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
CO2 via injection wells, and thus the rule will not have any
impact on them.

D. Unfunded Mandates Reform Act (UMRA)

    This rule does not contain a Federal mandate that may result in
expenditures of $100 million or more for State, local, and tribal
governments, in the aggregate, or the private sector in any one year.
The total annual incremental costs estimated for the implementation of
this rule are well under $100 million, resulting in expenditures for
the entity groupings required under an UMRA analysis that also fall far
below the $100 million per year threshold. Thus, this rule is not
subject to the requirements of sections 202 or 205 of UMRA.
    This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. Government
responsibilities for oversight and implementation of this rule reside
with State or Federal agencies and not with small governments.

E. Executive Order 13132: Federalism

    Under section 6(b) of Executive Order 13132, EPA may not issue an
action that has federalism implications, that imposes substantial
direct compliance costs, and that is not required by statute, unless
the Federal government provides

the funds necessary to pay the direct compliance costs incurred by
State and Local governments, or EPA consults with State and Local
officials early in the process of developing the proposed action. In
addition, under section 6(c) of Executive Order 13132, EPA may not
issue an action that has federalism implications and that preempts
State law, unless the Agency consults with State and Local officials
early in the process of developing the proposed action.
    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 CO2 should a firm
decide to undertake such a project. Health and risk assessments related
to GS of CO2 and its effects on humans and the environment
are presented in the Vulnerability Evaluation Framework for Geologic
Sequestration of Carbon Dioxide (USEPA, 2008b). Additionally, EPA notes
that it is funding and monitoring research related to the potential for
USDW contamination associated with GS projects. Much of this research
focuses on potential exceedances of drinking water standards (as
suggested), which were developed by EPA and take into account impacts
on children. Please see section II of this Preamble for more details on
this research.

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

    This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. The higher degree of regulatory
certainty and clarity in the permitting process may, in fact, have a
positive effect on the energy sector. Specifically, if climate change
legislation that imposes caps or taxes on CO2 emissions is
passed in the future, energy generation firms and other CO2
producing industries will have an economic incentive to reduce
emissions, and this rule will provide regulatory certainty in
determining how best to meet any new requirements (for example, by
maintaining or increasing production while staying within the emissions
cap or avoiding some carbon taxes). The rule may allow some firms to
extend the life of their existing capital investment in plant machinery
or plant processes.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
    This rulemaking involves environmental monitoring or measurement.
Consistent with the Agency's Performance Based Measurement System
(PBMS), EPA has decided not to require the use of specific, prescribed
analytic methods. Rather, the rule will allow the use of any method
that meets the performance criteria. The PBMS approach is intended to
be more flexible and cost-effective for the regulated community; it is
also intended to encourage innovation in analytical technology and
improved

data quality. While EPA is not precluding the use of any method,
whether it constitutes a voluntary consensus standard or not, as long
as it meets the performance criteria specified, the PBMS approach is
fully consistent with the use of voluntary consensus standards, as such
standards are generally designed to address the same types of criteria
required by PBMS.

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

    Executive Order 12898 (59 FR 7629; February 16, 1994) establishes
Federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it increases the
level of environmental protection for all affected populations.
Existing electric power generation plants that burn fossil fuels may be
more prevalent in areas with higher percentages of people who are
minorities or have lower incomes on average, but it is hard to predict
where new plants with CCS will be built. EPA is developing guidance for
UIC Directors that places emphasis on considering the potential impact
of any Class VI permits on communities (such as minority and low income
populations) when evaluating Class VI injection well permit
applications, as well as provides suggestions and tools for targeted
outreach to ensure more meaningful public input and participation from
the most affected communities during the permit evaluation and approval
process.
    This rule does not require that GS be undertaken; but does require
that if it is undertaken, operators will conduct the activity in such a
way as to protect USDWs from endangerment caused by CO2.
Additionally, this rule will ensure that all areas of the United States
are subject to the same minimum Federal requirements for protection of
USDWs from endangerment from GS. Additional detail regarding the
potential risk of the rule is presented in the Vulnerability Evaluation
Framework for Geologic Sequestration of Carbon Dioxide (USEPA, 2008b).

K. Congressional Review Act

    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 CO2 in
Saline Aquifers. Sally M. Benson, SPE, Stanford University.
Copyright 2008, Offshore Technology Conference.
Birkholzer, J., T. Apps, L. Zheng, Y. Zhang, T. Xu, and C.F. Tsang.
2008a. Research Project on CO2 Geological Storage and
Groundwater Resources: Water Quality Effects Caused by
CO2 Intrusion into Shallow Groundwater. LBNL paper
LBNL-1251E. http://repositories.cdlib.org/lbnl/LBNL-1251E.
Birkholzer, J., Zhou, Q., Zhang, K., Jordan, P., Rutqvist, J., and
C.F. Tsang. 2008b. Research Project on CO2 Geological
Storage and Groundwater Resources: Large-Scale Hydrological
Evaluation and Modeling of the Impact on Groundwater Systems. NETL
Project Annual Report, October 1, 2007 to September 30, 2008.
BLM. 2009. Framework for Geological Carbon Sequestration on Public
Land.
Celia, M.A., S. Bachu, J.M. Nordbotten, S.E. Gasda, and H.K. Dahle.
2004. Quantitative Estimation of CO2 Leakage from
Geological Storage: Analytical Models, Numerical Models, and Data
Needs. p. 663-671. In M. Wilson et al. (ed.) Proc. Int. Conf. on
Greenhouse Gas Control Technologies, 7th, Vancouver, BC, Canada. 5-9
Sept. 2004. Vol. 1. Elsevier Science, Amsterdam.
DOE NETL. 2007. Carbon Sequestration Atlas of the U.S. and Canada.
U.S. Department of Energy, Office of Fossil Energy, National Energy
Technology Laboratory. March 2007.
DOE NETL. 2008. Carbon Sequestration Atlas of the United States and
Canada (Atlas II). Second Edition. National Energy Technology
Laboratory, Pittsburgh, PA, USA.
Dooley, J.J., R.T. Dahowski, C.L. Davidson. 2008. On the Long-Term
Average Cost of CO2 Transport and Storage, Pacific
Northwest National Laboratory, PNNL-17389.
Dooley, J., C. Davidson, and R. Dahowski. 2009. An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009. Joint Global Change Research
Institute. Pacific Northwest National Laboratory. PNNL-18520.
Duncan, I.J., J.P. Nicot, and J.W. Choi. 2009. Risk Assessment for
Future CO2 Sequestration Projects Based on CO2
Enhanced Oil Recovery in the U.S. Energy Procedia 1(1): 2037-2042.
Energy Information Administration (EIA). 2009. Annual Energy Review,
2008.
EPRI. 1999. Enhanced Oil Recovery Scoping Study. Report TR-113836.
GAO. 2008. Climate Change--Federal Actions Will Greatly Affect the
Viability of Carbon Capture and Storage as a Key Mitigation Option.
GAO-08-1080.
GAO. 2010. Climate Change: A Coordinated Strategy Could Focus
Federal Geoengineering Research and Inform Governance Efforts. GAO-
10-903.
Holloway, S., J. Pearce, V. Hards, T. Ohsumi, and J. Gale. 2007.
Natural Emissions of CO2 from the Geosphere and their
Bearing on the Geological Storage of Carbon Dioxide. Energy 32:
1194-1201.
IEA. 2003. Acid Gas Injection: A Study of Existing Operations. Phase
1: Final Report.
IEA. 2008. CO2 Capture and Storage: A Key Abatement
Option. Energy Technology Analysis. Paris: IEA/OECD, 2008.
IPCC. 2005. IPCC Special Report on Carbon Dioxide Capture and
Storage. Prepared by Working Group III of the Intergovernmental
Panel on Climate Change. Metz, B., O. Davidson, H.C. de Coninck, M.
Loos, and L.A. Meyer (eds.). New York: Cambridge University Press.
IRS. 2009. Internal Revenue Service (IRS) Guidance for Tax
Incentives for GS Projects 2009-44 IRB http://www.irs.gov/irb/2009-44_IRB/ar11.html#d0e1860.
Julian, J.Y., G.E. King, J.E. Johns, J.K. Sack, and D.B. Robertson.
2007. Detecting 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 CO2 Injection into Natural Gas Reservoirs for Carbon
Sequestration and Enhanced Gas Recovery. Energy and Fuels 15: 293-
298.
Oil and Gas Journal. 2008. Enhanced Oil Recovery Survey. April 21,
2008, p. 41-59.
Schnaar, G., and D.C. Digiulio. 2009. Computational Modeling of the
Geologic Sequestration of Carbon Dioxide. Vadose Zone J. 8: 389-403.
Skinner, L. 2003. CO2 Blowouts: An Emerging Problem.
World Oil. 224(1).
Somaschini, G., J. Lovell, H. Abdullah, B. Chariyev, P. Singh, and
F. Arachman. 2009. Subsea Deployment of Instrumented Sand Screens in
High-Rate Gas Wells. Presented at SPE Annual Technical Conference
and Exhibition, 4-7 October 2009, New Orleans,

Louisiana. Society of Petroleum Engineers. Paper Number 125047-MS.
USEPA. 2001. Class I Underground Injection Control Program: Study of
the Risks Associated with Class I Underground Injection Wells.
USEPA. 2007. Using the Class V Experimental Technology Well
Classification for Pilot Carbon Geologic Sequestration Projects--
Underground Injection Control Program Guidance (UICPG  83).
March 2007.
USEPA. 2008a. Climate Change--Climate Economics. Economic Analyses.
Updated May 7, 2008. http://www.epa.gov/climatechange/economics/economicanalyses.html.
USEPA. 2008b. Vulnerability Evaluation Framework for Geologic
Sequestration of Carbon Dioxide.
USEPA. 2010. Climate Change Science Facts. 430-10-F-002.
USEPA. 2010a. International Geologic Sequestration Efforts: An
Overview of the Sleipner, Weyburn, and In Salah Projects and Summary
of International Regulatory Developments. 816-R10-011.
USEPA. 2010b. Drinking Water Treatment Considerations: Water
Quality, Carbon Dioxide Concentration, and Geologic Sequestration
Projects. 816-R10-014.
USEPA. 2010c. Technologies Available to Address Induced Faults and
Fractures: Considerations for GS Sites. 816-R10-0018.
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

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:

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

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.
* * * * *

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

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

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;

    (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

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

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

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

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,

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:

    (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

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