movement including planned 

injection wells and project monitoring wells associated with the proposed 

geologic sequestration project or any other projects in proximity to the 

predicted/modeled, final extent of the carbon dioxide plume and area of elevated 

pressure;

(ix) A description of the well construction and an assessment of the quality of 

plugs of all abandoned wells within the area of review; 
Page 263 of 274

(x) The distance between the injection zone and the nearest USDWs above and/or 

below the injection zone; and

(xi) Any additional site-specific factors required by the Director.

(2) Information submitted to support the demonstration in paragraph (c)(1) of this section 

must meet the following criteria:

(i) All analyses and tests performed to support the demonstration must be 

accurate, reproducible, and performed in accordance with the established quality 

assurance standards;

(ii) Estimation techniques must be appropriate and EPA-certified test protocols 

must be used where available;

(iii) Predictive models must be appropriate and tailored to the site conditions, 

composition of the carbon dioxide stream and injection and site conditions over 

the life of the geologic sequestration project; 

(iv) Predictive models must be calibrated using existing information (e.g., at Class 

I, Class II, or Class V experimental technology well sites) where sufficient data 

are available;

(v) Reasonably conservative values and modeling assumptions must be used and 

disclosed to the Director whenever values are estimated on the basis of known, 

historical information instead of site-specific measurements; 
Page 264 of 274

(vi) An analysis must be performed to identify and assess aspects of the 

alternative post-injection site care timeframe demonstration that contribute 

significantly to uncertainty. The owner or operator must conduct sensitivity 

analyses to determine the effect that significant uncertainty may contribute to the 

modeling demonstration. 

(vii) An approved quality assurance and quality control plan must address all 

aspects of the demonstration; and, 

(viii) Any additional criteria required by the Director.

(d) Notice of intent for site closure. The owner or operator must notify the Director in 

writing at least 120 days before site closure. At this time, if any changes have been made 

to the original post-injection site care and site closure plan, the owner or operator must 

also provide the revised plan. The Director may allow for a shorter notice period.

(e) After the Director has authorized site closure, the owner or operator must plug all 

monitoring wells in a manner which will not allow movement of injection or formation 

fluids that endangers a USDW.

(f) The owner or operator must submit a site closure report to the Director within 90 days 

of site closure, which must thereafter be retained at a location designated by the Director 

for 10 years. The report must include:

(1) Documentation of appropriate injection and monitoring well plugging as 

specified in §146.92 and paragraph (e) of this section. The owner or operator must 

Deleted: 

Deleted: (c)

Comment [A220]: Renumbered 11/11 to 

accommodate insertion per OIRA discussion.

Deleted: d

Comment [A221]: Renumbered 11/11 to 

accommodate insertion per OIRA discussion.

Deleted: e

Comment [A222]: Renumbered 11/11 to 

accommodate insertion per OIRA discussion.

Deleted: d

Comment [A223]: Edited 11/11 per OIRA 

discussion.
Page 265 of 274

provide a copy of a survey plat which has been submitted to the local zoning 

authority designated by the Director. The plat must indicate the location of the 

injection well relative to permanently surveyed benchmarks. The owner or 

operator must also submit a copy of the plat to the Regional Administrator of the 

appropriate EPA Regional Office;

(2) Documentation of appropriate notification and information to such State, local 

and Tribal authorities that have authority over drilling activities to enable such 

State, local, and Tribal authorities to impose appropriate conditions on subsequent 

drilling activities that may penetrate the injection and confining zone(s); and

(3) Records reflecting the nature, composition, and volume of the carbon dioxide 

stream.

(g) Each owner or operator of a Class VI injection well must record a notation on the 

deed to the facility property or any other document that is normally examined during title 

search that will in perpetuity provide any potential purchaser of the property the 

following information:

(1) The fact that land has been used to sequester carbon dioxide;

(2) The name of the State agency, local authority, and/or Tribe with which the 

survey plat was filed, as well as the address of the Environmental Protection 

Agency Regional Office to which it was submitted; and

Deleted: f

Comment [A224]: Renumbered 11/11 to 

accommodate insertion per OIRA discussion.
Page 266 of 274

(3) The volume of fluid injected, the injection zone or zones into which it was 

injected, and the period over which injection occurred. 

(h) The owner or operator must retain for 10 years following site closure, records 

collected during the post-injection site care period. The owner or operator must deliver 

the records to the Director at the conclusion of the retention period, and the records must 

thereafter be retained at a location designated by the Director for that purpose.

§146.94 Emergency and remedial response.

(a) As part of the permit application, the owner or operator must provide the Director 

with an emergency and remedial response plan that describes actions the owner or 

operator must take to address movement of the injection or formation fluids that may 

cause an endangerment to a USDW during construction, operation, and post-injection site 

care periods. The requirement to maintain and implement an approved plan is directly 

enforceable regardless of whether the requirement is a condition of the permit.

(b) If the owner or operator obtains evidence that the injected carbon dioxide stream and 

associated pressure front may cause an endangerment to a USDW, the owner or operator 

must:

(1) Immediately cease injection;

(2) Take all steps reasonably necessary to identify and characterize any release;

(3) Notify the Director within 24 hours; and 

Comment [A225]: Renumbered 11/11 to 

accommodate insertion per OIRA discussion.

Deleted: g
Page 267 of 274

(4) Implement the emergency and remedial response plan approved by the 

Director.

(c) The Director may allow the operator to resume injection prior to remediation if the 

owner or operator demonstrates that the injection operation will not endanger USDWs.

(d) The owner or operator shall periodically review the emergency and remedial response 

plan developed under paragraph (a) of this section. In no case shall the owner or operator 

review the emergency and remedial response plan less often than once every five years. 

Based on this review, the owner or operator shall submit an amended emergency and 

remedial response plan or demonstrate to the Director that no amendment to the 

emergency and remedial response plan is needed. Any amendments to the emergency and 

remedial response plan must be approved by the Director, must be incorporated into the 

permit, and are subject to the permit modification requirements at §§144.39 or 144.41 of 

this chapter, as appropriate. Amended plans or demonstrations shall be submitted to the 

Director as follows:

(1) Within one year of an area of review reevaluation; 

(2) Following any significant changes to the facility, such as addition of injection 

or monitoring wells, on a schedule determined by the Director; or 

(3) When required by the Director.

§146.95 Class VI injection depth waiver requirements.
Page 268 of 274

This section sets forth information which an owner or operator seeking a waiver of the 

Class VI injection depth requirements must submit to the Director; information the 

Director must consider in consultation with all affected Public Water System Supervision 

Directors; the procedure for Director – Regional Administrator communication and 

waiver issuance; and the additional requirements that apply to owners or operators of 

Class VI wells granted a waiver of the injection depth requirements. 

(a) In seeking a waiver of the requirement to inject below the lowermost USDW, the 

owner or operator must submit a supplemental report concurrent with permit application. 

The supplemental report must include the following, 

(1) A demonstration that the injection zone(s) is/are laterally continuous, is not a 

USDW, and is not hydraulically connected to USDWs; does not outcrop; has 

adequate injectivity, volume, and sufficient porosity to safely contain the injected 

carbon dioxide and formation fluids; and has appropriate geochemistry. 

(2) A demonstration that the injection zone(s) is/are bounded by laterally 

continuous, impermeable confining units above and below the injection zone(s)

adequate to prevent fluid movement and pressure buildup outside of the injection 

zone(s); and that the confining unit(s) is/are free of transmissive faults and 

fractures. The report shall further characterize the regional fracture properties and 

contain a demonstration that such fractures will not interfere with injection, serve 

as conduits, or endanger USDWs. 

(3) A demonstration, using computational modeling, that USDWs above and 

below the injection zone will not be endangered as a result of fluid movement. 

This modeling should be conducted in conjunction with the area of review 
Page 269 of 274

determination, as described in §146.84, and is subject to requirements, as 

described in §146.84(c), and periodic reevaluation, as described in §146.84(e).

(4) A demonstration that well design and construction, in conjunction with the 

waiver, will ensure isolation of the injectate in lieu of requirements at 

146.86(a)(1) and will meet well construction requirements in paragraph (f) of this 

section. 

(5) A description of how the monitoring and testing and any additional plans will 

be tailored to the geologic sequestration project to ensure protection of USDWs 

above and below the injection zone(s), if a waiver is granted. 

(6) Information on the location of all the public water supplies affected, 

reasonably likely to be affected, or served by USDWs in the area of review. 

(7) Any other information requested by the Director to inform the Regional 

Administrator’s decision to issue a waiver.

(b) To inform the Regional Administrator’s decision on whether to grant a waiver of the 

injection depth requirements at §§144.6 of this chapter, 146.5(f), and 146.86(a)(1), the 

Director must submit, to the Regional Administrator, documentation of the following :

(1) An evaluation of the following information as it relates to siting, construction, 

and operation of a geologic sequestration project with a waiver:

(i) The integrity of the upper and lower confining units;

(ii) The suitability of the injection zone(s) (e.g., lateral continuity; lack of 

transmissive faults and fractures; knowledge of current or planned 

artificial penetrations into the injection zone(s) or formations below the 

injection zone);
Page 270 of 274

(iii) The potential capacity of the geologic formation(s) to sequester

carbon dioxide, accounting for the availability of alternative injection 

sites;

(iv) All other site characterization data, the proposed emergency and 

remedial response plan, and a demonstration of financial responsibility;

(v) Community needs, demands, and supply from drinking water 

resources;

(vi) Planned needs, potential and/or future use of USDWs and nonUSDWs in the area;

(vii) Planned or permitted water, hydrocarbon, or mineral resource 

exploitation potential of the proposed injection formation(s) and other 

formations both above and below the injection zone to determine if there 

are any plans to drill through the formation to access resources in or 

beneath the proposed injection zone(s)/formation(s);

(viii) The proposed plan for securing alternative resources or treating 

USDW formation waters in the event of contamination related to the Class 

VI injection activity; and,

(ix) Any other applicable considerations or information requested by the 

Director.

(2) Consultation with the Public Water System Supervision Directors of all States 

and Tribes having jurisdiction over lands within the area of review of a well for 

which a waiver is sought.
Page 271 of 274

(3) Any written waiver-related information submitted by the Public Water System 

Supervision Director(s) to the (UIC) Director. 

(c) Pursuant to requirements at §124.10 of this chapter and concurrent with the Class VI 

permit application notice process, the Director shall give public notice that a waiver 

application has been submitted. The notice shall clearly state:

(1) The depth of the proposed injection zone(s); 

(2) The location of the injection well(s);

(3) The name and depth of all USDWs within the area of review;

(4) A map of the area of review; 

(5) The names of any public water supplies affected, reasonably likely to be 

affected, or served by USDWs in the area of review; and,

(6) The results of UIC-Public Water System Supervision consultation required 

under paragraph (b)(2) of this section. 

(d) Following public notice, the Director shall provide all information received through 

the waiver application process to the Regional Administrator. Based on the information 

provided, the Regional Administrator shall provide written concurrence or nonconcurrence regarding waiver issuance. 

(1) If the Regional Administrator determines that additional information is 

required to support a decision, the Director shall provide the information. At his 

or her discretion, the Regional Administrator may require that public notice of the 

new information be initiated. 

(2) In no case shall a Director of a State-approved program issue a waiver without 

receipt of written concurrence from the Regional Administrator.
Page 272 of 274

(e) If a waiver is issued, within 30 days of waiver issuance, EPA shall post the following 

information on the Office of Water’s Web site:

(1) The depth of the proposed injection zone(s); 

(2) The location of the injection well(s);

(3) The name and depth of all USDWs within the area of review; 

(4) A map of the area of review; 

(5) The names of any public water supplies affected, reasonably likely to be 

affected, or served by USDWs in the area of review; and

(6) The date of waiver issuance.

(f) Upon receipt of a waiver of the requirement to inject below the lowermost USDW for 

geologic sequestration, the owner or operator of the Class VI well must comply with: 

(1) All requirements at §§146.84, 146.85, 146.87, 146.88, 146.89, 146.91, 146.92, 

and 146.94;

(2) All requirements at §146.86 with the following modified requirements:

(i) The owner or operator must ensure that Class VI wells with a waiver are 

constructed and completed to prevent movement of fluids into any 

unauthorized zones including USDWs, in lieu of requirements at 

§146.86(a)(1).

(ii) The casing and cementing program must be designed to prevent the 

movement of fluids into any unauthorized zones including USDWs in lieu of 

requirements at §146.86(b)(1).

(iii) The surface casing must extend through the base of the nearest USDW 

directly above the injection zone and be cemented to the surface; or, at the 
Page 273 of 274

Director’s discretion, another formation above the injection zone and below 

the nearest USDW above the injection zone.

(3) All requirements at §146.90 with the following modified requirements: 

(i) The owner or operator shall monitor the groundwater quality, 

geochemical changes, and pressure in the first USDWs immediately above 

and below the injection zone(s); and in any other formations at the discretion 

of the Director. 

(ii) Testing and monitoring to track the extent of the carbon dioxide plume 

and the presence or absence of elevated pressure (e.g., the pressure front) by 

using direct methods to monitor for pressure changes in the injection zone(s);

and, indirect methods (e.g., seismic, electrical, gravity, or electromagnetic 

surveys and/or down-hole carbon dioxide detection tools), unless the Director 

determines, based on site-specific geology, that such methods are not 

appropriate.

(4) All requirements at §146.93 with the following, modified post-injection site 

care monitoring requirements:

(i) The owner or operator shall monitor the groundwater quality, 

geochemical changes and pressure in the first USDWs immediately above and 

below the injection zone; and in any other formations at the discretion of the 

Director. 

(ii) Testing and monitoring to track the extent of the carbon dioxide plume 

and the presence or absence of elevated pressure (e.g., the pressure front) by 

using direct methods in the injection zone(s); and indirect methods (e.g., 
Page 274 of 274

seismic, electrical, gravity, or electromagnetic surveys and/or down-hole 

carbon dioxide detection tools), unless the Director determines based on sitespecific geology, that such methods are not appropriate;

(5) Any additional requirements requested by the Director designed to ensure 

protection of USDWs above and below the injection zone(s). 

PART 147—STATE, TRIBAL, AND EPA-ADMINISTERED UNDERGROUND 

INJECTION CONTROL PROGRAMS

33. The authority citation for part 147 continues to read as follows:

Authority: 42, U.S.C. 300f et seq.; 42 U.S.C. 6901 et seq.

34. Section 147.1 is amended by adding paragraph (f) to read as follows:

§ 147.1 Purpose and scope.

* * * * *

(f) Class VI well owners or operators must comply with §146.91(e) notwithstanding any 

State program approvals. 

Billing code 6560-50-P

Deleted: 2

Deleted: 3