[Federal Register Volume 75, Number 237 (Friday, December 10, 2010)]
[Rules and Regulations]
[Pages 77230-77303]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-29954]



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Part III





Environmental Protection Agency





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40 CFR Parts 124, 144, 145, et al.



Federal Requirements Under the Underground Injection Control (UIC) 
Program for Carbon Dioxide (CO[bdi2]) Geologic Sequestration (GS) 
Wells; Final Rule

Federal Register / Vol. 75 , No. 237 / Friday, December 10, 2010 / 
Rules and Regulations

[[Page 77230]]


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ENVIRONMENTAL PROTECTION AGENCY

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

[EPA-HQ-OW-2008-0390 FRL-9232-7]
RIN 2040-AE98


Federal Requirements Under the Underground Injection Control 
(UIC) Program for Carbon Dioxide (CO<INF>2</INF>) Geologic 
Sequestration (GS) Wells

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: This action finalizes minimum Federal requirements under the 
Safe Drinking Water Act (SDWA) for underground injection of carbon 
dioxide (CO<INF>2</INF>) for the purpose of geologic sequestration 
(GS). GS is one of a portfolio of options that could be deployed to 
reduce CO<INF>2</INF> emissions to the atmosphere and help to mitigate 
climate change. This final rule applies to owners or operators of wells 
that will be used to inject CO<INF>2</INF> into the subsurface for the 
purpose of long-term storage. It establishes a new class of well, Class 
VI, and sets minimum technical criteria for the permitting, geologic 
site characterization, area of review (AoR) and corrective action, 
financial responsibility, well construction, operation, mechanical 
integrity testing (MIT), monitoring, well plugging, post-injection site 
care (PISC), and site closure of Class VI wells for the purposes of 
protecting underground sources of drinking water (USDWs). The elements 
of this rulemaking are based on the existing Underground Injection 
Control (UIC) regulatory framework, with modifications to address the 
unique nature of CO<INF>2</INF> injection for GS. This rule will help 
ensure consistency in permitting underground injection of 
CO<INF>2</INF> at GS operations across the United States and provide 
requirements to prevent endangerment of USDWs in anticipation of the 
eventual use of GS to reduce CO<INF>2</INF> emissions to the atmosphere 
and to mitigate climate change.

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

ADDRESSES: EPA has established a docket for this action under Docket ID 
No. EPA-HQ-OW-2008-0390. All documents in the docket are listed on the 
http://www.regulations.gov Web site. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, is not placed on the Internet and will be 
publicly available only in hard copy form. Publicly available docket 
materials are available either electronically through http://www.regulations.gov or in hard copy at the OW Docket, EPA/DC, EPA West, 
Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public 
Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through 
Friday, excluding legal holidays. The telephone number for the Public 
Reading Room is (202) 566-1744, and the telephone number for the OW 
Docket is (202) 566-2426.

FOR FURTHER INFORMATION CONTACT: Mary Rose (Molly) Bayer, Underground 
Injection Control Program, Drinking Water Protection Division, Office 
of Ground Water and Drinking Water (MC-4606M), Environmental Protection 
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone 
number: (202) 564-1981; fax number: (202) 564-3756; e-mail address: 
<a href="/cdn-cgi/l/email-protection#b5d7d4ccd0c79bd8d4c7ccc7dac6d0f5d0c5d49bd2dac3"><span class="__cf_email__" data-cfemail="1577746c70673b7874676c677a6670557065743b727a63">[email protected]</span></a>. For general information, visit the Underground 
Injection Control Geologic Sequestration Web site at http://www.epa.gov/safewater/uic/wells_sequestration.html.

SUPPLEMENTARY INFORMATION:

I. General Information

    This regulation affects owners or operators of injection wells that 
will be used to inject CO<INF>2</INF> into the subsurface for the 
purposes of GS. Regulated categories and entities include, but are not 
limited to, the following:

------------------------------------------------------------------------
             Category                  Examples of regulated entities
------------------------------------------------------------------------
Private...........................  Owners or Operators of 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 Sec.  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
CO<INF>2</INF> Carbon Dioxide
DOE United States Department of Energy
ECBM Enhanced Coal Bed Methane
EFAB Environmental Financial Advisory Board
EGR Enhanced Gas Recovery
EIS Environmental Impact Statement
EISA Energy Independence and Security Act of 2007
EO Executive Order
EOR Enhanced Oil Recovery
EPA United States Environmental Protection Agency
ER Enhanced Recovery
FPR Federally Permitted Releases
GAO General Accountability Office
GHG Greenhouse Gas
GS Geologic Sequestration
Gt CO<INF>2</INF> Gigatons CO<INF>2</INF>
GWPC Ground Water Protection Council
HHS United States Department of Health and Human Services
ICR Information Collection Request
IOGCC Interstate Oil and Gas Compact Commission
IPCC Intergovernmental Panel on Climate Change
IRS United States Internal Revenue Service
LBNL Lawrence Berkeley National Laboratory
Mg/L Milligrams per liter
MI Mechanical Integrity
MIT Mechanical Integrity Test
MMS United States Department of the Interior, Minerals Management 
Service
MPRSA Marine Protection, Research, and Sanctuaries Act of 1972
MRA Miscellaneous Receipts Act
MRR Mandatory Reporting Rule
MRV Monitoring, Reporting, and Verification
NAICS North American Industry Classification System
NASA National Aeronautics and Space Administration
NCER National Center for Environmental Research
NDWAC National Drinking Water Advisory Council
NEPA National Environmental Protection Act
NETL National Energy Technology Laboratory
NGO Non-Governmental Organization
NIWG National Indian Work Group
NOAA National Oceanic and Atmospheric Administration
NODA Notice of Data Availability
NOI Notice of Intent

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NTC National Tribal Caucus
NTTAA National Technology Transfer and Advancement Act of 1995
NTWC National Tribal Water Council
O&M Operation and Maintenance
OAR Office of Air and Radiation
OCS Outer Continental Shelf
OCSLA Outer Continental Shelf Lands Act
OMB Office of Management and Budget
ORD Office of Research and Development
PBMS Performance Based Measurement System
Pg Petagram
PISC Post-Injection Site Care
PRA Paperwork Reduction Act
PWSS Public Water System Supervision
QASP Quality Assurance and Surveillance Plan
RA Regulatory Alternative
RCRA Resource Conservation and Recovery Act
RCSP Regional Carbon Sequestration Partnership
RFA Regulatory Flexibility Act
RIC Regional Indian Coordinators
SDWA Safe Drinking Water Act
STAR Science To Achieve Results
STC3 State-Tribal Climate Change Council
SWP Southwest Regional Partnership on Carbon Sequestration
TCLP Toxicity Characteristic Leaching Procedure
TDS Total Dissolved Solids
TNW Tangible Net Worth
UIC Underground Injection Control
UICPG<greek-i>83 Underground Injection Control Program Guidance 
<greek-i> 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 Sec.  146.84.
    Automatic shut-off device: A valve which closes when a pre-
determined pressure or flow value is exceeded. Shut-off devices in 
injection wells can automatically shut down injection activities 
preventing an excursion outside of the permitted values.
    Ball valve: A valve consisting of a hole drilled through a ball 
placed in between two seals. The valve is closed when the ball is 
rotated in the seals so the flow path no longer aligns and is blocked.
    Biosphere: The part of the Earth's crust, waters, and atmosphere 
that supports life.
    Buoyancy: Upward force on one phase (e.g., a fluid) produced by the 
surrounding fluid (e.g., a liquid or a gas) in which it is fully or 
partially immersed, caused by differences in pressure or density.
    Capillary force: Adhesive force that holds a fluid in a capillary 
or a pore space. Capillary force is a function of the properties of the 
fluid, and surface and dimensions of the space. If the attraction 
between the fluid and surface is greater than the interaction of fluid 
molecules, the fluid will be held in place.
    Caprock: See confining zone.
    Carbon dioxide plume: The extent underground, in three dimensions, 
of an injected carbon dioxide stream.
    Carbon dioxide (CO<INF>2</INF>) stream: Carbon dioxide that has 
been captured from an emission source (e.g., a power plant), plus 
incidental associated substances derived from the source materials and 
the capture process, and any substances added to the stream to enable 
or improve the injection process. This subpart does not apply to any 
carbon dioxide stream that meets the definition of a hazardous waste 
under 40 CFR part 261.
    Casing: The pipe material placed inside a drilled hole to prevent 
the hole from collapsing. The two types of casing in most injection 
wells are (1) surface casing, the outermost casing that extends from 
the surface to the base of the lowermost USDW and (2) long-string 
casing, which extends from the surface to or through the injection 
zone.
    Cement: Material used to support and seal the well casing to the 
rock formations exposed in the borehole. Cement also protects the 
casing from corrosion and prevents movement of injectate up the 
borehole. The composition of the cement may vary based on the well type 
and purpose; cement may contain latex, mineral blends, or epoxy.
    Confining zone: A geologic formation, group of formations, or part 
of a formation stratigraphically overlying the injection zone(s) that 
acts as barrier to fluid movement. For Class VI wells operating under 
an injection depth waiver, confining zone means a geologic formation, 
group of formations, or part of a formation stratigraphically overlying 
and underlying the injection zone(s).
    Corrective action: The use of Director-approved methods to ensure 
that wells within the area of review do not serve as conduits for the 
movement of fluids into USDWs.
    Corrosive: Having the ability to wear away a material by chemical 
action. Carbon dioxide mixed with water forms carbonic acid, which can 
corrode well materials.
    Dip: The angle between a planar feature, such as a sedimentary bed 
or a fault, and the horizontal plane. The dip of subsurface rock layers 
can provide clues as to whether injected fluids may be contained.
    Director: The person responsible for permitting, implementation, 
and compliance of the UIC program. For UIC programs administered by 
EPA, the Director is the EPA Regional Administrator or his/her 
delegatee; for UIC programs in Primacy States, the Director is the 
person responsible for permitting, implementation, and compliance of 
the State, Territorial, or Tribal UIC program.
    Ductility: The ability of a material to sustain stress until it 
fractures.
    Enhanced Coal Bed Methane (ECBM) recovery: The process of injecting 
a gas (e.g., CO<INF>2</INF>) into coal, where it is adsorbed to the 
coal surface and methane is released. The methane can be captured and 
produced for economic purposes; when CO<INF>2</INF> is injected, it 
adsorbs to the surface of the coal, where it remains trapped or 
sequestered.
    Enhanced Oil or Gas Recovery (EOR/EGR): Typically, the process of 
injecting a fluid (e.g., water, brine, or CO<INF>2</INF>) into an oil 
or gas bearing formation to recover residual oil or natural gas. The 
injected fluid thins (decreases the viscosity) and/or displaces 
extractable oil and gas, which is then available for recovery. This is 
also used for secondary or tertiary recovery.
    Flapper valve: A valve consisting of a hinged flapper that seals 
the valve orifice. In Class VI wells, flapper valves can engage to shut 
off the flow of the CO<INF>2</INF> when acceptable operating parameters 
are exceeded.
    Formation or geological formation: A layer of rock that is made up 
of a certain type of rock or a combination of types.
    Geologic sequestration (GS): The long-term containment of a 
gaseous, liquid or supercritical carbon dioxide stream in subsurface 
geologic formations. This term does not apply to CO<INF>2</INF> 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

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at Sec.  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 Sec. Sec.  
146.4 and 144.7(d). It includes the subsurface three-dimensional extent 
of the carbon dioxide plume, associated area of elevated pressure, and 
displaced fluids, as well as the surface area above that delineated 
region.
    Geophysical surveys: The use of geophysical techniques (e.g., 
seismic, electrical, gravity, or electromagnetic surveys) to 
characterize subsurface rock formations.
    Injectate: The fluids injected. For the purposes of this rule, this 
is also known as the CO<INF>2</INF> stream.
    Injection zone: A geologic formation, group of formations, or part 
of a formation that is of sufficient areal extent, thickness, porosity, 
and permeability to receive CO<INF>2</INF> through a well or wells 
associated with a geologic sequestration project.
    Lithology: The description of rocks, based on color, mineral 
composition and grain size.
    Mechanical integrity (MI): The absence of significant leakage 
within the injection tubing, casing, or packer (known as internal 
mechanical integrity), or outside of the casing (known as external 
mechanical integrity).
    Mechanical Integrity Test: A test performed on a well to confirm 
that a well maintains internal and external mechanical integrity. MITs 
are a means of measuring the adequacy of the construction of an 
injection well and a way to detect problems within the well system.
    Model: A representation or simulation of a phenomenon or process 
that is difficult to observe directly or that occurs over long time 
frames. Models that support GS can predict the flow of CO<INF>2</INF> 
within the subsurface, accounting for the properties and fluid content 
of the subsurface formations and the effects of injection parameters.
    Packer: A mechanical device that seals the outside of the tubing to 
the inside of the long string casing, isolating an annular space.
    Pinch-out: A situation where a formation thins to zero thickness.
    Pore space: Open spaces in rock or soil. These are filled with 
water or other fluids such as brine (i.e., salty fluid). CO<INF>2</INF> 
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 Sec.  
146.93.
    Pressure front: The zone of elevated pressure that is created by 
the injection of carbon dioxide into the subsurface. For GS projects, 
the pressure front of a CO<INF>2</INF> 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 Sec.  146.93, at which the owner or 
operator of a GS site is released from post-injection site care 
responsibilities.
    Sorption (absorption, adsorption): Absorption refers to gases or 
liquids being incorporated into a material of a different state; 
adsorption is the adhering of a molecule or molecules to the surface of 
a different molecule.
    Stratigraphic zone (unit): A layer of rock (or stratum) that is 
recognized as a unit based on lithology, fossil content, age or other 
properties.
    Supercritical fluid: A fluid above its critical temperature 
(31.1[deg]C for CO<INF>2</INF>) and critical pressure (73.8 bar for 
CO<INF>2</INF>). Supercritical fluids have physical properties 
intermediate to those of gases and liquids.
    Total Dissolved Solids (TDS): The measurement, usually in mg/L, for 
the amount of all inorganic and organic substances suspended in liquid 
as molecules, ions, or granules. For injection operations, TDS 
typically refers to the saline (i.e., salt) content of water-saturated 
underground formations.
    Transmissive fault or fracture: A fault or fracture that has 
sufficient permeability and vertical extent to allow fluids to move 
between formations.
    Trapping: The physical and geochemical processes by which injected 
CO<INF>2</INF> is sequestered in the subsurface. Physical trapping 
occurs when buoyant CO<INF>2</INF> rises in the formation until it 
reaches a layer that inhibits further upward migration or is 
immobilized in pore spaces due to capillary forces. Geochemical 
trapping occurs when chemical reactions between dissolved 
CO<INF>2</INF> and minerals in the formation lead to the precipitation 
of solid carbonate minerals.
    Underground Source of Drinking Water (USDW): An aquifer or portion 
of an aquifer that supplies any public water system or that contains a 
sufficient quantity of ground water to supply a public water system, 
and currently supplies drinking water for human consumption, or that 
contains fewer than 10,000 mg/l total dissolved solids and is not an 
exempted aquifer.
    Viscosity: The property of a fluid or semi-fluid that offers 
resistance to flow. As a supercritical fluid, CO<INF>2</INF> is less 
viscous than water and brine.

Table of Contents

I. General Information
II. Background
    A. Why is EPA taking this regulatory action?
    1. What is GS?
    2. Why is GS under consideration as a climate change mitigation 
technology?
    3. What are the unique risks to USDWs associated with GS?
    B. Under what authority is this rulemaking promulgated?
    C. How does this rulemaking relate to the greenhouse gas (GHG) 
reporting program?
    D. How does this rulemaking relate to other federal authorities 
and GS and CCS activities?
    E. What steps did EPA take to develop this rulemaking?
    1. Developing Guidance for Experimental GS Projects
    2. Conducting Research
    a. Tracking the Results of CO<INF>2</INF> GS Research Projects
    b. Tracking State Regulatory Efforts
    c. Conducting Technical Workshops on Issues Associated with 
CO<INF>2</INF> 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
    1. Proposed Rule
    2. Notice of Data Availability and Request for Comment
    3. Final Approach
    E. Injection Well Operation
    F. Testing and Monitoring
    1. Testing and Monitoring Plan
    2. CO<INF>2</INF> Stream Analysis
    3. Mechanical Integrity Testing (MIT)
    4. Corrosion Monitoring
    5. Ground Water/Geochemical Monitoring
    6. Pressure Fall-Off Testing
    7. CO<INF>2</INF> Plume and Pressure Front Monitoring/Tracking

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    8. Surface Air/Soil Gas Monitoring
    9. Additional Requirements
    G. Recordkeeping and Reporting
    1. What Information Must Be Provided by the Owner or Operator?
    2. How Must Information Be Submitted?
    3. What are the Recordkeeping Requirements under This Rule?
    H. Well Plugging, Post-Injection Site Care (PISC), and Site 
Closure
    1. Injection Well Plugging
    2. Post-Injection Site Care (PISC)
    3. Site Closure
    I. Financial Responsibility
    J. Emergency and Remedial Response
    K. Involving the Public in Permitting Decisions
    L. Duration of a Class VI Permit
IV. Cost Analysis
    A. National Benefits and Costs of the Rule
    1. National Benefits Summary
    a. Relative Risk Framework--Qualitative Analysis
    b. Other Nonquantified Benefits
    2. National Cost Summary
    a. Cost of the Selected RA
    b. Nonquantified Costs and Uncertainties in Cost Estimates
    c. Supplementary Costs and Uncertainties in Cost Estimates
    B. Comparison of Benefits and Costs of RAs Considered
    1. Costs Relative to Benefits; Maximizing Net Social Benefits
    2. Cost Effectiveness and Incremental Net Benefits
    C. Conclusions
V. Statutory and Executive Order Review
VI. References

II. Background

    Today's action finalizes minimum Federal requirements under SDWA 
for injection of CO<INF>2</INF> for the purpose of GS. The purpose of 
the rulemaking is to ensure that GS is conducted in a manner that 
protects USDWs from endangerment. GS refers to a suite of technologies 
that can be deployed to reduce CO<INF>2</INF> emissions to the 
atmosphere and help mitigate climate change. Due to the large 
CO<INF>2</INF> injection volumes anticipated at GS projects, the 
relative buoyancy of CO<INF>2</INF>, its mobility within subsurface 
geologic formations, its corrosivity in the presence of water, and the 
potential presence of impurities in the captured CO<INF>2</INF> stream, 
the Agency has determined that tailored requirements, modeled on the 
existing UIC regulatory framework, are necessary to manage the unique 
nature of CO<INF>2</INF> injection for GS. This final rule applies to 
owners or operators of wells that will be used to inject CO<INF>2</INF> 
into the subsurface for the purpose of GS.
    To support today's final regulatory action, EPA proposed Federal 
Requirements Under the Underground Injection Control (UIC) Program for 
Carbon Dioxide (CO<INF>2</INF>) Geologic Sequestration (GS) Wells (73 
FR 43492) on July 25, 2008; and the Agency published a supplemental 
publication, Federal Requirements Under the Underground Injection 
Control (UIC) Program for Carbon Dioxide (CO<INF>2</INF>) Geologic 
Sequestration (GS) Wells; Notice of Data Availability and Request for 
Comment (74 FR 44802) on August 31, 2009. Final Class VI requirements 
are informed, in part, by comments and information submitted in 
response to these publications.
    Today's rule defines a new class of injection well (Class VI), 
along with technical criteria that tailor the existing UIC regulatory 
framework to address the unique nature of CO<INF>2</INF> injection for 
GS. It sets minimum technical criteria for Class VI wells to protect 
USDWs from endangerment, including:
    <bullet> 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.
    <bullet> Computational modeling of the AoR for GS projects that 
accounts for the physical and chemical properties of the injected 
CO<INF>2</INF> and is based on available site characterization, 
monitoring, and operational data.
    <bullet> Periodic reevaluation of the AoR to incorporate monitoring 
and operational data and verify that the CO<INF>2</INF> plume and the 
associated area of elevated pressure are moving as predicted within the 
subsurface.
    <bullet> Well construction using materials that can withstand 
contact with CO<INF>2</INF> over the life of the GS project.
    <bullet> Robust monitoring of the CO<INF>2</INF> stream, injection 
pressures, integrity of the injection well, ground water quality and 
geochemistry, and monitoring of the CO<INF>2</INF> plume and position 
of the pressure front throughout injection.
    <bullet> Comprehensive post-injection monitoring and site care 
following cessation of injection to show the position of the 
CO<INF>2</INF> plume and the associated area of elevated pressure to 
demonstrate that neither pose an endangerment to USDWs.
    <bullet> Financial responsibility requirements to ensure that funds 
will be available for all corrective action, injection well plugging, 
post-injection site care (PISC), site closure, and emergency and 
remedial response.
    Today's rule will help ensure consistency in permitting underground 
injection of CO<INF>2</INF> at GS operations across the United States 
(US) and provide requirements to prevent endangerment of USDWs in 
anticipation of the potential role of carbon capture and storage (CCS) 
in mitigating climate change. Today's action also briefly discusses the 
relationship between today's rule and other Federal and State 
activities related to GS and CCS in Sections II.C and D, and E.2.b, and 
III.F.2.

A. Why is EPA taking this regulatory action?

1. What is GS?
    GS is the process of injecting CO<INF>2</INF> into deep subsurface 
rock formations for long-term storage. It is part of the process known 
as CCS.
    CO<INF>2</INF> is first captured from fossil-fueled power plants or 
other emission sources. To transport captured CO<INF>2</INF> for GS, 
operators typically compress CO<INF>2</INF> to convert it from a 
gaseous state to a supercritical state (IPCC, 2005; IEA, 2008). 
CO<INF>2</INF> exists as a supercritical fluid at high pressures, and 
in this state it exhibits properties of both a liquid and a gas. After 
capture and compression, the CO<INF>2</INF> is delivered to the 
sequestration site, frequently by pipeline, or alternatively using 
tanker trucks or ships (WRI, 2007; IEA, 2008).
    At the GS site, the CO<INF>2</INF> is injected into deep subsurface 
rock formations through one or more wells, using technologies developed 
and refined by the oil, gas, and chemical manufacturing industries over 
the past several decades. EPA believes that many owners or operators 
will inject CO<INF>2</INF> in a supercritical state to depths greater 
than 800 meters (2,645 feet) for the purpose of maximizing capacity and 
storage.
    When injected into an appropriate receiving formation, 
CO<INF>2</INF> is sequestered by a combination of trapping mechanisms, 
including physical and geochemical processes (Benson, 2008). Physical 
trapping occurs when the relatively buoyant CO<INF>2</INF> rises in the 
formation until it reaches a stratigraphic zone with low permeability 
(i.e., geologic confining system) that inhibits further upward 
migration. Physical trapping can also occur as residual CO<INF>2</INF> 
is immobilized in formation pore spaces as disconnected droplets or 
bubbles at the trailing edge of the plume due to capillary forces. A 
portion of the CO<INF>2</INF> will dissolve from the pure fluid phase 
into native ground water and hydrocarbons. Preferential sorption occurs 
when CO<INF>2</INF> molecules attach to the surfaces of coal and 
certain organic-rich shales, displacing other molecules such as 
methane. Geochemical trapping occurs when chemical reactions between 
the dissolved CO<INF>2</INF> and minerals in the formation lead to the 
precipitation of solid carbonate minerals (IPCC, 2005). The timeframe 
over which CO<INF>2</INF> will be trapped by these mechanisms depends 
on properties of

[[Page 77234]]

the receiving formation and the injected CO<INF>2</INF> stream.
    The effectiveness of physical CO<INF>2</INF> trapping is 
demonstrated by natural analogs in a range of geologic settings where 
CO<INF>2</INF> has remained trapped for millions of years (Holloway et 
al., 2007). For example, CO<INF>2</INF> has been trapped for more than 
65 million years under the Pisgah Anticline, northeast of the Jackson 
Dome in Mississippi and Louisiana (IPCC, 2005). Other natural 
CO<INF>2</INF> sources include the following geologic domes: McElmo 
Dome, Sheep Mountain, and Bravo Dome in Colorado and New Mexico.
    Many of the injection and monitoring technologies that may be 
applicable to GS are commercially available today and will be more 
widely demonstrated over the next 10 to 15 years (Dooley et al., 2009). 
The oil and natural gas industry in the United States has over 35 years 
of experience of injection and monitoring of CO<INF>2</INF> in the deep 
subsurface for the purposes of enhancing oil and natural gas 
production. This experience provides a strong foundation for the 
injection and monitoring technologies that will be needed for 
commercial-scale CCS. US and international experience with enhanced 
recovery (ER) and commercial CCS projects, as well as ongoing research, 
demonstration, and deployment programs throughout the world, provide 
critical experience and information to inform the safe injection of 
CO<INF>2</INF>. For additional information about these projects, see 
section II.E.
    Although CCS is occurring now on a relatively small scale, it could 
play a larger role in mitigating greenhouse gas (GHG) emissions from a 
wide variety of stationary sources. According to the Inventory of US 
Greenhouse Gas Emissions and Sinks: 1990-2007, stationary sources 
contributed 67 percent of the total CO<INF>2</INF> emissions from 
fossil fuel combustion in 2007 (USEPA, 2008a). These sources represent 
a wide variety of sectors amenable to CO<INF>2</INF> capture: electric 
power plants (existing and new), natural gas processing facilities, 
petroleum refineries, iron and steel foundries, ethylene plants, 
hydrogen production facilities, ammonia refineries, ethanol production 
facilities, ethylene oxide plants, and cement kilns. Furthermore, 95 
percent of the 500 largest stationary sources are within 50 miles of a 
candidate GS reservoir (Dooley et al., 2008). Estimated GS capacity in 
the United States is over 3,500 Gigatons CO<INF>2</INF> (Gt 
CO<INF>2</INF>) (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):
    <bullet> Global surface temperatures have risen by 1.3 degrees 
Fahrenheit ([ordm]F) over the last 100 years.
    <bullet> Worldwide, the last decade has been the warmest on record.
    <bullet> The rate of warming across the globe over the last 50 
years (0.24[ordm]F per decade) is almost double the rate of warming 
over the last 100 years (0.13[ordm]F per decade).
    Most of this recent warming is very likely the result of human 
activities. Many human activities release greenhouse gases into the 
atmosphere (such as the combustion of fossil fuels). The levels of 
these gases are increasing at a faster rate than at any time in 
hundreds of thousands of years.
    Fossil fuels are expected to remain the mainstay of energy 
production well into the 21st century, and increased concentrations of 
CO<INF>2</INF> are expected unless energy producers reduce 
CO<INF>2</INF> emissions to the atmosphere. For example, CCS would 
enable the continued use of coal in a manner that greatly reduces the 
associated CO<INF>2</INF> emissions while other safe and affordable 
alternative energy sources are developed in the coming decades. The 
development and deployment of clean coal technologies including CCS 
will be a key to achieving domestic emissions reductions.
    GS is one of a portfolio of options that could be deployed to 
reduce CO<INF>2</INF> emissions to the atmosphere and help to mitigate 
climate change. Other options include energy conservation, efficiency 
improvements, and the use of alternative fuels and renewable energy 
sources. Ensuring that GS is done in a manner that is protective of 
USDWs will ensure the safety and efficacy of CO<INF>2</INF> injection 
for GS.
    While predictions about large-scale availability and the rate of 
CCS project deployment are subject to uncertainty, EPA analyses of 
Congressional climate change legislative proposals (the American Power 
Act of 2010 and the American Clean Energy and Security Act H.R. 2454 of 
2009, both in the 111th Congress) indicate that CCS has the potential 
to play a significant role in climate change mitigation scenarios. For 
example, analysis of the American Power Act indicates that CCS 
technology could account for 10 percent of CO<INF>2</INF> emission 
reductions in 2050 (USEPA, 2010f). These results indicate that CCS 
could play an important role in achieving national greenhouse gas 
reduction goals.
    Today's final rule provides minimum Federal requirements for the 
injection of CO<INF>2</INF> to protect USDWs from endangerment as this 
key climate mitigation technology is developed and deployed. It 
clarifies requirements that apply to CO<INF>2</INF> injection for GS, 
provides consistency in requirements across the US, and affords 
transparency about what requirements apply to owners or operators.
3. What are the unique risks to USDWs associated with GS?
    Large CO<INF>2</INF> injection volumes associated with GS, the 
buoyant and mobile nature of the injectate, the potential presence of 
impurities in the CO<INF>2</INF> stream, and its corrosivity in the 
presence of water could pose risks to USDWs. The purpose of today's 
Class VI requirements for GS is to ensure the protection of USDWs, 
recognizing that an improperly managed GS project has the potential to 
endanger USDWs. Proper siting, well construction, operation, and 
monitoring of GS projects are therefore necessary to reduce the risk of 
USDW contamination.
    It is expected that GS projects will inject large volumes of 
CO<INF>2</INF>. These volumes will be much larger than are typically 
injected in other well classes regulated through the UIC program, and 
could cause significant pressure increases in the subsurface. 
Supercritical or gaseous CO<INF>2</INF> in the subsurface is buoyant, 
and thus would tend to flow upwards if it were to come into contact 
with a migration pathway, such as a fault, fracture, or improperly 
constructed or plugged well. However, the pressures induced by 
injection will also influence CO<INF>2</INF> and mobilized fluids to 
flow away from the injection well in all directions, including 
laterally, upwards and downwards. When CO<INF>2</INF> mixes with 
formation fluids, a percentage of it will dissolve. The resulting 
aqueous mixture of CO<INF>2</INF> and water will sink due to a density 
differential between the mixture and the surrounding fluids. 
CO<INF>2</INF> is also highly mobile in the subsurface (i.e., has a 
very low viscosity), and, in the presence of water, CO<INF>2</INF> can 
be corrosive. These properties (of CO<INF>2</INF>), as well as the 
large

[[Page 77235]]

volumes that may be injected for GS result in several unique challenges 
for protection of USDWs in the vicinity of GS sites from endangerment.
    While CO<INF>2</INF> itself is not a drinking water contaminant, 
CO<INF>2</INF> in the presence of water forms a weak acid, known as 
carbonic acid, that, in some instances, could cause leaching and 
mobilization of naturally-occurring metals or other contaminants from 
geologic formations into ground water (e.g., arsenic, lead, and organic 
compounds). Another potential risk to USDWs is the presence of 
impurities in the captured CO<INF>2</INF> stream, which may include 
drinking water contaminants such as hydrogen sulfide or mercury. 
Additionally, pressures induced by injection may force native brines 
(naturally occurring salty water) into USDWs, causing degradation of 
water quality and affecting drinking water treatment processes. 
Research studies have shown that the potential migration of injected 
CO<INF>2</INF> or formation fluids into a USDW could cause impairment 
through one or several of these processes (e.g., Birkholzer et al., 
2008a).
    Today's action addresses endangerment to USDWs by establishing new 
minimum Federal requirements for the proper management of 
CO<INF>2</INF> 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\ UIC programs that regulate the subsurface injection of fluids 
onshore and offshore under submerged lands within the territorial 
jurisdiction of States\2\.
---------------------------------------------------------------------------

    \1\ Reference to ``States'' includes Tribes and Territories 
pursuant to 40 CFR 144.3.
    \2\ The Submerged Lands Act and Territorial Submerged Lands Act 
define the scope of territorial jurisdiction of States and 
Territories respectively.
---------------------------------------------------------------------------

    SDWA is designed to protect the quality of drinking water sources 
in the US and prescribes that EPA issue regulations for State UIC 
programs that contain ``minimum requirements for effective programs to 
prevent underground injection which endangers drinking water sources'' 
(42 U.S.C. 300h et seq.). Congress further defined endangerment as 
follows:

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

    Under this authority, the Agency promulgated a series of UIC 
regulations at 40 CFR parts 144 through 148 for federally approved UIC 
programs. The chief goal of any Federally approved UIC program (whether 
administered by a State, Territory, Tribe or EPA) is the protection of 
USDWs. This includes not only those formations that are presently being 
used for drinking water, but also those that can reasonably be expected 
to be used in the future. EPA has defined through its UIC regulations 
that USDWs are underground aquifers with less than 10,000 milligrams 
per liter (mg/L) total dissolved solids (TDS) and which contain a 
sufficient quantity of ground water to supply a public water system (40 
CFR 144.3). Section 1421(b)(3)(A) of the SDWA also provides that EPA's 
UIC regulations shall ``permit or provide for consideration of varying 
geologic, hydrological, or historical conditions in different States 
and in different areas within a State.''
    EPA promulgated administrative and permitting regulations, now 
codified in 40 CFR parts 144 and 146, on May 19, 1980 (45 FR 33290), 
and technical requirements, in 40 CFR part 146, on June 24, 1980 (45 FR 
42472). The regulations were subsequently amended on August 27, 1981 
(46 FR 43156), February 3, 1982 (47 FR 4992), January 21, 1983 (48 FR 
2938), April 1, 1983 (48 FR 14146), May 11, 1984 (49 FR 20138), July 
26, 1988 (53 FR 28118), December 3, 1993 (58 FR 63890), June 10, 1994 
(59 FR 29958), December 14, 1994 (59 FR 64339), June 29, 1995 (60 FR 
33926), December 7, 1999 (64 FR 68546), May 15, 2000 (65 FR 30886), 
June 7, 2002 (67 FR 39583), and November 22, 2005 (70 FR 70513).
    Under the SDWA, the injection of any ``fluid'' must meet the 
requirements of the UIC program. A ``fluid'' is defined under 40 CFR 
144.3 as any material or substance which flows or moves whether in a 
semisolid, liquid, sludge, gas or other form or state, and includes the 
injection of liquids, gases, and semisolids (i.e., slurries) into the 
subsurface. The types of fluids currently injected into wells subject 
to UIC requirements include: CO<INF>2</INF> for the purposes of 
enhancing recovery of oil and natural gas, water that is stored to meet 
water supply demands in dry seasons, and wastes generated by industrial 
users. CO<INF>2</INF> injected for the purpose of GS is subject to the 
SDWA.

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

    Today's rulemaking under SDWA authority complements the 
CO<INF>2</INF> Injection and GS Reporting rulemaking (subparts RR and 
UU) under the Greenhouse Gas Reporting Program's Clean Air Act (CAA) 
authority developed by EPA's Office of Air and Radiation (OAR).
    The CAA defines EPA's responsibilities for protecting and improving 
the nation's air quality and the stratospheric ozone layer. The GHG 
Reporting Program requires reporting of GHG emissions and other 
relevant information from certain source categories in the U.S. The GHG 
Reporting Program, which became effective on December 29, 2009, 
includes reporting requirements for facilities and suppliers in 32 
subparts. For more detailed background information on the GHG Reporting 
Program, see the preamble to the final rule establishing the GHG 
Reporting Program (74 FR 56260, October 30, 2009).
    In a separate action being finalized concurrently with this UIC 
Class VI rulemaking, EPA is amending 40 CFR part 98, which provides the 
regulatory framework for the GHG Reporting Program, to add reporting 
requirements covering facilities that conduct GS (subpart RR) and all 
other facilities that inject CO<INF>2</INF> underground (subpart UU). 
This data will inform Agency policy decisions under CAA sections 111 
and 112 related to the use of CCS for mitigating GHG emissions. In 
combination with data from other subparts of the GHG Reporting Program, 
data from subpart UU and subpart RR will allow EPA to track the flow of 
CO<INF>2</INF> across the CCS system. EPA will be able to reconcile 
subpart RR data on CO<INF>2</INF> received with CO<INF>2</INF> supply 
data in order to understand the quantity of CO<INF>2</INF> supply that 
is geologically sequestered.
    Owners or operators subject to today's rule are required to report 
under subpart RR. Subpart RR establishes reporting requirements for 
facilities that inject a CO<INF>2</INF> 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

[[Page 77236]]

Monitoring, Reporting, and Verification (MRV) plan which, once approved 
by EPA (in a process separate from the UIC permitting process), would 
be used to verify the amount of CO<INF>2</INF> sequestered and to 
quantify emissions in the event that injected CO<INF>2</INF> leaks to 
the surface. For more information on subpart RR, see http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.
    UIC requirements and Subpart RR requirements: EPA designed the 
reporting requirements under subpart RR with consideration of the 
requirements for Class VI well owners or operators in subpart H of part 
146 of today's rule. Subpart RR builds on the Class VI requirements 
outlined in today's rule with the additional goals of verifying the 
amount of CO<INF>2</INF> sequestered and collecting data on any 
CO<INF>2</INF> surface emissions from GS facilities as identified under 
subpart RR of part 98.
    The Agency acknowledges that there are similar data elements that 
must be reported pursuant to requirements in this action and those 
required to be reported under subpart RR. Specifically, owners or 
operators subject to both regulations must report the amount (flow 
rate) of injected CO<INF>2.</INF> The Class VI and subpart RR rules 
differ, not only in purpose but in the specific requirements for the 
measurement unit and collection/reporting frequency. The UIC program 
Class VI rule requires that owners or operators report information on 
the CO<INF>2</INF> stream to ensure appropriate well siting, 
construction, operation, monitoring, post-injection site care, site 
closure, and financial responsibility to ensure protection of USDWS. 
Under subpart RR, owners or operators must report the amount (flow 
rate) of injected CO<INF>2</INF> for the mass balance equation that 
will be used to quantify the amount of CO<INF>2</INF> 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   Yes.................  N/A.
 onsite.
Quantity (flow rate) of CO2   Yes.................  Yes.
 injected.
Fugitive and vented           Yes.................  N/A.
 emissions from surface
 equipment.
Quantity of CO2 produced      Yes.................  N/A.
 with oil or natural gas
 (ER).
Percent of CO2 estimated to   Yes.................  N/A.
 remain with the oil and gas
 (ER).
Quantity of CO2 emitted from  Yes.................  N/A.
 the subsurface.
Quantity of CO2 sequestered   Yes.................  N/A.
 in the subsurface.
Cumulative mass of CO2        Yes.................  N/A.
 sequestered in the
 subsurface.
Monitoring plan for           Yes.................  Yes.\1\
 detecting air emissions.
Monitoring plan for           Yes.................  N/A.
 quantifying air emissions.
------------------------------------------------------------------------
(1) UIC Class VI rule allows for surface air/soil gas monitoring for
  USDW protection at the discretion of the UIC Director.

    EPA requires reporting of other data to satisfy various 
programmatic needs. See section III of this preamble and associated 
requirements in subpart H of part 146 and the preamble to subpart RR 
for additional information on these specific requirements and their 
purpose. Table II-1 provides a comparison of the major reporting 
requirements in subpart RR and the extent to which there is overlap 
with Class VI requirements. For the monitoring plan listed in Table II-
1, EPA will accept a UIC Class VI permit to satisfy certain subpart RR 
MRV plan requirements. However, the reporter must include additional 
information to outline how monitoring will achieve surface detection 
and quantification of CO<INF>2</INF>. EPA is pursuing ways to better 
integrate data management between the UIC and GHG Reporting Programs to 
ensure that data needs are harmonized and the burden to regulated 
entities is minimized.

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

    While the SDWA provides EPA with the authority to develop 
regulations to protect USDWs from endangerment, it does not provide 
authority to develop regulations for all areas related to GS. EPA 
received a number of public comments on the proposal (73 FR 43492, July 
25, 2008) indicating that the Agency should further explore 
environmental and regulatory issues beyond the scope of the proposed 
SDWA requirements for underground injection of CO<INF>2</INF> for GS.
    In response to comments and as a result of the presidential memo 
``A Comprehensive Strategy on Carbon Capture and Storage'' (http://www.whitehouse.gov/the-press-office/presidential-memorandum-a-comprehensive-Federal-strategy-carbon-capture-and-storage), the Agency 
continues to evaluate areas of potential applicability of other Federal 
environmental statutes including, but not limited to, the CAA 
(discussed in section II.C), the Resource Conservation and Recovery Act 
(RCRA; discussed in section III.F.2), the Comprehensive Environmental 
Response, Compensation, and Liability Act (CERCLA; discussed in section 
III.F.2), and the Marine Protection, Research and Sanctuaries Act 
(MPRSA; discussed in this section) to various aspects of GS and CCS.
    Additionally, EPA and the US Department of Energy (DOE) co-chaired 
the Interagency Task Force on Carbon Capture and Storage to develop a 
plan to overcome the barriers to the widespread, cost-effective 
deployment of CCS within 10 years, with a goal of bringing five to 10 
commercial demonstration projects online by 2016. The Task Force's 
report is available at http://www.whitehouse.gov/administration/eop/ceq/initiatives/ccs.
    This section clarifies the distinction between today's rulemaking 
and a number of other Federal rulemakings and initiatives.
    National Environmental Protection Act (NEPA): The SDWA UIC program 
is exempt from performing an Environmental Impact Statement (EIS) under 
section 101(2)(C) and an alternatives analysis under section 101(2)(E) 
of NEPA under a functional equivalence analysis. See Western Nebraska 
Resources Council 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 CO<INF>2</INF> injection for GS 
may, in certain circumstances, be defined as ocean dumping and subject 
to regulation under the MPRSA. Application of the MPRSA would entail 
coordination of the permitting processes under the SDWA and MPRSA, 
pursuant to MPRSA sections 106(a) and (d). The substantive 
environmental protection requirements of both statutes would need to be 
satisfied prior to the

[[Page 77237]]

commencement of GS. The MPRSA was enacted in 1972 and implements the 
London Convention on the Prevention of Marine Pollution by Dumping of 
Wastes and Other Matter (the ``London Convention''). In 1996, the 
Protocol to the London Convention (the ``London Protocol'') was 
established. The Protocol stipulates that sub-seabed GS may be approved 
provided that: (1) Disposal is into a sub-seabed geologic formation; 
(2) the CO<INF>2</INF> stream consists overwhelmingly of 
CO<INF>2</INF>, with only incidental associated substances derived from 
the source material and capture and sequestration process used; and, 
(3) no wastes or other matter are added for the purpose of disposal. 
The US has signed, but has not yet ratified, the Protocol. If the 
Protocol is ratified, and implementing legislation is enacted, EPA, in 
conjunction with other Federal agencies, will develop any necessary 
regulations for implementing the provisions relevant to sub-seabed GS.
    Bureau of Ocean Energy Management, Regulation, and Enforcement 
(BOEMRE) Outer Continental Shelf Lands Act (OCSLA): BOEMRE, formerly 
the Minerals Management Service (MMS), an agency within the Department 
of the Interior, administers the OCSLA. As a result of recent OCSLA 
amendments by the Energy Policy Act of 2005, the OCSLA provides for the 
grant of leases, easements, or rights-of-way on the outer continental 
shelf to the extent that an activity ``supports production, 
transportation, or transmission of energy from sources other than oil 
and gas'' and complies with the other provisions of OCSLA section 8(p). 
Offshore geologic sequestration of CO<INF>2</INF> on the outer 
continental shelf may be subject to requirements under the OCSLA.
    As indicated in the Report of the Interagency Task Force on Carbon 
Capture and Storage (2010), ratification of the London Protocol and 
associated amendment of the MPRSA as well as amendment of the Outer 
Continental Shelf Lands Act (OCSLA) will ensure a comprehensive 
statutory framework for the storage of CO<INF>2</INF> on the outer 
continental shelf.
    Bureau of Land Management (BLM) Report to Congress: The BLM, 
another agency within the Department of Interior, was required by 
Section 714 of the Energy Independence and Security Act (EISA) of 2007 
(Pub. L. 110-140, HR 6) to prepare a report outlining a regulatory 
framework that could be applied to lands managed by the Bureau for 
natural resource development, chiefly oil and gas. With assistance from 
both EPA and the DOE, BLM submitted a Report to Congress titled 
``Framework for Geological Carbon Sequestration on Public Land'' (BLM, 
2009). This report affirms BLM's role in appropriately managing Federal 
lands where GS injection projects may be sited. Additionally, the 
report makes recommendations regarding approaches for effective 
regulation of such activities under existing Federal authorities 
including the SDWA and UIC program requirements.
    United States Geological Survey (USGS) GS Capacity Methodology: 
USGS, another agency within the Department of Interior and the primary 
Federal agency responsible for national geological research, has been 
an active participant with DOE and EPA at conferences and workshops on 
CCS. In 2008, in response to the EISA, USGS initiated development of a 
methodology for estimating the capacity to store CO<INF>2</INF> in 
geologic formations of the U.S. While previous capacity estimates 
published by DOE/National Energy Technology Laboratory (NETL) have been 
broad in scope (i.e., geologic basin-wide), the USGS is focusing on 
small-scale, refined estimates. In 2009, USGS published a proposed, 
risk-based methodology for GS capacity estimation. After input from 
other agencies and stakeholders, USGS released a final report: A 
Probabilistic Assessment Methodology for the Evaluation of Geologic 
Carbon Dioxide Storage (USGS, 2010). The report is available at http://pubs.usgs.gov/of/2010/1127/. USGS continues to work on capacity 
estimation as required under the EISA.
    Internal Revenue Service (IRS) Guidance for Tax Incentives for GS 
Projects: In response to the Energy Improvement and Extension Act of 
2008, IRS, in consultation with EPA and DOE, issued guidance 2009-44 
IRB (IRS, 2009) for taxpayers seeking to claim tax credits for 
capturing and sequestering CO<INF>2</INF> from a qualified facility in 
the U.S. Under section 45Q of the Internal Revenue Code, a taxpayer who 
stores CO<INF>2</INF> under the predetermined conditions may qualify 
for the tax credit ($10 per metric ton of qualified CO<INF>2</INF> at 
ER projects; $20 per metric ton of qualified CO<INF>2</INF> for non-ER 
projects). The taxpayer will be responsible for maintaining records for 
inspection by the IRS and tax credit amounts will be adjusted for 
inflation for any taxable year beginning after 2009. The Internal 
Revenue Service published IRS Notice 2009-83 (available at: http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860) to provide guidance 
regarding eligibility for the section 45Q tax credit, computation of 
the section 45Q tax credit, reporting requirements for taxpayers 
claiming the section 45Q tax credit, and rules regarding adequate 
security measures for ``secure geological storage of CO<INF>2.</INF>''
    Following publication of today's final Class VI requirements, and 
as clarified in the guidance, taxpayers claiming the section 45Q tax 
credit must follow the appropriate UIC requirements (e.g., Class II or 
Class VI). The guidance also clarifies that taxpayers claiming section 
45Q tax credit must follow the GS monitoring, reporting, and 
verification procedures finalized in the CO<INF>2</INF> Injection and 
GS Reporting Rule that is part of the GHG Reporting Program.
    General Accountability Office Reports on GS and CCS: The United 
States General Accountability Office (GAO) has prepared, or is in the 
process of preparing, several reports for Congressional requestors 
related to the GS of CO<INF>2</INF>. In September 2008, GAO (GAO-08-
1080) completed a report related to assessing the application of CCS 
technologies entitled: Climate Change--Federal Actions Will Greatly 
Affect the Viability of Carbon Capture and Storage as a Key Mitigation 
Option (GAO, 2008). In September 2010, GAO released a report entitled: 
Climate Change, A Coordinated Strategy Could Focus Federal 
Geoengineering Research and Inform Governance Efforts (GAO-10-903) 
which describes innovative technologies that may alter climate change, 
details current research activities, and clarifies how coordination 
could inform subsequent climate science efforts. GAO initiated another 
report (GAO-10-675) focused on the methods by which coal-fired power 
plants may capture carbon emissions. The draft title of that study is: 
Coal Power Plants--Opportunities Exist for DOE to Provide Better 
Information on the Maturity of Key Technologies to Reduce Carbon 
Emissions (GAO, 2010).
    EPA will continue to coordinate internally and with other Federal 
agencies to promote consistency in existing and future GS and CCS 
initiatives.

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

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

[[Page 77238]]

determine how best to tailor existing UIC requirements to 
CO<INF>2</INF> 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 <greek-i>83 is available at: http://www.epa.gov/safewater/uic/wells_sequestration.html. EPA is preparing 
additional guidance for owners or operators and Directors regarding the 
use of Class V experimental technology wells for GS following 
promulgation of today's rule.
2. Conducting Research
    EPA participated in and supported research to inform today's 
rulemaking including: Supporting and tracking the development and 
results of national and international CO<INF>2</INF> GS field and 
research projects; tracking GS-related State regulatory and legislative 
efforts; and conducting technical workshops on issues associated with 
CO<INF>2</INF> GS. EPA described these research activities in detail in 
the proposed rule (July 2008) and the NODA and Request for Comment 
(August 2009). Additional information pertaining to these activities, 
which are summarized below, may be found in the rulemaking docket.
a. Tracking the Results of CO<INF>2</INF> GS Research Projects
    To inform today's rulemaking, EPA tracked the progress and results 
of national and international GS research projects. DOE leads field 
research on GS in the U.S. in conjunction with the Regional Carbon 
Sequestration Partnerships (RCSPs). Currently, DOE's NETL is developing 
and/or operating GS projects, a number of which have either completed 
injection or are in the process of injecting CO<INF>2</INF>. The seven 
RCSPs are conducting pilot and demonstration projects to study site 
characterization (including injection and confining formation 
information, core data and site selection information); well 
construction (well depth, construction materials, and proximity to 
USDWs); frequency and types of tests and monitoring conducted (on the 
well and on the project site); modeling and monitoring results; and 
injection operation (injection rates, pressures, and volumes, 
CO<INF>2</INF> source and co-injectates). See section II.E.5 for more 
information on the status of these projects.
    Lawrence Berkeley National Laboratory (LBNL) research: EPA and DOE 
are jointly funding work by the LBNL to study potential impacts of 
CO<INF>2</INF> injection on ground water aquifers and drinking water 
sources. The preliminary results have been used to inform today's 
rulemaking and are described in detail in section II.E.5.
    In addition, EPA is funding an analysis by LBNL to integrate 
experimental and modeling information. LBNL will characterize ground 
water samples and aquifer mineralogies from select sites in the U.S. 
and conduct controlled laboratory experiments to assess the potential 
mobilization of hazardous constituents by dissolved CO<INF>2</INF>. 
These experiments will provide data that will be used to validate 
previous predictive modeling studies (of aquifer vulnerabilities to 
potential CO<INF>2</INF> leaks) which may be applied to other GS sites 
in the future to assess the fate and migration of CO<INF>2</INF>-
mobilized constituents in ground water.
    EPA's Office of Research and Development (ORD) GS research: EPA's 
ORD engages Agency scientists and engineers in targeted research to 
provide information to stakeholders and policy makers focused on areas 
of national environmental concern, including climate change and GS. In 
addition, ORD's National Center for Environmental Research (NCER) 
provides extramural research grants for similar investigations through 
a competitive solicitation process. In the fall of 2009, NCER awarded 
six Science To Achieve Results (STAR) grants to recipients from major 
universities and institutions. The awards were granted to projects 
focused on Integrated Design, Modeling and Monitoring of GS of 
Anthropogenic CO<INF>4</INF> to Safeguard Sources of Drinking Water. 
Work under the grants began in late 2009 and includes: Evaluating 
potential impacts on drinking water aquifers of CO<INF>2</INF>-rich 
dissolved brines (Clemson University); reducing the hydrologic and 
geochemical uncertainties associated with CO<INF>2</INF> sequestration 
in deep, saline reservoirs (University of Illinois-Urbana); assessing 
appropriate monitoring approaches at GS sites (University of Texas at 
Austin); integrating design, monitoring, and modeling of GS to assist 
in developing a practical methodology for characterizing risks to USDWs 
(University of Utah); conducting laboratory experiments on shallow 
aquifer systems to improve our understanding of geochemical and 
microbiological reactions under low pH/high CO<INF>2</INF> stress 
(Columbia University); and, developing a set of computational tools to 
model CO<INF>2</INF> and brine movement associated with GS (Princeton 
University).
    International projects: EPA is tracking the progress of 
international GS efforts. The largest and longest-running commercial, 
large-scale projects in operation today include: The Sleipner Project 
in the Norwegian North Sea (operating since 1996); the Weyburn enhanced 
oil recovery (EOR) project in Saskatchewan, Canada (operating since 
2000); the In Salah Gas Project in Algeria (operating since 2004); and 
Snohvit, also in offshore Norway in the Barents Sea (operating since 
2008). Other projects EPA is tracking include Otway in Australia 
(operating since 2008); Ketzin in Germany (operating since 2008); and 
Lacq in France (operating since 2009). EPA is also tracking two 
projects that are anticipated to begin injection in the near future: 
CarbFix in Iceland (anticipated to commence injection in 2010) and 
Gorgon in Australia (anticipated to start in 2014). EPA evaluated 
available information and experiences gained from these international 
projects to inform today's action, as appropriate. Additional 
information on how these and other international projects informed the 
GS rulemaking is contained in the rulemaking docket (USEPA, 2010a).
b. Tracking State Regulatory Efforts
    EPA has made it a priority to engage States and State organizations 
throughout the rulemaking effort. EPA recognizes the complexity and 
importance of the States' approaches to managing GS and is aware that 
States are in various stages of developing statutory frameworks, 
regulations,

[[Page 77239]]

technical guidance, and strategies for addressing CCS and GS. 
Throughout the regulatory development process for the Class VI 
regulation, EPA monitored States' regulatory efforts and approaches and 
sought input on State activities related to addressing GS in the 
proposed rule and NODA. At present, several States have published GS 
regulations, while others are investigating and developing strategies 
to address GS issues (e.g., management of multi-purpose injection wells 
in oil and gas reservoirs). EPA is tracking regulatory efforts in 18 
States: Colorado, Illinois, Kansas, Kentucky, Louisiana, Michigan, 
Mississippi, Montana, New Mexico, New York, North Dakota, Oklahoma, 
Pennsylvania, Texas, Utah, Washington, West Virginia, and Wyoming. EPA 
is considering this information as it develops guidance on the primacy 
application and approval process for Class VI wells. Information about 
these State activities may be found in the docket for today's 
rulemaking.
c. Conducting Technical Workshops on Issues Associated With 
CO<INF>2</INF> 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 CO<INF>2</INF> GS. 
The workshops included the following: Measurement, Monitoring, and 
Verification (in New Orleans, Louisiana on January 16, 2008); 
Geological Setting and AoR Considerations for CO<INF>2</INF> GS (in 
Washington, DC on July 10-11, 2007); Well Construction and MIT (in 
Albuquerque, New Mexico on March 14, 2007); a State Regulators' 
Workshop on GS of CO<INF>2</INF> (in collaboration with DOE in San 
Antonio, Texas on January 24, 2007); an International Symposium on Site 
Characterization for CO<INF>2</INF> Geological Storage (co-sponsored 
with LBNL in Berkeley, California on March 20-22, 2006); Risk 
Assessment for Geologic CO<INF>2</INF> Storage (co-sponsored with the 
Ground Water Protection Council (GWPC) in Portland, Oregon on September 
28-29, 2005); and Modeling and Reservoir Simulation for Geologic Carbon 
Storage (in Houston, Texas on April 6-7, 2005). Summaries of these 
workshops are available on EPA's Web site, at http://www.epa.gov/safewater/uic/wells_sequestration.html.
3. Conducting Stakeholder Coordination and Outreach
    Throughout the rulemaking process, the Agency conducted public 
workshops and public hearings and consulted with specific groups. EPA 
representatives also attended meetings to explain the GS rulemaking 
effort to interested members of the public and stakeholder groups. 
Meeting information, notes, and summaries are available in the docket 
for this rulemaking.
    Public stakeholder coordination: EPA held public meetings to 
discuss EPA's rulemaking approach, and consulted with other stakeholder 
groups including non-governmental organizations (NGOs) to gain an 
understanding of stakeholder interests and concerns. As part of this 
outreach, EPA conducted two public stakeholder workshops with 
participants from industry, environmental groups, utilities, academia, 
States, and the general public. These workshops were held in December 
2007 and February 2008. Workshop summaries are available on EPA's Web 
site, at http://www.epa.gov/safewater/uic/wells_sequestration.html.
    EPA also coordinated with GWPC, a State association that focuses on 
ensuring safe application of injection well technology and protecting 
ground water resources, and IOGCC, a chartered State association 
representing oil and gas producing States throughout the rulemaking 
process. Members of GWPC and IOGCC have specific expertise regulating 
the injection of CO<INF>2</INF> for the ER of oil and gas. EPA staff 
attended national meetings and calls of these organizations, as well as 
those held by technical and trade organizations, NGOs, States, and 
Tribal organizations to discuss the rulemaking process and GS-specific 
technical issues.
    Consultation with the National Drinking Water Advisory Council 
(NDWAC): In November 2008, during the public comment period for the 
proposed rule, EPA met with NDWAC to discuss the proposed rule. At the 
meeting, EPA presented information about the rulemaking and responded 
to NDWAC questions and comments. NDWAC members indicated that they 
understood the role of GS as a climate mitigation tool and encouraged 
the Agency to continue to ensure the protection of USDWs. Since 
proposal publication, EPA has met with NDWAC to discuss the status of 
the rule and answer questions from NDWAC members. The notes of these 
meetings are in the rulemaking docket.
    Consultations with States, Tribes, and Territories: EPA engaged 
States, Tribes, and Territories early and throughout the rulemaking 
process to promote open communication and solicit input and feedback on 
all aspects of the rule.
    In April of 2008, prior to publication of the proposed rule, the 
Agency sent background information about the rulemaking to all 
Federally-recognized Indian Tribes and invited participation in a 
dedicated GS consultation effort. EPA Regional Indian Coordinators 
(RICs), the National Indian Workgroup (NIWG), the National Tribal 
Caucus (NTC) and the National Tribal Water Council (NTWC) contacts were 
also invited to participate in the consultation. EPA provided 
additional rulemaking updates after publication of the proposal with 
the above-mentioned groups as well as the National Water Program State-
Tribal Climate Change Council (STC3). The Fort Peck Assiniboine and 
Sioux Tribes and the Navajo Nation received UIC program primacy for the 
Class II program (under section 1425 of the SDWA) during the proposal 
period for this rule (73 FR 65556; 73 FR 63639). Therefore, the Agency 
initiated an additional consultation effort with these Tribal co-
regulators post-proposal. Summaries of the Tribal consultation 
conference calls are included in the docket for today's rulemaking.
    To ensure that States were consulted, the Agency also sent 
background information about the rulemaking to States and State 
organizations including the National Governors' Association, National 
Conference of State Legislatures, Council of State Governments, and the 
National League of Cities, among others, and held a dedicated 
conference call on GS for interested State representatives in April 
2008. Additionally, the Agency participated in rulemaking updates, as 
appropriate, during national meetings and conferences, and gave 
presentations to State organizations throughout development of the 
rule. A summary of these efforts is included in the docket for today's 
rulemaking.
    Consultation with the United States Department of Health and Human 
Services (HHS): Pursuant to SDWA section 1421, EPA consulted with the 
U.S. Department of Health and Human Services during the rulemaking 
process. Prior to proposal publication and rule finalization, the 
Agency provided background information to HHS on the purpose and scope 
of the rule. In June of 2010, EPA met with HHS to discuss the GS 
rulemaking process as well as key elements of the proposed rule, the 
Notice of Data Availability and Request for Comment, and the final 
rule. During the June 2010 briefing, HHS participants asked about 
technical criteria for Class VI wells and monitoring technologies 
applicable to GS projects. The Agency addressed questions and comments 
and HHS certified that the EPA satisfied consultation obligations under 
the SDWA. The memo certifying this consultation is available in the 
docket for today's rulemaking.

[[Page 77240]]

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 
CO<INF>2</INF> injection for GS, including:
    <bullet> Site characterization requirements that would apply to 
owners or operators of Class VI wells and require submission of 
extensive geologic, hydrogeologic, and geomechanical information on the 
proposed GS site to ensure that Class VI wells are located in suitable 
formations. EPA also proposed that owners or operators identify 
additional containment/confining zones, if required by the Director, to 
improve USDW protection.
    <bullet> Enhanced AoR and corrective action requirements (e.g., 
plugging abandoned wells) to delineate the AoR for GS projects using 
computational modeling that accounts for the physical and chemical 
properties of all phases of the injected CO<INF>2</INF> stream. EPA 
also proposed that owners or operators periodically reevaluate the AoR 
around the injection well to incorporate monitoring and operational 
data and verify that the CO<INF>2</INF> is moving as predicted within 
the subsurface.
    <bullet> Well construction using materials that are compatible with 
and can withstand contact with CO<INF>2</INF> over the life of the GS 
project.
    <bullet> Multi-faceted monitoring of the CO<INF>2</INF> stream, 
injection pressures, the integrity of the injection well, groundwater 
quality above the confining zone(s), and the position of the 
CO<INF>2</INF> plume and the pressure front throughout injection.
    <bullet> 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.
    <bullet> Financial responsibility requirements to ensure that 
financial resources would be available for corrective action, injection 
well plugging, post-injection site care, and site closure, and 
emergency and remedial response.
    Following publication of the proposed rule, EPA initiated a 120-day 
public comment period, which the Agency extended by 30 days to 
accommodate requests from interested parties. The public comment period 
for the proposed rule closed on December 24, 2008. EPA received 
approximately 400 unique submittals from 190 commenters, including late 
submissions. Commenters represented States; industry (including the oil 
and gas industry, electric utilities, and energy companies); 
environmental groups; and associations (including water organizations 
and CCS associations).
    During the public comment period, the Agency held public hearings 
on the proposed rule in Chicago, IL on September 30, 2008 and in 
Denver, CO on October 2, 2008. The two hearings collectively drew 
approximately 100 people representing non-governmental organizations, 
academia, industry, and other organizations. At the hearings, 29 people 
submitted oral comments. Transcripts of the public hearings are in the 
rulemaking docket (Docket ID Nos. EPA-HQ-OW-2008-0390-0185 and EPA-HQ-
OW-2008-0390-0256).
5. Notice of Data Availability and Request for Comment
    Based on public comments received on the proposed rule, the Agency 
identified several topics on which it needed additional public comment. 
EPA published Federal Requirements Under the Underground Injection 
Control (UIC) Program for Carbon Dioxide (CO<INF>2</INF>) Geologic 
Sequestration (GS) Wells; Notice of Data Availability and Request for 
Comment (74 FR 44802) on August 31, 2009, to describe additional topics 
and request comment.
    The NODA and Request for Comment presented new data and information 
from three DOE-sponsored RCSP projects including: (1) The Escatawpa, 
Mississippi project; (2) the Aneth Field, Paradox Basin project in 
Southeast Utah; and, (3) the Pump Canyon Site project in New Mexico. 
Additional information on these projects and responses to comments 
received on the NODA and Request for Comment are available in the 
docket for this rulemaking.
    The NODA and Request for Comment also provided results of two GS-
related modeling studies conducted by the LBNL. The first study 
(Birkholzer et al., 2008a) focused on the potential for GS to cause 
changes in ground water quality as a result of potential CO<INF>2</INF> 
leakage and subsequent mobilization of trace elements such as arsenic, 
barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium. 
Results from this model simulation suggest that if CO<INF>2</INF> were 
to leak into a shallow aquifer, mobilization of lead and arsenic could 
occur, causing increases in the concentration of these trace elements 
in ground water and potential for drinking water standard exceedances.
    The second study modeled a theoretical scenario of GS in a 
sedimentary basin to demonstrate the potential for basin-scale 
hydrologic impacts of CO<INF>2</INF> storage (Birkholzer et al., 
2008b). Model results indicate that basin-wide pressure influences may 
be large and that predicted pressure changes could move saline water 
upward into overlying aquifers if localized pathways, such as 
conductive faults, are present. This example illustrates the importance 
of basin-scale evaluation of reservoir pressures and far-field 
pressures resulting from CO<INF>2</INF> injection.
    Additional information on LBNL's research and responses to comments 
received on the NODA and Request for Comment are available in the 
docket for this rulemaking.
    The full publications on the LBNL research are also available on 
LBNL's Web site at http://esd.lbl.gov/GCS/projects/CO2/index_CO2.html.
    Lastly, the NODA and Request for Comment presented an alternative 
to address public comments and concerns about the proposed injection 
depth requirements for Class VI wells. Section III.D of today's action 
contains more information on this subject.
    Following publication of the NODA and Request for Comment, EPA 
initiated a 45-day public comment period, which closed on October 15, 
2009. EPA received 67 unique submittals from 64 commenters, many of 
whom commented on the proposed rule. The Agency also held a public 
hearing in Chicago, IL on September 17, 2009. Six people, representing 
the oil and gas industry, electric utilities, water associations, and 
academia attended the hearing. Two attendees submitted oral comments at 
the hearing. A transcript of the public hearing is in the rulemaking 
docket (EPA-HQ-OW-2008-0390-391).

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

    In the preamble to the proposed rule (73 FR 43492), EPA explained 
the need for and merits of using an adaptive approach to regulating 
injection of CO<INF>2</INF> for GS at 40 CFR parts 144 through 146. The 
Agency indicated that this approach would provide regulatory certainty 
to owners or operators, promote consistent permitting approaches, and 
ensure that Class VI permitting Agencies are able to meet current and 
future demand for Class VI permits. The proposal also clarified that, 
as the Agency reviewed public comments, it would continue to evaluate 
ongoing research and demonstration projects and gather other

[[Page 77241]]

relevant information as needed to make refinements to the rulemaking 
process.
    Many commenters strongly supported an adaptive, flexible approach 
and suggested that the Agency initially take a conservative approach in 
developing the UIC-GS requirements, with a provision for periodic 
review of the rule to allow EPA to incorporate operational experience 
as it is gained. These commenters also urged EPA not to wait until the 
completion of DOE's pilot projects before finalizing the GS rule, 
expressing a need for early regulatory certainty.
    Some commenters expressed concerns about an adaptive approach, 
stating that it could lead to regulatory uncertainty because 
modifications could be made after the initial regulations are 
promulgated. One commenter said that GS will not scale-up rapidly, 
leaving ample time to study and assess possible regulatory approaches.
    EPA agrees with commenters who supported an adaptive approach to 
the UIC rulemaking for GS. Additionally, the Agency believes that there 
is a need to have regulations in place during the earliest phases of GS 
deployment. Finalizing today's requirements will allow early Class VI 
wells to be permitted in a manner that addresses the unique 
characteristics of CO<INF>2</INF> injection for GS and allow early 
projects to demonstrate successful confinement of CO<INF>2</INF> in a 
manner that is protective of USDWs. EPA also believes that an adaptive 
approach enables the Agency to make changes to the program as necessary 
to incorporate new research, data, and information about GS and 
associated technologies (e.g., modeling and well construction). This 
new information may increase protectiveness, streamline implementation, 
reduce costs, or otherwise inform the requirements for GS injection of 
CO<INF>2</INF>. The Agency plans, every six years, to review the 
rulemaking and data on GS projects to determine whether the appropriate 
amount and types of information and appropriate documentation are being 
collected, and to determine if modifications to the Class VI UIC 
requirements are appropriate or necessary. This time period is 
consistent with the periodic review of National Primary Drinking Water 
Standards under Section 1412 of SDWA.

G. How does this action affect UIC program implementation?

    Under section 1421(b), the SDWA mandates that EPA develop minimum 
Federal requirements for State UIC primary enforcement responsibility, 
or primacy, to ensure protection of USDWs. In order to implement the 
UIC program, States must apply to EPA for primacy approval. In the 
primacy application, States must demonstrate: (1) State jurisdiction 
over underground injection projects; (2) that their State regulations 
are at least as stringent as those promulgated by EPA (e.g., 
permitting, inspection, operation, monitoring, and recordkeeping 
requirements); and (3) that the State has the necessary administrative, 
civil, and criminal enforcement penalty remedies pursuant to 40 CFR 
145.13 authorities.
    Once an application for primacy is received, the EPA Administrator 
must review and approve or disapprove the State's primacy application. 
EPA may also choose to approve or disapprove part of the application. 
This determination is based on EPA's mandate under the SDWA as 
implemented by UIC regulations established in 40 CFR part 144 through 
146, and must be made by a rulemaking. Most States were authorized with 
full or partial primacy for the UIC program in the early 1980s; 
recently, two Tribes received primacy for the Class II program under 
section 1425 of the SDWA. EPA directly implements the UIC program in 
States that have not applied for primacy and States that have primacy 
for part of the UIC program. A complete list of the primacy agencies in 
each State is available at http://www.epa.gov/safewater/uic/primacy.html.
    EPA may approve primacy for States as authorized by sections 1422 
and 1425 of the SDWA. There are fundamental differences between how 
these two statutory provisions are applied. Under section 1422, States 
must demonstrate that their proposed UIC program meets the statutory 
requirements under section 1421 and that their program contains 
requirements that are at least as stringent as the minimum Federal 
requirements provided for in the UIC regulations to ensure protection 
of USDWs. Alternatively, States seeking primacy under section 1425 have 
the option to demonstrate that their Class II program is an 
``effective'' program to prevent underground injection that endangers 
USDWs. Typically, these States follow the broader elements of a State 
program submission established by EPA in 40 CFR part 145, subpart C. In 
today's final rule, and in accordance with the SDWA section 1422, all 
Class VI State programs must be at least as stringent as the minimum 
Federal requirements finalized in today's rule.
    UIC program implementation: Authority to administer a State UIC 
program may be granted to one or more State agencies. States may choose 
to include in their UIC primacy application a program that is 
administered by multiple agencies. Under 40 CFR 145.23, in order for 
more than one agency to be responsible for administration of the 
program, each agency must have Statewide jurisdiction over the class of 
injection activities for which they are responsible. Some States 
administer their program for all injection well classes through a 
single agency, whereas other States elect to divide the program between 
agencies. For example, in most States, the Class II program is run by 
an oil and gas agency and other well classes are run by a State 
environmental agency (e.g., the Oklahoma Corporation Commission 
oversees Class II wells in the State, and the Oklahoma Department of 
Environmental Quality oversees other well classes). Additionally, 
several States allow their oil and gas agencies to administer their UIC 
program for specific well classes or subclasses provided they meet all 
minimum Federal requirements (e.g., the Railroad Commission of Texas 
oversees Class III brine-mining wells and Class V geothermal wells in 
Texas). EPA believes that retaining this flexibility for States to 
identify the appropriate agency to oversee Class VI wells will address 
commenters' concerns that States should be afforded the opportunity to 
determine which agency should oversee Class VI wells, and recognizes 
the existing expertise of both State oil and gas agencies and deep well 
injection programs, generally overseen by State environmental agencies.
    Proposed approach for Class VI primacy and public comment: In the 
proposed rule, EPA emphasized that States, Territories, and Tribes 
seeking primacy for Class VI wells would be required to demonstrate 
that their regulations are at least as stringent as the proposed 
minimum Federal requirements. Recognizing that some States may wish to 
obtain primacy for only Class VI wells, the Agency requested comment on 
the merits and possible disadvantages of allowing primacy approval for 
Class VI wells independent of other well classes.
    Commenters representing States, industry, various trade 
associations, and electric utilities supported the concept of allowing 
independent primacy for Class VI wells. Commenters asserted that States 
have the best knowledge of regional geology and areas in need of 
special protection, along with necessary pre-existing relationships 
with the regulated community. Commenters also agreed with EPA's 
statement in the proposal that independent primacy would encourage 
States to develop a

[[Page 77242]]

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 Sec.  145.1(i) of today's 
rule, and will accept applications from States for independent primacy 
under section 1422 of the SDWA for managing UIC-GS projects under Class 
VI. EPA believes that States are in the best position to implement UIC-
GS programs, and by allowing for independent Class VI primacy, EPA 
encourages States to take responsibility for implementation of Class VI 
regulations. The Agency's UIC program believes that this may, in turn, 
help provide for a more comprehensive approach to managing GS projects 
by promoting the integration of GS activities under SDWA into a broader 
framework for States managing issues related to CCS that may lie 
outside the scope of the UIC program or other EPA programs. This would 
harness the unique efficiencies States can offer to promote adoption of 
GS technology that incorporates issues in the broader scope of CCS, 
while ensuring that USDWs are protected through the UIC regulatory 
framework. Allowing States to apply only for Class VI primacy will also 
shorten the primacy approval process.
    EPA's willingness to accept independent primacy applications for 
Class VI wells applies only to Class VI well primacy and does not apply 
to any other well class under SDWA section 1422 (i.e., I, III, IV, and 
V). EPA believes that this shift in its longstanding policy of 
discouraging ``partial'' or ``independent'' primacy is warranted to 
encourage States to seek primacy for Class VI wells and allow States to 
address the unique challenges that would otherwise be barriers to 
comprehensive and seamless management of GS projects.
    The Agency recognizes that some States are currently addressing 
off-facility surface access for corrective action and monitoring, pore 
space ownership and trespass issues, and amalgamation of correlative 
rights in depleted reservoirs for GS. Additionally, because GS 
technologies are an important component of CCS, the Agency considers 
the allowance for independent Class VI primacy important and unique to 
this well class. This decision is expected to ensure that the Class VI 
primacy application process does not serve as a barrier to GS and CCS 
deployment. EPA will not consider applications for independent primacy 
for any other injection well class under SDWA section 1422 other than 
Class VI, nor will the Agency accept the return of portions of existing 
1422 programs. EPA will continue to process primacy applications for 
Class II injection wells under the authority of section 1425 of the 
SDWA.
    Today's final rule includes a new subparagraph Sec.  145.1(i) that 
establishes EPA's intention to allow for independent primacy for Class 
VI wells. The Agency is developing implementation materials to provide 
guidance to States applying for Class VI primacy under section 1422 of 
SDWA and to assist UIC Directors evaluating permit applications.
    Effective date of the GS rule and Class VI primacy application and 
approval timeframe: Today's rule, at Sec.  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 
Sec.  145.21(h), States will have 270 days following final promulgation 
of the GS rule September 6, 2011 to submit a complete primacy 
application that meets the requirements of Sec. Sec.  145.22 or 145.32. 
Pursuant to the SDWA, this 270-day timeframe allows States that seek 
primacy for the new Class VI wells a reasonable amount of time to 
develop and submit their application to EPA for approval. EPA will 
assist States in meeting the 270-day deadline by developing 
implementation materials for States and conducting training on the 
process of applying for and receiving primacy for Class VI wells under 
section 1422 of SDWA. EPA will also assist States as they develop GS 
regulations that are the equivalent of minimum Federal requirements and 
plans to use an expedited process for approving primacy.
    Although the SDWA allows the Administrator to extend the date for 
submission of an application for up to 270 additional days for good 
cause, the Agency has determined that it will not provide for an 
extension for States applying for Class VI primacy. Instead, EPA 
believes that, in light of national priorities for promoting climate 
change mitigation strategies and Administration priorities for 
developing and deploying CCS projects in the next few years, it is 
important to have enforceable Class VI regulations in place nationwide 
as soon as possible.
    If a State does not submit a complete application during the 270-
day period, or EPA has not approved a State's Class VI program 
submission, then EPA will establish a Federal UIC Class VI program in 
that State after the 270-day application period closes. This will 
ensure that tailored State- or Federally-enforceable requirements 
applicable to GS projects will be in place nationwide as soon as 
possible after rule finalization. Further, a clear, nationally-
consistent deadline will avoid potential confusion that may arise if 
some States have approved Class VI programs and others do not. EPA will 
publish a list of the States where the Federal Class VI requirements 
have become applicable in the Federal Register and update 40 CFR part 
147. It is important to note that, although the Agency is not accepting 
extension requests, a State may, at any time in the future, apply for 
primacy for the new GS requirements following establishment of a 
Federal Class VI UIC program. If a State receives approval after the 
270-day deadline (for a primacy application submitted either before or 
after the deadline), EPA will publish a subsequent notice of the 
approval as required by the SDWA; at that point, the State, rather than 
EPA, will implement the Class VI program.
    The Agency clarifies that States may not issue Class VI UIC permits 
until their Class VI UIC programs are approved. During the first 270-
days and prior to EPA approval of a Class VI primacy application, 
States without existing SDWA section 1422 primacy programs must direct 
all Class VI GS permit applications to the appropriate EPA Region. EPA 
Regions will issue permits using existing authorities and well 
classifications (e.g., Class I or Class V), as appropriate.
    States with existing UIC primacy for all non-Class VI well classes 
under section 1422 that receive Class VI permit applications within the 
first 270

[[Page 77243]]

days after promulgation of the final rule may consider using existing 
authorities (e.g., Class I or Class V), as appropriate, to issue 
permits for CO<INF>2</INF> 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 Sec.  146.81(c), with minimal additional 
effort on the part of the owner or operator or the Director.
    After the 270-day deadline, and until a State has an approved Class 
VI program, EPA will establish and implement a Class VI program. 
Therefore, all permit applications in States without Class VI programs 
must be directed to the appropriate EPA Region in order for a Class VI 
permit to be issued. In States where EPA directly implements the Class 
VI program, Class I permits for CO<INF>2</INF> 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 Sec. Sec.  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 
Sec.  145.23(f) includes new language describing the requirements for 
Class VI State program descriptions. Specifically, Sec.  145.23(f)(1) 
requires States to include a schedule for issuing Class VI permits for 
wells within the State that require them within two years after 
receiving program approval from EPA, and Sec.  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 Sec.  145.23(f)(4) requires the Director 
of Class VI programs approved before December 10, 2011, to provide a 
description of the process for notifying owners or operators of any 
Class I wells previously permitted for the purpose of geologic 
sequestration or Class V experimental technology wells no longer being 
used for experimental purposes that will continue injection of carbon 
dioxide for the purpose of GS that they must apply for a Class VI 
permit pursuant to requirements at Sec.  146.81(c) within one year of 
December 10, 2011. Sec.  145.23(f)(4) also requires the Director of a 
Class VI Program approved after December 10, 2011, to provide a 
description of the process for notifying owners or operators of any 
Class I wells previously permitted for the purpose of geologic 
sequestration or Class V experimental technology wells no longer being 
used for experimental purposes that will continue injection of carbon 
dioxide for the purpose of GS or Class VI wells permitted by EPA that 
they must apply to the State program for a Class VI permit pursuant to 
requirements at Sec.  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 
Sec.  145.23 may help ensure expeditious implementation of Class VI 
requirements across the country.
    Today's rule, at Sec.  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 Sec.  145.23(f)(9), the 
final rule also requires States receiving Class VI program approval to 
incorporate information related to any EPA approved exemptions 
expanding the areal extent of an existing Class II EOR/EGR aquifer 
exemption for Class VI injection. This requirement complements aquifer 
exemption requirements promulgated under today's rule and ensures that 
State programs incorporate information regarding the specific location 
(and any associated supporting data) into their program descriptions.
    The Agency plans to review these requirements as part of the 
adaptive rulemaking approach to ensure that the tailored requirements 
are appropriate to ensure USDW protection from endangerment.

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

    Today's rulemaking establishes a new class of injection well, Class 
VI, for GS projects because CO<INF>2</INF> 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.
    <bullet> 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.
    <bullet> Class II wells inject fluids (e.g., CO<INF>2</INF>; brine) 
in connection with conventional

[[Page 77244]]

oil or natural gas production, enhanced oil and gas production, and the 
storage of hydrocarbons that are liquid at standard temperature and 
pressure.
    <bullet> Class III wells inject fluids associated with the 
extraction of minerals, including the mining of sulfur and solution 
mining of minerals (e.g., uranium).
    <bullet> 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.
    <bullet> Class V includes all injection wells that are not included 
in Classes I-IV. In general, Class V wells inject non-hazardous fluids 
into or above USDWs; however, there are some deep Class V wells that 
are used to inject below USDWs. This well class includes Class V 
experimental technology wells including those permitted as GS pilot 
projects.
    The Agency acknowledges that owners or operators of wells regulated 
under existing well classifications may want to change the purpose of 
their injection activity. The following sections describe the 
applicability of today's rule to owners or operators of existing wells 
and considerations for Directors evaluating existing wells that may be 
re-permitted as Class VI wells.
    Class I wells: Wells previously permitted as Class I wells for GS, 
including wells permitted prior to rule promulgation and wells 
permitted during the 270-day period after rule promulgation, must apply 
for Class VI permits within one year of promulgation by December 10, 
2011, pursuant to requirements at Sec.  146.81(c). The Agency 
anticipates that permit applications (e.g., Class I or Class V) 
developed for CO<INF>2</INF> GS following publication of today's rule 
will follow the Class VI requirements and be designed to facilitate 
efficient re-permitting as Class VI wells. Such forethought will allow 
new Class VI permits to be issued with minimal additional effort on the 
part of the owner or operator and the Director. Additional information 
on Class V experimental technology wells is discussed in this section. 
For additional information on permitting authorities and UIC program 
implementation, see section II.G.
    Class II CO<INF>2</INF> injection wells designated for enhanced 
recovery: Enhanced oil recovery (EOR) and enhanced gas recovery (EGR) 
technologies, collectively referred to as enhanced recovery (ER), are 
used in oil and gas reservoirs to increase production. Injection of 
CO<INF>2</INF> 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.
    CO<INF>2</INF> currently injected for ER in the U.S. comes from 
both natural and anthropogenic sources, which provide 79 percent and 21 
percent, respectively, of CO<INF>2</INF> supply (DOE NETL, 2008). 
Natural CO<INF>2</INF> sources consist of geologic domes in Colorado, 
New Mexico, and Mississippi. Anthropogenic sources of CO<INF>2</INF> 
supplied for ER today include natural gas processing, ammonia and 
fertilizer production, and coal gasification facilities.
    Historically, CO<INF>2</INF> purchases comprise about 33 to 68 
percent of the cost of a CO<INF>2</INF>-ER project (EPRI, 1999). For 
this reason, CO<INF>2</INF> injection volumes are carefully tracked at 
ER sites. CO<INF>2</INF> recovered from production wells during ER is 
recycled (i.e., separated and re-injected), and at the conclusion of an 
ER project as much CO<INF>2</INF> as is feasible is recovered and 
transported to other ER facilities for re-use. However, a certain 
amount of CO<INF>2</INF> remains underground. Current Class II ER 
requirements do not require tracking and monitoring of the injectate; 
therefore, the migration and fate of the unrecovered CO<INF>2</INF> is 
not documented.
    As of 2008, there were 105 CO<INF>2</INF>-EOR projects within the 
US (Oil and Gas Journal, 2008). The majority (58) of these projects are 
located in Texas, and the remaining projects are located in 
Mississippi, Wyoming, Michigan, Oklahoma, New Mexico, Utah, Louisiana, 
Kansas, and Colorado. CO<INF>2</INF>-EOR projects recovered 323,000 
barrels of oil per day in 2008, 6.5 percent of total domestic oil 
production. A total of 6,121 CO<INF>2</INF> injection wells among 105 
projects were used to inject 51 million metric tons of CO<INF>2</INF> 
(Oil and Gas Journal, 2008; EIA, 2009; DOE NETL, 2008). Compared to 
CO<INF>2</INF>-EOR, CO<INF>2</INF>-EGR remains largely in the 
development stage (e.g., Oldenburg et al., 2001).
    Future deployment of CCS may fundamentally alter CO<INF>2</INF>-ER 
in the U.S. DOE anticipates that many early GS projects will be sited 
in depleted or active oil and gas reservoirs because the reservoirs 
have been previously characterized for hydrocarbon recovery and may 
have suitable infrastructure (e.g., wells, pipelines, etc.) in place. 
Additionally, oil and gas fields now considered to be ``depleted'' may 
resume operation because of increased availability and decreased cost 
of anthropogenic CO<INF>2</INF>.
    EPA believes that if the business model for ER changes to focus on 
maximizing CO<INF>2</INF> injection volumes and permanent storage, then 
the risk of endangerment to USDWs is likely to increase. This is 
because reservoir pressure within the injection zone will increase as 
CO<INF>2</INF> injection volumes increase. Elevated reservoir pressure 
is a significant risk driver at GS sites, as it may cause unintended 
fluid movement and leakage into USDWs that may cause endangerment. 
Additionally, increasing reservoir pressure within the injection zone 
as a result of GS will stress the primary confining zone (i.e., 
geologic caprock) and well plugs to a greater degree than during 
traditional ER (e.g., Klusman, 2003). Finally, active and abandoned 
well bores are much more numerous in oil and gas fields than other 
potential GS sites, and under certain circumstances could serve as 
potential leakage pathways. For example, in typical productive oil and 
gas fields, a CO<INF>2</INF> plume with a radius of about 5 km (3.1 
miles) may come into contact with several hundred producing or 
abandoned wells (Celia et al., 2004).
    EPA proposed that the Class VI GS requirements would not apply to 
Class II ER wells as long as any oil or gas production is occurring, 
but would apply only after the oil and gas reservoir is depleted. Under 
the proposed approach, Class II wells could be used for the injection 
of CO<INF>2</INF>, as long as oil production is simultaneously 
occurring from the same formation. The preamble to the proposal sought 
comment on the merits of this approach.
    Some commenters agreed with the proposed approach while others 
suggested that the approach did not adequately address risks posed to 
USDWs by injection operations transitioning from production to long-
term storage of CO<INF>2</INF>. A majority of commenters requested that 
EPA develop specific criteria for this transition.
    Consistent with these comments, EPA determined that owners or 
operators of wells injecting CO<INF>2</INF> in oil and gas reservoirs 
for GS where there is an increased risk to USDWs compared to 
traditional Class II operations using CO<INF>2</INF> should be required 
to obtain a Class VI permit, with some special consideration for the 
fact that they are transitioning from a well not originally designed to 
meet Class VI requirements. Additionally, EPA recognizes that further 
clarification is needed to sufficiently characterize the factors that 
lead to increased risks and warrant conversion from Class II to Class 
VI.
    Therefore, today's rule clarifies that Class VI requirements apply 
to any CO<INF>2</INF> injection project (regardless of formation

[[Page 77245]]

type) when there is an increased risk to USDWs as compared to 
traditional Class II operations using CO<INF>2</INF>. Traditional ER 
projects are not impacted by this rulemaking and will continue 
operating under Class II permitting requirements. EPA recognizes that 
there may be some CO<INF>2</INF> 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 Sec.  144.19 and include: (1) Increase in reservoir 
pressure within the injection zone; (2) increase in CO<INF>2</INF> 
injection rates; (3) decrease in reservoir production rates; (4) the 
distance between the injection zone and USDWs; (5) the suitability of 
the Class II AoR delineation; (6) the quality of abandoned well plugs 
within the AoR; (7) the owner's or operator's plan for recovery of 
CO<INF>2</INF> at the cessation of injection; (8) the source and 
properties of injected CO<INF>2</INF>; and (9) any additional site-
specific factors as determined by the Director. Any single factor may 
not necessarily result in a determination that a Class II owner or 
operator must apply for a Class VI permit; rather, all factors must be 
evaluated comprehensively to inform a Director's (or owners' or 
operators') decision. The Agency is also developing guidance to support 
Directors and owners or operators in evaluating these factors and 
making the determination on whether to apply Class VI requirements.
    Owners and operators of Class II wells that are injecting carbon 
dioxide for the primary purpose of long-term storage into an oil and 
gas reservoir must apply for and obtain a Class VI permit where there 
is an increased risk to USDWs compared to traditional Class II 
operations using CO<INF>2</INF>. 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 (Sec.  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 Sec.  146.81(c), in order to facilitate the transition from Class II 
to Class VI wells without undue regulatory burden. As outlined in 
section II.G, today's rule clarifies that State oil and gas agencies 
that oversee the Class II program in many States may assume regulatory 
authority for Class VI by either a memorandum of understanding with the 
Class VI primacy agency, or by obtaining primacy for the entire Class 
VI program as long as it is identified in the State's program 
description under Sec.  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 Sec.  144.19 adequately address risks 
to USDWs and whether additional or amended Federal regulations or other 
actions are warranted for transitioning wells from ER to long-term 
storage of CO<INF>2</INF>.
    Class V Experimental Technology Wells: Prior to finalization of the 
Class VI regulation, a number of CO<INF>2</INF> injection projects were 
permitted as Class V experimental technology wells for the purpose of 
testing GS technology in the U.S. Wells permitted under this 
classification are designed for the purpose of testing new technology 
that is of an experimental nature. EPA understands that some of the 
wells previously permitted as Class V experimental technology wells may 
no longer be used for this purpose. GS wells that are not being used 
for experimental purposes must be re-permitted as Class VI wells and 
will be subject to today's requirements.
    In the preamble to the proposed rule, EPA described UIC Program 
Guidance <greek-i>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 Sec.  146.81(c), requires 
owners or operators of Class V experimental technology wells no longer 
being used for experimental purposes (e.g., wells that will continue 
injection of CO<INF>2</INF> 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 Sec.  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 Sec.  144.15. 
Experimental projects are those whose primary purpose is to test new, 
unproven technologies. EPA does not consider it appropriate to permit 
CO<INF>2</INF> injection wells that are testing the injectivity or 
appropriateness of an individual formation (e.g., as a prelude to a 
commercial-scale operation) as Class V experimental technology wells. 
Such wells should be permitted as Class VI wells.
    Other commenters suggested that owners or operators of wells 
injecting CO<INF>2</INF> 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

[[Page 77246]]

projects testing GS technology will continue. EPA anticipates that 
these projects will be small-scale and involve limited CO<INF>2</INF> 
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 (Sec.  144.15).
    The Agency is preparing additional guidance for owners or operators 
and Directors regarding the use of the Class V experimental technology 
well classification for GS following promulgation of today's rule. The 
guidance will assist owners and operators and Directors in determining 
what constitutes a Class V experimental technology well for the 
purposes of testing GS technology.
    Grandfathering for Class I, Class II and Class V Experimental 
Technology Wells: Recognizing that owners or operators of existing 
Class I, Class II, and Class V experimental technology wells may seek 
to change the purpose of their injection well, EPA proposed to give the 
Director discretion to carry over or ``grandfather'' the construction 
requirements (e.g., permanent, cemented well components) provided he or 
she is able to make a determination that these wells would not endanger 
USDWs. EPA sought comment on this approach and how the proposed 
grandfathering provisions for existing wells may affect compliance with 
Class VI construction requirements.
    Nearly all industry commenters favored grandfathering of Class I, 
II, and V well construction requirements for GS, indicating that most 
wells are built to appropriate specifications and would have sufficient 
mechanical integrity for GS in order to protect USDWs from 
endangerment. These commenters cited oil and gas industry experience 
with CO<INF>2</INF> 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 Sec.  146.86 
may actually compromise the integrity of those wells. One commenter 
also mentioned that pre-existing wells, including wells approved for 
sequestration as Class I and/or Class II wells, have not been 
constructed to the same standards. These existing wells penetrating the 
injection zone may, therefore, become potential threats to USDWs.
    In response, EPA recognizes that the oil and gas industry has 
decades of experience injecting CO<INF>2</INF> for ER and that many 
Class V experimental technology wells, including those used in the 
RCSP's projects, are specifically designed for injection of 
CO<INF>2</INF> and are being constructed to Class I non-hazardous waste 
well specifications. In today's final rule, at Sec.  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 Sec.  
146.86(a) and ensure protection of USDWs from endangerment in lieu of 
requirements at Sec.  146.86(b) and Sec.  146.87(a). Based on the owner 
or operator's demonstration, the Director will determine if a well is 
appropriately constructed for GS. If the Director determines that the 
construction is appropriate for GS, the well will be re-permitted as a 
Class VI well and must meet the operational, testing and monitoring, 
reporting, injection well plugging, and PISC and site closure 
requirements in subpart H of part 146. If an owner or operator seeking 
to grandfather an existing Class I, II, or V well to a Class VI well 
cannot make this demonstration, then grandfathering of the constructed 
well and re-permitting as a Class VI well is prohibited.

III. What is EPA's final regulatory approach?

    Today's rule creates a new class of injection well (Class VI) under 
the existing UIC program with new minimum Federal requirements that 
protect USDWs from endangerment during underground injection of 
CO<INF>2</INF> for the purpose of GS. Today's action includes 
requirements for the permitting, siting, construction, operation, 
financial responsibility, testing and monitoring, PISC, and site 
closure of Class VI injection wells that address the pathways through 
which USDWs may be endangered. These requirements are tailored from 
existing UIC program components to ensure that they are appropriate for 
the unique nature of injecting large volumes of CO<INF>2</INF> 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.
    <bullet> 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.
    <bullet> 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, Sec.  145.21 of today's rule 
allows States to gain primacy for Class VI wells independent of other 
well classes. See section II.G.
    <bullet> Explanation of the considerations for permitting wells 
that are transitioning from Class II to Class VI. To clarify the point 
at which the purpose of CO<INF>2</INF> injection transitions from ER 
(i.e., a Class II well) to long-term storage (i.e., Class VI) and the 
risk posed to USDWs increases and is greater than traditional ER 
projects injecting CO<INF>2</INF>, today's rule at Sec.  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.
    <bullet> 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 
Sec.  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 (Sec.  144.7(d)). See 
section III.D.
    <bullet> 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 (Sec.  146.82(a)) and information that must be submitted 
before well operation is authorized (Sec.  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

[[Page 77247]]

time the operator develops their initial permit application, See 
section III.A.
    <bullet> 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 (Sec.  146.84(e), Sec.  146.90(j), and Sec.  146.94(d)). 
Any significant changes to the plans require a permit modification 
(under Sec.  144.39(a)(5)). See Sections III.F and III.K.
    <bullet> Increasing the frequency of AoR reevaluations. To address 
concerns about the inherent uncertainties in modeling CO<INF>2</INF> 
movement, the emerging nature of GS technology, and the importance of 
targeting monitoring activities where risk to USDWs is greatest, 
today's rule at Sec.  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.
    <bullet> 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 Sec.  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.
    <bullet> Revisions to the GS site monitoring and plume tracking 
requirements to ensure that the most appropriate methods are used to 
identify potential risks to USDWs posed by injection activities, verify 
predictions of CO<INF>2</INF> plume movement, provide inputs for 
modeling, identify needed corrective actions, and target other 
monitoring activities. Today's rule, at Sec.  146.90(g), requires Class 
VI well owners or operators to use direct methods to monitor for 
pressure changes in the injection zone and to supplement these direct 
methods with indirect, geophysical techniques unless the Director 
determines, based on site-specific geology, that such methods are not 
appropriate. See section III.F.
    EPA believes that these changes will result in a clearer, more 
protective approach to permitting GS projects across the U.S. while 
still allowing for consideration of site specific variability.
    In addition to protecting USDWs, today's rule provides a regulatory 
framework to promote consistent approaches to permitting GS projects 
across the U.S. and supports the development of a key climate change 
mitigation technology.
    Today's final GS rule contains tailored requirements for geologic 
siting; AoR and corrective action; construction; operation; monitoring 
and MIT; recordkeeping and reporting; well plugging, PISC, and site 
closure; financial responsibility; emergency and remedial response; 
public involvement; and permit duration of Class VI wells.
    To develop today's final regulatory approach, EPA considered public 
comments submitted in response to the proposed rule and the NODA and 
Request for Comment. Sections III.A through L focus on the aspects of 
the GS regulation that are tailored to the unique nature of GS and 
highlight the changes between the proposed and final GS rule. 
Additional background information is available in the preamble, NODA 
and Request for Comment, and docket for this rulemaking.

A. Site Characterization

    Today's final action requires owners or operators of Class VI wells 
to perform a detailed assessment of the geologic, hydrogeologic, 
geochemical, and geomechanical properties of the proposed GS site to 
ensure that GS wells are sited in appropriate locations and inject into 
suitable formations. Class VI well owners or operators must also 
identify additional confining zones, if required by the Director, to 
increase USDW protection.
    Site characterization is a fundamental component of the UIC 
program. Owners or operators must identify the presence of suitable 
geologic characteristics at a site to ensure the protection of USDWs 
from endangerment associated with injection activities. Existing UIC 
regulations for siting injection wells include requirements to identify 
geologic formations suitable to receive injected fluids and confine 
those fluids such that they are isolated in order to ensure protection 
of USDWs from endangerment. Today's rule similarly requires the owner 
or operator to perform a detailed assessment to evaluate the presence 
and adequacy of the various geologic features necessary to receive and 
confine large volumes of injected CO<INF>2</INF> so that the injection 
activities will not endanger USDWs. Today's requirements for Class VI 
wells are based extensively on the long-standing site characterization 
requirements of the UIC program, and are tailored to address the unique 
nature of GS. Specifically, Sec.  146.83 of today's rule sets forth the 
criteria for a GS site that is geologically suitable to receive and 
confine the injected CO<INF>2</INF>, while Sec.  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 Sec.  146.83.
    Today's rule at Sec.  146.83 retains the minimum criteria for 
siting as proposed. Owners or operators of Class VI wells must provide 
extensive geologic data to demonstrate to the Director that wells will 
be sited in areas with a suitable geologic system comprised of a 
sufficient injection zone and a confining zone free of transmissive 
faults or fractures to ensure USDW protection. In addition, the Agency 
proposed that owners or operators must, at the Director's discretion, 
identify and characterize additional (secondary) confinement zones that 
will impede vertical fluid movement. EPA sought comment on the merits 
of identifying these additional zones, and received many comments on 
this topic.
    The majority of commenters who commented on the requirement to 
identify additional zones at the Director's discretion disagreed with 
the proposed approach, saying that the requirement is unnecessary if 
the injection zone and confining zones were competent, and believing it 
would reduce the number of GS storage site opportunities. EPA disagrees 
with the commenters' assertion that secondary confinement and 
containment zones should not be required under the final rule and 
received no data or information to support commenters' assertion that 
characterizing secondary confining zones is technically infeasible. 
Therefore, EPA is retaining the requirement that owners or operators 
must, at the Director's discretion, identify and characterize 
additional confining zones. In certain geologic settings, these zones 
may be appropriate to ensure USDW protection, impede vertical fluid 
movement, allow for pressure dissipation, and provide additional 
opportunities for monitoring, mitigation and remediation (Sec.  
146.83(b)).
    Today's rule at Sec.  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

[[Page 77248]]

lateral limits of all USDWs within the AoR. The Agency anticipates that 
owners or operators will use existing wells within the AoR or construct 
stratigraphic test wells for purposes of data collection; such wells 
may be subsequently converted to monitoring wells. Site 
characterization identifies potential risks and eliminates unacceptable 
sites, e.g., sites with potential seismic risk or sites that contain 
transmissive faults or fractures. Data and information collected during 
site characterization also inform the development of construction and 
operating plans, provide inputs for AoR delineation models, and 
establish baseline information to which geochemical, geophysical, and 
hydrogeologic site monitoring data collected over the life of the 
injection project can be compared.
    Today's rule also requires owners or operators to submit, with 
their permit applications, a series of comprehensive site-specific 
plans: An AoR and corrective action plan, a monitoring and testing 
plan, an injection well plugging plan, a PISC and site closure plan, 
and an emergency and remedial response plan. This requirement for a 
comprehensive series of site-specific plans is new to the UIC program. 
The Director will evaluate all of the plans in the context of the 
geologic data, proposed construction information, and proposed 
operating data submitted as part of the site characterization process, 
to ensure that planned activities at the facility are appropriate to 
the site-specific circumstances and address all risks of endangerment 
to USDWs.
    EPA sought comment on the proposed submissions required for permit 
applications, and received many comments indicating that not all of the 
information listed in the proposed rule at Sec.  146.82 will be 
available at the time the operator develops their initial permit 
application. In response to comments, EPA revised Sec.  146.82 so that 
the final regulation specifies separate requirements for information to 
be submitted with the permit application (Sec.  146.82(a)) and 
information that must be submitted before well operation is authorized 
(Sec.  146.82(c)).
    Today's final rule includes requirements at Sec.  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 Sec.  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 (Sec.  146.94)). These 
requirements respond to comments received regarding the anticipated 
large AoRs and injection volumes for GS and the importance of ensuring 
trans-boundary coordination across the U.S. The Agency encourages 
transparency in the permitting process and anticipates that State-
State/State-Tribal communication on GS permitting will facilitate 
information sharing and encourage safe, protective projects.
    The final GS permitting requirements provided in today's rule in 
conjunction with the minimum siting requirements at Sec.  146.83 enable 
flexibility and the discretion of the permitting authority when 
appropriate, while ensuring USDW protection. This flexibility and 
permitting authority discretion serves to maximize efficiencies for 
owners or operators and permitting agencies. The rule enables owners or 
operators to choose from the variety of technologies and methods 
appropriate to their site-specific conditions. At the same time, the 
rule provides the foundation for national consistency in permitting of 
GS projects. To promote national consistency, the Agency is developing 
guidance to support comprehensive site characterization required under 
today's rule.

B. Area of Review (AoR) and Corrective Action

    Today's rule at Sec.  146.84 enhances the existing UIC requirements 
for AoR and corrective action to require computational modeling of the 
AoR for GS projects that accounts for the physical and chemical 
properties of the injected CO<INF>2</INF> and is based on available 
site characterization, monitoring, and operational data. Owners or 
operators must periodically reevaluate the AoR to incorporate 
monitoring and operational data and verify that the CO<INF>2</INF> is 
moving as predicted within the subsurface.
    AoR modeling and reevaluation are important components of the 
overall proposed strategy to track the CO<INF>2</INF> plume and 
pressure front through an iterative process of site characterization, 
modeling, and monitoring at GS sites. This approach addresses the 
unique and complex movement of CO<INF>2</INF> at GS sites.
1. AoR Requirements
    Under the UIC program, EPA established an evaluative process to 
determine that there are no features near an injection well (such as 
faults, fractures or artificial penetrations) where injected fluid 
could move into a USDW or displace native fluids into USDWs resulting 
in endangerment to USDWs. Existing UIC regulations require that the 
owners or operators define the AoR, within which they must identify 
artificial penetrations (regardless of property ownership) and 
determine whether they have been properly completed or plugged. The AoR 
determination is integral to assessing geologic site suitability 
because it requires the delineation of the expected extent of the 
carbon dioxide plume and associated pressure front and identification 
and evaluation of any penetrations that could result in the 
endangerment of USDWs. For existing injection well classes (I through 
V), the AoR is defined either by a fixed radius around the injection 
well or by a simple radial calculation (40 CFR 146.6).
    AoR and corrective action plan: EPA proposed that owners or 
operators of Class VI wells prepare, maintain, and comply with a plan 
to delineate the AoR for a proposed GS project, periodically reevaluate 
the delineation, and perform corrective action that meets the 
requirements of this section and is acceptable to the Director. 
Commenters supported the proposed requirement for an AoR and corrective 
action plan, particularly advocating updates that ensure that 
facilities are being properly managed to address changing circumstances 
(e.g., addition of monitoring wells or operational changes). The Agency 
is developing guidance that describes the content of project plans 
required in the GS rule, including the AoR and corrective action plan.
    Today's final rule retains the requirement for owners or operators 
to develop and implement an AoR and corrective action plan; the 
approved plan will be incorporated into the Class VI permit and will be 
considered permit conditions; failure to follow the plan will result in 
a permit violation under SDWA section 1423. Owners or operators must 
also review the AoR and corrective action plan following the most 
recent AoR reevaluation and submit an amended plan, or demonstrate to 
the Director that no amendment to the AoR and corrective action plan is 
needed (Sec.  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

[[Page 77249]]

confirms that the plan is appropriate as written. The plan review 
process also supports development and review of effective testing and 
monitoring programs. Additional information on updates to the AoR and 
corrective action plan is discussed in subsequent sections.
    AoR definition: In the proposed rule, EPA defined the AoR for a GS 
project as ``the region surrounding the GS project that may be impacted 
by the injection activity,'' and stated that ``the AoR is based on 
computational modeling that accounts for the physical and chemical 
properties of all phases of the injected CO<INF>2</INF> stream.'' 
Several commenters stated that the proposed AoR definition for Class VI 
wells was vague and open to broad interpretation, which could lead to 
overly large or small AoRs. Other commenters believed that specific 
CO<INF>2</INF> phases and areas of quantitative measures of elevated 
pressure should be included in the definition.
    EPA evaluated all comments on the AoR definition, and determined 
that a performance-based definition provides sufficient instruction 
regarding the region that should be included within the AoR. However, 
to provide additional clarity, EPA modified the Class VI AoR definition 
for today's final rulemaking. The AoR is defined in the final rule as, 
``the region surrounding the geologic sequestration project where USDWs 
may be endangered by the injection activity. The AoR is delineated 
using computational modeling that accounts for the physical and 
chemical properties of all phases of the injected CO<INF>2</INF> stream 
and displaced fluids and is based on available site characterization, 
monitoring, and operational data as set forth in Sec.  146.84.'' The 
Agency is developing guidance on AoR and corrective action to support 
AoR delineation (i.e., including regions of the CO<INF>2</INF> plume 
and pressure front).
    Use and applicability of computational models: EPA proposed that 
the AoR for Class VI wells be determined using sophisticated 
computational modeling that accounts for multiphase flow and the 
buoyancy of CO<INF>2</INF>, 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 Sec.  
146.84(a). The Agency is developing guidance on AoR and corrective 
action to support the use of computational modeling for AoR 
delineation. Available data from pilot projects and research studies 
(e.g., Schnaar and Digiulio, 2009) support today's final approach of 
requiring the use of computational models to delineate the AoR for GS 
sites.
    Comments were submitted both in support of and against allowing the 
use of proprietary models. Several commenters who supported allowing 
the use of proprietary models said that allowing the use of these 
models will save costs and increase efficiency, as many existing 
CO<INF>2</INF> injection projects currently rely on proprietary models. 
However, commenters suggested that the Director be given access to the 
model in order to fully evaluate results and modeling assumptions. 
Commenters that opposed the use of proprietary models did not believe 
that such models are sufficiently transparent, and believed that the 
Director would not be able to replicate the results.
    EPA's final approach allows the use of proprietary models at the 
discretion of the Director. EPA does not agree with commenters who 
believe that the use of proprietary models will prohibit full 
evaluation of model results and assumptions. Several available 
proprietary models meet minimum Federal requirements for use in AoR 
delineation and their use has been documented in peer-reviewed research 
studies. Class VI well owners or operators, including those using 
proprietary AoR delineation models, are required to disclose the code 
assumptions, relevant equations, and scientific basis to the 
satisfaction of the Director. To ensure that all predictive models used 
for AoR delineation are meeting the Agency's intent, EPA will collect 
and review project data on models used in early GS projects as part of 
its adaptive rulemaking approach. See section II.F.
    AoR reevaluation: EPA proposed that the AoR delineation be 
reevaluated periodically over the life of the project in order to 
incorporate CO<INF>2</INF> monitoring data into models to ensure 
protection of USDWs from endangerment. Under the proposed approach, AoR 
reevaluation would occur at a minimum of every 10 years during 
CO<INF>2</INF> injection, or when monitoring data and modeling 
predictions differ significantly. EPA sought comment on the requirement 
for reevaluation every 10 years and what conditions would merit 
reevaluation of the AoR.
    The majority of commenters agreed that AoR reevaluations are 
necessary, citing the large volumes of CO<INF>2</INF> that may be 
injected, the uncertainty of CO<INF>2</INF> movement in the subsurface, 
the need to incorporate monitoring data, and the lack of experience in 
tracking large volumes of CO<INF>2</INF>. EPA agrees with commenters 
who supported the proposed approach for periodic AoR reevaluation. EPA 
believes that in order to sufficiently protect USDWs from endangerment, 
the CO<INF>2</INF> plume and pressure front should be tracked over the 
lifetime of the project using an iterative approach of site 
characterization, modeling, and monitoring. Periodic AoR reevaluation, 
as required in today's final action, is an integral component of this 
approach. EPA believes that the AoR reevaluation is an efficient use of 
resources and notes that if the CO<INF>2</INF> plume and pressure front 
are moving as predicted, the burden of the AoR reevaluation requirement 
will be minimal. In cases where the observed monitoring data agree with 
model predictions, an AoR reevaluation may simply consist of a 
demonstration to the Director that monitoring data validate modeled 
predictions.
    Several commenters supported the proposed reevaluation timeframe of 
a minimum of 10 years or when monitoring and modeling data differ. 
However, many commenters believed that 10 years was too infrequent and 
suggested more frequent reevaluations or basing the reevaluation 
timeframe on a performance standard, given the potential risks posed by 
these projects to USDWs and the general uncertainty related to 
CO<INF>2</INF> movement at GS projects. Based on consideration of 
public comments, EPA agrees that reevaluations of the AoR every 10 
years may not be sufficient, and today's final approach requires an AoR 
reevaluation at a minimum of once every five years, or when monitoring 
data and modeling predictions differ significantly. EPA believes that 
this revised frequency addresses commenters' concerns about the 
inherent uncertainties in modeling CO<INF>2</INF> movement, the 
emerging nature of GS technology, and the importance of targeting 
monitoring activities where

[[Page 77250]]

risk of endangerment to USDWs is greatest.
2. Corrective Action Requirements
    EPA proposed that owners or operators of Class VI wells identify 
and evaluate all artificial penetrations within the AoR. Based on this 
review, owners or operators, in consultation with the Director, would 
identify the wells that need corrective action to prevent the movement 
of CO<INF>2</INF> or other fluids into or between USDWs. Owners or 
operators would perform corrective action to address deficiencies in 
any wells (regardless of ownership) that are identified as potential 
conduits for fluid movement into USDWs. This inventory and review 
process is similar to what is required of Class I and Class II 
injection well owners or operators. The proposal did not prescribe any 
specific methods or cements that should be used for corrective action, 
but stated that the methods used must be appropriate for CO<INF>2</INF> 
injection and compatible with all fluids.
    Phased corrective action: Due to the anticipated large size of the 
AoR for Class VI wells, EPA proposed allowing owners or operators to 
conduct corrective action on a phased basis during the lifetime of the 
project, at the discretion of the Director. In these cases, corrective 
action would not need to be conducted throughout the entire AoR prior 
to injection. Corrective action would only be necessary in areas near 
the injection well with a high certainty of CO<INF>2</INF> exposure 
during the first years of injection as informed by site-
characterization data and model predictions. Artificial penetrations in 
areas farther from the injection well would be addressed after 
injection has commenced, but prior to CO<INF>2</INF> plume and pressure 
front movement into that area. The proposal sought comment on allowing 
for phased corrective action at the discretion of the Director.
    The majority of commenters agreed with EPA's proposed approach of 
allowing phased corrective action at the Director's discretion. Most 
commenters believed that phased corrective action is a practical and 
cost effective approach. However, some commenters argued that phased 
corrective action should be allowed at all sites and not left to 
Director's discretion. Others argued that specific timeframes (e.g., 
two to five years) for corrective action should be mandated to ensure 
that wells are addressed prior to plume movement into that area. 
Several State commenters disagreed with EPA's proposal to allow phased 
corrective action and believed that all corrective action should be 
completed prior to injection.
    EPA agrees with commenters who supported allowing for phased 
corrective action at the discretion of the Director, and retains this 
provision in today's final regulation at Sec.  146.84(d). Phased 
corrective action may provide many benefits to a project including 
spreading corrective action costs throughout the life of a GS project, 
avoiding delays in project start-up, allowing for use of future, 
improved corrective action techniques, and addressing unanticipated 
changes in the movement of the CO<INF>2</INF> plume or pressure front. 
Given the wide range of conditions and site-specific considerations 
unique to GS sites, Director's discretion is appropriate as Directors 
are in the best position to make decisions about the appropriateness of 
phased corrective action.
    EPA agrees with commenters that corrective action on wells should 
be completed in advance of the anticipated arrival of the 
CO<INF>2</INF> plume or pressure front. However, it is not appropriate 
to set a specific timeframe for completing corrective action because 
CO<INF>2</INF> 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 Sec.  146.86) for the 
design and construction of Class VI wells using materials that can 
withstand contact with CO<INF>2</INF> over the life of the GS project 
in order to prevent movement of fluids into USDWs.
    Proper construction of injection wells provides multiple layers of 
protection to ensure the prevention of fluid movement into USDWs. 
Today's final approach is based on existing construction requirements 
for surface casing, long-string casing, and tubing and packer for Class 
I hazardous waste injection wells, with modifications to address the 
unique physical characteristics of CO<INF>2</INF>, including its 
buoyancy relative to other fluids in the subsurface and the potential 
presence of impurities in captured CO<INF>2</INF>. In addition to 
protecting USDWs, today's comprehensive construction requirements 
respond to concerns about GS project safety and potential impacts on 
USDWs.
    Surface and long-string casing requirements: EPA proposed that 
surface casing for a Class VI well be set through the base of the 
lowermost USDW and cemented to the surface; and, that the long-string 
casing be cemented in place along its entire length from the injection 
zone to the surface. This is consistent with existing requirements for 
Class I hazardous waste injection wells.
    EPA proposed the enhanced casing requirements for Class VI wells to 
maintain additional barriers to CO<INF>2</INF> leakage outside of the 
injection zone, and solicited comment on the proposed construction 
requirements related to the depth of the surface casing. Commenters 
objecting to the proposed requirements argued that the surface casing 
and long-string casing requirements may preclude GS in areas with very 
deep USDWs. They commented that, under certain circumstances, it would 
be too burdensome or technologically infeasible to construct the 
casings to the required depth. Commenters also argued that these 
requirements would adversely impact acceptance of GS and would slow 
down large-scale deployment of this climate change mitigation 
technology. These commenters recommended that the rule allow more 
flexibility regarding surface and long-string casing depths to 
accommodate varied conditions where Class VI wells may be constructed 
throughout the U.S. Other commenters agreed with the Agency's proposed 
long-string casing requirements for Class VI wells, stating that the 
requirements prevent undesirable migration of fluids behind the casing 
and provide maximum zonal isolation.
    The Agency disagrees that the surface and long-string casing 
requirements are not flexible enough to address the varied geological 
formations and aquifer characteristics across the United States. EPA 
adds that cementing of deep wells has been performed successfully by 
owners or operators of Class I wells at depths up to 12,000 feet 
(USEPA, 2001). Protection of USDWs from endangerment, regardless of 
their depth or stratigraphic location, is the primary mission of the 
UIC program and the purpose of all requirements for injection wells.
    However, in order to address concerns about lack of flexibility 
while ensuring USDW protection, EPA modified the surface casing 
requirements at Sec.  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

[[Page 77251]]

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 Sec.  
146.95 for owners or operators that seek a waiver of the injection 
depth requirements. Owners or operators of wells operating under 
injection depth waivers must comply with additional construction 
requirements to ensure that wells used to inject above or between USDWs 
are protective and will not endanger USDWs. See section III.D for a 
detailed discussion of the waiver approach.
    Cement and well materials requirements: EPA proposed that all 
materials used in the construction of Class VI wells must be compatible 
with fluids with which the materials may be expected to come into 
contact, and that cement and cement additives must be compatible with 
the CO<INF>2</INF> stream and formation fluids and of sufficient 
quality and quantity to maintain integrity over the design life of the 
project. The Agency requested comment on cementing of the long-string 
casing, including the use of degradation-resistant well construction 
materials, such as acid-resistant cements and corrosion-resistant 
casing for Class VI wells.
    Commenters who disagreed with EPA's proposed requirements for well 
materials and cement argued that the specific use of acid-resistant/
corrosion-resistant cement is excessive. They expressed concerns that 
the proposed rule did not reflect actual field experience or recent 
laboratory research and they encouraged the Agency to defer imposing 
these additional requirements until further field experience and 
research are conducted. These commenters suggested that the Agency 
allow Director's discretion in determining the standards for casing and 
cementing on a case-by-case basis.
    Commenters who supported the use of acid-resistant/degradation-
resistant cement and materials asserted that their use is essential to 
reduce the risk of leaks associated with compromised mechanical 
integrity and to protect USDWs from endangerment, at a modest cost 
relative to the long-term benefit of well integrity.
    Some commenters supported the use of Class II well construction 
standards for Class VI wells. These commenters indicated that the oil 
and gas industry has several decades of CO<INF>2</INF> injection 
experience, which, they believe demonstrates that Class II construction 
standards are sufficient to protect human health and the environment. 
EPA recognizes that the oil and gas industry has experience injecting 
CO<INF>2</INF> 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 Sec.  146.86. For example, the volume of 
CO<INF>2</INF> anticipated to be injected in Class VI wells is 
significantly greater than for Class II wells. Additionally, formation 
pressures are expected to be higher as a result of Class VI injection 
when compared to formation pressures associated with Class II ER 
projects. Today's final rule does provide for grandfathering of 
construction for wells transitioning to GS provided the owner or 
operator can demonstrate to the Director (during the re-permitting 
process) that wells were constructed and cemented with materials 
compatible with GS activities; see section II.H.
    EPA agrees with commenters that cement additives and degradation 
resistant materials are crucial to proper construction of Class VI 
wells. Because of the numerous approaches developed for cement design 
and due to continually evolving well materials and construction 
technology (as evidenced by oil and gas industry experience 
demonstrating the effectiveness of existing cementing materials and 
procedures), EPA believes it would not be prudent or feasible to 
specify design standards for cement or cementing procedures, such as 
wellbore conditioning. Instead, the final rule specifies a performance 
standard at Sec.  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 Sec.  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 
CO<INF>2</INF> injection volumes into a particular reservoir and 
increase the total effective GS CO<INF>2</INF> storage capacity in the 
U.S.
    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 Sec.  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

[[Page 77252]]

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 
CO<INF>2</INF> 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 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 CO<INF>2</INF> trapping mechanisms, 
including physical trapping, dissolution of CO<INF>2</INF> in native 
fluids and mineralization, to occur over time--thereby reducing risks 
that CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 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 
Sec. Sec.  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 Sec.  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 gas-related 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 Sec.  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 Sec.  
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 CO<INF>2</INF> 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, 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 CO<INF>2</INF> (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

[[Page 77253]]

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.
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 U.S. 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 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 CO<INF>2</INF> 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 
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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 re-permitted 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 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.

[[Page 77254]]

    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 
Sec.  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.
    The Agency is finalizing these requirements to ensure USDW 
protection while providing flexibility to UIC program Directors and 
owners or operators who will undertake CO<INF>2</INF> 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 CO<INF>2</INF> 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 Sec.  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 Sec.  146.82(a) for the site-specific characterization 
of geologic, hydrogeologic, geochemical, and geomechanical properties 
and Sec.  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 Sec.  
146.82(d) and outlined at Sec.  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 Sec.  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 
Sec.  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 Sec.  
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 Sec.  146.95(b)(2) also establish the manner in 
which the UIC Director will consult with the 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 Sec.  146.95(c) and pursuant to requirements at Sec.  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

[[Page 77255]]

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 Sec.  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 Sec.  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 Sec.  146.95(d), the 
Regional Administrator will provide written concurrence or non-
concurrence regarding waiver issuance. The requirements at Sec.  
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 
Sec.  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. EPA also believes that Agency 
involvement in the waiver decision process will contribute to national 
consistency in waiver issuance.
    The requirements at Sec.  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 
U.S.
    Today's rule finalizes additional requirements at Sec.  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 Sec.  146.95(f)(1)). The 
additional requirements are designed to complement existing 
requirements by:
    <bullet> Building upon the site characterization and AoR 
delineation conducted during the waiver application process (at Sec.  
146.95(a)),
    <bullet> Supplementing specific requirements that are not 
applicable due to the fact that certain Class VI requirements (e.g., at 
Sec.  146.86) reference the ``lowermost USDW,''
    <bullet> Expanding the monitoring requirements during operation and 
PISC to address protection of USDWs underlying and overlying the 
injection zone, and,
    <bullet> 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, 
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 Sec.  
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 Sec. Sec.  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 Sec.  146.81(c).
    If an owner or operator applies for a Class VI permit to inject 
CO<INF>2</INF> 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 
Sec.  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

[[Page 77256]]

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) CO<INF>2</INF> 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 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 Sec.  144.7(b)(3). In addition, today's rule requires 
that all such aquifer exemption expansion requests be treated as 
substantial program revisions under Sec.  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 
CO<INF>2</INF> 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 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 CO<INF>2</INF> 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 Sec.  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 Sec.  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 Sec.  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., Sec.  144.12; Sec.  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 CO<INF>2</INF> 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 Sec.  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

[[Page 77257]]

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 Sec.  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 U.S. and evaluate the applicability of injection into all formation 
types.

E. Injection Well Operation

    Today's final rule contains tailored requirements at Sec.  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 CO<INF>2</INF> 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 (Sec.  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 
injection pressure may cause damage to the well or the formation. EPA 
changed the requirements in Sec.  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 CO<INF>2</INF> 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 shut-off devices are an important barrier against 
endangerment of USDWs from the escape of CO<INF>2.</INF> 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 shut-off 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 
CO<INF>2</INF> and the elevated injection pressures associated with GS 
increase the likelihood of an uncontrolled flow of CO<INF>2</INF> out 
of the well. If CO<INF>2</INF> 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 CO<INF>2</INF> which can cause 
damage to the wellhead and other well instrumentation; such damage has 
been documented in CO<INF>2</INF> ER wells (Skinner, 2003; Duncan et 
al., 2009). Automatic

[[Page 77258]]

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 Sec.  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 shut-off 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 Sec.  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 down-hole shut-off device will immediately shut-in 
the well to cease injection (limiting CO<INF>2</INF> 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 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 site-specific 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 Sec.  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.
    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, SF<INF>6</INF>, noble gases, and 
stable isotopes such <SUP>18</SUP>O and <SUP>14</SUP>C.
    Some commenters supported the use of tracers in Class VI injection 
wells, maintaining that tracers are a useful method for detecting 
CO<INF>2</INF> 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 CO<INF>2</INF> movement were available. 
These commenters cited

[[Page 77259]]

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 CO<INF>2</INF> 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 
CO<INF>2</INF> 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 Sec.  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, 
CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 Sec.  
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 CO<INF>2</INF> stream; 
MIT (internal and external); corrosion monitoring; determination of the 
position of the CO<INF>2</INF> 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 
CO<INF>2</INF> 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. Owners or operators must also 
periodically review the testing and monitoring plan to incorporate 
operational and monitoring data and the most recent AoR reevaluation 
(Sec.  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. CO<INF>2</INF> Stream Analysis
    Injectate analysis provides information on the chemical composition 
and physical characteristics of the injectate. Analysis of the 
CO<INF>2</INF> 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 CO<INF>2</INF> 
stream be conducted prior to commencing injection and throughout 
injection operations at an appropriate frequency based on the 
CO<INF>2</INF> source and the likelihood of variability in the 
injectate composition. Commenters supported the need for analysis of 
the CO<INF>2</INF> stream. The final rule retains the requirement that 
owners or operators need to characterize their CO<INF>2</INF> stream as 
part of

[[Page 77260]]

their UIC permit application (Sec.  146.82(a)(7)), and throughout the 
operational life of the injection facility (Sec.  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 
CO<INF>2</INF> Streams: EPA received public comment asserting that the 
proposed UIC Class VI requirements were unclear as to whether the 
CO<INF>2</INF> stream would be a RCRA hazardous waste, and left 
uncertain the type of permit needed. Many commenters stated that a 
CO<INF>2</INF> 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 
CO<INF>2</INF> 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 CO<INF>2</INF> streams and that the Class VI regulations 
would better ensure the proper management of a CO<INF>2</INF> 
injectate. EPA did not receive any new data on CO<INF>2</INF> 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 CO<INF>2</INF> stream is not itself a listed RCRA hazardous 
waste. EPA has reviewed estimates of CO<INF>2</INF> 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 
CO<INF>2</INF> capture technology. These estimates indicate that 
captured CO<INF>2</INF> 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 CO<INF>2</INF> stream is hazardous under EPA's RCRA 
regulations, and if so, any injection of the CO<INF>2</INF> 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 
CO<INF>2</INF> stream).
    EPA supports the use of CO<INF>2</INF> capture technologies that 
minimize impurities in the CO<INF>2</INF> 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 CO<INF>2</INF> streams being 
geologically sequestered, including the possible option of a 
conditional exemption from the RCRA requirements for CO<INF>2</INF> GS 
in Class VI wells (see RIN 2050-AG60, EPA Semiannual Regulatory Agenda, 
Spring 2010, EPA-230-Z-10-001). 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 CO<INF>2</INF> 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.
    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.
    CO<INF>2</INF> itself is not listed as a hazardous substance under 
CERCLA. However, the CO<INF>2</INF> 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 CO<INF>2</INF> 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 Sec.  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 Sec.  
146.94) and that owners or operators demonstrate that financial 
resources are set aside to implement the plans if necessary (pursuant 
to the financial responsibility requirements at Sec.  146.85).

[[Page 77261]]

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 Sec.  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 CO<INF>2</INF> in the presence of water and the 
anticipated high 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 CO<INF>2</INF>. 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 
CO<INF>2</INF>, today's rule requires owners or operators of 
CO<INF>2</INF> injection wells to demonstrate external MI at least once 
annually during injection operations using a tracer survey or a 
temperature or noise log (Sec.  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 CO<INF>2</INF> (in the presence of water) on well components 
(steel casing and cement) and the buoyant nature of supercritical 
CO<INF>2</INF> 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 (Sec.  146.89(e)).
    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 Sec.  
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 CO<INF>2</INF> or CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 Sec.  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 timely detection of any leakage of 
CO<INF>2</INF> 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 
CO<INF>2</INF>) 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.

[[Page 77262]]

    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 Sec.  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 Sec.  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 Sec.  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, 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 Sec.  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. CO<INF>2</INF> Plume and Pressure Front Monitoring/Tracking
    Monitoring the movement of the CO<INF>2</INF> 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 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 CO<INF>2</INF> 
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 
Sec.  146.90 requires Class VI well owners or operators to perform 
monitoring to track the extent of the CO<INF>2</INF> 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 CO<INF>2</INF> detection tools) are required unless the Director 
determines, based on site-specific geology that such methods are not 
appropriate (Sec.  146.90(g)).
    The purpose of monitoring in the injection zone (Sec.  
146.90(g)(1)) is to track the development and movement of the pressure 
front and CO<INF>2</INF> 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 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 Sec.  146.90(d)) to provide additional 
verification that no pressure changes are occurring above the confining 
zone due to CO<INF>2</INF> 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, Sec.  146.90(g)(2) requires owners or operators to 
track the position of the CO<INF>2</INF> plume using indirect methods 
(e.g., seismic, electrical, gravity, or electromagnetic surveys and/or 
down-hole CO<INF>2</INF> 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

[[Page 77263]]

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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> out of the 
subsurface, with elevation of CO<INF>2</INF> 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 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 Sec.  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 Sec.  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 Sec.  
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 CO<INF>2</INF> sequestered and collecting data 
on any CO<INF>2</INF> surface emissions. If a Director requires surface 
air/soil gas monitoring pursuant to requirements at Sec.  146.90(h) and 
an owner or operator demonstrates that monitoring employed under 
Sec. Sec.  98.440 to 98.449 of subpart RR meets the requirements at 
Sec.  146.90(h)(3), the Director must approve the use of monitoring 
employed under subpart RR.
    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 part 
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 Sec.  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 CO<INF>2</INF> 
sequestered and collect data on any CO<INF>2</INF> 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 CO<INF>2</INF> 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 Sec.  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

[[Page 77264]]

necessary based on review of project-specific information submitted.
    The final rule, at Sec.  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 Sec.  1445(a)(1) of the SDWA, today's final rule at 
Sec.  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 Sec.  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 Sec.  
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 non-electronic 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 with their 
permit conditions, and are sufficiently protective of USDWs. The 
information compiled under Sec.  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 co-regulators. 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 Sec.  
146.91(e), information to the Director to support Class VI permit 
applications (this information is enumerated at Sec.  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 Sec.  146.91, 
requires owners or operators to submit project monitoring and 
operational data at varying intervals, 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 (Sec.  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 (Sec.  
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 
(Sec.  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 CO<INF>2</INF> 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 (Sec.  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 Sec.  
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

[[Page 77265]]

believes that the reporting required at Sec.  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 (Sec.  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 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-by-case 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 Sec.  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 Sec.  146.91(f). Class VI well owners or operators must 
retain data collected to support permit applications and data on the 
CO<INF>2</INF> stream until 10 years after site closure. Owners or 
operators must retain monitoring data collected under the testing and 
monitoring requirements at Sec.  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 (Sec.  146.91(f)(5)). Well plugging reports, 
PISC data, and site closure reports must be kept for 10 years after 
site closure (Sec. Sec.  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. Site-
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 site-specific 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 
Sec.  146.91(c), including, but not limited to: Evidence that the 
injected CO<INF>2</INF> stream or associated pressure front may cause 
an endangerment to a USDW; triggering of a shut-off system; or failure 
to maintain mechanical integrity is used to inform the Director of any 
evidence

[[Page 77266]]

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 Sec.  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 Sec.  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 
CO<INF>2</INF> 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 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 Sec.  146.92. The owners or operators must prepare and comply with a 
Director-approved injection well plugging plan submitted with their 
permit application (Sec.  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 (Sec.  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 Sec.  146.93 incorporates a PISC period, 
specific to Class VI wells. PISC is the period after CO<INF>2</INF> 
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 (Sec.  146.93) with an additional requirement at Sec.  
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 Sec.  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 (Sec.  
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 CO<INF>2</INF> 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

[[Page 77267]]

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 
CO<INF>2</INF> 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 CO<INF>2</INF> trapping. Commenters 
suggested that the PISC timeframe should be specific to the 
characteristics of a project, including the predicted extent of the 
CO<INF>2</INF> plume and the area of elevated pressure, geologic 
factors, modeled predictions of CO<INF>2</INF> 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.
    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 Sec.  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 Sec.  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 
Sec.  146.93(c)) must continue monitoring until they submit, for 
Director review and approval, a demonstration based on monitoring and 
other site-specific 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 Sec.  146.93(c), affords the Director 
discretion to approve a demonstration during the permitting process 
(per requirements at Sec.  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 Sec.  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 
pursuant to Sec.  146.84) and information that supports the PISC and 
site closure plan development required at Sec.  146.93(a), including 
the predicted timeframe for pressure decline within the injection zone 
and any other zones; the predicted rate of CO<INF>2</INF> plume 
migration and timeframe for the cessation of migration; site-specific 
chemical processes that will result in CO<INF>2</INF> trapping (e.g., 
by capillary trapping, dissolution, and mineralization); the predicted 
rate of CO<INF>2</INF> 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 Sec.  146.82(a)(3)); the presence of potential conduits for fluid 
movement near the injection well (per Sec.  146.84(c)(2)); the quality 
of wells and well plugs in wells within the AoR (per Sec.  
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 Sec.  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 Sec.  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 Sec.  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 Sec.  146.93(a)(2)(iv); and, must be 
incorporated in the permit as part of the PISC and site closure plan as 
required at Sec.  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 Sec.  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 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 Sec.  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

[[Page 77268]]

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 (Sec.  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 Sec.  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 CO<INF>2</INF>. Site 
closure would proceed according to the approved PISC and site closure 
plan. Today's final regulation retains these closure requirements (at 
Sec.  146.93(d) through (h)).
    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 CO<INF>2</INF> 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 
Sec. Sec.  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 Sec.  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 
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, 
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

[[Page 77269]]

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 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:
    <bullet> 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;
    <bullet> That the owner or operator be required to notify the 
Director by certified mail of any proceeding under Title 11 
(Bankruptcy), U.S. 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, 
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;
    <bullet> 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
    <bullet> 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 Sec.  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.
    (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 U.S. 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:
    <bullet> A ratio of total liabilities to net worth less than 2.0;
    <bullet> A ratio of current assets to current liabilities greater 
than 1.5;
    <bullet> A ratio of the sum of net income plus depreciation, 
depletion, and amortization to total liabilities greater than 0.1;
    <bullet> A ratio of current assets minus current liabilities to 
total assets greater than -0.1; and
    <bullet> 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

[[Page 77270]]

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 (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 Sec.  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 ``pay-in 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 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 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 Sec.  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 CO<INF>2</INF>, 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.
    (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

[[Page 77271]]

instruments for well plugging and PISC (Sec.  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 (Sec.  146.85(a)(5)(i)).
    EPA adds that under today's final rulemaking at Sec.  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.
    EPA has added language, at Sec.  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 Sec.  146.85(c), also requires that the owner or 
operator adjust the cost estimates to address amendments to the AoR and 
corrective action plan (Sec.  146.84), the injection well plugging plan 
(Sec.  146.92), the PISC and site closure plan (Sec.  146.93), and the 
emergency and remedial response plan (Sec.  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 Sec.  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 Sec.  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., three-years 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 Sec.  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 U.S. 
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 Sec.  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 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

[[Page 77272]]

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 Sec.  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 Sec.  
146.93, under section 1423 of the SDWA for violating Sec.  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. Sec. Sec.  7401-7671; CERCLA, 42 U.S.C. Sec.  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 Sec.  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 (Sec.  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 CO<INF>2</INF> 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 Sec.  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 
CO<INF>2</INF>; 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.

[[Page 77273]]

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.
    Today's rule at Sec.  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 Sec.  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 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 decision-making officials.
    GS of CO<INF>2</INF> 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.
    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 Sec.  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 (Sec.  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 owner or operator 
and the

[[Page 77274]]

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 (Sec.  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 
(Sec.  146.84(e), Sec.  146.90(j), and Sec.  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 Sec. Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 CO<INF>2</INF> 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 
(Sec.  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 Sec.  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 (Sec.  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 Sec.  146.86(a) and ensure protection of USDWs from 
endangerment in lieu of requirements at Sec.  146.86(b) and Sec.  
146.87(a).

[[Page 77275]]

    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 Sec.  
146.84(c)(1) must delineate the projected lateral and vertical movement 
of the CO<INF>2</INF> 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 CO<INF>2</INF> 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.
    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 CO<INF>2</INF>. 
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 
CO<INF>2</INF> 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 
CO<INF>2</INF>, nor does it include transporting the CO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 
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 Rule <SUP>4</SUP>
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.

[[Page 77276]]

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 Regulations 5
------------------------------------------------------------------------
                                             Direction of change in risk
               Requirements                 for selected RA (relative to
                                                      baseline)
------------------------------------------------------------------------
                      1. Geologic Characterization
------------------------------------------------------------------------
Baseline
Identify a geologic system consisting of a  Decrease.
 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.
------------------------------------------------------------------------
           2. Area of Review (AoR) Study and Corrective Action
------------------------------------------------------------------------
Baseline
The AoR determined as either a \1/4\ mile   Decrease.
 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.
------------------------------------------------------------------------
                     3. Injection Well Construction
------------------------------------------------------------------------
Baseline
The well must be cased and cemented to      Decrease (enhanced well
 prevent movement of fluids into or          construction requirements);
 between USDWs and to withstand the         Increase (A waiver to inject
 injected materials at the anticipated       above the lowermost USDW in
 pressure, temperature and other             limited cases).
 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.)
------------------------------------------------------------------------
                            4. Well Operation
------------------------------------------------------------------------
Baseline
Limit injection pressure to avoid           Decrease.
 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.
------------------------------------------------------------------------
                  5. Mechanical Integrity Testing (MIT)
------------------------------------------------------------------------
Baseline
Demonstrate internal mechanical integrity,  Decrease.
 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.
------------------------------------------------------------------------
                              6. Monitoring
------------------------------------------------------------------------
Baseline
Monitor the nature of injected fluids at a  Decrease.
 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.

[[Page 77277]]

 
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.
------------------------------------------------------------------------
          7. Well Plugging and Post-Injection Site Care (PISC)
------------------------------------------------------------------------
Baseline
Ensure that the well is in a state of       Decrease.
 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.
------------------------------------------------------------------------
                       8. Financial Responsibility
------------------------------------------------------------------------
Baseline
Demonstrate and maintain financial          Decrease.
 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.
------------------------------------------------------------------------
                   9. Emergency and Remedial Response
------------------------------------------------------------------------
Baseline
No specific requirement under Baseline.     Decrease.
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.
------------------------------------------------------------------------
Overall...................................  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.


    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 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 CO<INF>2</INF>. 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).

[[Page 77278]]

[GRAPHIC] [TIFF OMITTED] TP10DE10.091

    Table IV-3 presents a breakout of the annualized incremental costs 
of the selected RA by rule component using a 3-percent discount rate:
    <bullet> 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 CO<INF>2</INF> 
or formation fluids.
    <bullet> 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.
    <bullet> 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 CO<INF>2</INF> leak may have occurred and allows the owner or 
operator to prevent compromises to well integrity.
    <bullet> Construction of Class VI wells using the corrosion-
resistant design and materials necessary to withstand exposure to 
CO<INF>2</INF> accounts for approximately 3.2 percent of the 
incremental cost of the selected RA.
    <bullet> 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.
    <bullet> 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.
    <bullet> 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.

[[Page 77279]]

[GRAPHIC] [TIFF OMITTED] TP10DE10.092

b. Nonquantified Costs and Uncertainties in Cost Estimates
    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 
CO<INF>2</INF> 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 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 
CO<INF>2</INF> 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 labor rates in the event that rapid deployment does 
drive up costs, EPA conducted sensitivity analyses using labor rates 
that were 50% higher than those used in the primary analysis. 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

[[Page 77280]]

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 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 $107.23 in 2008$ 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.
    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 
CO<INF>2</INF>. These costs over the full lifetime of the sequestration 
project are estimated to be $1.40/metric tonne CO<INF>2</INF>. 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 CO<INF>2</INF> 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

[[Page 77281]]

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 CO<INF>2</INF> emissions in the United States (approximately 
one percent).
---------------------------------------------------------------------------

    \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.
    \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.
---------------------------------------------------------------------------

    The U.S. fleet of 1,493 coal-fired power generators emits 1.932 Pg 
CO<INF>2</INF> 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 labor or service costs is not likely to contribute 
significantly as a rapid, wide-scale increase in deployment is not 
expected.\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, capital and labor cost trends, and the 
shape of the learning curve among industry and State/Federal operators.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 CO<INF>2</INF> 
($42.90/metric tonne CO<INF>2</INF> for capture from an integrated 
gasification combined cycle power plant.\11\) 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 
CO<INF>2</INF>.\12\ EPA estimates total sequestration costs for a 
commercial-size deep saline project to be approximately $3.80/metric 
tonne CO<INF>2</INF>, of which approximately $1.40/metric tonne 
CO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \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 
CO<INF>2</INF> Capture and Storage: Issues and Challenges,'' Feb. 
2009, INGAA Foundation.

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

[[Page 77282]]

[GRAPHIC] [TIFF OMITTED] TP10DE10.093

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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 
CO<INF>2</INF> 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 CO<INF>2</INF> 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.

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

[[Page 77283]]

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.
[GRAPHIC] [TIFF OMITTED] TP10DE10.094

    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 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 
CO<INF>2</INF> 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

[[Page 77284]]

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 U.S. Conference of Mayors, the National Association of 
Counties, the International City/County Management Association, the 
National Association of Towns and Townships, and the County Executives 
of America. 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 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 CO<INF>2</INF> should a firm 
decide to undertake such a project. Health and risk assessments related 
to GS of CO<INF>2</INF> 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 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 CO<INF>2</INF> emissions is 
passed in the future, energy generation firms and other CO<INF>2</INF> 
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 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

[[Page 77285]]

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.

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 CO<INF>2</INF>. 
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

    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 January 10, 2011.

VI. References

Benson. 2008. Multi-Phase Flow and Trapping of CO<INF>2</INF> 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 CO<INF>2</INF> Geological Storage and 
Groundwater Resources: Water Quality Effects Caused by 
CO<INF>2</INF> Intrusion into Shallow Groundwater. LBNL paper 
<greek-i>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 CO<INF>2</INF> 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 CO<INF>2</INF> 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.
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 CO<INF>2</INF> 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 CO<INF>2</INF> Sequestration Projects Based on CO<INF>2</INF> 
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 CO<INF>2</INF> 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. CO<INF>2</INF> 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 Ultra-Small 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 CO<INF>2</INF> 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.
Skinner, L. 2003. CO<INF>2</INF> 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,

[[Page 77286]]

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 <greek-i> 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.
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.

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 recordkeeping requirements, Water supply.

40 CFR Part 147

    Environmental protection, Indian--lands, Intergovernmental 
relations, Penalties, Reporting and recordkeeping requirements, Water 
supply.

    Dated: November 22, 2010.
Lisa P. Jackson,
Administrator.

0
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

0
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

0
2. Section 124.10 is amended by revising paragraph (c) introductory 
text and by adding paragraph (c)(1)(xi) to read as follows:


Sec.  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 e-mailing 
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

0
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

0
4. Section 144.1 is amended by adding paragraph (f)(1)(viii) and by 
revising paragraph (g) introductory text to read as follows.


Sec.  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,'' Sec.  144.3). The six classes of wells are set 
forth in Sec.  144.6. All owners or operators of these injection wells 
must be authorized either by permit or rule by the Director. 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 Sec.  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 (Sec.  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 (Sec.  144.13). For Class V wells, 
if remedial action appears necessary, a permit may be required (Sec.  
144.25) or the Director must require remedial action or closure by 
order (Sec.  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 Sec.  144.3, even if 
it has not been ``identified.'' The Director may also designate 
``exempted aquifers'' using the

[[Page 77287]]

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 Sec.  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 Sec.  145.23(f)(9).
* * * * *

0
5. Section 144.3 is amended by adding in alphabetic order the 
definition ``geologic sequestration'' to read as follows:


Sec.  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.
* * * * *

0
6. Section 144.6 is amended by revising paragraph (e) and adding 
paragraph (f) to read as follows:


Sec.  144.6  Classification of wells.

* * * * *
    (e) Class V. Injection wells not included in Class I, II, III, IV, 
or VI. Specific types of Class V injection wells are described in Sec.  
144.81.
    (f) Class VI. Wells 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 Sec.  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 Sec. Sec.  146.4 of this chapter and 144.7(d).

0
7. Section 144.7 is amended as follows:
0
a. Revising paragraph (a);
0
b. Revising paragraphs (b)(1) and (b)(2); and
0
c. Adding paragraph (d) as follows:


Sec.  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 
Sec.  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 Sec.  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 
Sec.  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 Sec.  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 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 Sec.  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 
Sec.  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 that are requested to be designated as exempted using the 
criteria in Sec.  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 Sec.  
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 Sec.  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 Sec.  146.84(e); and
    (iv) Any information submitted to support a waiver request made by 
the owner or operator under Sec.  146.95, if appropriate.

0
8. Section 144.8 is amended by adding paragraph (b)(2)(iii) to read as 
follows:

[[Page 77288]]

Sec.  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 Sec.  146.91 of this chapter.
* * * * *

Subpart B--General Program Requirements

0
9. Section 144.12 is amended by revising the first sentence in 
paragraph (b) to read as follows:


Sec.  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. * * *
* * * * *

0
10. Section 144.15 is added to read as follows:


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

    The construction, operation or maintenance of any non-experimental 
Class V geologic sequestration well is prohibited.

0
11. Section 144.18 is added to subpart B to read as follows:


Sec.  144.18  Requirements for Class VI wells.

    Owners or operators of Class VI wells must obtain a permit. Class 
VI wells cannot be authorized by rule to inject carbon dioxide.

0
12. Section 144.19 is added to subpart B to read as follows:


Sec.  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. In 
determining if there is an increased risk to USDWs, the owner or 
operator must consider the factors specified in Sec.  144.19(b).
    (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.

Subpart C--Authorization of Underground Injection by Rule

0
13. Section 144.22 is amended by revising paragraph (b) to read as 
follows:


Sec.  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 Sec. Sec.  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 Sec. Sec.  144.28(c) and 146.10 of this 
chapter; and upon submission of a plugging and abandonment report 
pursuant to Sec.  144.28(k); or upon conversion in compliance with 
Sec.  144.28(j).

Subpart D--Authorization by Permit

0
14. Section 144.31 is amended by revising paragraph (e) introductory 
text to read as follows:


Sec.  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 Sec.  146.82 of 
this chapter.
* * * * *

0
15. Section 144.33 is amended by revising paragraph (a)(4) and adding 
paragraph (a)(5).


Sec.  144.33  Area permits.

    (a) * * *
    (4) Used to inject other than hazardous waste; and
    (5) Other than Class VI wells.
* * * * *

0
16. Section 144.36 is amended by revising paragraph (a) to read as 
follows:


Sec.  144.36  Duration of permits.

    (a) Permits for Class I and V wells shall be effective for a fixed 
term not to exceed 10 years. UIC permits for Class II 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 
Sec. Sec.  144.39, 144.40, or 144.41.
* * * * *

0
17. Section 144.38 is amended by revising paragraph (b) introductory 
text to read as follows:


Sec.  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:
* * * * *

0
18. Section 144.39 is amended as follows:
0
a. Revising the second sentence in paragraph (a) introductory text;
0
b. Revising the second sentence in paragraph (a)(3) introductory text; 
and
0
c. Adding a new paragraph (a)(5) to read as follows:


Sec.  144.39  Modification or revocation and reissuance of permits.

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

[[Page 77289]]

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 Sec.  146.84(e)(1) of this 
chapter;
    (ii) Any amendments to the testing and monitoring plan under Sec.  
146.90(j) of this chapter;
    (iii) Any amendments to the injection well plugging plan under 
Sec.  146.92(c) of this chapter;
    (iv) Any amendments to the post-injection site care and site 
closure plan under Sec.  146.93(a)(3) of this chapter;
    (v) Any amendments to the emergency and remedial response plan 
under Sec.  146.94(d) of this chapter; or
    (vi) A review of monitoring and/or testing results conducted in 
accordance with permit requirements.
* * * * *

0
19. Section 144.41 is amended by adding a new paragraph (h) to read as 
follows:


Sec.  144.41  Minor modifications of permits.

* * * * *
    (h) Amend a Class VI injection well testing and monitoring plan, 
plugging plan, post-injection 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

0
20. Section 144.51 is amended to read as follows:
0
a. Adding a new paragraph (j)(4);
0
b. Revising paragraph (o); and
0
c. Removing the first sentence in paragraph (q)(1) and adding two 
sentences in its place; and
0
d. Revising the first sentence in paragraph (q)(2).


Sec.  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 Sec. Sec.  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 Sec.  
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 Sec.  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 Sec.  
146.92 of this chapter. Where the plan meets the requirements of Sec.  
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 Sec.  146.8 of this chapter 
and the owner or operator of Class VI wells must maintain mechanical 
integrity as defined in Sec.  146.89 of this chapter. * * *
    (2) When the Director determines that a Class I, II, III or VI well 
lacks mechanical integrity pursuant to Sec. Sec.  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. * * *
* * * * *

0
21. Section 144.52 is amended as follows:
0
a. By revising paragraph (a) introductory text;
0
b. Revising paragraph (a)(2);
0
c. Revising paragraphs (a)(7)(i)(A) and (a)(7)(ii); and
0
d. Revising paragraph (a)(8).


Sec.  144.52  Establishing permit conditions.

    (a) In addition to conditions required in Sec.  144.51, the 
Director shall establish conditions, as required on a case-by-case 
basis under Sec.  144.36 (duration of permits), Sec.  144.53(a) 
(schedules of compliance), Sec.  144.54 (monitoring), and for EPA 
permits only Sec.  144.53(b) (alternate schedules of compliance), and 
Sec.  144.4 (considerations under Federal law). Permits for owners or 
operators of hazardous waste injection wells shall include conditions 
meeting the requirements of Sec.  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 Sec. Sec.  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 Sec. Sec.  
144.51(o), 146.10, and 146.92 of this chapter, and submitted a plugging 
and abandonment report pursuant to Sec.  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 Sec.  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 Sec.  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 Sec.  146.8, or Sec.  146.89 of this chapter for 
Class VI, that the well has mechanical integrity.
* * * * *

[[Page 77290]]

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

0
22. Section 144.80 is amended by revising the first sentence in 
paragraph (e) and by adding paragraph (f) to read as follows:


Sec.  144.80  What is a Class V injection well?

* * * * *
    (e) Class V. Injection wells not included in Class I, II, III, IV 
or VI. * * *
    (f) Class VI. Wells used for geologic sequestration of carbon 
dioxide 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 Sec.  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 Sec.  146.4 of this chapter and Sec.  
144.7(d).

PART 145--STATE UIC PROGRAM REQUIREMENTS

0
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

0
24. Section 145.1 is amended by adding paragraph (i) to read as 
follows:


Sec.  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

0
25. Section 145.21 is amended by adding paragraph (h) to read as 
follows:


Sec.  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 September 6, 2011, submit 
to the Administrator a new or revised State UIC program complying with 
Sec. Sec.  145.22 or 145.32 of this part. Beginning on September 6, 
2011 the requirements of subpart H of part 146 of this chapter 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 September 6, 2011, EPA will publish a list of the 
States where subpart H of part 146 has become applicable.

0
26. Section 145.22 is amended by revising paragraphs (a) introductory 
text and (a)(5) to read as follows:


Sec.  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;
* * * * *

0
27. Section 145.23 is amended as follows:
0
a. By revising the introductory text;
0
b. Revising paragraph (c);
0
c. Revising paragraph (d);
0
d. Revising paragraphs (f)(1), (f)(2), (f)(3), (f)(4), and (f)(9); and
0
e. Adding paragraph (f)(13) to read as follows:


Sec.  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;
    (2) The priorities (according to criteria set forth in Sec.  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 Sec.  146.8 of this chapter, or, for 
Class VI wells, the mechanical integrity testing requirements of Sec.  
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 approved before 
December 10, 2011, 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 Sec.  146.81(c) within one year of December 10, 2011. 
For Class VI programs approved following December 10, 2011, 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

[[Page 77291]]

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 Sec.  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 Sec.  144.7(b) as exempted aquifers, and a summary 
of supporting data. For 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 
Sec. Sec.  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.

0
28. Section 145.32 is amended by adding a sentence at the end of 
paragraph (b)(2) to read as follows:


Sec.  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

0
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.


0
30. Section 146.4 is amended by revising the introductory text and 
adding paragraph (d) to read as follows:


Sec.  146.4  Criteria for exempted aquifers.

    An aquifer or a portion thereof which meets the criteria for an 
``underground source of drinking water'' in Sec.  146.3 may be 
determined under Sec.  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 Sec.  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.

0
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:


Sec.  146.5  Classification of injection wells.

* * * * *
    (e) Class V. Injection wells not included in Class I, II, III, IV 
or VI. * * *
* * * * *
    (f) Class VI. Wells 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 Sec.  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 Sec.  
146.4 and Sec.  144.7(d) of this chapter.

0
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


Sec.  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 
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 Sec.  146.86(a) and ensure protection of USDWs, in lieu 
of requirements at Sec. Sec.  146.86(b) and 146.87(a). By December 10, 
2011, 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 Sec. Sec.  
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 delineated using

[[Page 77292]]

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 Sec.  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.
    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 Sec.  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 Sec.  
146.4 and Sec.  144.7(d) of this chapter. 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 
Sec.  146.93.
    Pressure front means the zone of elevated pressure that is created 
by the injection of carbon dioxide into the subsurface. For the 
purposes of this subpart, the pressure front of a carbon dioxide plume 
refers to a zone where there is a pressure differential sufficient to 
cause the movement of injected fluids or formation fluids into a USDW.
    Site closure means the point/time, as determined by the Director 
following the requirements under Sec.  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.


Sec.  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 Sec.  146.91(e), and the Director shall consider the 
following:
    (1) Information required in Sec.  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 Sec.  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;
    (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 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;

[[Page 77293]]

    (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 Sec.  
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 Sec.  146.86;
    (13) Proposed area of review and corrective action plan that meets 
the requirements under Sec.  146.84;
    (14) A demonstration, satisfactory to the Director, that the 
applicant has met the financial responsibility requirements under Sec.  
146.85;
    (15) Proposed testing and monitoring plan required by Sec.  146.90;
    (16) Proposed injection well plugging plan required by Sec.  
146.92(b);
    (17) Proposed post-injection site care and site closure plan 
required by Sec.  146.93(a);
    (18) At the Director's discretion, a demonstration of an 
alternative post-injection site care timeframe required by Sec.  
146.93(c);
    (19) Proposed emergency and remedial response plan required by 
Sec.  146.94(a);
    (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 Sec.  
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;
    (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 Sec.  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 Sec.  146.87;
    (8) A demonstration of mechanical integrity pursuant to Sec.  
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 Sec.  146.95 and 
submit a supplemental report, as required at Sec.  146.95(a). The 
supplemental report is not part of the permit application.


Sec.  146.83  Minimum criteria for siting.

    (a) Owners or operators of Class VI wells must demonstrate to the 
satisfaction of the Director that the wells will be sited in areas with 
a suitable geologic system. The 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.


Sec.  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.
    (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

[[Page 77294]]

or operator proposes to reevaluate the area of review;
    (ii) The monitoring and operational conditions that would warrant a 
reevaluation of the area of review prior to the next scheduled 
reevaluation as determined by the minimum fixed frequency established 
in paragraph (b)(2)(i) of this section.
    (iii) How monitoring and operational data (e.g., injection rate and 
pressure) will be used to inform an area of review reevaluation; and
    (iv) How corrective action will be conducted to meet the 
requirements of paragraph (d) of this section, including what 
corrective action will be performed prior to injection and what, if 
any, portions of the area of review will have corrective action 
addressed on a phased basis and how the phasing will be determined; how 
corrective action will be adjusted if there are changes in the area of 
review; and how site access will be guaranteed for future corrective 
action.
    (c) Owners or operators of Class VI wells must perform the 
following actions to delineate the area of review 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 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 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 
Sec. Sec.  144.39 or 144.41 of this chapter, as appropriate.
    (f) The emergency and remedial response plan (as required by Sec.  
146.94) and the demonstration of financial responsibility (as described 
by Sec.  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.


Sec.  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.
    (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 Sec.  
146.84);
    (ii) Injection well plugging (that meets the requirements of Sec.  
146.92);
    (iii) Post injection site care and site closure (that meets the 
requirements of Sec.  146.93); and
    (iv) Emergency and remedial response (that meets the requirements 
of Sec.  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 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

[[Page 77295]]

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 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 (Sec.  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 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 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.
    (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.
    (2) During the active life of the geologic sequestration project, 
the

[[Page 77296]]

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 (Sec.  146.84), the 
injection well plugging plan (Sec.  146.92), the post-injection site 
care and site closure plan (Sec.  146.93), and the emergency and 
remedial response plan (Sec.  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 (Sec.  
146.84), the injection well plugging plan (Sec.  146.92), the post-
injection site care and site closure plan (Sec.  146.93), and the 
emergency and response plan (Sec.  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 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 Sec.  146.84), injection well 
plugging (as required by Sec.  146.92), post-injection site care and 
site closure (as required by Sec.  146.93), and emergency and remedial 
response (as required by Sec.  146.94).
    (f) The Director must approve the use and length of pay-in-periods 
for trust funds or escrow accounts.


Sec.  146.86  Injection well construction requirements.

    (a) General. The owner or operator must ensure that all Class VI 
wells are constructed and completed to:
    (1) Prevent the movement of fluids into or between USDWs or into 
any unauthorized zones;
    (2) Permit the use of appropriate testing devices and workover 
tools; and
    (3) Permit continuous monitoring of the annulus space between the 
injection tubing and long string casing.
    (b) Casing and Cementing of Class VI Wells.
    (1) Casing and cement or other materials used in the construction 
of each Class VI well must have sufficient structural strength and be 
designed for the life of the geologic sequestration project. All well 
materials must be compatible with fluids with which the materials may 
be expected to come into contact and 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.
    (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

[[Page 77297]]

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.


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

    (a) During the drilling and construction of a Class VI injection 
well, the owner or operator must run appropriate logs, surveys and 
tests to determine or verify the depth, thickness, porosity, 
permeability, and lithology of, and the salinity of any formation 
fluids in all relevant geologic formations to ensure conformance with 
the injection well construction requirements under Sec.  146.86 and to 
establish accurate baseline data against which future measurements may 
be compared. The owner or operator must submit to the Director a 
descriptive report prepared by a knowledgeable log analyst that 
includes an interpretation of the results of such logs and tests. At a 
minimum, such logs and tests must include:
    (1) Deviation checks during drilling on all holes constructed by 
drilling a pilot hole which 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;
    (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,
    (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.


Sec.  146.88  Injection well operating requirements.

    (a) Except during stimulation, the owner or operator must ensure 
that injection pressure does not exceed 90 percent of the fracture 
pressure of the injection zone(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 
Sec.  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.
    (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,

[[Page 77298]]

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.


Sec.  146.89  Mechanical integrity.

    (a) A Class VI well has mechanical integrity if:
    (1) There is no significant leak in the casing, tubing, or packer; 
and
    (2) There is no significant fluid movement into a USDW through 
channels adjacent to the injection well bore.
    (b) To evaluate the absence of significant leaks under paragraph 
(a)(1) of this section, owners or operators must, following an initial 
annulus pressure test, continuously monitor injection pressure, rate, 
injected volumes; pressure on the annulus between tubing and long-
string casing; and annulus fluid volume as specified in Sec.  146.88 
(e);
    (c) At least once per year, the owner or operator must use one of 
the following methods to determine the absence of significant fluid 
movement under paragraph (a)(2) of this section:
    (1) 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 Sec.  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 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.


Sec.  146.90  Testing and monitoring requirements.

    The owner or operator of a Class VI well must prepare, maintain, 
and comply with a testing and monitoring plan to verify that the 
geologic sequestration project is operating as permitted and is not 
endangering USDWs. The 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;
    (b) Installation and use, except during well workovers as defined 
in Sec.  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 Sec.  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
    (2) The monitoring frequency and spatial distribution of monitoring 
wells based on baseline geochemical data that has been collected under 
Sec.  146.82(a)(6) and on any modeling results in the area of review 
evaluation required by Sec.  146.84(c).
    (e) A demonstration of external mechanical integrity pursuant to 
Sec.  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 Sec.  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:

[[Page 77299]]

    (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;
    (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 Sec.  144.12 of this 
chapter;
    (3) If an owner or operator demonstrates that monitoring employed 
under Sec. Sec.  98.440 to 98.449 of this chapter (Clean Air Act, 42 
U.S.C. 7401 et seq.) accomplishes the goals of paragraphs (h)(1) and 
(2) of this section, and meets the requirements pursuant to Sec.  
146.91(c)(5), a Director that requires surface air/soil gas monitoring 
must approve the use of monitoring employed under Sec. Sec.  98.440 to 
98.449 of this chapter. Compliance with Sec. Sec.  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 Sec.  146.84(c) and to 
determine compliance with standards under Sec.  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 Sec.  146.88, and the most 
recent area of review reevaluation performed under Sec.  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 
Sec. Sec.  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.


Sec.  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;
    (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 Sec.  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 Sec.  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;
    (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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 post-injection site care timeframe, 
and the site closure report collected pursuant to requirements at 
Sec. Sec.  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.


Sec.  146.92  Injection well plugging.

    (a) Prior to the well plugging, the owner or operator must flush 
each Class VI injection well with a buffer fluid, determine bottomhole 
reservoir pressure, and perform a final 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

[[Page 77300]]

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;
    (2) Appropriate testing methods to ensure external mechanical 
integrity as specified in Sec.  146.89;
    (3) The type and number of plugs to be used;
    (4) The placement of each plug, including the elevation of the top 
and bottom of each plug;
    (5) The type, 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 Sec.  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 
Sec. Sec.  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 Sec.  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.


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

    (a) The owner or operator of a Class VI well must prepare, 
maintain, and comply with a plan for post-injection site care and site 
closure that meets the requirements of paragraph (a)(2) of this section 
and is acceptable to the Director. 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 
post-injection 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 Sec.  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 Sec.  146.91(e); and,
    (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 Sec. Sec.  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 
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 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 post-injection 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 Sec. Sec.  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:

[[Page 77301]]

    (i) The results of computational modeling performed pursuant to 
delineation of the area of review under Sec.  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;
    (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 site-specific 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;
    (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;
    (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 Sec.  146.92 and paragraph (e) 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.
    (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
    (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.


Sec.  146.94  Emergency and remedial response.

    (a) As part of the permit application, the owner or operator must 
provide the Director with an emergency and remedial response plan that 
describes actions 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
    (4) Implement the emergency and remedial response plan approved by 
the Director.

[[Page 77302]]

    (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 Sec. Sec.  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.


Sec.  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. This modeling should be conducted in conjunction with 
the area of review determination, as described in Sec.  146.84, and is 
subject to requirements, as described in Sec.  146.84(c), and periodic 
reevaluation, as described in Sec.  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 Sec. Sec.  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);
    (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 non-
USDWs 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.
    (3) Any written waiver-related information submitted by the Public 
Water System Supervision Director(s) to the (UIC) Director.
    (c) Pursuant to requirements at Sec.  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 non-concurrence 
regarding waiver issuance.
    (1) If the Regional Administrator determines that additional 
information

[[Page 77303]]

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.
    (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 Sec. Sec.  146.84, 146.85, 146.87, 146.88, 
146.89, 146.91, 146.92, and 146.94;
    (2) All requirements at Sec.  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 
Sec.  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 Sec.  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 Sec.  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 Sec.  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., 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;
    (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

0
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.


0
34. Section 147.1 is amended by adding paragraph (f) to read as 
follows:


Sec.  147.1  Purpose and scope.

* * * * *
    (f) Class VI well owners or operators must comply with Sec.  
146.91(e) notwithstanding any State program approvals.

[FR Doc. 2010-29954 Filed 12-9-10; 8:45 am]
BILLING CODE 6560-50-P


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