Geologic site   Monitoring      well       Area of      Well       MIT     and post-  responsibility   authority    Total
                                                                   characterization              construction    review   operation             injection        \1\          admin
                                                                                site care
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                3 Percent Discount Rate
                                                                  ------------------------------------------------------------------------------------------------------------------------------
Baseline.........................................................           $0.7           $1.8        $10.4        $0.6      $18.5       $0.1       $0.1          $0.0          $0.1      $32.3
Alternative 3....................................................            1.2           10.9         11.0         0.7       21.8        0.7        0.9           0.0           0.1       47.3
Alt 3 Incremental................................................            0.4            9.1          0.6         0.1        3.3        0.6        0.8           0.0           0.0       15.0
Incremental--% of Total..........................................             3%            60%           4%          1%        22%         4%         5%            0%            0%       100%
                                                                  ------------------------------------------------------------------------------------------------------------------------------
                                                                                7 Percent Discount Rate
                                                                  ------------------------------------------------------------------------------------------------------------------------------
Baseline.........................................................           $0.9           $2.1        $12.5        $0.6      $17.3       $0.1       $0.1          $0.0          $0.1      $33.6
Alternative 3....................................................            1.4           12.0         13.3         0.8       20.3        0.7        0.7           0.0           0.1       49.2
Alt 3 Incremental................................................            0.5            9.9          0.8         0.2        3.0        0.6        0.6           0.0           0.0       15.6
Incremental--% of Total..........................................             3%            63%           5%          1%        19%         4%         4%            0%            0%       100%
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Costs related to demonstration of Financial Responsibility are less than $100,000 in annualized terms.

b. Nonquantified Costs and Uncertainties in Cost Estimates
    The purpose of the GS proposed rule is to mitigate any risk
introduced by CO2 GS activity to the quality, and indirectly
the quantity, of current and potential future USDWs. Furthermore, the
rule proposes requirements that are intended to provide redundant
safeguards. In the rare case where the rule, if finalized, is non-
implementable or not readily comprehensible, contamination could occur
to a USDW. In that case, the cost of cleaning up the USDW or finding an
alternative source of drinking water could be attributable to the rule.
Based on data from States regarding implementation of the UIC program
and current research, EPA considers the likelihood of this occurring
very small, and has not quantified this risk.
    Should the final GS rule somehow impede CO2 GS from
happening, then the opportunity costs of not capturing the benefits
associated with GS of CO2 could be attributed to the
regulations; however, the Agency has tried to develop a proposed rule
that balances risk with practicability and economic considerations, and
believes the probability of such impedance is very low. If finalized,
the GS rule would ensure protection of USDWs from GS activities while
also providing regulatory certainty to industry and permitting
authorities and an increased understanding of GS through public
participation and outreach. Thus, EPA believes the proposed rule will
not impede CO2 GS from happening and has not quantified such
risk.
    Uncertainties in the analysis are included in some of the basic
assumptions as well as some detailed cost items. Uncertainties related
to economic trends, the future rate of CCS deployment, and GS
implementation choices may affect three basic assumptions on which the
analysis is based: (1) The estimated number of projects that will be
affected by the GS proposed rule; (2) the labor rates applied; and (3)
the estimated number of monitoring wells to be constructed per
injection well to adequately monitor in a given geologic setting.
    First, the number of projects that will deploy from 2012 through
2036 may be significantly underestimated in this analysis given the
uncertainty in future deployment of this technology. The current
baseline assumption is that 22 projects will deploy during the 25-year
period, as described in Chapter 3 of the proposed rule Cost Analysis
and explained in detail in the Geologic CO2 Sequestration
Activity Baseline (USEPA, 2008f) document.
    Second, the labor rate adopted for each of the labor categories
described in Section 5.2.1 of the Cost Analysis (Geoscientist,
Geological Engineer, State Geologist, and Agency Geologist) may be
underestimated. The practice of CO2 injection represents an
activity that, although already practiced widely in some contexts
(i.e., EOR), is expected to expand rapidly in the coming years. This
expansion may be exponential under certain climate legislative
scenarios, which may lead to shortages in labor and equipment in the
short term, resulting in rapid cost escalation for many of the cost
components discussed in this chapter. (Anecdotal evidence based on
discussions with industry representatives suggests that there may
already be labor shortages developing in some critical disciplines.)
Because the cost analyses presented in this chapter are based on
current industry costs, the level and pace of price responses as the
level of CO2 GS increases represent a highly uncertain
component in the cost estimates presented in this chapter.
    Third, the Agency assumes three monitoring wells per injection well
for the purpose of estimating national costs; however, the Agency
recognizes that

operators and primacy agency Directors may choose more or fewer
monitoring wells depending on project site characteristics. Because the
monitoring wells and associated costs represent a significant component
of the Cost Analysis, the Agency acknowledges that this factor may be
significant in the overall uncertainty of the Cost Analysis. EPA
requests comment on whether three monitoring wells per injection well
is an appropriate costing assumption.
    Additional uncertainties correspond more directly to specific
assumptions made in constructing the cost model. If the assumptions for
such items are incorrect, there may be significant cost implications
outside of the general price level uncertainties discussed above. These
cost items are described in section 5.9.2 of the GS proposed rule Cost
Analysis.
c. Supplementary Cost Information
    To better establish the context in which to evaluate the Cost
Analysis for this proposal, we consider three types of costs that are
not accounted for explicitly for this proposed rule: (1) Costs that are
incurred beyond the 25-year timeframe of the Cost Analysis, (2) costs
that could arise due to a higher rate of deployment of CCS in the
future, and (3) the proportion of overall CCS costs attributable to the
proposed requirements. Because geologic sequestration of CO2
is in the early phase of development, and given the significant
interest in research, development, and eventual commercialization of
CCS, EPA provides a preliminary discussion of the impact of these costs
below.
    The Cost Analysis for this proposed rule explores costs that might
be incurred during a 25-year timeframe.\2\ When analyzing costs for a
commercial size sequestration project that begins in year one of the
Cost Analysis, EPA assumes that the first year is a construction
period, followed by 20 years of injection, followed by 50 years of
post-injection site care as indicated in the proposal. The 20-year
injection period reflects the assumption that a source such as a coal-
fired power plant, with a potential operational lifetime of 40 to 60
years, would plan for the sequestration of only half of its emissions
at a time, rather than incur those costs all at once. EPA requests
comment on this assumption. Given the 25-year timeframe of the
analysis, only the first four years of post-injection care period would
be captured in the Cost Analysis for a project beginning in year 1, and
fewer or no years of post-injection care for a project beginning later
in the 25-year analytical time frame. Based on estimates of the first
four years of the post-injection care period, EPA estimates that the
average costs for one large deep saline project incurred beyond the 25-
year timeframe of the Cost Analysis are approximately $0.30/t
CO2 for the remaining 46 years of post-injection site care.
The full amount of the 46 years of post-injection site care is
incremental to the baseline. The incremental sequestration costs above
the baseline, over the full lifetime of the sequestration project, are
estimated to be $1.20/t CO2. Thus the 25-year timeframe
captures approximately 75% of the lifetime incremental costs associated
with implementing this rule. It should be noted that the longer the
time horizon over which costs are estimated, the greater the
uncertainty surrounding those estimates.
---------------------------------------------------------------------------

    \2\ A detailed discussion of timeframe over which the proposed
requirements were estimated can be found in the Cost Analysis.
---------------------------------------------------------------------------

    The Cost Analysis assumes that 22 projects will inject 350 Mt
CO2 cumulatively over the next 25 years.\3\ The start years
of these projects, for both pilot and large sizes, are staggered over
the 25 years.\4\ Based on the assumed deployment schedule, the analysis
captures the full injection periods for three large-scale projects
(with an injection period of 20 years), 12 pilot projects (with an
injection period of seven years), and partial injection periods for the
remaining seven projects. While the baseline injection amount
represents a significant step towards demonstrating the feasibility of
CCS, it represents a small amount of current CO2 emissions
in the U.S.
---------------------------------------------------------------------------

    \3\ A more detailed discussion of these projects can be found in
the Cost Analysis.
    \4\ A detailed table of the scheduled deployment of projects
assumed in the baseline over the 25-year timeframe can be found in
Exhibit 3.1 of the Cost Analysis.
---------------------------------------------------------------------------

    The U.S. fleet of 1,493 coal-fired generators emits 1,932 Mt
CO2 per year. The technical or economic viability of
retrofitting these or other industrial facilities with CCS is not the
subject of this proposed rulemaking. However, if some percentage of
these facilities undertook CCS, they (or the owner or operator of the
CO2 injection wells) would be subject to the UIC
requirements. For example, if 25% of these facilities undertook CCS
(assuming a 90% capture rate and the incremental proposed rule
sequestration costs outlined in Table VII-4) the incremental
sequestration costs associated with meeting the proposed Class VI
requirements, assuming they are finalized, would be on the order of
$500 million. Similarly, if 100% of these plants undertook CCS, the
incremental costs would be on the order of $2 billion, although it is
unlikely that all coal plants would deploy CCS simultaneously. These
preliminary cost estimates represent the annualized incremental cost of
meeting the additional sequestration requirements in the proposed rule
that would be incurred over the lifetime of the sequestration projects,
assuming that all sequestration projects begin in the same year. These
cost estimates were not generated from a full economic analysis or
included in the Cost Analysis for this proposal, due to the uncertainty
of what percentage, if any, of such facilities will deploy CCS in the
future. These estimates represent a snapshot of potential costs
assuming 25% or 100% of all plants undertake CCS beginning in the same
year, and do not take into consideration CCS deployment rates and
project-specific costs. Actual annualized costs incurred as CCS deploys
in the future could be higher or lower, depending on a number of
factors including deployment rates, capital and labor cost trends, and
the shape of the learning curve.
    Based on current literature, sequestration costs are expected to be
a small component of total CCS project costs. Table VII-4 shows example
total CCS project costs broken down by capture, transportation, and
sequestration components. The largest component of total CCS project
costs is the cost of capturing CO2 ($42/t CO2 for
capture from an Integrated Gasification Combined Cycle power plant
\5\). Transportation costs vary widely depending on the distance from
emission source to sequestration site, but we can use a long-term
average estimate of $3/t CO2.\6\ We estimate total
sequestration costs for a commercial size deep saline project to be
approximately $3.40/t CO2, of which approximately $1.20/t
CO2 is attributable to complying with requirements of this
proposed rule (including the full 50 years of post-injection site
care). Based on the project costs outlined in Table VII-4, the proposed
requirements amount to approximately 3% of the total CCS project costs.
---------------------------------------------------------------------------

    \5\ Cost and Performance Baseline for Fossil Energy Plants, Vol.
1, DOE/NETL-2007/1281, May 2007.
    \6\ On the Long-Term Average Cost of CO2 Transport
and Storage, JJ Dooley, RT Dahowski, CL Davidson, Pacific Northwest
National Laboratory Operated for the U.S. Department of Energy by
Battelle Memorial Institute, PNNL-17389, March 2008.

              Table VII-4.--Example Total CCS Project Costs
------------------------------------------------------------------------
  Example Total CCS project costs  (including capture at an IGCC plant,
      transportation, and deep saline reservoir at commercial scale
                             sequestration)
-------------------------------------------------------------------------
                                             Cost over     Percentage of
                                            lifetime of      total CCS
                                           project  ($/    project cost
                                               tCO2)            (%)
------------------------------------------------------------------------
Capture (IGCC plant)....................          $42.00              87
Transportation Estimate.................            3.00               6
Baseline Sequestration..................            2.20               4
Incremental Proposed Rule Sequestration             1.20               3
 Requirements...........................
                                         -------------------------------
    Total CCS Project Cost..............           48.40  ..............
------------------------------------------------------------------------

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

a. Costs Relative to Benefits; Maximizing Net Social Benefits
    Because EPA lacks the data to perform a quantified analysis of
benefits, a direct numerical comparison of costs to benefits cannot be
done. Costs can only be compared to qualitative relative risks as
discussed in section VII-1.
    Compared to the baseline, RA3 provides greater protection to USDWs
because it is specifically tailored to the injection of CO2.
The current regulatory requirements do not specifically consider the
injection of a buoyant corrosive fluid. In particular, RA3 includes
increased monitoring requirements that provide the amount of protection
the Agency estimates is necessary for USDWs. As described in the prior
section (A. National Benefits and Costs of the Proposed Rule),
monitoring requirements account for 60 percent of the incremental
regulatory costs, of which 70 percent is incurred for the construction,
operation, and maintenance of monitoring wells, and the other 30
percent for tracking of the plume and pressure front through complex
modeling at a minimum of every 10 years for all operators (the cost
model assumes every 5 years) and monitoring for CO2 leakage.
Public awareness of these protective measures would be expected to
enhance public acceptance of CO2 GS.
    RA1 and RA2 do not provide the specific safeguards against
CO2 migration that RA3 does because of a significantly
greater amount of discretion allowed to Directors and operators for
interpreting requirements, and less stringent requirements for some
compliance activities. (Only RA3 and RA4 require the periodic complex
modeling exercise for tracking the plume, for example.) RA4 provides
greater safeguards against CO2 migration, but at a much
higher cost.
b. Cost Effectiveness and Incremental Net Benefits
    RA1 and RA2 provide lower costs than RA3 but at increased levels of
risk to USDWs. Although RA4 has more stringent requirements, EPA does
not believe that the increased requirements and the increased costs are
necessary to provide protection to USDWs. Therefore EPA believes that
RA3 is the best alternative.

C. Conclusions

    RA3 provides a high level of protection to USDWs overlying
injection zones of CO2. It does so at lower costs than the
more stringent RA4 while providing significantly more protection than
RA1 or RA2. Therefore EPA believes RA3 is the preferred regulatory
alternative. The Agency seeks comment on cost assumptions in today's
proposal.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993),
this action is a ``significant regulatory action.'' Accordingly, EPA
submitted this action to the Office of Management and Budget (OMB) for
review under EO 12866 and any changes made in response to OMB
recommendations have been documented in the docket for this action.

B. Paperwork Reduction Act (PRA)

    The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) document prepared by EPA has been
assigned EPA ICR number 2309.01.
    The information collected as a result of this proposed rule will
allow EPA and State permitting authorities to review geologic
information about a proposed GS site to evaluate its suitability for
safe and effective GS. It also allows the Agency to verify throughout
the life of the injection project that UIC protective requirements are
in place and that USDWs are protected. The Paperwork Reduction Act
requires EPA to estimate the burden on owners or operators of
CO2 GS wells, and States, Territories, and Tribes with
primacy. Burden is defined at 5 CFR 1320.3(b).
    For GS well operators applying for permits, this burden includes
the time, effort, and financial resources needed to collect information
to furnish EPA with the following information:

--UIC permit applications and information to support the site
characterization, such as maps and cross sections, information on the
geologic structure, hydrogeologic properties, and baseline geochemical
data on the proposed site.
--AoR and corrective action plan.
--Testing and monitoring plan.
--Well plugging and post-injection site care plans.
--Emergency and remedial response plans.
--Reports of well logs and tests performed during well construction.
--Periodic updates to the AoR models and corrective action status.
--Demonstration of financial responsibility and periodic updates.
--Periodic reports of monitoring and testing.
--Reports of post-injection monitoring.
--Non-endangerment demonstrations and the conclusion of all post-
injection site care.

    For the first 3 years after publication of the final rule in the
Federal Register, the major information requirements apply to operators
of GS wells that are submitting an application for the construction of
a CO2 GS well (or seeking a Class VI permit for an existing
well) or monitoring and MIT data during the operation of the GS
project.

    States and Tribes with primacy will incur burden associated with
the following activities:

--Applying for primacy.
--Reviewing permit applications and associated data submitted by
operators (including the testing and monitoring plan, AoR and
corrective action plan, injection well plugging plan, post-injection
site care and closure plan, and emergency and remedial response plan).
--Making decisions on whether to grant or deny permits and writing
permits.
--Reviewing testing and monitoring data submitted by operators, e.g.,
continuous monitoring and MIT results.

    For the first 3 years after publication of the final rule in the
Federal Register, preparing primacy applications will account for the
majority of primacy agency burden. This is a one-time burden to each
State or Tribe that seeks primacy and, in subsequent ICRs, primacy
agency burden is expected to decrease by approximately 90 percent.
    The collection requirements are mandatory under the SDWA (42 U.S.C.
300h et seq.). Calculation of the information collection burden and
costs associated with today's proposal can be found in the Information
Collection Request for the Federal Requirements Under the Underground
Injection Control Program for Carbon Dioxide Geologic Sequestration
Wells (USEPA, 2008g), available through http://www.regulation.gov under
Docket ID EPA-HQ-OW-2008-0390.
    As shown in Table VIII-1, the total burden associated with the
proposed rule over the 3 years following promulgation is 62,117 hours,
or an average of 20,706 hours per year. The total cost over this period
is $7.3 million, or an average of $2.4 million per year. The average
burden per response for each activity that requires a collection of
information is 164 hours; the average cost per response is $19,310.
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information request 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.
    To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, EPA has established a public docket for
this proposed rule under Docket ID number EPA-HQ-OW-2008-0390. Submit
any comments related to the ICR to EPA and OMB. See ADDRESSES section
at the beginning of this notice for where to submit comments to EPA.
Send comments to OMB at the Office of Information and Regulatory
Affairs, Office of Management and Budget, 725 17th Street, NW.,
Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is
required to make a decision concerning the ICR between 30 and 60 days
after July 25, 2008, a comment to OMB is best assured of having its
full effect if OMB receives it by August 25, 2008. The final rule will
respond to any OMB or public comments on the information collection
requirements contained in this proposal.

    Table VIII-1.--Annual, Total, and Annual Average Burden Hours and Costs for the Proposed Rule Information
                                    Collection Request 3-Year Approval Period
----------------------------------------------------------------------------------------------------------------
                                                                                Annual
                                      Year 1          Year 2          Year 3           Total          average
----------------------------------------------------------------------------------------------------------------
                   Total (Owners/Operators, Primay Agencies, and DI Programs/EPA Headquarters)
----------------------------------------------------------------------------------------------------------------
Burden (in hours)...............        21,934.2        18,293.7        18,435.2        62,117.0        20,705.7
Respondents.....................            24.3            28.2            29.9            47.0            27.5
Responses.......................           131.0           113.0           129.0           378.0           126.0
Costs ($).......................      $3,412,795      $2,428,168      $2,702,335      $7,299,064      $2,433,021
    Labor ($)...................      $1,132,302        $877,087        $887,616      $3,145,843      $1,048,614
    Non-Labor ($)...............      $2,280,493      $1,551,081      $1,814,719      $4,119,644      $1,373,215
Burden per Response.............           167.4           161.9           142.9           164.3           164.3
Cost per Response...............         $26,052         $21,488         $20,948         $19,310         $19,310
Burden per Respondent...........           901.4           648.4           615.9         1,321.6           753.1
Cost per Respondent.............        $140,252         $86,065         $90,278        $155,299         $88,495
----------------------------------------------------------------------------------------------------------------
                                                Operators/Owners
----------------------------------------------------------------------------------------------------------------
Burden (in hours)...............         5,359.5         2,118.0         2,228.5        13,160.0         4,386.7
Respondents.....................             3.0             4.0             5.0             5.0             4.0
Responses.......................            63.0            54.0            65.0           187.0            62.3
Costs ($).......................      $2,678,179      $1,711,130      $1,983,931      $5,129,006      $1,709,669
    Labor ($)...................        $397,687        $160,049        $169,212        $975,786        $325,262
    Non-Labor ($)...............      $2,280,493      $1,551,081      $1,814,719      $4,119,644      $1,373,215
Avg. Burden per Response........            85.1            39.2            34.3            70.4            70.4
Avg. Cost per Response..........         $42,511         $31,688         $30,522         $27,428         $27,428
Burden per Respondent...........         1,786.5           529.5           445.7           2,632         1,096.7
Cost per Respondent.............        $892,726        $427,783        $396,786      $1,025,801        $427,417
----------------------------------------------------------------------------------------------------------------
                                                Primacy Agencies
----------------------------------------------------------------------------------------------------------------
Burden (in hours)...............        11,278.8        10,990.7        11,013.1        33,281.8        11,093.9
Respondents.....................            10.3            13.2            13.9            31.0            12.5
Responses.......................            36.3            29.8            33.4            99.4            33.1
Costs ($).......................        $475,547        $463,433        $464,374      $1,403,354        $467,785
    Labor ($)...................        $475,547        $463,433        $464,374      $1,403,354        $467,785
    Non-Labor ($)...............  ..............  ..............  ..............  ..............  ..............
Burden per Response.............           311.1           369.1           330.0         1,010.2           336.7
Cost per Response...............         $13,117         $15,565         $13,915         $42,597         $14,199
Burden per Respondent...........         1,091.4           831.8           790.4         2,713.6           904.5

Cost per Respondent.............         $46,021         $35,073         $33,328        $114,422         $38,141
----------------------------------------------------------------------------------------------------------------
                                          DI Programs/EPA Headquarters
----------------------------------------------------------------------------------------------------------------
Burden (in hours)...............         5,296.6         5,184.9         5,193.6        15,675.2         5,225.1
Respondents.....................            11.0            11.0            11.0            11.0            11.0
Responses.......................            31.7            29.2            30.6            91.6            30.5
Costs ($).......................        $259,069        $253,605        $254,029        $766,703        $255,568
    Labor ($)...................        $259,069        $253,605        $254,029        $766,703        $255,568
    Non-Labor ($)...............  ..............  ..............  ..............  ..............  ..............
Burden per Response.............           166.8           177.4           169.6           171.1           171.1
Cost per Response...............          $8,161          $8,677          $8,294          $8,370          $8,370
Burden per Respondent...........           481.5           471.4           472.1         1,425.0           475.0
Cost per Respondent.............         $23,552         $23,055         $23,094         $69,700         $23,233
----------------------------------------------------------------------------------------------------------------
Note: Numbers may not appear to add due to rounding.

C. Regulatory Flexibility Act (RFA)

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure 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 proposed rule on small entities,
small entity is defined as: (1) A small business as defined by the
Small Business Administration's (SBA) regulations at 13 CFR 121.201;
(2) 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 (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not
dominant in its field.
    After considering the economic impacts of today's proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. This
proposed rule will not impose any requirements on small entities.
Sequestering CO2 via injection wells is a voluntary action
that would only be undertaken by a small entity if it were in its
interest compared to other alternatives it may have. GS of
CO2 is still a scientifically 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. We continue to be interested in the
potential impacts of the proposed rule on small entities and welcome
comments on issues related to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA regulation for which a written
statement is needed, section 205 of UMRA generally requires EPA to
identify and consider a reasonable number of regulatory alternatives
and adopt the least costly, most cost-effective or least burdensome
alternative that achieves the objectives of the rule. The provisions of
section 205 do not apply when they are inconsistent with applicable
law. Moreover, section 205 allows EPA to adopt an alternative other
than the least costly, most cost-effective or least burdensome
alternative if the Administrator publishes with the final rule an
explanation why that alternative was not adopted. Before EPA
establishes any regulatory requirements that may significantly or
uniquely affect small governments, including tribal governments, it
must have developed under section 203 of UMRA a small government agency
plan. The plan must provide for notifying potentially affected small
governments, enabling officials of affected small governments to have
meaningful and timely input in the development of EPA regulatory
proposals with significant Federal intergovernmental mandates, and
informing, educating, and advising small governments on compliance with
the regulatory requirements.
    Based on the analysis of 22 pilot projects, EPA has determined that
this proposed 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.
Expenditures associated with compliance for these projects, defined as
the incremental costs beyond the existing regulations under which a
CO2 GS well could be permitted and deployed, will not
surpass $100 million in the aggregate in any year. Thus, today's
proposed rule is not subject to the requirements of sections 202 and
205 of UMRA. However, EPA recognizes that if CCS is used more widely,
the incremental costs of the requirements associated with this rule
could exceed $100 million in the aggregate in some years. EPA will
determine the applicability of UMRA for the final rule and provide any
necessary analysis.
    EPA has determined that this proposed rule contains no regulatory
requirements that might significantly or uniquely affect small
governments. Most regulated entities are anticipated to be private
entities, not governments.

E. Executive Order 13132: Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have Federalism

implications.'' ``Policies that have Federalism implications'' is
defined in the Executive Order to include regulations that have
``substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government.''
    This proposed rule does not have Federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. Currently, States may gain the
authority to regulate a full or partial UIC program in their State by
applying for primacy. States with primacy must develop a program
incorporating all new Federal requirements for Class VI wells if they
wish to regulate CO2 GS, and all programs will be subject to
EPA approval. Since application for primacy is a voluntary process, the
addition of this proposed regulation to the UIC regulations should not
significantly impact States or their right to primacy for other classes
of wells. If States do not develop a program for Class VI wells, EPA
will oversee CO2 GS in those States. Thus, Executive Order
13132 does not apply to this proposal.
    Although section 6 of Executive Order 13132 does not apply to this
rule, EPA did consult with State and local officials early in the
process of developing this proposed rule to permit them to have
meaningful and timely input in its development. EPA sent letters with
background about the rulemaking and an invitation for consultation to
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. EPA held a meeting with interested parties from these
organizations in April 2008.
    In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed rule
from State and local officials. A summary of the concerns raised during
that consultation and EPA's response to those concerns will be provided
in the preamble to the final rule.

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

    Executive Order 13175, entitled ``Consultation and Coordination
With Indian Tribal Governments'' (65 FR 67249, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' This proposed rule does not
have tribal implications as specified in Executive Order 13175.
Currently, no Indian Tribes have primacy. However, Indian Tribes may
acquire authority to regulate a partial or full UIC program in lands
under their jurisdiction by applying for and gaining primacy from the
Agency. Tribes seeking primacy must develop requirements at least as
stringent as the new proposed Federal requirements for Class VI wells
if they wish to regulate CO2 GS, and all programs will be
subject to EPA approval. If Tribes do not develop a program for Class
VI wells, EPA is responsible for regulating the GS of CO2 on
tribal lands. The application for primacy is a voluntary process.
Furthermore, this proposal clarifies regulatory ambiguity rather than
placing new requirements on tribal or other governmental entities.
Therefore, this proposed rule should not change the Tribal-Federal
relationship and should not significantly impact Tribes. Thus,
Executive Order 13175 does not apply to this proposed rule.
    Although Executive Order 13175 does not apply to this proposed
rule, EPA consulted with tribal officials in developing this proposed
rule. EPA sent letters with background about the rulemaking and an
invitation for consultation to all of the federally recognized Indian
Tribes. EPA held a meeting with interested parties from Tribal
governments in April 2008.
    EPA specifically solicits additional comment on this proposed rule
from tribal officials.

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 in EO
12866, and because the Agency does not believe the environmental health
or safety risks addressed by this action present a disproportionate
risk to children. Moreover, this proposed rule will not require that
CO2 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. This action's
health and risk assessments are contained in Risk and Occurrence
Document for Geologic Sequestration Proposed Rulemaking (USEPA, 2008e).
    The public is invited to submit comments or identify peer-reviewed
studies and data that assess the effects of early life exposure to
changes in drinking water quality that may be caused by geologic
sequestration of carbon dioxide.

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

    EPA has tentatively determined that this rule is not a
``significant energy action'' as defined in Executive Order 13211,
``Actions Concerning Regulations That Significantly Affect Energy
Supply, Distribution, or Use'' (66 FR 28355, May 22, 2001) because
application of these requirements to the 22 pilot projects is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. EPA will consider the potential effects
of more widespread application of the rule requirements and make a
final determination regarding EO 13211 applicability for the final rule
(see UMRA discussion above).
    The higher degree of regulatory certainty and clarity in the
permitting process may, in fact, have a positive effect on the energy
sector. Specifically, if climate change legislation that imposes caps
or taxes on CO2 emissions is passed in the future, energy
generation firms and other CO2 producing industries will
have an economic incentive to reduce emissions, and this rule will
provide regulatory certainty in determining how to maximize operations
(for example, by increasing production while staying within the
emissions cap or avoiding some carbon taxes). The proposed rule may
allow some firms to extend the life of their existing capital
investment in plant machinery or plant processes.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards

bodies. NTTAA directs EPA to provide Congress, through OMB,
explanations when the Agency decides not to use available and
applicable voluntary consensus standards.
    The proposed rulemaking involves technical standards. Therefore,
the Agency conducted a search to identify potentially applicable
voluntary consensus standards. However, we identified no such
standards, and none were brought to our attention. Thus the Agency
decided to convene numerous workshops (discussed further in Chapter 2
of the Cost Analysis for the GS proposed rule) to develop standards
based on current information available from experts in industry,
government, and non-governmental organizations. EPA proposes to use a
combination of technologies and standard practices that it estimates
will provide the necessary protection to USDWs with regard to site
characterization, construction, operation, monitoring, closure, and
post-closure requirements for CO2 GS wells, without placing
undue burden on well operators. These methods are listed in Chapter 2
of the Cost Analysis for the GS proposed rule and described in further
detail in the Geologic CO2 Sequestration Technology & Cost Analysis
(USEPA, 2008h) developed in support of this proposed rule.
    EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially
applicable voluntary consensus standards and to explain why such
standards should be used in this regulation.

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

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 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, any 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 proposed 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 without
having any disproportionately high and adverse human health or
environmental effects on any population, including any minority or low-
income population.
    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. This proposed rule
would not require that CO2 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 proposed rule if finalized 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 proposed
rule is presented in the Risk and Occurrence Document for Geologic
Sequestration Proposed Rulemaking (USEPA, 2008e).
    EPA believes that UIC permit writers should consider the impact of
GS on any communities in the geographic areas of GS sites. Permit
writers can ask specific questions to specifically address any
potentially different impacts on minority and/or low-income
communities. Examples include: In reviewing the application or Notice
of Intent (NOI) for a GS permit, is there any indication that a
minority and/or low-income community would be adversely affected? Are
there measures that should be undertaken to understand minority and/or
low-income community concerns during the permit drafting and
development phase, including the development of permit conditions? If
an environmental justice issue is identified, does the program solicit
input and participation from minority and/or low-income populations?
    EPA seeks comment on environmental justice considerations for GS
permit writers.

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Harris, J.M. and R.T. Langan. 2001. Crosswell Seismic Profiling:
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CO2 in a Tree-Kill Soil at Mammoth Mountain, California:
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List of Subjects

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 146

    Environmental protection, Hazardous waste, Indian lands, Reporting
and recordkeeping requirements, Water supply.

    Dated: July 15, 2008.
Stephen L. Johnson,
Administrator.
    For the reasons set forth in the preamble, title 40 chapter I of
the Code of Federal Regulations is proposed to be amended as follows:

PART 144--UNDERGROUND INJECTION CONTROL PROGRAM

    1. The authority citation for part 144 continues to read as
follows:

    Authority: 42 U.S.C. 300f et seq.; Resource Conservation and
Recovery Act, 42 U.S.C. 6901 et seq.

Subpart A--General Provisions

    2. Section 144.1 is amended as follows:
    a. Adding new paragraph (f)(1)(viii); and
    b. Revising the first two sentences in paragraph (g) introductory
text.

Sec.  144.1  Purpose and scope of part 144.

* * * * *
    (f) * * *
    (1) * * *
    (viii) Subpart H of this part 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 injections 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. * * *
* * * * *
    3. Section 144.6 is amended as follows:
    a. Revising paragraph (e); and
    b. Adding new paragraph (f).

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 used for geologic sequestration of carbon
dioxide beneath the lowermost formation containing a USDW.

Subpart B--General Program Requirements

    4. Adding Sec.  144.15 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.
    5. Adding Sec.  144.18 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 are not authorized by rule to inject.

Subpart D--Authorization by Permit

    6. Section 144.36 is amended by revising the first two sentences in
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, III and VI wells
shall be issued for a period up to the operating life of the facility.
* * *
* * * * *
    7. Section 144.39 is amended by revising the second sentence in
paragraph (a) introductory text and by revising the second sentence in
paragraph (a)(3) introductory text 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 terms for this cause only as follows: * * *
* * * * *

Subpart E--Permit Conditions

    8. Section 144.51 is amended by revising the first sentence in
paragraph (q)(1) and the first sentence in paragraph (q)(2) to read as
follows:

Sec.  144.51  Conditions applicable to all permits.

* * * * *
    (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 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.  146.8 or Sec.  146.89 for
Class VI of this chapter, he/she shall give written notice of his/her
determination to the owner or operator. * * *
* * * * *
    9. Section 144.52 is amended by revising paragraph (a)(8) to read
as follows:

Sec.  144.52  Establishing permit conditions.

    (a) * * *
    (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.  146.08 or Sec.  146.89 for Class VI that the
well has mechanical integrity.
* * * * *

    10. Section 144.55 is amended by revising the first sentence in
paragraph (a) to read as follows:

Sec.  144.55  Corrective action.

    (a) Coverage. Applicants for Class I, II, (other than existing),
III or VI injection well permits shall identify the location of all
known wells within the injection well's area of review which penetrate
the injection zone, or in the case of Class II wells operating over the
fracture pressure of the injection formation, all known wells within
the area of review penetrating formations affected by the increase in
pressure. Applicants for Class VI shall perform corrective action as
specified in Sec.  146.84.* * *
* * * * *

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

    11. 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.

PART 146--UNDERGROUND INJECTION CONTROL PROGRAM: CRITERIA AND
STANDARDS

    12. 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.

    13. Section 146.5 is amended as follows:
    a. Revising the first sentence in paragraph (e) introductory text;
and
    b. Adding paragraph (f).

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 used for geologic sequestration of carbon
dioxide beneath the lowermost formation containing an underground
source of drinking water (USDW).
    14. 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.

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 Class VI carbon dioxide geologic
sequestration injection wells.
    (b) This subpart applies to 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 applies to owners and operators of permit or rule-
authorized Class I industrial, 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. If the Director
determines that USDWs will not be endangered, such wells are exempt, at
the Director's discretion, from the casing and cementing requirements
at Sec. Sec.  146.86(b) and 146.87(a)(1) through (3).
    (d) Definitions. The following definitions apply to this subpart.
To the extent that these definitions conflict with those in Sec.  146.3
these definitions govern:
    Area of review means the region surrounding the geologic
sequestration project that may be impacted by the injection activity.
The area of review is based on computational modeling that accounts for
the physical and chemical properties of all phases of the injected
carbon dioxide stream.
    Carbon dioxide plume means the underground extent, 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 that
acts as a barrier to fluid movement.
    Corrective action means the use of Director approved methods to
assure that wells within the area of review do not serve as conduits
for the movement of fluids into underground sources of drinking water
(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 its 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. It includes the subsurface three-dimensional extent
of the carbon dioxide plume, associated pressure front, and displaced
brine, as well as the surface area above that delineated region.
    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 assure 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 the point/time, as determined by the Director
following the requirements under Sec.  146.93, at which the owner or
operator of a GS site is released from post-injection site care
responsibilities.
    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 the owner or operator
must submit to the Director in order to be permitted as a Class VI
well. The application for a permit for construction and operation of a
Class VI well must include the following:
    (a) Information required in 40 CFR 144.31(e)(1) through (6);
    (b) A map showing the injection well(s) for which a permit is
sought and the applicable area of review. 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 and other pertinent surface features
including structures intended for human occupancy 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;
    (c) The area of review based on modeling, using data obtained
during logging and testing of the well and the formation as required by
paragraphs (l), (r), and (s) of this section;
    (d) Information on the geologic structure and hydrogeologic
properties of the proposed storage site and overlying formations,
including:
    (1) Maps and cross sections of the area of review;
    (2) 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;
    (3) Information on seismic history including the presence and depth
of seismic sources and a determination that the seismicity would not
interfere with containment;
    (4) 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;
    (5) Geomechanical information on fractures, stress, ductility, rock
strength, and in situ fluid pressures within the confining zone; and
    (6) Geologic and topographic maps and cross sections illustrating
regional geology, hydrogeology, and the geologic structure of the local
area.
    (e) 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;
    (f) 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;
    (g) Baseline geochemical data on subsurface formations, including
all USDWs in the area of review;
    (h) Proposed operating data:
    (1) Average and maximum daily rate and volume of the carbon dioxide
stream;
    (2) Average and maximum injection pressure;
    (3) The source of the carbon dioxide stream; and
    (4) An analysis of the chemical and physical characteristics of the
carbon dioxide stream;
    (i) The compatibility of the carbon dioxide stream with fluids in
the injection zone 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;
    (j) Proposed formation testing program to obtain an analysis of the
chemical and physical characteristics of the injection zone and
confining zone;
    (k) Proposed stimulation program and a determination that
stimulation will not interfere with containment;
    (l) The results of the formation testing program as required in
paragraph (j) of this section;
    (m) Proposed procedure to outline steps necessary to conduct
injection operation;
    (n) Schematic or other appropriate drawings of the surface and
subsurface construction details of the well;
    (o) Injection well construction procedures that meet the
requirements of Sec.  146.86;
    (p) Proposed area of review and corrective action plan that meets
the requirements under Sec.  146.84;
    (q) The status of corrective action on wells in the area of review;
    (r) All available logging and testing program data on the well
required by Sec.  146.87;
    (s) A demonstration of mechanical integrity pursuant to Sec.
146.89;
    (t) A demonstration, satisfactory to the Director, that the
applicant has met the financial responsibility requirements under Sec.
146.85;
    (u) Proposed testing and monitoring plan required by Sec.  146.90;
    (v) Proposed injection well plugging plan required by Sec.
146.92(b);
    (w) Proposed post-injection site care and site closure plan
required by Sec.  146.93(a);
    (x) Proposed emergency and remedial response plan required by Sec.
146.94; and
    (y) Any other information requested by the Director.

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 geologic system must be comprised of:
    (1) An injection zone of sufficient areal extent, thickness,
porosity, and permeability to receive the total anticipated volume of
the carbon dioxide stream;
    (2) A confining zone(s) that is 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); and
    (b) At the Director's discretion, owners or operators of Class VI
wells must 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 that may be impacted by the injection activity.
The area of review is based on computational modeling that accounts for
the physical and chemical properties of all phases of the injected
carbon dioxide stream.
    (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. 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 10 years, 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, identify all wells
that require corrective action, and perform corrective action on those
wells:
    (1) Predict, using 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, pressure differentials sufficient to cause
the movement of injected fluids or formation fluids into a USDW are no
longer present, or after 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, confining zone and any additional zones; and
anticipated operating data, including injection pressures, rates and
total volumes over the proposed life of the geological sequestration
project;
    (ii) Take into account any geologic heterogeneities, 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.
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 (as required by Sec.  146.92) in a manner that prevents the
movement of carbon dioxide or associated fluids that may endanger
USDWs.
    (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 necessary to prevent the movement of
fluid into or between USDWs including use of corrosion resistant
materials, where appropriate.
    (e) If monitoring data indicate an endangerment to USDWs, the owner
or operator must notify the Director and cease operations as required
by Sec.  146.94.
    (f) At the minimum fixed frequency, not to exceed 10 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)(2) 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 (c)(3) 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.
    (g) The emergency and remedial response plan (as required by Sec.
146.94) and a demonstration of financial responsibility (as described
by Sec.  146.85) must account for the entire area of review, regardless
of whether or not corrective action in the area of review is phased.

Sec.  146.85  Financial responsibility.

    (a) The owner or operator must demonstrate and maintain financial
responsibility and resources for corrective action (that meets the
requirements of Sec.  146.84), injection well plugging (that meets the
requirements of Sec.  146.92), post-injection site care and site
closure (that meets the requirements of Sec.  146.93), and emergency
and remedial response (that meets the requirements of Sec.  146.94) in
a manner prescribed by the Director until:
    (1) The Director receives and approves the completed post-injection
site care and site closure plan; and
    (2) The Director determines that the site has reached the end of
the post-injection site care period.
    (b) The owner or operator must provide to the Director, at a
frequency determined by the Director, written updates of adjustments to
the cost estimate to account for any amendments to the area of review
and corrective action plan (Sec.  146.84), the injection well plugging
plan (Sec.  146.92), and the post-injection site care and site closure
plan (Sec.  146.93).
    (c) The owner or operator must notify the Director 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.
    (d) The operator must provide an adjustment of the cost estimate to
the Director if the Director has reason to believe that the original
demonstration is no longer adequate to cover the cost of injection well
plugging (as required by Sec.  146.92) and post-injection site care and
site closure (as required by Sec.  146.93).

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 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;
    (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 zones;
    (viii) Type or grade of cement; 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.
    (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) All owner and 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.
    (2) 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);
    (iii) Injection pressure;
    (iv) Annular pressure;
    (v) Injection rate (intermittent or continuous) and volume of the
carbon dioxide stream;
    (vi) Size of 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 assure 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 are enlarged by reaming or another method.
Such checks must be at sufficiently frequent intervals to determine the
location of the borehole and to assure 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, 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, if required by the Director; and
    (5) Any alternative methods that provide equivalent or better
information and that are required of and/or approved of by the
Director.
    (b) The owner or operator must take and submit to the Director
whole cores or sidewall cores of the injection zone and confining
system and formation fluid samples from the injection zone(s). The
Director may accept 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 the 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 zones; and
    (3) Physical and chemical characteristics of the formation fluids
in the injection zone.
    (e) Upon completion, but prior to operation, the owner or operator
must conduct the following tests to verify hydrogeologic
characteristics of the injection zone:
    (1) A pump test; or
    (2) 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 so as to assure that the injection does
not initiate new fractures or propagate existing fractures in the
injection zone. In no case may injection pressure initiate fractures in
the confining zone(s) or cause the movement of injection or formation
fluids that endangers a USDW.
    (b) Injection between the outermost casing protecting USDWs and the
well bore is prohibited.
    (c) The owner or operator must fill the annulus between the tubing
and the long string casing with a non-corrosive fluid approved by the
Director. The owner or operator must maintain on the annulus a pressure
that exceeds the operating injection pressure, unless the

Director determines that such requirement might harm the integrity of
the well.
    (d) Other than during periods of well workover (maintenance)
approved by the Director in which the sealed tubing-casing annulus is
of necessity 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 continuous recording
devices to monitor: The injection pressure; the rate, volume, 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 must install and use alarms and automatic down-hole shut-
off systems, designed to alert the operator and shut-in the well when
operating parameters such as annulus pressure, injection rate or other
parameters approved by the Director diverge beyond permitted ranges
and/or gradients specified in the permit;
    (f) If a down-hole automatic shutdown 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 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, and pressure on the annulus between tubing and long
stem 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) A tracer survey such as oxygen-activation logging;
    (2) A temperature or noise log; or
    (3) A casing inspection log, if required by the Director.
    (d) The Director may require any other test to evaluate mechanical
integrity under paragraph (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, the Director must submit a
written request to the Administrator, which must set forth the proposed
test and all technical data supporting its use. The Administrator must
approve the request if 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.
    (e) 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.
    (f) The Director may require additional or alternative tests if the
results presented by the owner or operator under paragraph (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 significant
movement of fluid into or between USDWs 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 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. 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.  146.86(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;
    (c) Corrosion monitoring of the well materials for loss of mass,
thickness, cracking, pitting and other signs of corrosion must be
performed on a quarterly basis to ensure that the well components meet
the minimum standards for material strength and performance set forth
in Sec.  146.86(b) by:
    (1) Placing coupons of the well construction materials 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; 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 or additional identified
zones:
    (1) The location and number of monitoring wells must be based on
specific information about the geologic sequestration project,
including injection rate and volume, geology, the presence of
artificial penetrations and other factors;
    (2) The monitoring frequency and spatial distribution of monitoring
wells must be based on baseline geochemical data that has been
collected under Sec.  146.82(a)(6) and any modeling results in the area
of review evaluation required by Sec.  146.84(b);
    (e) A demonstration of external mechanical integrity pursuant to
Sec.  146.89(c) at least once per year throughout the duration of the
geologic sequestration project;
    (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 position of the pressure front by either
monitoring for pressure changes in the first formation overlying the
confining zone or using indirect, geophysical techniques (e.g.,
seismic, electrical, gravity, or electromagnetic surveys and/or down-
hole carbon dioxide detection tools);
    (h) At the Director's discretion, surface air monitoring and/or
soil gas monitoring to detect movement of carbon dioxide that could
endanger a USDW.
    (1) The testing and monitoring plan must be based on potential
vulnerabilities within the area of review;
    (2) The monitoring frequency and spatial distribution of surface
air monitoring and/or soil gas monitoring must reflect baseline data
and the monitoring plan must include how the proposed monitoring will
yield useful information on the area of review delineation and/or
compliance with standards under 40 CFR 144.12;
    (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(b) and to
determine compliance with standards under 40 CFR 144.12; and
    (j) 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 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 as specified in the permit;
    (4) A description of any event which triggers a shutdown device
required pursuant to Sec.  146.88(e) and the response taken;
    (5) The monthly volume of the carbon dioxide stream injected over
the reporting period and project cumulatively;
    (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 other test of the injection well conducted by the permittee
if required by the Director; and
    (3) Any well workover.
    (c) Owners or operators must submit reports in an electronic format
acceptable to the Director. At the discretion of the Director, other
formats may be accepted.

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 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 test or measure to determine bottomhole reservoir
pressure;
    (2) Appropriate testing methods to ensure 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 and 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 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. At
the discretion of the Director, a shorter notice period may be allowed.
    (d) Plugging report. Within 60 days after plugging or at the time
of the next semi-annual report (whichever occurs earlier) the owner or
operator must submit a plugging report to the Director. If the semi-
annual report is due less than 15 days after completion of plugging,
then the report must be submitted within 60 days after plugging. 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.)

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.
    (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;
    (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(b);
    (iii) A description of post-injection monitoring location, methods,
and proposed frequency; and
    (iv) A proposed schedule for submitting post-injection site care
monitoring results to the Director.
    (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.
    (4) The owner or operator may modify and resubmit the post-
injection site care and site closure plan for the Director's approval
within 30 days of such change.
    (b) The owner or operator shall monitor the site following the
cessation of injection to show the position of the carbon dioxide plume
and pressure front and demonstrate that USDWs are not being endangered.
    (1) The owner or operator shall continue to conduct monitoring as
specified in the Director-approved post-injection site care and site
closure plan for at least 50 years following the cessation of
injection. At the Director's discretion, the monitoring will continue
until the geologic sequestration project no longer poses an
endangerment to USDWs.
    (2) If the owner or operator can demonstrate to the satisfaction of
the Director before 50 years, based on monitoring and other site-
specific data, that the geologic sequestration project

no longer poses an endangerment to USDWs, the Director may approve an
amendment to the post-injection site care and site closure plan to
reduce the frequency of monitoring or may authorize site closure before
the end of the 50-year period.
    (3) Prior to authorization for site closure, the owner or operator
must submit to the Director a demonstration, based on monitoring and
other site-specific data, that the carbon dioxide plume and pressure
front have stabilized and that no additional monitoring is needed to
assure that the geologic sequestration project does not pose an
endangerment to USDWs.
    (4) If such a demonstration cannot be made (i.e., if the carbon
dioxide plume and pressure front have not stabilized) after the 50-year
period, the owner or operator must submit to the Director a plan to
continue post-injection site care.
    (c) Notice of intent for site closure. The owner or operator must
notify the Director at least 120 days before site closure. At this
time, if any changes have been made to the original post-injection site
care and site closure plan, the owner or operator must also provide the
revised plan. At the discretion of the Director, a shorter notice
period may be allowed.
    (d) After the Director has authorized site closure, the owner or
operator must plug all monitoring wells in a manner which will not
allow movement of injection or formation fluids that endangers a USDW.
    (e) Once the Director has authorized site closure, the owner or
operator must submit a site closure report within 90 days that must
thereafter be retained at a location designated by the Director. The
report must include:
    (1) Documentation of appropriate injection and monitoring well
plugging as specified in Sec.  146.92 and paragraph (c) of this
section. The owner or operator must provide a copy of a survey plat
which has been submitted to the local zoning authority designated by
the Director. The plat must indicate the location of the injection well
relative to permanently surveyed benchmarks. The owner or operator must
also submit a copy of the plat to the Regional Administrator of the
appropriate EPA Regional Office;
    (2) Documentation of appropriate notification and information to
such State, local and tribal authorities as have authority over
drilling activities to enable such State and local authorities to
impose appropriate conditions on subsequent drilling activities that
may penetrate the injection and confining zone(s); and
    (3) Records reflecting the nature, composition and volume of the
carbon dioxide stream.
    (f) Each owner or operator of a Class VI injection well must record
a notation on the deed to the facility property or any other document
that is normally examined during title search that will in perpetuity
provide any potential purchaser of the property the following
information:
    (1) The fact that land has been used to sequester carbon dioxide;
    (2) The name of the State agency, local authority, and/or tribe
with which the survey plat was filed, as well as the address of the
Regional Environmental Protection Agency Office to which it was
submitted; and
    (3) The volume of fluid injected, the injection zone or zones into
which it was injected, and the period over which injection occurred.
    (g) The owner or operator must retain for three years following
site closure, records collected during the post-injection site care
period. The owner or operator must deliver the records to the Director
at the conclusion of the retention period, and the records must
thereafter be retained at a location designated by the Director for
that purpose.

Sec.  146.94  Emergency and remedial response.

    (a) As part of the permit application, the owner or operator must
provide the Director with an emergency and remedial response plan that
describes actions to be taken to address movement of the injection or
formation fluids that may cause an endangerment to a USDW during
construction, operation, closure and post-closure periods.
    (b) If the owner or operator obtains evidence that the injected
carbon dioxide stream and associated pressure front may cause an
endangerment to a USDW, the owner or operator must:
    (1) Immediately cease injection;
    (2) Take all steps reasonably necessary to identify and
characterize any release;
    (3) Notify the Director within 24 hours; and
    (4) Implement the emergency and remedial response plan approved by
the Director.
    (c) The Director may allow the operator to resume injection prior
to remediation if the owner or operator demonstrates that the injection
operation will not endanger USDWs.
    (d) The owner or operator must notify the Director and obtain his
approval prior to conducting any well workover.

 [FR Doc. E8-16626 Filed 7-24-08; 8:45 am]

BILLING CODE 6560-50-P