This comment letter response contains two parts:

(1) The original submittal from the commenter. (2) A data base printout of EPA’s response to each point raised by the commenter.

Notes about the response letters:

• The response letters were generated by a data base used to track the content of all public

comment submittals and ensure that the Agency responds to each. Each comment letter

was assigned a Letter ID that corresponds to the last four digits of the docket number of the

original comment (as posted on www.regulations.gov).

• Each response letter includes: comment text; an EPA

‐ assigned comment code; and an

individual response. These are described and explained below.

• The data base contains Comment text from the letters submitted by commenters.

Many hard copy letters were scanned into electronic format for inclusion in the data

base. As a result, there may be some typographical errors attributable to optical

character recognition issues. However, all original submittals were reviewed in the

process of drafting responses to ensure that the comment content was understood and

appropriately addressed.

• The content of each comment letter was divided into topic areas and assigned a unique

Comment ID. Additionally, one or more Comment Codes (i.e., unique topic area ID) was assigned to each discrete point raised by a commenter. This information was added to

the data base. To inform final rulemaking decisions, all comments and information

received on a given topic were reviewed by technical experts in each rule area (e.g., on

construction requirements).

• Following decisions on the final rule requirements, Individual responses were drafted

by topic area to ensure completeness and consistency of the responses with the final

rule and other responses to similar comments. Each discrete point made by a

commenter was given a unique response.

• Upon completion of comment responses, all information was entered into the data base.

Each letter response is a compilation of each comment and its individual response, compiled in the order of the original comment letter. As a result of this process, there is

repetition in the response text. The Agency believes this approach ensures completeness

and attention to each comment letter that was submitted.

• All comments in a topic area were reviewed, evaluated, and responded to concurrently.

Responses on each topic area are compiled and are also available in the rulemaking docket.March 31, 2009

Cynthia C. Dougherty

Director

Office of Ground Water and Drinking Water U. S. Environmental Protection Agency 1200 Pennsylvania Ave., NW. Washington, DC 20460

Re: Proposed Rule for Geologic Se questration, Docket No. EPA–HQ–OW–2008–0390

Dear Director Dougherty:

The organizations identified by the signatures at the end of this letter submit the attached proposed provisions (Attachment A) with the r ecommendation that these be adopted as the requirements for geologic sequestration (GS) in o il and gas reservoirs that does not meet the provisions of the (b)(4) language recommended in the joint letter submitted by the MultiStakeholder Group (MSG) on December 23, 2008. We respectfully request that EPA include in its Notice of Data Availability (NODA) on this proposed rule a request for public comment on these proposed requirements.

Background

As indicated in the joint MSG letter submitted December 23, 2008 and in the letters submitted to you on March 17, 2009 by the Clean Air Task For ce (CATF), the Environmental Defense Fund (EDF) and jointly by the American Petroleum Institute (API), the Ed ison Electric Institute (EEI) and the Carbon Sequestration Council (CSC), the MSG has continued effo rts toward developing recommendations reflecting common views on a nu mber of the issues in this rulemaking.

The March 17 letters noted that the MSG has followe d a modified approach to focus in part on the potential publication of a NO DA. The undersigned organizati ons are sending this letter at this time because we understand that the publi cation of a NODA is still contemplated. The December 23, 2008 joint MSG letter explained th e agreement reached on the proposed language describing wells in classification (b)(4) that esta blishes a “bright line” de finition for wells that inject CO 2 for EOR/EGR and GS. The signatories to that letter recommended, consistent with

EPA’s intent, that these wells should remain in Class II and be subject to the current requirements for Class II. We also agreed that the wells used for GS in oil and gas reservoirs that do not meet the criteria of (b)(4) should be subj ect to additional requirements. We noted our agreement to define such wells as wells used “for geologic sequestration in oil and gas formations and where the criteria of paragraph (b)(4 ) are not met.” This letter and the attached provisions specifically addr ess requirements for GS in oil and gas reservoirs when the criteria of paragraph (b)(4) are not met.Cynthia C. Dougherty

March 31, 2009 Page 2

In our discussions since then, MSG participants have agreed that these wells used for GS in oil and gas reservoirs should be subject to a set of requirements different from those that would apply under the current Cl ass II provisions to wells that inject CO 2 for EOR/EGR and GS, due to the potential change in the risk profile when EOR/EGR activities cease. This common view is reflected in the four letters you received on Ma rch 17 from MSG participants. Each of these letters asks EPA to include this approach in its final GS rule. The MSG has also discussed the desirability for EPA to take advantage of the oppor tunity to publish propose d regulations for this category of wells for public review and commen t in conjunction with a NODA, allowing others to address this recommendation in responding to th e NODA. That discussion is also reflected in

several of the March 17 letters. To that end, the signatories to this letter submit the language in Attachment A with the request that EPA incl ude in its NODA a request for public comment on these proposed requirements.

The signatories to this letter and Attachment A do not include all of the members of the MSG who signed the December 23, 2008 MSG letter because consensus has not been achieved on all of the provisions. We will continue the MSG disc ussion of these provisions to seek consensus,

as noted in some of the March 17 letters. We hope to achieve consensus on these requirements in time to provide comments on the NODA. Rather than press forward with our discussions and withhold these recommendations until consensus is achieved, thus possibly missing an opportunity for obtaining broader re view and comment, it seemed more beneficial at this point to provide you a set of provis ions that reflect the efforts to date , address the appropr iate issues, and provide a good basis for seeking comment on th is recommended approach. We have discussed the potential benefit of submitting the attached recommendations with the MSG and understand that you may hear from some of the other pa rticipants with respect to this request.

Recommended Provisions for GS in Oil and Gas Reservoirs

The undersigned recommend that the requirements in Attachment A be added to Class II through

an amendment to add a new section 146.25, as shown. The MSG discussions, however, have also considered that these requirements could be promulgated as a new Class VII in a new Part 146, Subpart I. To acknowledge those discussions and to provide EPA with a basis for seeking comment on that alternative approach, this le tter also addresses that alternative.

The Class II Approach

In conjunction with the requirements proposed in Attachment A, the addition of these requirements as section 146.25 should be accompanied by the addition of the word “and” at the end of paragraphs 144.5(b)(4), 144.80(b)(4) an d 146.5(b)(4) as proposed in the December 23 MSG letter and the addition of a new paragr aph (5) in subsections 144.5(b), 144.80(b) and 146.5(b) reading:

(5) For geologic sequestration in oil and ga s formations and where the criteria of paragraph (b)(4) are not met.

And subsections 144.5(f), 144.80(f) and 146.5(f) should be revi sed to read as follows:Cynthia C. Dougherty

March 31, 2009 Page 3

(f) Class VI. Wells injecting a carbon dioxide stream for geologic sequestration except those wells described in paragraphs (b)(4) and (b)(5) of this section or

otherwise excluded from this Class.

The Class VII Approach

Alternatively, if a new Class VII were created, a new subsection (g) could be added to sections

144.5, 144.80 and 146.5 as follows:

(g) Class VII. Wells injecting a carbon dioxide stream for ge ologic sequestration in oil and gas formations and where the cr iteria of paragraph (b)(4) are not met.

And subsections 144.5(f), 144.80(f) and 146.5(f) should be revi sed to read as follows:

(f) Class VI. Wells injecting a carbon dioxide stream for geologic sequestration except those wells described in subsecti ons (b)(4) and (g) of this section or

otherwise excluded from this Class.

Conclusion

The undersigned submit these recommendations with the request that the recommendations be published as a basis for seeking public comment on this approach and the related issues in conjunction with any NODA that is published. In addition, we are committed to continuing the MSG discussions with an objective of devel oping additional specific recommendations for improvement of a final rule that could be a dopted, consistent with your previously published schedule, by late 2010 or early 2011 or sooner.

As noted in the December 23, 2008 letter, the consen sus recommendations presented in this letter are solely for the purpose of GS regulation under the Safe Drinking Water Act to protect USDWs and not for the purpose of addressing verificatio n requirements for carbon credits. Accordingly, we specifically recommend that these requirem ents be published for comment in conjunction with a NODA if one is published.

Sincerely,

Kyle Isakower Director, of Policy Analysis

American Petroleum InstituteCynthia C. Dougherty

March 31, 2009 Page 4

Craig Walters General Manager, Enhanced Oil Recovery Anadarko Petroleum Corporation

Michael E. Moore Vice President External Affairs & CCS Business Development

Blue Source LLC

Brian Williams Global CO2 Storage Manager BP Alternative Energy North America Inc.

Karen St. John Director Regulatory Affairs

BP America Inc.

Robert F. Van Voorhees Counsel to the Carbon Sequestrati on Council (CCS Contact Group)

Ronald T. Evans Senior Vice President, Reservoir Engineering Denbury Resources Inc.Cynthia C. Dougherty

March 31, 2009 Page 5

William L. Fang Deputy General Counsel

Edison Electric Institute

Tiffany Rau Manager, Policy & Communications Hydrogen Energy International LLC

Al Collins

Senior Director, Regulatory Affairs Occidental Petroleum Corporation

Kevin Wanttaja Manager, Environmental Services Salt River Project

Karl R. Moor

Vice President and Asso ciate General Counsel Southern CompanyCynthia C. Dougherty

March 31, 2009 Page 6

L. Stephen Melzer

President Texas Carbon Capture & Storage Association

cc: Steve Heare Ann Codrington

Bruce Kobelski Suzanne Kelly

Lee WhitehurstATTACHMENT A

Requirements for Geologic Sequestration

Oil and Gas Reservoirs

§ 146.25 Geologic sequestration in oil or gas reservoirs for wells under §146.5(b)(5)

Except as otherwise provided in this section, injection wells used for geologic sequestration and meeting the classification criteria of 40 C.F.R. §146.5(b)(5) shall be subject to the following requirements in lieu of the requirements of 40 C.F.R. §146.22-24:

(a) Minimum Criteria for Siting - The owner or operator must have demonstrated to the satisfaction of the Director that existing wells are, and new wells will be, sited in areas with a suitable geologic system. The geologic sys tem must be comprised of:

(1) An injection zone of sufficient areal exten t, thickness, porosity, and permeability to receive the total anticipated volume of the carbon dioxide stream;

(2) A confining zone(s) that is laterally contin uous and free of known transmissive faults or fractures over an area sufficient to prevent th e movement of fluids that endangers a USDW;

(b) Area of Review and Corrective Action

(1) The area of review is based on computationa l modeling using all available data including monitoring and operational data that account for the physical and chemical properties of all phases and volumes of the injected carbon dioxide stream.

(2) The owner or operator must prepare, maintain, and comply with a plan to delineate the area of review for a proposed geologic sequest ration project under this section, reevaluate the delineation, and perform corrective action th at meets the requirements of this section in a manner and at a frequency acceptable to the Director. As a part of the permit application or revision, the owner or operator must submit an area of review and corrective action plan that includes the following information:

(i) The method for delineating the area of review that meets the requirements of §146.25(b)(1) and (3), including the model to be used, assumptions that will be made,

and the site characterization and other data including any existing monitoring data on

which the model will be based;

(ii) A description of:

(A) How monitoring and operational da ta (e.g., injection rate and pressure)

will be used to inform an area of review reevaluation; and

(B) How corrective action will be conducted to meet the requirements of §146.25(b)(4), including what correct ive action will be performed prior to injection and what, if any, portions of the area of review will have corrective

Multi-Stakeholder DiscussionsGS in Oil and Gas Reservoirs March 31, 2008

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 assured for future corrective action.

(3) The owner or operator 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:

(i) Project, using computational modelin g and available monitoring data, the projected lateral and vertical migration of the carbon dioxide plume and formation

fluids in the subsurface from the co mmencement of carbon dioxide injection activities until the plume movement ceases or pressure differentials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer present. The model must:

(A) Be based on detailed geologic data collected to characterize the injection and confining zones, available monitori ng data, and on anticipated operating data, including injection pressures, rates and total volumes over the duration of injection;

(B) Take into account relevant geologic heterogeneities, and data quality, and their possible impact on model projections; and

(C) Consider potential migration through faults, fractures, and artificial penetrations.

(ii) Using methods approved by the Director, identify all known artificial penetrations into the confining zone, incl uding active, inactive and abandoned wells and underground mines, in the area of re view 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, an d any additional information the Director may require; and

(iii) Determine which abandoned wells identified in §146.25(b)(3)(ii) have been plugged in a manner that prevents the mo vement of carbon dioxide or displaced formation fluids that may endanger USDWs;

(iv) Determine which inactive wells identified in §146.25(b)(3)(ii) have been completed in a manner that prevents the movement of carbon dioxide or displaced formation fluids that may endanger USDWs.

(4) The owner or operator must perform corrective action using materials suitable for use with the carbon dioxide stream on all wells identified in §146.25(b)(3)(ii) that are determined to need corrective action in accordance with 146.25(b)(2)(ii)(B).

(5) When monitoring and operational conditi ons warrant, including in conjunction with reviews conducted pursuant to §146.25(h)(4), the owner or operator must:

Multi-Stakeholder Discussions 2GS in Oil and Gas Reservoirs March 31, 2008

(i) Reevaluate the area of review in the same manner specified in §146.25(b)(3)(i);

(ii) Identify all wells in the reevaluated ar ea of review that require corrective action in the same manner specified in §146.25(b)(3)(ii).

(iii) Perform corrective action on wells requiri ng corrective action in the reevaluated area of review in the same manner specifi ed in §146.25(b)(2)(ii)(B) and (4); and

(iv) Submit an amended area of review and corrective action plan or demonstrate to the Director through monitoring data and modeling results that no change to the area of review and corrective action plan is needed.

(6) The emergency and remedial response plan (as required by §146.25(l)) and a demonstration of financial responsibility (as required by §146.25(c)) must account for the entire area of review (as modified) regardless of whether or not corrective action in the area of review is phased.

(c) Financial Assurance

(1) The owner or operator must demonstrate th e adequacy of existing financial responsibility or provide and maintain financial responsibili ty and resources for: corrective action (that meets the requirements of § 146.25 (b)), injecti on well plugging (that meets the requirements of § 146.25(j)), and post-injecti on site care and site closure (that meets the requirements of § 146.25 (k) and emergency and remedial response (that meets the requirements of § 146.25(l) in a manner prescribed by the Director until:

(i) The Director receives well plugging report identified in §146.25(j)(4) or completion of the post-injecti on site care and site closure plan as appropriate; and

(ii) The Director determines that the site has reached the end of the post-injection site care period.

(2) The owner or operator must provide to the Director, at a frequency determined by the Director, but no more frequently than annually , written updates or adjustments to the cost estimate to account for any changes to the area of review and corrective action plan (§146. 25(b)(2)) , the injection well plugging plan (§146. 25(j)(2)) , and the post-injection site care and site closure plan (§146. 25(k)(1))

.

(3) The owner or operator must notify the Director of adverse financial conditions that may affect the ability to carry out injection well plugging and post-injection site care and site

closure.

(4) The owner or operator must provide an adjustme nt of the cost estimate to the Director if

the Director has reason to believe that the mo st recent demonstration is no longer adequate to cover the cost of injection well pl ugging (as required by §146. 25(j)) and post-injection site care and site closure (as required by §146. 25(k)).

Multi-Stakeholder Discussions 3GS in Oil and Gas Reservoirs March 31, 2008

(d) Well Construction Requirements

(1) Applicability

(i) Existing wells must meet the constru ction requirements of 40 C.F.R. §146.22.

(ii) Newly-drilled wells in existing fields where carbon dioxide injection has occurred are subject to the construction requirements of 40 C.F.R. §146.22 if:

(A) They meet the requirements for casing and cementing applicable to permitted Class II injection wells operated in that field in conjunction with the extraction of hydrocarbons; and

(B) Well injection will not result in the movement of fluids into an underground source of drinking water so as to create a significant risk to the health of persons.

(iii) Except as provided in paragraph (d)(1)( ii) of this section, newly-drilled wells shall be subject to the requirements of subsection (d)(2) of this section.

(2) Construction Requirements for newly-drilled injection wells.

(i) General. The owner or operator must ensure that newly-drilled injection wells are constructed and completed to:

(A) Prevent the movement of fluids that endangers a USDW;

(B) Permit the use of appropriate testing devices and workover tools; and

(C) Permit continuous monitoring of the annulus space between the injection tubing and long string casing.

(ii) Casing and cement or other materials used in the construction of each well to which this section is applicable must have sufficient structural strength and be designed for the life of the operating life of the well. All well materials must be compatible with fluids with which the ma terials may be expected to come into

contact and meet or exceed test standards or practices 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 that en dangers USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information:

(A) Depth to the injection zone;

(B) Hole size;

Multi-Stakeholder Discussions 4GS in Oil and Gas Reservoirs March 31, 2008

(C) Size and grade of all casing stri ngs (wall thickness, external diameter, nominal weight, length, joint specification and construction material);

(D) Predicted corrosive characteristic of the combined carbon dioxide stream

and formation fluids;

(E) Down-hole temperatures and pressures;

(F) Lithology of injection and confining zones;

(G) Type or grade of cement and additives; and

(H) Quantity, chemical composition, and temperature of the carbon dioxide

stream.

(iii) Casing must extend through the base of the lowermost USDW above the injection zone and be cemented to the surface. Surface casing need not extend through the base of the lowermost USDW above the injection zone if a combination of cement around the surface casing and inter mediate or long-string casing achieves continuous cement through the base of the lowermost USDW above the injection

zone.

(iv) At least one long string casing, usin g a sufficient number of centralizers, which at a minimum, would create a cement bond through the confining zone, and which must extend to the injection zone and must be isolated by placing cement and/or other isolation technologies as necessary to provide adequate isolation of the injection zone and provide for protection of USDWs.

(v) Cement and cement additives must be suitable for use with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the operating life the well. The integrity and location of the cement shall be verified using technology capa ble of evaluating cement quality and identifying the location of channels to ensure that USDWs are not endangered.

(vi) Tubing and packer.

(A) Owners and operators must inject fl uids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the

Director.

(B) In order for the Director to determine and specify requirements for tubing and packer, the owner or operator must submit the following

information:

(1) Depth of setting and the depth of the injection zone;

Multi-Stakeholder Discussions 5GS in Oil and Gas Reservoirs March 31, 2008

(2) Composition of the carbon dioxide stream.

(3) Maximum proposed Injection temperature and pressure;

(4) Maximum proposed Annular pressure;

(5) Maximum proposed Injection rate (intermittent or continuous)

and volume of the carbon dioxide stream;

(e) Logging, sampling, and testing prior to new well operation – The following requirements apply only to newly-drilled wells.

(1) During the drilling and construction of an 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 evaluate conformance with applicable injection well construction requirements 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 interpr etation of the results of such logs and tests. The Director may require such logs and tests as may be needed after taking into account the availability in the area of the drilling site of da ta having similar quality and reliability as would be obtained with new logs and tests, the c onstruction plan, and the need for additional information that may arise from time to time as the construction of the well progresses and these may include the following:

(i) Deviation checks during drilling on a ll holes constructed by drilling a pilot hole that is enlarged by reaming or another method. Such checks must be at sufficiently frequent intervals to determine the loca tion of the borehole and to assure that

vertical avenues for fluid movement in th e form of diverging holes are not created during drilling;

(ii) Before and upon installation of the surface casing:

(A) Resistivity, spontaneous potential, an d caliper logs before the casing is

installed; and

(B) A cement evaluation log or logs after the casing is set and cemented.

(iii) Before and upon installation of the long string casing:

(A) Resistivity, spontaneous potential, porosity, caliper, gamma ray and anyother logs the Director requires based on site specific conditions and riskbased factors for the given geology be fore the casing is installed; and

(B) Cement evaluation log(s) and/or map(s) after the casing is set and cemented to evaluate cement quality wi th sufficient radial resolution to

Multi-Stakeholder Discussions 6GS in Oil and Gas Reservoirs March 31, 2008

identify channels or missing cement that would prevent compliance with §146.25(d)(2).

(iv) Test(s) designed to demonstrate the in ternal and external mechanical integrity of injection wells, which may include:

(A) A pressure test with liquid or gas;

(B) Diagnostic tools such as oxygen-activation logging;

(C) A temperature or noise log;

(D) A casing inspection log; and

(E) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director.

(2) The owner or operator must submit to the Director a report describing whole cores or sidewall cores representative of the injection zo ne and confining system and formation fluid samples from the injection zone(s). The Dir ector may accept data from cores and fluid samples from nearby wells if the owner or operator can demonstrate that such data are representative of conditions in the wellbore.

(3) Prior to injection well operation, the owner or operator must record the formation temperature, formation fluid pH and conductivity, and reservoir pressure of the injection zone(s).

(4) At any time prior to injection well operation, the owner or operator must determine fracture pressures of the injection and conf ining zones and conduct tests to verify hydrogeologic and geomechanical char acteristics of the injection zone.

(5) 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 upon spudding the well and submit any changes to the schedule 48 hours prior to the scheduled test.

(f) Injection well operating requirements

(1) The owner or operator must comply with a maximum injection pressure limit approved by the Director and specified in the permit. In approving a maximum injection pressure limit, the Director shall consider the results of well tests and, where appropriate, geomechanical or other studies that assess the risks of tensile failure and shear failure. The Director shall approve limits that, with a reas onable degree of certainty, will avoid initiation or propagation of fractures in the confining z one or cause otherwise non-transmissive faults transecting the confining zone to become transmissive. In no case may injection pressure cause movement of injection or formation fl uids in a manner prohibited by 40 C.F.R. §144.12(a).

Multi-Stakeholder Discussions 7GS in Oil and Gas Reservoirs March 31, 2008

(2) Injection of the CO2 stream into any annulus or between the outermost casing protecting USDWs and the well bore is prohibited.

(3) For injection wells constructed with injection tubing and packer, the owner or operator must fill the annulus between the tubing and the long string casing with a corrosion inhibiting fluid approved by the Director and must maintain a positive pressure on the

annulus.

(4) The owner or operator must install and use continuous recording devices to monitor: the injection pressure and the rate, volume, and temperature of the carbon dioxide stream. For injection wells constructed with injection tubing and packer, the owner or operator must regularly monitor the pressure on the annulus bet ween the tubing and the long string casing. The owner or operator must install, test and use alarms and automatic shut-off systems, designed to alert the operator and shut-in the well when operating parameters such as injection rate, injection pressure, or other pa rameters approved by the Director diverge beyond ranges and/or gradients specified in the permit.

Notes:

The duty to establish and maintain mechanical integrity is already imposed under 40 C.F.R. §144.51(q)(1).

Requirements for responding to a potential la ck of mechanical integrity are imposed under 40 C.F.R. §144.51(q).

Requirements for 24-hour reporting are im posed under 40 C.F.R. §144.51(l)(6).

(5) Mechanical integrity

(i) A well has mechanical integrity if:

(A) There is no significant leak in the casing, tubing or packer; and

(B) There is no significant fluid move ment into a USDW through channels adjacent to the injection well bore.

(ii) To evaluate the absence of significan t leaks under this subsection, owners or operators must, following an initial annulus pressure test, continuously monitor and record at least daily injection pressure, rate, injected volumes, and – for wells constructed with an injection tube an d packer – pressure on the annulus between tubing and long stem casing and annulus fluid volume as specified in §146.25(g)(2)(ii);

(iii) At least once per year, the owner or operator must confirm the absence of significant fluid movement under paragraph (5)(i)(B) of this section using a method

Multi-Stakeholder Discussions 8GS in Oil and Gas Reservoirs March 31, 2008

acceptable to the Director (e.g. includ ing diagnostic surveys such as oxygenactivation logging or temperature or noise logs).

(iv) The Director may require any other test to evaluate mechanical integrity under paragraph (i)(A) or (i)(B) 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.

(v) In conducting and evaluating the tests en umerated 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 tes ts 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.

(vi) 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 paragra phs (i)(A) and (i)(B) of this section.

(g) Testing and Monitoring

(1) Based on a site-specific assessment of the potential for fluid movement from the injection well or injection zone, and on the potential value of monitoring wells to detect such movement, the owner or operator of a well must prepare, maintain, and comply with a testing and monitoring plan. 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.

(2) The testing and monitoring plan must, at a minimum, include:

(i) analysis of the carbon dioxide stream with sufficient freque ncy to yield data representative of its chemical and physical characteristics;

(ii) Installation and use, except during we ll workovers as defined in section 146.88(d), of continuous monitoring devices (including digital devices capturing periodic data) to monitor injection pressure, rate and volume; and, for wells constructed with

Multi-Stakeholder Discussions 9GS in Oil and Gas Reservoirs March 31, 2008

injection tubing and packer, to record at least daily the pressure on the annulus between the tubing and th e long strong casing;

(iii) demonstration of external mechanical integrity pursuant to §146.25(f)(5) until the well is plugged;

(iv) monitoring of the pressure buildup in the injection zone annually, including at a minimum, a shut down of the well for a time sufficient to conduct a valid observation of the pressure fall-off curve at least once every five years; and

(v) a quality assurance plan.

(3) Where appropriate, the testing and m onitoring plan shall also include:

(i) Continuous monitoring for pressure changes in an appropriately porous and permeable formation overlying the confining zone. When a well is installed to enable such monitoring, the owner or operato r shall, on a specified frequency or at specified times, sample the formation and analyze for constituents specified in the plan;

(ii) The use of indirect, geophysical techni ques to determine the position of the CO2 stream front, the water quality in a designated formation, or to provide other site specific data;

(iii) Periodic monitoring of water quality in an appropriately porous and permeable formation overlying the injection zone;

(iv) Periodic monitoring of water quality in one or more USDWs;

(v) Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting and other signs of corrosion performe d and recorded at least quarterly which may be modified to be less frequent as approved by the Director based on construction materials, operating conditions , and monitoring history to ensure that the well components meet minimum standards for material strength and performance by:

(A) Analyzing coupons of the well cons truction materials placed in contact

with the carbon dioxide stream; or

(B) Routing the carbon dioxide stream through a loop constructed with the material used in the well and inspecting the materials in the loop; or

(C) Using an alternative method, materials, or time period approved by the

Director;

(vi) Any additional monitoring, as requir ed by the Director, based on site-specific conditions and risk-based factors, necessary to support, upgrade, and improve

Multi-Stakeholder Discussions 10GS in Oil and Gas Reservoirs March 31, 2008

computational modeling of the area of review evaluation required under § 146.84(b);

and

(vii) Any additional testing and monitoring necessary to determine whether fluid movement is occurring that would endanger a USDW.

(h) Reporting and Certification Requirements

The owner or operator must, at a minimum, provide the following reports to the Director, for each permitted well:

(1) Semi-annual or less frequently as deter mined by the Director reports containing:

(i) Any significant changes to the physical, chemical and other relevant characteristics of the carbon dioxide stream from the proposed operating data;

(ii) Monthly average, maximum and minimu m values for injection pressure, flow rate and volume, and annular pressure;

(iii) A description of any event that significantly exceeds operating parameters for annulus pressure or injection pressure as specified in the permit;

(iv) A description of any event which tri ggers a shutdown device required pursuant to §146.25(f)(4) and the response taken;

(v) The monthly volume of the carbon diox ide stream injected over the reporting period and project cumulatively;

(vi) Monthly annulus fluid volume added; and

(vii) The results of monitoring prescribed under §146.25(g).

(2) Report, within 30 days the results of:

(i) Periodic tests of mechanical integrity;

(ii) Any other test of the injection well conducted by the permittee if required by the

Director; and

(iii) Any well workover.

(3) Owners or operators must submit reports in an electronic format acceptable to the

Director. At the discretion of the Di rector, other formats may be accepted.

(4) Owners or operators must submit an annu al certification, signed by the appropriate company official, that the company has:

Multi-Stakeholder Discussions 11GS in Oil and Gas Reservoirs March 31, 2008

(i) reviewed the area of review and all of the required plans;

(ii) reviewed all monitoring and operational data since the previous

certification that are relevant to a de cision on whether to update the area of review and each plan;

(iii) determined with regard to the area of review and each plan whether an update was warranted; and

(iv) completed an update pursuant to section 146.84(f) for the area of review if warranted by material change,

(v) completed an update and attached a summary of the modifications for each of the plans for which an update was warranted by material change.

(5) The Director may require submission of c opies of any updated plans and/or additional information regarding the reasons why updates of particular plans have or have not been prepared.

(6) The Director may require reevaluation of the area of review pursuant to section 146.84(f) or the revision of any required plan whenever the Director determines on the basis of information available to him that an update is necessary to comply with the requirements of this Subpart.

(i) Required permit information

This section sets forth the information which the ow ner or operator must submit to the Director in order to be permitted. The application for a permit for construction and operation of an injection well must include the following:

(1) Information required in 40 CFR 144.31(e)(1) through (6);

(2) A surface map showing the proposed locations for 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 known 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. Only information of public record is required to be included on this map;

(3) A map delineating the area of review base d upon modeling, using all available data including data available from any logging and testing of wells within the area of review.

(4) Sufficient information on the geologic structure and reservoir properties of the proposed storage site and overlying formations, which may include:

Multi-Stakeholder Discussions 12GS in Oil and Gas Reservoirs March 31, 2008

(i) Isopach maps of the proposed injecti on and confining zone(s), a structural contour map aligned with the top of the proposed injection zone, and at least two geologic cross sections of the area of re view reasonably perpendicular to each other showing the geologic formations from the surface to total depth of the well.

(ii) Location, orientation, and propert ies of known or suspected subsurface faults that may transect the confining zone(s) in the area of review and a determination that they would not interfere with containment;

(iii) Information on seismic history that ha ve affected the proposed area of review including knowledge of previous seismic events and history of these events, including the presence and depth of seismic sources and a determination that the seismicity would not compromise containment;

(iv) Data sufficient to demonstrate the effectiveness of the injection and confining zone(s), including data on the depth, areal extent, thickness, mineralogy, porosity, vertical permeability reservoir pressure and of the injection and confining zone(s) within the area of review; including geologic changes based on field data which may include geologic cores, outcrop data, seis mic surveys, well logs, capillary pressure tests and names and lithologic descriptions;

(v) Geomechanical information on the confining zone(s) within the area of review;

and

(vi) Geologic and topographic maps and cross sections illustrating geology, hydrogeology, and the geologic st ructure of the area of review.

(5) A compilation of all artificial penetrations within the area of review which penetrate the injection or confining zone(s). Such data m ust 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;

(6) Maps and stratigraphic cross sections indicati ng the general vertical and lateral limits of all USDWs, the location of water wells and perenni al springs within the area of review, their positions relative to the injection zone(s) and the direction of water movement, where

known;

(7) A compilation of available baseline geoche mical data on the proposed injection zone and nearest adjacent porous and permeable formati on to the confining zone, existing utilized water supply aquifers and any other USDWs designated by the Director.

(8) Proposed operating data:

Multi-Stakeholder Discussions 13GS in Oil and Gas Reservoirs March 31, 2008

(i) Average and maximum daily injection rate and volume of the carbon dioxide

stream;

(ii) Average and maximum surface injection pressure;

(iii) The source of the carbon dioxide stream; and

(iv) An analysis of the chemical and phys ical characteristics of the carbon dioxide

stream;

(9) The compatibility of the carbon dioxide stream with fluids in the injection zone and minerals in both the injection and the conf ining zone(s), based on the results of the formation testing program or other data, and with the materials used to construct the well;

(10) Proposed formation testing program to obtai n an analysis of the chemical and physical characteristics of the injection zone and confining zone;

(11) Proposed stimulation program and a determination that stimulation will not compromise containment;

(12) The results of the formation testing program as required in paragraph (j) of this section;

(13) Proposed procedure to outline steps necessary to conduct injection operation;

(14) A wellbore schematic of the subsurface construction details and surface wellhead

construction;

(15) Injection well construction procedures that meet applicable requirements;

(16) Proposed corrective action plan for artificialpenetrations within the area of review, if

necessary;

(17) All available logging and testing progra m data on the well required by §146.25(e)(1);

(18) The proposed demonstration method for m echanical integrity pursuant to §146.25(j)(5);

(19) A demonstration, satisfactory to the Director, that the applicant has met the financial responsibility requirements under §146.25(c);

(20) Proposed testing and monitoring plan required by §146.25(g);

(21) Proposed injection and monitoring well(s) plugging plan required by §146.25(j)(2);

(22) Proposed post-injection site care and site closure plan required by §146.25(k);

Multi-Stakeholder Discussions 14GS in Oil and Gas Reservoirs March 31, 2008

(23) Proposed emergency and remedial response plan required by § 146.25(l); and

(24) Any other information requested by the Director.

(j) Injection well plugging

(1) Prior to the well plugging, the owner or ope rator must flush each injection well with a buffer fluid, determine bottomhole reservoi r pressure, and perform a final external mechanical integrity test.

(2) Well Plugging Plan. The owner or operator of a well must prepare, maintain, and comply with a plan that is acceptable to the Directo r. The requirement to maintain and implement an approved plan is directly enforceable regard less 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:

(i) Appropriate test or measure to dete rmine bottomhole reservoir pressure;

(ii) Appropriate testing methods to ensur e final external mechanical integrity as specified in §146.25(f)(5);

(iii) The type and number of plugs to be used;

(iv) The placement of each plug includin g the elevation of the top and bottom of each plug;

(v) The type and grade and quantity of mater ial to be used in plugging. The material must be suitable for use with the carbon dioxide stream, reservoir and fluid

conditions; and

(vi) The method of pl acement of the plugs.

(3) 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 s horter notice period may be allowed.

(4) Plugging report. Within 60 days after pl ugging the owner or operator must submit a plugging report to the Director. The report must be certified as accurate by the owner or operator and by the person who performed the plugging operation (if other than the owner or operator.)

(k) Post-injection site care and site closure

Multi-Stakeholder Discussions 15GS in Oil and Gas Reservoirs March 31, 2008

(1) The owner or operator of a well must prepare, maintain, and comply with a plan for post-injection site care and site closure that me ets the requirements of paragraph (1)(ii) of this section and is acceptable to the Director.

(i) 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.

(ii) The post-injection site care and site closure plan must include the following

information:

(A) The pressure differential betwe en pre-injection and projected postinjection pressures in the injection zone;

(B) The projected position of the carbon dioxide plume and associated pressure front at site closure as demonstr ated in the area of review evaluation required under §146.25(b)(1), (3) and (5);

(C) A description of post-injection monitoring location, methods, and proposed frequency; and

(D) A proposed schedule for submitting post-injection site care monitoring

results to the Director.

(iii) Upon cessation of injection, owners or operators of wells must either submit an amended post-injection site care and site clo sure plan or demonstrate to the Director through monitoring data and modeling results that no amendment to the plan is

needed.

(iv) 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

(2) The owner or operator shall monitor the site following the cessation of injection.

(i) The owner or operator shall continue to conduct monitoring as specified in the Director-approved post-injecti on site care and site closur e plan, pursuant to the performance based criteria described in §146.25(k)(2)(iii).

(ii) The owner or operator can request and demonstrate to the satisfaction of the Director that the post-injection site care and site closure plan should be revised to reduce the frequency of monitoring.

(iii) Prior to authorization for site closur e, the owner or operator must demonstrate to the Director, based on monitoring, othe r site-specific data, and modeling that is reasonably consistent with site performance th at no additional monitoring is needed to assure that the geologic sequestration project does not pose an endangerment to USDWs. The owner or operator must demonstrate, based on the current understanding of the site, including monitoring data and/or modeling, all of the

Multi-Stakeholder Discussions 16GS in Oil and Gas Reservoirs March 31, 2008

following: (A) the estimated magnitude an d extent of the project footprint (CO2 plume and the area of elevated pressure) ; (B) the estimated location of the detectable CO2 plume ; (C) that there is no signific ant leakage of either CO2 or displaced formation fluids that is endangering USDWs; (D) that the injected or displaced fluids are not expected to migrate in the future in a manner that encounters a potential leakage pathway into a USDW; (E) that the injection wells at the site completed into or through the injection zone or confining zone are plugged and abandoned in accordance with these requirements; and (F ) any remaining project monitoring wells at the site are being managed by a person and in a manner acceptable to the Director.

(3) Notice of intent for site closure. The owne r 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, th e owner or operator must also provide the revised plan. At the discretion of the Dir ector, a shorter notice period may be allowed.

(4) After the Director has aut horized 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.

(5) Once the Director has authorized site closur e, the owner or operator must submit a site closure report within 90 days after completi on of all closure operations. The report must

include:

(i) Documentation of appropriate injection an d monitoring well plugging as specified in §146.25(j ) and paragraph (4 ) of this section. The owner or operator must provide a copy of a survey plat which has been su bmitted to the local zoning authority designated by the Director. The plat must indicate the location of the injection well(s) relative to permanently surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Re gional Administrator of the appropriate EPA Regional Office;

(ii) 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

(iii) Records reflecting the nature, composition and volume of the carbon dioxide

stream.

(6) Each owner or operator of a injection well must provide notification to the designated state authority of the following information:

(i) The fact that land has been used to sequester carbon dioxide;

(ii) 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

Multi-Stakeholder Discussions 17GS in Oil and Gas Reservoirs March 31, 2008

(iii) The volume of fluid injected, the injection zone or zones into which it was injected, and the period over which injection occurred.

(7) The owner or operator must retain for three years following site closure, records collected during the post-injection site care peri od. 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 desi gnated by the Director for that purpose.

(l) Emergency and Remedial Response Plan

(1) As part of a permit application or request for revision to operate under this section, the owner or operator must provide the Director with an emergency, risk-based remedial response plan that describes actions to be taken to address movement of the injection or formation fluids that may cause an endang erment to a USDW during construction, operation, closure and post-closure periods.

(2) If the owner or operator obtains evidence that the injected carbon dioxide stream, displaced formation fluids or and associated pressure front endangers a USDW, the owner

or operator must:

(i) Cease injection in a prudent manner considering circumstances. (ii) Take all steps reasonably necessary to identify and characterize the endangerment posed; (iii) Notify the Director or the designat ed representative within 24 hours of becoming aware of the endangerment; and (iv) Implement the emergency and remedial response plan approved by the Director and keep the Director apprized of the implementation.

(3) 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.

(4) The owner or operator must notify the Director and obtain his approval prior to conducting any well workover or other remedi ation measures not listed in the emergency and remedial response plan.

(5) If an owner or operator obtains evidence that a pressure front associated with one geologic sequestration project intersects or will intersect the area of review associated with another project, the owner or operator obtaining such evidence must notify the Director. If the Director deter mines that the pressure front associated with one project will interfere with the abili ty of another project to comply with the terms of its permit(s), the Director ma y require the owner or operator of the potentially interfering project to modify operations as necessary to avoid such interference. Such modification may incl ude mutually agreed modifications in operations to both projects or other actions if the respective owners and operators agree to requirements to implement modifications or other actions approved by the Director that will mitigate the interference.”

Multi-Stakeholder Discussions 18GS in Oil and Gas Reservoirs March 31, 2008

Note: Requirements for responding to a potential lack of mechanical integrity are imposed under 40 C.F.R. §144.51(q). Requirements for 24-hour reporting are imposed under 40 C.F.R. §144.51(l)(6).

Multi-Stakeholder Discussions 19Letter ID: 0290 Commenter: Kyle Isakower Organization: American Petroleum Institute

Letter ID: 0290 Comment ID: 25281 Letter Lines: 64 to 77

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: In our discussions since then, MSG partic ipants have agreed that these wells used for GS in oil and gas reservoirs s hould be subject to a set of requirements different from those that would apply unde r the current Class II provisions to wells that inject CO2 for EOR/EGR and GS , due to the potentia l change in the risk profile when EOR/EGR activities cease. This common view is reflected in the four letters you received on March 17 from MSG partic ipants. Each of these letters asks EPA to include this approach in its final GS rule. The MSG has also discussed the desirability for EPA to ta ke advantage of the opportunity to publish proposed regulations for this categ ory of wells for public review and comment in conjunction with a NODA, allowing others to address this recommendation in responding to the NODA. Th at discussion is also reflected in

several of the March 17 lette rs. To that end, the signato ries to this letter submit the language in Attachment A with the request that EPA include in its NODA a request for public comment on these proposed requirements.

Individual Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery should remain under the Cla ss II Program. EPA also recognizes that the oil and gas industry has decades of experience inj ecting CO2 for the purpose of EOR, and that sites used for EOR may be suitable for GS and may be among the first GS sites. However, EPA believes that injection for the primary purpose of l ong term storage is sufficiently different from Class II EOR operations and warrants tailored re quirements. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater th an for Class II wells. Reservoir pressure conditions wi ll also be different, with Cla ss VI injection operations involving large volumes of CO2 and likely having higher pressures within th eir storage formations than Class II EOR projects.

Letter ID: 0290 Comment ID: 25282 Letter Lines: 96 to 139

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: The undersigned recommend that the requireme nts in Attachment A be added to Class II through an amendment to add a new section 146.25, as shown. The MSG discussions, however, have also considered that these requirements could be promulgated as a new Class VII in a ne w Part 146, Subpart I. To acknowledge

1those discussions and to provide EPA with a basis for seeking comment on that alternative approach, this letter al so addresses that alternative.

[In the section below, the text in al l CAPS denotes added text. For redline

strikeout version of this attachme nt see PDF Docket ID EPA-HQOW-2008-0390-0290.]

The Class II Approach

In conjunction with the requirements proposed in Attachment A, the addition of these requirements as section 146.25 shoul d be accompanied by the addition of the word "and" at the end of paragr aphs 144.5(b)(4), 144.80(b)(4) and 146.5(b) (4) as proposed in the December 23 MS G letter and the addition of a new paragraph (5) in subsections 144.5( b), 144.80(b) and 146.5(b) reading:

(5) For geologic sequestration in oil and gas formations and where the criteria of paragraph (b)(4) are not met.

And subsections 144.5(f), 144.80( f) and 146.5(f) should be revised to read as

follows:

(f) Class VI. Wells INJECTING A CA RBON DIOXIDE STREAM FOR GEOLOGIC SEQUESTRATION EXCEPT THOSE WELLS DESCRIBED IN PARAGRAPHS (B)(4) AND (B) (5) OF THIS SECTION OR OTHERWIS E EXCLUDED FROM THIS CLASS.

The Class VII Approach

Alternatively, if a new Class VII were created, a new subsec tion (g) could be added to sections 144.5, 144.80 and 146.5 as follows:

(g) Class VII. Wells injecting a car bon dioxide stream for geologic sequestration in oil and gas forma tions and where the criteria of paragraph (b)(4) are not met.

And subsections 144.5(f), 144.80( f) and 146.5(f) should be revised to read as

follows:

(f) Class VI. Wells INJECTING A CA RBON DIOXIDE STREAM FOR GEOLOGIC SEQUESTRATION EXCEPT THOSE WELLS DESCRIBED IN SUBSECTIONS (B)(4) AND (G)

OF THIS SECTION OR OTHERWISE EXCLUDED FROM THIS CLASS.

Individual Response: As described above, EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery shoul d remain under the Class II Program, but that there are significant difference s between how ER and GS project s are operated. EPA disagrees

2that the creation of a Class VII well category for GS that occurs in oil and gas formations is necessary because the Class VI requirements are appropriate for GS in al l formations. For more information, please see the discussion on transition of Class II wells in the preamble to the final

GS rule.

Letter ID: 0290 Comment ID: 25284 Letter Lines: 143 to 156 ; 218 to 1062

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: The undersigned submit these recommenda tions with the re quest that the recommendations be published as a basi s for seeking public comment on this approach and the related issues in conj unction with any NODA that is published. In addition, we are committed to conti nuing the MSG discussions with an objective of developing additional specific recommendations for improvement of a final rule that could be adopted, consis tent with your previously published schedule, by late 2010 or early 2011 or sooner.

As noted in the December 23, 2008 lette r, the consensus recommendations presented in this letter are solely fo r the purpose of GS regulation under the Safe Drinking Water Act to protect USDW s and not for the purpose of addressing verification requirements for carbon cred its. Accordingly, we specifically recommend that these requirements be publis hed for comment in conjunction with a NODA if one is published.

ATTACHMENT A Requirements for Geologic Sequestration

Oil and Gas Reservoirs

§ 146.25 Geologic sequestration in oil or gas reservoirs for wells under §146.5(b)(5)

Except as otherwise provided in this section, injection wells used for geologic sequestration and meeting the classifica tion criteria of 40 C.F.R. §146.5(b)(5) shall be subject to the following requiremen ts in lieu of the requirements of 40 C.F.R. §146.22-24:

(a) Minimum Criteria for Siting - The owner or operator must have demonstrated

to the satisfaction of the Director that existing wells are, a nd new wells will be, sited in areas with a suitable geologi c system. The geologic system must be comprised of:

(1) An injection zone of sufficient ar eal extent, thickness, porosity, and permeability to receive the total antic ipated volume of the carbon dioxide

stream;

3(2) A confining zone(s) that is la terally continuous and free of known

transmissive faults or fractures over an area sufficient to prevent the movement of fluids that endangers a USDW;

(b) Area of Review and Corrective Action

(1) The area of review is based on com putational modeling us ing all available data including monitoring and operational data that acc ount for the physical and chemical properties of all phases and vol umes of the injected carbon dioxide

stream.

(2) The owner or operator must prepare, maintain, and comply with a plan to delineate the area of review for a propos ed geologic sequest ration project under this section, reevaluate the delineati on, and perform corrective action that meets the requirements of this section in a manner and at a frequency acceptable to the Director. As a part of the permit application or revisi on, the owner or operator must submit an area of review a nd corrective action plan that includes the following information:

(i) The method for delineating the area of review that meets the requirements of §146.25(b)(1) and (3), including the model to be used, assumptions that will be made, and the site characterization a nd other data includ ing any existing monitoring data on which the model will be based;

(ii) A description of:

(A) How monitoring and operational data (e .g., injection rate a nd pressure) will

be used to inform an area of review reevaluation; and

(B) How corrective action will be conducte d to meet the requirements of §146.25(b)(4), including what corrective action will be performed prior to injection and what, if any, portions of th e 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 ther e are changes in the area of review;

and how site access will be assure d for future corrective action.

(3) The owner or operator 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:

(i) Project, using computational modeli ng and available monitoring data, the projected lateral and vertical migrat ion of the carbon dioxide plume and

formation fluids in the subsurface from the commencement of carbon dioxide injection activities until the plume moveme nt ceases or pressure differentials sufficient to cause the movement of inject ed fluids or formation fluids into a

4USDW are no longer present. The model must:

(A) Be based on detailed geologic data co llected to characterize the injection and confining zones, available monito ring data, and on anticipated operating data, including injection pr essures, rates and total volumes over the duration of injection;

(B) Take into account relevant geologic heterogeneities, and data quality, and their possible impact on model projections; and

(C) Consider potential migr ation through faults, fract ures, and ar tificial penetrations.

(ii) Using methods approved by the Dir ector, identify all known artificial penetrations into the confining zone, in cluding active, inactive 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, r ecord of plugging and/or completion, and any

additional information the Di rector may require; and

(iii) Determine which abandoned wells id entified in §146.25(b)(3)( ii) have been plugged in a manner that prevents the m ovement of carbon dioxide or displaced formation fluids that may endanger USDWs;

(iv) Determine which inactive wells id entified in §146.25(b)(3)(ii) have been completed in a manner that prevents the movement of carbon dioxide or displaced formation fluids that may endanger USDWs.

(4) The owner or operator must perfor m corrective action using materials

suitable for use with the carbon dioxide stream on a ll wells identified in §146.25(b)(3)(ii) that are determined to need corrective action in accordance with 146.25(b)(2)(ii)(B).

(5) When monitoring and operational condi tions warrant, including in conjunction with reviews conducted pursuant to §146.25(h) (4), the owner or operator must:

(i) Reevaluate the area of review in the same manner specified in §146.25(b)(3) (i);

(ii) Identify all wells in the reeval uated area of review that require

corrective action in the same manne r specified in §146.25(b)(3)(ii).

(iii) Perform corrective action on wells requiring corrective action in the

reevaluated area of review in the same manner specified in §146.25(b)(2 )(ii)(B) and (4); and

5(iv) Submit an amended area of review a nd corrective action plan or demonstrate to the Director through monitoring data a nd modeling results that no change to

the area of review and correc tive action plan is needed.

(6) The emergency and remedial respons e plan (as required by §146.25(l)) and a demonstration of financial responsi bility (as required by §146.25(c)) must account for the entire area of review (as modified) regardless of whether or not

corrective action in the area of review is phased.

(c) Financial Assurance

(1) The owner or operator must demonstrat e the adequacy of existing financial responsibility or provide and maintain financial responsibil ity and resources for: corrective action (that meets the requirements of § 146.25 (b)), injection well plugging (that meets th e requirements of § 146.25(j)), and post-injection site care and site closure (that meet s the requirements of § 146.25 (k) and emergency and remedial response (that m eets the requirements of § 146.25(l) in a manner prescribed by the Director until:

(i) The Director receives well plugging report identif ied in §146.25(j)(4) or completion of the post-injection site care and site closure plan as appropriate;

and

(ii) The Director determines that the site has reached the end of the postinjection site care period.

(2) The owner or operator must provide to the Director, at a frequency determined by the Director, but no more frequently than annually, written updates or adjustments to the cost estim ate to account for any changes to the

area of review and correc tive action plan (§146. 25(b)(2 )), the injection well plugging plan (§146. 25(j)(2)), and the post-injection site care and site closure plan (§146. 25(k)(1)).

(3) The owner or operator must notify the Director of a dverse financial conditions that may affect the ability to carry out injecti on well plugging and post-injection site care and site closure.

(4) The owner or operator must provide an adjustment of the cost estimate to the

Director if the Director has reason to believe that the most recent demonstration is no longer adequate to c over the cost of injection well plugging (as required by §146. 25(j)) and post-injec tion site care and site closure (as required by §146. 25(k)).

(d) Well Construction Requirements

(1) Applicability

6(i) Existing wells must meet the constr uction requirements of 40 C.F.R. §146.22.

(ii) Newly-drilled wells in existing fiel ds where carbon dioxide injection has occurred are subject to the constructi on requirements of 40 C.F.R. §146.22 if:

(A) They meet the requirements for casi ng and cementing applicable to permitted Class II injection wells operated in that field in conj unction with the extraction of hydrocarbons; and

(B) Well injection will not re sult in the movement of fluids into an underground source of drinking water so as to create a significant risk to the health of

persons.

(iii) Except as provided in paragraph (d)(1 )(ii) of this section, newly-drilled wells shall be subject to the requirements of subsection (d)(2) of this section.

(2) Construction Requirements for ne wly-drilled injection wells.

(i) General. The owner or operator must ensure that newly-drilled injection wells are constructed and completed to:

(A) Prevent the movement of fluids that endangers a USDW; (B) Permit the use of appropriate tes ting devices and workover tools; and (C) Permit continuous monitoring of the annulus space between the injection tubing and long string casing.

(ii) Casing and cement or other materials used in the construction of each well to which this section is applicable must have sufficient struct ural strength and be designed for the life of the operating life of the well. All well materials must be compatible with fluids with whic h the materials may be expected to come

into contact and meet or exceed test sta ndards or practices developed for such materials by the American Petroleum Institu te, ASTM International, or comparable standards acceptable to the Director. Th e casing and cementing program must be designed to prevent the movement of fluids that endangers USDWs. In order to allow the Director to determine and sp ecify casing and cementing requirements, the owner or operator must provi de the following information:

(A) Depth to the injection zone; (B) Hole size; (C) Size and grade of all casing strings (wall thickness, external diameter, nominal weight, length, joint specific ation and construction material); (D) Predicted corrosive charac teristic of the combined carbon dioxide stream and formation fluids; (E) Down-hole temperatures and pressures; (F) Lithology of injectio n and confining zones;

7(G) Type or grade of cement and additives; and (H) Quantity, chemical composition, and temperature of the carbon dioxide

stream.

(iii) Casing must extend through the base of the lowermost USDW above the injection zone and be cemented to th e surface. Surface casing need not extend through the base of the lowermost USDW above the injection zone if a combination of cement around the surface casing and in termediate or long-string casing achieves continuous cement through the base of the lowermost USDW above the injection zone.

(iv) At least one long stri ng casing, using a sufficient number of centralizers, which at a minimum, would create a cem ent bond through the confining zone, and which must extend to the injection zone and must be isolated by placing cement and/or other isolation technologies as n ecessary to provide adequate isolation of the injection zone and provi de for protection of USDWs.

(v) Cement and cement additives must be su itable for use with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the operating life the well. The integrity and location of the cement shall be verified using technol ogy capable of evalua ting cement quality and identifying the location of channe ls to ensure that USDWs are not endangered.

(vi) Tubing and packer.

(A) Owners and operators must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Director.

(B) In order for the Director to determ ine and specify requirements for tubing and packer, the owner or operator must submit the following information:

(1) Depth of setting and the de pth of the injection zone; (2) Composition of the carbon dioxide stream. (3) Maximum proposed Injection temperature and pressure; (4) Maximum proposed Annular pressure; (5) Maximum proposed Injection rate (inter mittent or continuous) and volume of the carbon dioxide stream;

(e) Logging, sampling, and testing prior to new well operation - The following requirements apply only to newly-drilled wells.

(1) During the drilling and construction of an 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 evaluate

8conformance with applicable injection well construction requirements and to establish accurate baseline data agains t which future measurements may be compared. The owner or operator must subm it to the Director a descriptive report prepared by a knowledgeable l og analyst that includes an interpretation of the results of such logs and tests. The Direct or may require such logs and tests as may be needed after taking into account the availability in the area of the drilling site of data having similar quality and reliability as would be obtained with new logs and tests, the construction plan, and the need for additional information that may arise from time to time as the construction of the well progresses and these may include the following:

(i) Deviation checks during drilling on all holes constructed by drilling a pilot hole that is enlarged by reaming or another method. Such checks must be at sufficiently frequent intervals to determ ine the location of the borehole and to

assure that vertical avenues for fluid m ovement in the form of diverging holes

are not created dur ing drilling;

(ii) Before and upon installa tion of the surface casing:

(A) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and

(B) A cement evaluation log or logs af ter the casing is set and cemented.

(iii) Before and upon installation of the long string casing:

(A) Resistivity, spontaneous potential, porosity, caliper, gamma ray and any other logs the Director re quires based on site specific conditions and riskbased factors for the given geology befo re the casing is installed; and

(B) Cement evaluation log(s) and/or map(s) after the casing is set and cemented to evaluate cement quality with suffi cient radial resolution to identify channels or missing cement that would prevent compliance with §146.25(d)(2).

(iv) Test(s) designed to demonstrate th e internal and exte rnal mechanical integrity of injection wells, which may include:

(A) A pressure test w ith liquid or gas; (B) Diagnostic tools such as oxygen-activation logging; (C) A temperature or noise log; (D) A casing inspection log; and (E) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director.

(2) The owner or operator must submit to the Director a repor t describing whole cores or sidewall cores representative of the injection zone and confining

9system and formation fluid samples from the injection zone(s). The Director may accept data from cores and fluid samples from nearby wells if the owner or operator can demonstrate that such data are representative of conditions in the

wellbore.

(3) Prior to injection well operation, th e owner or operator must record the formation temperature, formation flui d pH and conductivity, and reservoir pressure of the injection zone(s).

(4) At any time prior to injection well operation, the owner or operator must determine fracture pressures of the inj ection and confining zones and conduct tests to verify hydrogeologic and geomechani cal characteristics of the injection

zone.

(5) 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 upon spudding the well and submit any changes to the schedule 48 hours prior to the scheduled test.

(f) Injection well operating requirements

(1) The owner or operator must comply w ith a maximum injection pressure limit approved by the Director and specified in the permit. In approving a maximum injection pressure limit, the Director sh all consider the results of well tests and, where appropriate, geomechanical or ot her studies that as sess the risks of tensile failure and shear failure. The Director shall approve limits that, with a reasonable degree of certainty, will avoid initiation or propagation of fractures in the confining zone or cau se otherwise non-tran smissive faults transecting the confining zone to become transmissive. In no case may injection pressure cause movement of injection or formation fluids in a manner prohibited by 40 C.F.R. §144.12(a).

(2) Injection of the CO2 stream into any annulus or between th e outermost casing protecting USDWs and the well bore is prohibited.

(3) For injection wells constructed with injection tubing and packer, the owner or operator must fill the annulus between the tubing and the long string casing with a corrosion inhibiting fluid approved by the Director and must maintain a positive pressure on the annulus.

(4) The owner or operator must install a nd use continuous recording devices to monitor: the injection pressure and the rate, volume, and temperature of the carbon dioxide stream. For inj ection wells constructed w ith injection tubing and packer, the owner or operator must regularly monitor the pressu re on the annulus between the tubing and the long string casing. The owner or operator must install, test and use alarms and automa tic shut-off systems, designed to alert

10the operator and shut-in the well when ope rating parameters such as injection rate, injection pressure, or other parame ters approved by the Director diverge beyond ranges and/or gradients specified in the permit.

Notes:

The duty to establish and ma intain mechanical integrity is already imposed under 40 C.F.R. §144.51(q)(1).

Requirements for responding to a potentia l lack of mechanical integrity are imposed under 40 C.F.R. §144.51(q).

Requirements for 24-hour reporting are imposed under 40 C.F.R. §144.51(l)(6).

(5) Mechanical integrity

(i) A well has mechanical integrity if:

(A) There is no significant leak in the casing, tubing or packer; and (B) There is no significant fl uid movement into a USDW through channels adjacent to the injection well bore.

(ii) To evaluate the absence of signifi cant leaks under this subsection, owners or operators must, following an initial annulus pressure test, continuously monitor and record at least daily injec tion pressure, rate, injected volumes, and - for wells constructed with an inject ion tube and packer - pressure on the annulus between tubing and long stem casing and annulus fluid volume as specified in §146.25(g)(2)(ii);

(iii) At least once per year, the owner or operator must confir m the absence of significant fluid movement under paragraph (5)(i)(B) of this section using a method acceptable to the Director (e.g. in cluding diagnostic surveys such as oxygen-activation logging or temp erature or noise logs).

(iv) The Director may require any other te st to evaluate mechanical integrity under paragraph (i)(A) or (i)(B) of this section. Also, the Director may allow

the use of a test to demonstrate mechani cal integrity other than those listed above with the written approval of the Ad ministrator. To obta in approval, the Director must submit a written request to the Administrator, which must set forth the proposed test and all tec hnical data supporting its use. The Administrator must approve the request if it will reliably demonstrate the mechanical integrity of wells for whic h its use is propose d. Any alternate method approved by the Administrator will be published in the Federal Register and may be used in all States in accord ance with applicable State law unless its use is restricted at the time of approval by the Administrator.

11(v) In conducting and evaluati ng 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 desc ription of the test(s) and the method(s) used. In making his/her evaluation, the Director mu st review monitoring and other test data submitted since the previous evaluation.

(vi) 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 demonstrat e 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 (i)(A) and (i)(B) of this section.

(g) Testing and Monitoring

(1) Based on a site-specific assessment of the potential for fluid movement from the injection well or injection zone, a nd on the potential va lue of monitoring wells to detect such movement, the owner or operator of a well must prepare, maintain, and comply with a testing and monitoring plan. 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.

(2) The testing and monitoring plan must, at a minimum, include:

(i) analysis of the carbon dioxide stream with suffici ent frequency to yield data representative of its chemi cal and physical characteristics;

(ii) Installation and use, except during well workovers as defined in section 146.88(d), of continuous monitoring devices (including digital devices capturing periodic data) to monitor injection pre ssure, rate and volume; and, for wells constructed with injection tubing and packer, to record at least daily the pressure on the annulus between the tubing and the long strong casing;

(iii) demonstration of external mechan ical integrity pursu ant to §146.25(f)(5) until the well is plugged;

(iv) monitoring of the pressure build up in the injection zone annually, including at a minimum, a shut down of th e well for a time sufficient to conduct a valid observation of the pressure fa ll-off curve at least once every five years; and

(v) a quality assurance plan.

12(3) Where appropriate, the testing and monitoring pl an shall also include:

(i) Continuous monitoring for pressure ch anges in an appropria tely porous and permeable formation overlying the confini ng zone. When a well is installed to enable such monitoring, the owner or operator shall, on a specified frequency or at specified times, sample the formati on and analyze for constituents specified in the plan;

(ii) The use of indirect, geophysical techniques to de termine the position of the CO2 stream front, the wa ter quality in a designated formation, or to provide other site specific data;

(iii) Periodic monitoring of water quality in an appropriately porous and permeable formation overlying the injection zone;

(iv) Periodic monitoring of water quality in one or more USDWs;

(v) Corrosion monitoring of the well ma terials for loss of mass, thickness, cracking, pitting and other signs of corro sion performed and recorded at least quarterly which may be modified to be le ss frequent as approved by the Director based on construction materials, operating conditions, and monitoring history to ensure that the well components meet mini mum standards for material strength and performance by:

(A) Analyzing coupons of the well construc tion materials placed in contact with the carbon dioxide stream; or (B) Routing the carbon dioxide stream through a loop constructed with the material used in the well and inspec ting the materials in the loop; or (C) Using an alternative method, materi als, or time period approved by the Director;

(vi) Any additional monitoring, as requi red by the Director, based on sitespecific conditions and risk-based factor s, necessary to support, upgrade, and improve computational modeling of the ar ea of review evaluation required under § 146.84(b); and

(vii) Any additional testing and monitoring necessary to determine whether fluid movement is occurring that would endanger a USDW.

(h) Reporting and Certification Requirements

The owner or operator must, at a minimum, provide the following reports to the Director, for each permitted well:

(1) Semi-annual or less frequently as determined by the Director reports containing:

13(i) Any significant changes to the physi cal, chemical and other relevant

characteristics of the carbon dioxide str eam from the proposed operating data; (ii) Monthly average, maximum and minimum values for injection pressure, flow rate and volume, and annular pressure; (iii) A description of any event that significantly exceeds operating parameters for annulus pressure or injection pr essure as specified in the permit; (iv) A description of any event which triggers a shutdown device required pursuant to §146.25(f)(4) and the response taken; (v) The monthly volume of the carbon dioxide stream injected over the reporting period and project cumulatively; (vi) Monthly annulus fluid volume added; and (vii) The results of monitori ng prescribed under §146.25(g).

(2) Report, within 30 days the results of:

(i) Periodic tests of mechanical integrity; (ii) Any other test of the injection we ll conducted by the permittee if required by the Director; and (iii) Any well workover.

(3) 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.

(4) Owners or operators must submit an annual certification, signed by the appropriate company official , that the company has:

(i) reviewed the area of review and all of the required plans; (ii) reviewed all monitoring and ope rational data since the previous

certification that are releva nt to a decision on whether to update the area of review and each plan; (iii) determined with regard to the ar ea of review and each plan whether an update was warranted; and (iv) completed an update pursuant to sect ion 146.84(f) for the area of review if warranted by material change, (v) completed an update and attached a su mmary of the modifications for each of the plans for which an update was warranted by material change.

(5) The Director may require submission of copies of any updated plans and/or additional information regarding the reas ons why updates of particular plans have or have not been prepared.

(6) The Director may require reevaluati on of the area of review pursuant to section 146.84(f) or the revision of any required plan whenever the Director

determines on the basis of information available to him that an update is

14necessary to comply with the re quirements of this Subpart.

(i) Required permit information

This section sets forth the information wh ich the owner or operator must submit to the Director in order to be perm itted. The application for a permit for construction and operation of an injection well must include the following:

(1) Information required in 40 CFR 144.31(e)(1) through (6);

(2) A surface map showing the proposed lo cations for 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 known 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 f eatures including structures intended for human occupancy and roads. Only inform ation of public record is required to be included on this map;

(3) A map delineating the area of revi ew based upon mode ling, using all available data including da ta available from any logging and testing of wells

within the area of review.

(4) Sufficient information on the geologic structure and reservoir properties of the proposed storage site and overlyi ng formations, which may include:

(i) Isopach maps of the pr oposed injection and confini ng zone(s), a structural contour map aligned with the top of the proposed injection zo ne, and at least two geologic cross sections of the area of review reasonably perpendicular to each other showing the geologic formations from the surface to total depth of

the well.

(ii) Location, orientation, and propert ies of known or susp ected subsurface faults that may transect the confining zone(s) in the area of review and a determination that they would not interfere with containment;

(iii) Information on seismic history that have affected the proposed area of review including knowledge of previous seismic events and history of these events, including the presence and depth of seismic sources and a determination that the seismicity would not compromise containment;

(iv) Data sufficient to demonstrate th e effectiveness of the injection and confining zone(s), including data on the depth, areal extent, thickness, mineralogy, porosity, vertical permeability reservoir pressu re and of the injection and confining zone (s) within the area of review; including geologic

15changes based on field data which may include geologic cores, outcrop data, seismic surveys, well logs, capillary pre ssure tests and names and lithologic descriptions;

(v) Geomechanical information on the c onfining zone(s) with in the area of review; and

(vi) Geologic and topographic maps and cross sections illustrating geology, hydrogeology, and the geologic struct ure of the area of review.

(5) A compilation of all artificial penetr ations within the area of review which penetrate the injection or confining z one(s). Such data must include a description of each well’s type, constr uction, date drilled, location, depth, record of plugging and/ or completion, and any additional information the Director may require;

(6) Maps and stratigraphic cross sections indicating th e general vertical and lateral limits of all USDWs, the location of water wells and perennial springs within the area of review, their positions relative to the injection zone(s) and the direction of water movement, where known;

(7) A compilation of available baseli ne geochemical data on the proposed injection zone and nearest adjacent por ous and permeable formation to the confining zone, existing u tilized water supply aquifers and any other USDWs designated by the Director.

(8) Proposed operating data:

(i) Average and maximum daily injection rate and volume of the carbon dioxide

stream; (ii) Average and maximum surface injection pressure; (iii) The source of the carbon dioxide stream; and (iv) An analysis of the chemical a nd physical characteristics of the carbon dioxide stream;

(9) The compatibility of the carbon dioxide stream with fluids in the injection zone and minerals in both the injection a nd the confining zone(s), based on the

results of the formation te sting program or other data , and with the materials used to construct the well;

(10) Proposed formation testing program to obtain an analysis of the chemical and physical characteristics of the in jection zone and confining zone;

(11) Proposed stimulation program and a de termination that stimulation will not compromise containment;

16(12) The results of the formation testi ng program as required in paragraph (j) of this section;

(13) Proposed procedure to outline step s necessary to c onduct injection operation;

(14) A wellbore schematic of the subsur face construction details and surface wellhead construction;

(15) Injection well construc tion procedures that meet applicable requirements;

(16) Proposed corrective acti on plan for artificial penetr ations within the area of review, if necessary;

(17) All available logging and testing pr ogram data on the well required by §146.25(e)(1);

(18) The proposed demonstration method fo r mechanical integrity pursuant to §146.25(j)(5);

(19) A demonstration, satisfactory to the Director, that the applicant has met the financial responsibility requirements under §146.25(c);

(20) Proposed testing and monito ring plan required by §146.25(g);

(21) Proposed injection and monitori ng well(s) plugging plan required by §146.25(j)(2);

(22) Proposed post-injecti on site care and site cl osure plan required by §146.25(k);

(23) Proposed emergency and remedial re sponse plan required by § 146.25(l); and

(24) Any other information requested by the Director.

(j) Injection well plugging

(1) Prior to the well plugging, the owner or operator must flush each injection well with a buffer fluid, determine bottom hole reservoir pressure, and perform a final external mechanical integrity test.

(2) Well Plugging Plan. The owner or operato r of a well must prepare, maintain, and comply with a plan that is acceptabl e 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 perm it application and must include the

17following information:

(i) Appropriate test or measure to de termine bottomhole re servoir pressure; (ii) Appropriate testing methods to ensure final external mechanical integrity as specified in §146.25(f)(5); (iii) The type and number of plugs to be used; (iv) The placement of each plug including the elevation of the top and bottom of each plug; (v) The type and grade and quantity of material to be used in plugging. The

material must be suitable for use with the carbon dioxide st ream, reservoir and fluid conditions; and (vi) The method of placement of the plugs.

(3) 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, th e owner or operator must also provide the revised well plugging pl an. At the discretion of the Director, a shorter notice period may be allowed.

(4) Plugging report. Within 60 days afte r plugging the owner or operator must submit a plugging report to the Director. The report must be certified as accurate by the owner or operator and by the person who performed the plugging operation (if other than th e owner or operator.)

(k) Post-injection site care and site closure

(1) The owner or operator of a well must prepare, maintain, and comply with a plan for post-injection site care and site closure that meets the requirements of paragraph (1)(ii) of this section and is acceptable to the Director.

(i) The owner or operator must submit th e post-injection site care and site closure plan as a part of the permit app lication to be approve d by the Director.

(ii) The post-injection site care and si te closure plan must include the following information:

(A) The pressure differentia l between pre-injection and projected post-injection pressures in the injection zone;

(B) The projected position of the carbon dioxide plume a nd associated pressure

front at site closure as de monstrated in the area of review evaluation required under §146.25(b)(1), (3) and (5);

(C) A description of post-injection mon itoring location, methods, and proposed frequency; and

18(D) A proposed schedule for submitting pos t-injection site care monitoring

results to the Director.

(iii) Upon cessation of inject ion, owners or operators of 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.

(iv) The owner or operator may modify a nd resubmit the post-injection site care and site closure plan for the Director’s approval within 30 days of such change

(2) The owner or operator shall monito r the site following the cessation of injection.

(i) The owner or operator shall continue to conduct monitoring as specified in the Director-approved post-injection site care and site closure plan, pursuant to the performance based criteria described in § 146.25(k)(2)(iii).

(ii) The owner or operator can request a nd demonstrate to the satisfaction of the Director that the post- injection site care and site closure plan should be

revised to reduce the fr equency of monitoring.

(iii) Prior to authorization for site closure, the owner or operator must demonstrate to the Director, based on m onitoring, other site-specific data, and modeling that is reasonably consistent with site perf ormance that no additional monitoring is needed to assure that the geologic sequestration project does not pose an endangerment to USDWs. The owner or operator must demonstrate, based on the current understanding of the site , including monitori ng data and/or modeling, all of the following: (A) the estimated magnit ude and extent of the project footprint (CO2 plume and the ar ea of elevated pre ssure) ; (B) the estimated location of the detectable CO2 plume ; (C) that there is no significant leakage of either CO2 or di splaced formation fluids that is endangering USDWs; (D) that the injected or displaced fluids are not expected to migrate in the future in a manner that encounters a potential leakage pathway into a USDW; (E) that the injection wells at the site completed into or through the injection zone or confining zone are plugged and abandoned in accordance with these requirements; a nd (F) any remaining project monitoring wells at the site are being managed by a person and in a manner acceptable to the Director.

(3) Notice of intent for site closure. The owner or operator must notify the Director at least 120 days be fore site closure. At th is time, if any changes have been made to the original post-inj ection 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.

(4) After the Director has authorized site closure, the owner or operator must

19plug all monitoring wells in a manner which will not allow moveme nt of injection or formation fluids that endangers a USDW.

(5) Once the Director has authorized site closure, the owner or operator must submit a site closure report within 90 days after completion of all closure operations. The report must include:

(i) Documentation of appropriate inje ction and monitoring well plugging as specified in §146.25(j) and para graph (4) 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 mu st indicate the location of the injection well(s) 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;

(ii) Documentation of appropriate notific ation and information to such State,

local and tribal authorities as have authority over drilling activities to

enable such State and local authorities to impose a ppropriate conditions on subsequent drilling activities that may penetrate the injection and confining zone(s); and

(iii) Records reflecting the nature, composition and volum e of the carbon

dioxide stream.

(6) Each owner or operator of a injecti on well must provide notification to the designated state authority of the following information:

(i) The fact that land has been us ed to sequester carbon dioxide;

(ii) The name of the State agency, local authority, and/or tr ibe 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

(iii) The volume of fluid injected, the in jection zone or zones into which it was injected, and the period ove r which injection occurred.

(7) The owner or operator must retain fo r three years following site closure, records collected during the post-injection site ca re period. The owner or operator must deliver the records to th e Director at the conclusion of the retention period, and the records must th ereafter be retained at a location designated by the Director for that purpose.

(l) Emergency and Remedial Response Plan

(1) As part of a permit application or request for revisi on to operate under this section, the owner or ope rator must provide the Director with an emergency,

20risk-based remedial response plan that de scribes 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-cl osure periods.

(2) If the owner or operator obtains ev idence that the inj ected carbon dioxide stream, displaced formation fluids or and associated pressure front endangers a USDW, the owner or operator must:

(i) Cease injection in a prudent manner considering circumstances.

(ii) Take all steps reasonably necessa ry to identify and characterize the endangerment posed;

(iii) Notify the Director or the designated represen tative within 24 hours of becoming aware of the endangerment; and

(iv) Implement the emergency and remedial response plan approved by the Director and keep the Director appri zed of the implementation.

(3) The Director may allow the operator to resume injection prior to remediation if the owner or operator demonstrates th at the injection op eration will not endanger USDWs.

(4) The owner or operator must notify the Director and obtain hi s approval prior to conducting any well workover or other re mediation measures not listed in the emergency and remedial response plan.

(5) If an owner or operator obtains evid ence that a pressure front associated with one geologic sequestration project inte rsects or will intersect the area of review associated with another project, the owner or operator obtaining such evidence must notify the Director. If the Di rector determines that the pressure front associated with one project will interfere with the ability of another project to comply with the terms of its permit(s), the Director may require the owner or operator of the potentially inte rfering project to modify operations as necessary to avoid such interference. Su ch modification may include mutually agreed modifications in operations to bot h projects or other actions if the respective owners and operators agree to requirements to implement modifications or other actions approved by the Director that will mitigate the interference."

Note: Requirements for responding to a poten tial lack of mechanical integrity are imposed under 40 C.F.R. §144.51(q). Requi rements for 24-hour reporting are imposed under 40 C.F.R. §144.51(l)(6).

Individual Response: As described above, EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery shoul d remain under the Class II Program, but that there are significant difference s between how EOR and GS projec ts are operated for purposes of

2122 protecting USDWs from endangerment. EPA does not believe that GS in oil and gas formations should be regulated separately from GS in othe r geologic formations or that the creation of a Class VII well category for GS is necessar y. EPA has taken a regulatory approach which promotes USDW protection, incorporates flexibil ity or the discretion of the permitting authority when appropriate, seeks to limit burden on owners or operators and permitting agencies, and provides a foundation for national consistency in permitting of GS projects. For example, under the final rule, many of the permit requirements mu st be established thr ough site-specific plans (e.g., AOR and corrective action pl an, testing and monitoring pla n, etc.) developed by the owner or operator and approved by the Director. Conseque ntly EPA expects that owners or operators

will consult with the Dir ector as they develop, implement, and update these plans. Additionally,

the Director has the discretion to approve alternatives to the requirements in some cases. For example, the Director may in certain situations m odify the length of the post-injection site care period under §146.93, allow the use of alternate met hods for mechanical in tegrity testing under §146.89, or grant waivers from the requirement to inject below the lowermost USDW under §146.95.

The Agency believes that the nature and risks of CO2 injection for the primary purpose of long term storage poses different risks than injection for the primary purpose of EOR, and therefore has developed new Class VI regulations to addre ss these unique risks. For example, the volume of CO2 anticipated to be inject ed for long term storage is sign ificantly greater than for EOR operations. Reservoir pressure c onditions will also be differe nt, with Class VI injection operations involving large volumes of CO2 and likely having higher pressures within their storage formations than Class II EOR projects, wh ich may lead to fluid movement that endangers

a USDW.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment EPA has made many revisi ons to the GS Rule. For more information, please see the discussion on transiti on of Class II wells in the pr eamble to the final GS rule.