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GS Multi-Stakeholder Discussions 1 sanderson@edf.org rfvanvoorhees@bryancave.com 

### Overview of the GS Multi-St akeholder Recommendations

The Geologic Sequestration Multi-Stakehol der Discussion (MSD) group and process

involves:

• Organizations representing a broad array of interests in the issues associated with geologic sequestration (GS) rulemaking

• Organizations discussing interests and issues in an effort to reach consensus or at

least narrow differences

• Organizations making joint recommenda tions to the U.S. Environmental Protection Agency (EPA) and states

• A changing group of participants

Participating organizations have va ried over time, but have included:

American Petroleum Institute Carbon Sequestration Council

Clean Air Task Force

Edison Electric Institute

Environmental Defense Fund

Ground Water Protection Council Interstate Oil and Gas Compact Commission

Natural Resources Defense Council U.S. State UIC program and o il and gas agency officials Texas Carbon Capture and Storage Association

Participating companies have also varied but have included:

American Electric Power Anadarko Petroleum Corporation

Blue Source LLC BP Alternative Energy North America Inc.

BP America Inc. ConocoPhillips Denbury Resources Inc. Duke Energy

E.ON U.S. LLC Hydrogen Energy California LLC Occidental Petroleum Corporation Salt River Project Shell Exploration and Production Southern Company

Background for the MSD process – this effo rt was facilitated by a number of other activities that provided opportunities for stake holders to interact.February 4, 2010

GS Multi-Stakeholder Discussions 2 sanderson@edf.org rfvanvoorhees@bryancave.com • Facilitated by EPA’s technical wo rkshops on carbon capture and geologic sequestration

• Helped by EPA’s public meetings to discuss its rulemaking approach

• Enabled by the Interstate Oil and Ga s Compact Commissi on’s Workgroup that included state regulators, ENGOs and industry

• Enhanced by the efforts of the Ground Water Protection Council through its CO 2 Workgroup and Committee (also included st ate regulators, ENGOs and industry)

• World Resources Institute’s de velopment of CCS Guidelines

• DOE Regional Carbon Seque stration Partnerships

The November 17, 2008 comment extensi on request included a broad group of organizations, not all of which chose to participate in th e subsequent MSDs.

• 15 organizations requested 25 day exte nsion of Nov 24 comment deadline:

Signatories:

American Petroleum Institute

American Water Works Association

Edison Electric Institute

Environmental Defense Fund

Ground Water Protection Council Interstate Oil and Gas Compact Commission

Natural Resources Defense Council

Supporters:

American Public Power Association Carbon Sequestration Council

Clean Air Task Force

Clean Water Action

National Ground Water Association National Mining Association North American Carbon Captur e and Storage Association

The Sierra Club

• Advised EPA and incoming Obama Administration:

Agreed that EPA’s proposal pr ovides a solid foundation on which to develop the regulat ory framework for geologic sequestration on issues within the purview of the SDWA and that development of this rule should proceed with EPA’s proposal as the starting point

• EPA Granted a 30-day extension

MS Discussion Principles:February 4, 2010

GS Multi-Stakeholder Discussions 3 sanderson@edf.org rfvanvoorhees@bryancave.com Groups invited to participate in the multi- stakeholder discussion group were asked to agree to the following basic principles:

I. Geologic sequestration of CO2 (GS) could have a role to play in a greenhouse gas mitigation portfolio a nd should be one of the options

considered.

II. GS can be performed in a safe and effective manner that does not endanger USDWs if projects are well managed and regulated adequately.

III. EPA's proposed rule on GS, with the necessary technical amendments and if implemented effectively, can ensure that GS projects are well managed, and hence will be safe and effective operations.

IV. It is desirable that stakeholders reach consensus to the degree possible on key issues raised by the proposed rule.

V. EPA should proceed with the pr omulgation of the rule under the proposed 2010-2011 timeline.

VI. The discussions will address issues relating di rectly to EPA's proposed GS rule, including establishment of injection pressure limitations for geologic sequestration injection well s; how various types of target

formations should be addressed with in the underground injection control (UIC) program, including requirements for geologic sequestration in oil and gas reservoirs; the process and criteria for achieving closure of geologic sequestration projects; pr otection of underground sources of drinking water, and any other issues that participants agree should be

added to this list.

VII. Each participant agr ees not to disclose (1) any information about the discussions to the press or to EPA dur ing the course of discussions and (2) either during the course of discussions or afterwards, the identity or the affiliation of any speaker(s) who made particular statements or addressed particular points without obtaini ng the permission of the speaker.

General approach to the MSD reco mmendations for GS regulations:

• Build on existing knowledge of technology and sites

• Preference for performance standards

• Allow for adaptation based on “learning by doing” from both specific projects and

collective results

• Using plans to allow flexibility for si te specific and progressive adaptation

• Recognition of important role modeling will play

• Iterative process to allow for use of data to verify and modify modeling as necessary and appropriateFebruary 4, 2010

GS Multi-Stakeholder Discussions 4 sanderson@edf.org rfvanvoorhees@bryancave.com The first recommendation letter – Decem ber 23, 2008 addressed four key issues:

• Enhanced recovery of oil or natural gas and geologic sequestration of CO2

• Injection Pressure Limitations

• Project/Site Closure Standard

• Need for adequate government implementation resources

Enhanced oil recovery (EOR) with geologic sequestration (EOR+GS):

“We recommend that the rules be clarif ied to provide more certainty about the applicability of Class II requirements where GS of CO 2 occurs in

connection with EOR/EGR activities.”

“Specifically, the UIC rules should provi de a ‘bright line’ definition as to the applicable class of wells where CO 2 injection for EOR/EGR production and for GS occur in tandem.”

The December 23, 2008 MSD letter spelled out the “bright line” – essentially concluding that regulation of GS in oil and gas reservoi rs should change when projects are injecting

more CO 2 than needed for “business as usual” EOR operations:

The “bright line” distinguishes between “busin ess as usual” EOR with GS and other GS in oil and gas reservoirs

Under this approach, Class II would include wells used: “For enhanced recovery of o il or natural gas where geologic sequestration is occurring during or in connection with enhanced recovery of oil or natural gas provided (i) ther e is reasonable expectation of more than insignificant future production volu mes or rates as a result of carbon dioxide injection and (ii) operating pressures are no higher than reasonably necessary to produce such volumes or rates;”

Geologic Sequestration in oil and gas reservoirs:

• The signatories to [the MSD letters in December 2008 and October 2009 have] recommended, consistent with EPA’s inte nt, that wells used for EOR/EGR should

remain in Class II and that wells used for EOR/EGR with GS – that meet the (b)(4) definition – should also remain in Class II and be subj ect to the current requirements for Class II.

• [These] Signatories . . . also agreed that the wells used for GS in oil and gas

reservoirs that do not meet the criteria of (b)(4) shoul d be subject to additional requirements. That letter noted an agreemen t 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.” The Oct ober 9, 2009 letter and the attachedFebruary 4, 2010

GS Multi-Stakeholder Discussions 5 sanderson@edf.org rfvanvoorhees@bryancave.com provisions provide specific recommende d requirements for GS in oil and gas reservoirs when the criteria of paragraph (b)(4) are not met.

• In the Multi-Stakeholder Discussions since March 31, 2009, the signatories to the October 9 letter agreed that wells used for GS in oil and gas reservoirs that do not meet the criteria of paragraph (b)(4) s hould be subject to a set of additional requirements different from those that would apply under the current Class 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 also reflected in the four letters EPA received on March 17, 2009 from MSD participants. Each of those March 17 letters asked EPA to include this approach in its final GS rule. The March 31, 2009 MSD letter included a smaller number of signatories than the October 9, 2009 letter because consensus on all of the attached requiremen ts to that letter had not been achieved

at that time. A broader consensus was ach ieved for the October 9 letter, allowing submission of the comprehensive recomme ndations attached to that letter.

• Specifically, the October 9, 2009 letter reco mmend that requirements be added to Class II through an amendment to ad d a new section 146.25. Although the MSD process had also considered that these requirements might be promulgated as a new Class VII in a new Part 146, Subpart I, the October 9 signatories agreed that the addition to Class II through a new 146.25 is the better approach provided that EPA adopts the delegation standard for primacy explained in that letter. Specifically, the signatories agreed th at the proposed section 146.25 requirements should be subject to state primacy approva l under the standard of section 1422 of the Safe Drinking Water Act (SDWA) rather than the alternative standard of section 1425, especially wh ere it will be clear that injection for geologic sequestration in an oil and gas reservoir will be done without recovery of oil or natural gas.

This would add to Class II:

Wells used for geologic sequestration but not including those wells used for geologic sequestration that are re gulated under another Class. Wells used for geologic sequestration in ba salts, coal seams, salt caverns or shales are regulated under Class V as experimental wells until such time as the Administrator establishes separate requirements by rule for the specific type of formation or determines, following public notice and opportunity for comment, that wells used for ge ologic sequestration of carbon dioxide streams into the specific type of formation should be regulated under

another class.”

The resulting MSD recommendations anticipa te the following breakdown of GS wells:

• Class II – All wells used for GS in oil and gas reservoirsFebruary 4, 2010

GS Multi-Stakeholder Discussions 6 sanderson@edf.org rfvanvoorhees@bryancave.com • Class V – “Experimental” – Wells used for in basalts, coal seam s, salt caverns or shales would be regulated as experiment al wells until appropriate requirements are established by rule – a nd other experimental wells

• Class VI - Wells used for GS unl ess regulated under another Class

Another major accomplishment of the MSD pr ocess involves the development of the process for maintaining the plans that incor porate the adaptive performance measures that must be implemented by operators:

• Although the proposed §146.84(f) would requ ire “reevaluation” of the AoR at a “minimum” fixed frequency of ten year s or “when operational and monitoring conditions warrant,” the sp ecific language of §146.84 runs the risk that revisions will not be made on a timely basis.

• We recommend imposing a continual oblig ation on operators to assess whether the AoR and any of the plans required by the regulations – including but not limited to the monitoring plan – should be revised,

requiring an annual statement th at the owner or operator

has reviewed the circumstan ces (including operating and monitoring data) during the pr eceding year to determine

whether any updates were warranted by material change in the monitoring and operational data or in the evaluation of the monitoring and operational data by the owner or operator, and

requiring that revisions be done when required by the Director as well as when the operator determines that

conditions warrant.

• To accomplish this, it is useful to break down the concept of “reevaluation” into two ideas – (i) “assessment” of the need to revise the AoR and the plans and (ii) the actual process of “revision.”

• We believe that these suggestions will resu lt in increased accuracy and reliability in the site performance data while avoidi ng work that is not warranted by the site data and site performance or improved understanding of both.

• Moreover, a continuous obligation to asse ss whether revisions are needed, when coupled with an annual review and conf irmation requirement will create a clear accountability trail for both operator a nd Director in case of disputes.

• Given this annual review process, we believe it is unnecessary to require a

reevaluation on a fixed basis ev ery 10 years in every case.

• An annual review requirement can also be used to enhance the ability of both Director and operators to keep track of which plans require updating and whether or not plans that ought to be update d have in fact been revised.

• Such a shared understanding is essential if there is to be the “ongoing dialogue” between regulators and operators that EPA anticipates.

• We considered the inclusion of an annual report as described in the preamble at 73 Fed. Reg. 43518, but concluded that the benef its of that particular report wouldFebruary 4, 2010

GS Multi-Stakeholder Discussions 7 sanderson@edf.org rfvanvoorhees@bryancave.com be outweighed by the burden. The reco mmended annual review would be much simpler.

Other major issues on which agreement has been reached:

• Injection Pressure Limitations

• Project/Site Closure Standards

• Need for adequate government implementation resources

The May 14 and 15, 2009 Letters

• GS in Basalts, Coal Seams, Salt Caverns, Shales

• Non-interference Provision for adjacent projects

• Regulatory Definitions of Tran smissive fault or fracture, Confining zone and Area

of Review

• Area of Review Requirements

• Area of Review Delineation

• Reevaluation and Update of AoR and Project Plans

• Plan Maintenance and Update

• Emergency Response provisions

The October 9, 2009 Letter

• Class II(b)(5) requirements to be added in 40 CFR §146.25

### Overview of the GS Multi-St akeholder Recommendations

Letters submitted to U.S. Environmental Protection Agency from the Multi-Stakeholder Discussions (MSDs):

1. November 17, 2008 Request for extension of the public comment period on proposed rule for geologic sequestration

2. December 23, 2008 Recommendations:

a. Enhanced recovery of oil or natural gas and geologic sequestration of CO 2

b. Injection Pressure Limitations

c. Closure Standard

d. Need for adequate implementation resources

3. May 14, 2009 Recommendations

a. Basalts, Coal Seams, Salt Caverns, and Shales

b. Non-interference principle

c. Definition of transmissive faults or fractures

d. Definition of confining zone

e. Area of review definition and basis

f. Area of review and corrective action requirements

g. Well construction

h. Reevaluation of the Area of Review and Revision and

Maintenance of Plans

i. Emergency Response

4. May 15, 2009 Recommendations

a. Pressurized annulus

b. Down-hole shutoff valves

5. October 9, 2009 Recommendation of comprehensive 40 CFR 146.25 regulations for geologic seque stration (GS) in oil and gasreservoirs that does not meet the provisions of the (b)(4) language recommended in the joint letter submitted by a number of participants in the Multi-Stakeholder Di scussion (MSD) group on December 23, 2008

APPENDIX: Letters Relating to the Inte rim 40 CFR 146.25 Recommendations

1. March 17, 2009 Letter from American Petroleum Institute, Carbon Sequestration Council and Ed ison Electric Institute

2. March 17, 2009 Letter from Clean Air Task Force (CATF)

3. March 17, 2009 Letter from Environmental Defense Fund (EDF)

4. March 17, 2009 Letter from Natural Resources Defense Council (NRDC)

5. March 27, 2009 Letter from EDF and CATF

6. March 31, 2009 Letter from industry stakeholders

7. March 31, 2009 Letter from Gr ound Water Protection CouncilDecember 23, 2008

Cynthia C. Dougherty

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

Dear Director Dougherty:

The organizations identified below submit these comments and recommendations to the Environmental Protection Agency (EPA) in res ponse to the proposed rule for geologic sequestration of carbon dioxide under the Sa fe Drinking Water Act (SDWA). "Federal Requirements Under the Underground Injection Cont rol (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells", 73 Fed. Reg. 43491-541 (July 25, 2008). We appreciated the extension of the public comment period that was granted by Assistant Administrator Benjamin Grumbles, announced in the Federal Register on November 21 and confirmed in your letter of November 24. The organizations submitting thes e recommendations represent a broad array of

interests in the issues associated with this rulema king and many of us have been discussing these

interests and issues in an effort to reach consensu s or at least narrow our di fferences. We used this extension period to continue efforts toward de veloping recommendations reflecting common views on a number of the major issues in this rulemaking on which EPA expressly requested comment and several other issues. We share your hope th at these comments and recommendations will help the Agency develop a rule that will allow the technology to be permitted under an appropriate injection class while also ensuring protection of unde rground sources of drinking water as well as

human health and the environment.

EPA has noted that the proposed rules do not ad dress "accounting or certification for greenhouse gas (GHG) reductions." 73 Fed. Reg. 43492, 43 495 (July 25, 2008). By the same token, the consensus 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 verification requirements for carbon credits.

Enhanced recovery of oil or natural gas and geologic sequestration of CO 2

EPA’s Proposal would continue to regulate and permit injection of CO 2 for EOR/EGR purposes as Class II injection “as long as any production is occurring.” EPA has asked for comment on the merits of this approach “since owners or operato rs of some Class II EOR/EGR wells may wish to use wells for the purposes of production and GS pr ior to the field being completely depleted.” 73 Fed. Reg. at 43502. We recommend that the rule s be clarified to provide more certainty about the applicability of Class II requirements where GS of CO2 occurs in connection with EOR/EGR activities. Specifically, the UIC rules should provid e a “bright line” definition as to the applicableCynthia C. Dougherty December 23, 2008 Page 2

class of wells where CO2 injection for EOR/EGR production and for GS occur in tandem. We recommend the following language to accomplish that objective:

§ 144.6, 144.80 and 146.5, and Classification of injection wells.

Injection wells are classified as follows:

* * * (b) Class II. Wells which inject fluids:

(1) Which are brought to the surface in c onnection with conventional oil or natural gas production and may be commingled with waste waters from gas plants which are an integral part of production operations, unless those waters are classified as a hazardous waste at the time of injection.

(2) For enhanced recovery of oil or natural gas;

(3) For storage of hydrocarbons which are liquid at standard temperature and

pressure;

(4) For enhanced recovery of oil or natural gas where geologic sequestration is occurring during or in c onnection with enhanced recovery of oil or natural gas provided (i) there is reasonable expectation of more than insignificant future production volumes or rates as a result of carbon dioxide injection and (ii) operating pressures are no higher than reasonably necessary to produce such volumes or rates ;
* * * (f) Class VI. Wells injecting a carbon di oxide stream for geologic sequestration except those wells described in subsection (b)(4) of this section or otherwise

excluded from this Class

. 1 /

The undersigned have agreed that proposed lang uage describing wells in classification (b)(4) establishes a “bright line” definition for wells that inject CO2 for EOR/EGR and GS and, consistent with EPA’s intent, should remain in Class II and be subject to the current requirements of Class II. We have also agreed that the wells used for GS in oil and gas reservoirs that do not meet the criteria of (b)(4) should be subject to additional requirements. We have tentatively defined such wells as wells used “for geologic sequestration in oil and gas formations and where the criteria of paragraph (b)(4) are not met.” But we have not yet attempted to define what specific

1/ Please note that well classification for geologic sequestration in certain formations is a matter still under

discussion within the multi-stakeholde r group and may be addressed further in future recommendations from the group. In the mean time individual participants in these discussions will be expressing views on this and other issues with an openness to revising th eir views if a consensus can be reached.Cynthia C. Dougherty December 23, 2008 Page 3

requirements should apply to these wells. We ar e committed to working toward agreement on those requirements (probably within a Class II context) and submitting the results of that effort to EPA by February 28, 2009 for your consideration.

Injection Pressure Limitations

We are concerned about three aspects of proposed section 146.88(a), governing injection pressure limitations. First, it “restricts” fractures in th e injection zone “except during stimulation” rather than focusing on maintaining the integrity of the confining zone, which is what really matters for protecting USDWs. Second, it fails to refer specifi cally to the full range of potential geomechanical failure modes potentially posed by operations at a particular site. Third, the type of geomechanical risk that is addressed (initiation or propagation of fr actures), is dealt with in a potentially arbitrary fashion (the 90% of fracture pressure limit), wh ich may not be appropriate in all cases.

Our recommended language addresses these concerns by focusing on maintaining the integrity of the confining zone and including tensile failure and shear failure as transmissivity concerns. It calls for additional geomechanical studies of tensile fa ilure and shear failure only “where appropriate”

because there will be locations where experience or existing in formation will provide sufficient evidence to avoid the need for additional studies. The need for conducting additional tests and for determining which tests would be acceptable is left to the Director’s discretion.

The owner or operator must comply wi th 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 sha ll approve limits that, with a reasonable degree of certainty, will avoid initiation or propagation of fractures in the confining

zone or cause otherwise non-transmissive fa ults transecting the confining zone to become transmissive. In no case may injection pressure cause movement of injection or formation fluids in a manner pr ohibited by 40 CFR Part 144.12(a).

Closure Standard

We believe there are three problems with the closur e standard in proposed section 146.93(b). First, the presumption that monitoring should continue for 50 years is unnecessary and counterproductive. A straight performance standard is preferable to this or any other fixed time period because it provides a clearer standard and an incentive to maximize the understanding of site and project performance and as such is more protective of USDWs. Second, the proposal requires a showing that the CO2 plume has “stabilized”, which is undefined. Cessation of plume movement is not necessarily essential to show that a project poses no threat of endangerment to USDWs— plumes that are still moving may, nonetheless, remain contained. Instead, it is more protective to show that the plume is not expected to encounter a leakage pathway. Third, the required showingCynthia C. Dougherty December 23, 2008 Page 4

that “no additional monitoring is needed” does not provide guidance regarding how an operator is to show that no additional monitoring is needed. The proposal below provides specific guidance on what the operator must show.

We recommend the standard in the proposed al ternative language for section 146.93(b) below

because it sets forth detailed criter ia, all of which must be satisfied, to demonstrate that the site does not pose an endangerment to USDWs. The specifi c criteria listed in our proposal will serve to provide the Director with the requisite informati on to make the appropriate determination. The advantage of this approach is that it establishe s clear criteria that an operator must demonstrate before obtaining site closure based upon particular site characteristics and is, therefore, reasonably applicable to any storage site as opposed to a standa rd based upon a fixed-duration. Furthermore, it is more stringent than a purely discretionary approach because it establishes specific criteria that must be shown before site closure may be granted. We believe this language, which is an extension of work done by the World Resources Institute and the Ground Water Protection Council, avoids the noted shortcomings and provides stronger protection for USDWs.

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

(1) The owner or operator shall continue to conduct monitoring as specified in the Director-approved post- injection site care and site clo sure plan until closure is authorized pursuant to 146.93(b)(3).

(2) 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.

(3) 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 performance, that no additional monitoring is needed to assure that the ge ologic sequestration project does not and is not expected to pose an endangerment to USDWs. The Director shall approve closure if the owner or operator demonstr ates, based on the current understanding of the site, including monitoring data and/or modeling, all of the following: (i) the estimated magnitude and extent of the proj ect footprint (CO2 plume and the area of elevated pressure) ; (ii) the estimated locati on of the detectable CO 2 plume; (iii) that there is no significant leakage of either CO2 or displaced formation fluids that is endangering USDWs; (iv) that the injected or displaced fluids are not expected to migrate in the future in a manner that en counters a potential leakage pathway into a USDW; (v) that the injection wells at the site completed into or through the injection zone or confining zone are plugged and abandoned in accordance with theseCynthia C. Dougherty December 23, 2008 Page 5

requirements; and (vi) any remaining project monitoring wells at the site are being managed by a person and in a manner acceptable to the Director.

Need for adequate implementation resources

Although not directly addressed in the EPA proposal , the need for adequate resources to implement the regulatory program for geologic sequestration at both the federal and state levels is a major

consideration and one that EPA should be addre ssing both internally and in its discussions with Congress. The annual national budget for the UIC program (approximately $11 million) has remained static for many years, while UIC agen cies have been asked to take on additional responsibilities. Furthermore, inflation of salaries and other expenses has eroded the buying power of the unchanging UIC budget. If state and regi onal agencies are asked to take on the additional

workload of CO 2 injection, while ensuring careful scient ific review as well as an expeditious processing time, they will require additional trained staff and other resources.

If the nation is serious about controlling CO 2 through underground injection, significant additional

resources will need to be made available to hire new permitting staff and field inspectors. Those new staff, along with the existing cadre of UIC staff an d managers, must be trained in subjects that will enable them to make prudent permitting, mana gement, and oversight decisions. As momentum grows to begin sequestering CO 2 underground, EPA and states will need to develop new regulatory requirements for CO 2 wells and prepare to review applications and make permitting decisions. Failure to provide sufficient resources will likely cr eate permitting backlogs, resulting in a bottleneck in the overall geologic sequestration effort.

The Ground Water Protection Council (GWPC) estima ted in 2004 that an annual funding increase to $56 million would be needed just to meet the needs of the existi ng UIC program at the state level even without the addition of geolog ic sequestration project permitting. 2 / GWPC has further

estimated that EPA will n eed to provide funding at a level of $100 million annually to meet the needs for the full UIC program, including the regulation of geologic sequestration.

Conclusion

We greatly appreciate the extension of the public comment period, as it has allowed us to make substantial progress in expanding our shared understanding on the releva nt issues and to reach significant agreement on how these issues can be a ddressed and resolved by EPA. The undersigned submit these recommendations with the request that the recommendations be considered as a whole because the recommendations were developed in combination to accurately reflect our shared understanding. In addition, we are committed to c ontinuing our discussions and to inviting others to participate with an objective of developing additional specific recommendations for improvement of a final rule that could be adopted by your sc heduled date in late 2010 or early 2011, including development of the requirements to be applied to o il and gas reservoir geologic sequestration that is

2/ GWPC, Class V Resource Needs Su rvey, Summary (September 2004).Cynthia C. Dougherty December 23, 2008 Page 6

not conducted in conjunction with enhanced oil an d gas production operations. We will be working toward submission of additional recommendations by February 28, 2009.

Sincerely,

Kyle Isakower Director, of Policy Analysis

American Petroleum Institute

Craig Walters General Manager, Enhanced Oil Recovery Anadarko Petroleum Corporation

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

Karen St. John Director Regulatory Affairs

BP America Inc.

Tiffany Rau Policy & Communications Manager Hydrogen Energy International LLCCynthia C. Dougherty December 23, 2008 Page 7

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

Kurt Waltzer Carbon Storage Development Coordinator

Clean Air Task Force

Jeff W. Sheets

Senior Vice President Planning & Strategy ConocoPhillips

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

William L. Fang Deputy General Counsel

Edison Electric InstituteCynthia C. Dougherty December 23, 2008 Page 8

Scott Anderson Senior Policy Advisor, Climate and Air Program

Environmental Defense Fund

Michel Paque

Executive Director

Ground Water Protection Council

Al Collins Senior Director, Regulatory Affairs Occidental Petroleum Corporation

Karl R. Moor

Vice President and Associate General Counsel Southern Company

Darrick W. Eugene

General Counsel Texas Carbon Capture & Storage Association

cc: Ben Grumbles

Steve Heare Ann CodringtonMay 14, 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 EPA–HQ–OW–2008–0390

Dear Director Dougherty:

The organizations identified by the signature s at the end of this letter have been participating in multi-stakeholder group (MSG ) discussions regarding the proposed rule for geologic sequestration (GS) of carbon di oxide under the Safe Drinking Water Act (SDWA), 73 Fed. Reg. 43491-541 (July 25, 2008). We have achieved consensus on specific rule language recommendations for all of the issues addressed in this letter.

As noted in previous letters , the consensus recommendations presented in this letter address only the objective of protecting unde rground sources of dr inking water (USDWs)

under the SDWA and do not address verifi cation requirements for carbon credits. 1 /

1. Basalts, Coal Seams, Salt Caverns, and Shales

We agree that EPA has ample basis for adopt ing rules to regulate GS in hydrocarbon reservoirs and in deep saline formations under the SDWA. For these types of geologic formations, there is a widespread technical consensus on how to assess and manage risks,

what data is needed to charac terize sites, how to select sites, how to conduct injection operations, how to model the behavior of CO 2 in the reservoir, and how to monitor project performance.

There is less technical suppor t on the ability to conduct GS in basalts, coal seams, salt caverns, and shales. As compared with deep saline formations and hydrocarbon reservoirs, the trapping/containment mechanisms of CO 2 and/or operational engineering involved in basalts, coal seams, salt caverns and shales may be signi ficantly different and using identical regulatory language might not be appropriate. In fact, it is not known at this time whether GS (or even injection in some cases) can be done at commercial scale in each of these types of formations – GS ef forts in these formations are still in the experimental stage. Wells in basalts, coal seams, salt caverns and shale formations

1 /

The recommendations presented in this letter reflect a consensus among the signatories on the specific issues addressed; however, some of the sign atories note that their participation should not be interpreted as an express or implied change in views on other issues that may be related to the issues addressed. In particular, CATF, EDF and NRDC re serve the respective views they have expressed regarding the appropriate legal author ity for the rule, the definition of ge ologic sequestration, and necessary requirements needed if injection is to be allowed above the lowermost underground source of drinking water ( see comments to EPA dated December 24, 2008 and letters dated March 17, 2009).Cynthia C. Dougherty May 14, 2009 Page 2 of 12

should be treated as experimental wells unde r Class V, recognizing that completing the process of research, development and demons tration likely will require initial full scale experimental projects in a ddition to pilot projects.

Keeping these wells under Class V would a llow EPA and the states to gain enough experience to develop suitable permitting requirements for such wells and to tailor those requirements at both the pilot and commercial scales until the agencies are ready to regulate such wells under an appropriate class.

To implement this approach, sections 144.6(f), 144.80(f), 146.5(f) a nd the definition of sequestration in 146.81 should be revised. The proposed 144.15 provision that the construction, operation or maintenance of any non-experimental Class V GS well is prohibited should be retained, but only with the understanding that this prohibition is not

intended to limit the size or scal e of any experimental GS operation.

“Class VI. Wells used for geologic sequestration but not including those wells used for geologic sequestrati on that are regulated under another Class. Wells used for geologic seques tration in basalts, coal seams, salt caverns or shales are regulated under Class V as experimental wells until such time as the Administrator establishes separate requirements by rule for the specific type of formation or determines, following public notice and opportunity for comment, that wells used for geologic sequestration of carbon dioxide streams into the speci fic type of formation should be regulated under another class. ”

2. Non-interference principle

EPA notes in the preamble (page 43506), “it is ... possible that multiple owners or operators will be injecting CO 2 into formations that are hydr aulically connected and thus the elevated pressure zones may intersect or interfere with each other.” We have agreed that this possibility should be addressed through a revi sion to the regulations. Until more comprehensive approaches to basin-scale management are developed and based on the proposed definition of “pressure front”, we recommend the adoption of the following addition to §146.94:

“ (e) If an owner or operator obtains evidence that a pressure front associated with one geol ogic sequestration project in tersects or will more likely than not intersect the pressure front or area of review associated with another project, the owner or operator obtaining such evidence must notify the Director. The Director sha ll notify the owner or operator of the other geologic sequestration project. If the Director determines that the pressure front associated with one project interferes or will more likely than not interfere with the ability of another project to comply with the terms of its permit(s), the Director ma y require the owners or operators ofCynthia C. Dougherty May 14, 2009 Page 3 of 12

the interfering or potentially interfer ing projects to m odify operations as necessary to mitigate or avoid such in terference. Such modifications may also include modifications mutually agreed upon by the respective owners and operators and approved by the Director .”

3. Transmissive faults or fractures

The proposed rule in §146.83(a)(2 ) requires a confining z one(s) that is free of transmissive faults or fractures, while §146.81 de fines this term as “A fault or fracture that has sufficient permeability and vertical extent to allow flui ds to move between formations”. We recommend the following m odification to the defi nition in §146.81(d) in order to avoid unduly restricting movement that is merely between formations:

“Transmissive fault or fracture means a fault or fracture that has sufficient permeability and vertical extent to allow fluids to move beyond a confining zone .”

4. Definition of confining zone

The proposed definition of confining zone in §146.81(d) requires that the formation act as “a barrier” to fluid movement, which may be unnecessarily strict. The definition also fails to recognize that it is movement through and beyond the confining zone that needs to be limited. We recommend retaining the current UIC program definition of confining zone as preferable to the proposed definition with one revision to address the possibility that a confining zone for a particular project may be beneath rather than above the injection

zone.

“ Confining zone means a geological formation, group of formations, or part of a formation that is capable of limiting fl uid movement from an injection zone .”

5. Area of review definition and basis

We also suggest that the second sentence of the proposed definition of GS project be

transferred to the definition of area of review as recommended below. This language also reflects a change from “brine” to “formation fluids.”

“

Area of review means the subsurface three-dime nsional extent of the carbon dioxide stream plume and the asso ciated pressure front, as well as the overlying formations, [any USDWs underlying an injection zone alongCynthia C. Dougherty May 14, 2009 Page 4 of 12

with any intervening formations,] 2 / and the surface area above that delineated region .”

In addition, we recommend that the second sentence includ ed both in EPA’s proposed

definition of area of review and in section 146.84(a) be dropped from the definition and retained in section 146.84(a) but modified to read as follows:

“(a) The area of review is based on computational m odeling, as well as monitoring and other operational data , that account for the physical and chemical properties of all phases of the injected carbon dioxide stream.”

The first sentence of section 146.84(a), which dup licates the definition of area of review, should be deleted from section 146.84(a) a nd retained in the definition with the modifications presented above.

6. Area of review and corrective action requirements

In proposed §144.55(a) the rule w ould require Class I, II (other than existing), III or VI permit applicants to identify the location “of all known wells within the injection well’s area of review which penetrate the injecti on zone” or, in the ca se of Class II wells operating over the fracture pressure of the injection formation, “all known wells within the area of review penetrating formations affected by the increase in pressure.”

Since injection in deep saline formations will result in an area of el evated pressure (above the original reservoir pressure) that will be larger than the CO 2 plume and could conceivably affect overlying or underlying formations, we have agreed that the requirement for Class II wells operating above th e fracture pressure should also apply to Class VI wells. This would help prevent the unwanted migrati on of reservoir fluids from the injection zone as a result of the pressu re increase. We ther efore recommend that §144.55(a) be revised to read as follows, with revisions shown in blue:

“(a) Coverage. Applicants for Class I, II, (other than existing), or III, injection well permits sha ll identify the location of all known wells within the injection well's area of review wh ich penetrate the injection zone. In the case of Class II wells that operate over the fracture pressure of the injection formation, applicants shall also identify the location of all known wells within the area of review penetrating formations affected by the increase in pressure

. For such wells which are improperly sealed, completed, or abandoned, the applicant shall also submit a plan consisting of such steps or modifications as ar e necessary to prevent movement of

2 /

The bracketed language should be included to the extent that the regulations authorize GS above USDWs, an issue on which the signatories have expressed differing views in our respective comments on the proposed rule. See footnote 1 above.Cynthia C. Dougherty May 14, 2009 Page 5 of 12

fluid into underground sources of dr inking water (‘‘corrective action’’). Where the plan is adequate, the Dir ector shall incorporate it into the permit as a condition. Where the Direct or’s review of an application indicates that the permittee’s plan is inadequate (based on the factors in §146.07), the Director shall require th e applicant to re vise the plan, prescribe a plan for corrective actio n as a condition of the permit under paragraph (b) of this section, or de ny the application. The Director may disregard the provisions of §146.06 (Area of Review) and §146.07 (Corrective Action) when reviewing an application to permit an existing

Class II well. Applicants for permits for Class VI wells [or for wells in other classes that are used for geolog ic sequestration and do not meet the criteria for §144.6(b)(4)] 3 / shall identify the location of all known wells within the area of review penetrat ing the injection zone and all known

wells within the area of review which penetrate formations affected by the pressure front and shall perform co rrective action as specified in §146.84. ”

7. Well construction

EPA’s proposed §146.86(b)(3) would require the long string casing to be cemented by circulating cement to surface in one or more stages. Yet that may be hard to accomplish in some cases, such as very deep wells. Ther e are also potential disadvantages of this approach with regard to the weight of the cem ent column and its relation to well integrity. Sealing this annulus also eliminates an approach for monitoring the integrity of the cement in that critical interval through the primary confining interval and above. We

recommend that EPA not make this a manda tory requirement. The requirement should also recognize that there may be other technol ogies that could be as effective as cement and centralizers, which may not be feasible in some applications; furthermore, current research and development efforts are likely to yield additional te chnologies the use of

which should not be foreclosed. Accordin gly, we recommend the following language for §146.86(b)(3):

“(3) At least one long string ca sing, using a sufficient number of centralizers, which at a minimum: must be s ealed from within the injection zone upward through the overlying c onfining zone, and must provide adequate isolation of the injection z one and other intervals as necessary for protection of USDWs using cement and/or other isolation techniques. The Director may approve the use of packers or alternative isolation techniques, provided these are demonstrated to be equivalent to cement or more effective to provide adequate isolation and to protect USDWs. ”

3 /

The undersigned, except NRDC which does not support the Group’s proposed bright line definition and language for §144.6(b)(4) ( see MSG letter of Dec. 23, 2008), believe that this clause in

brackets should be included.Cynthia C. Dougherty May 14, 2009 Page 6 of 12

8. Reevaluation of the Area of Review a nd Revision and Maintenance of Plans

Although the proposed §146.84(f) would require “reevaluation” of the AoR at a “minimum” fixed frequency of ten years or “when operational and m onitoring conditions warrant,” the specific language of §146.84 runs the risk that revisions will not be made on a timely basis. We recommend imposing a continual obligation on operators to assess whether the AoR itself, the AoR and corrective action plan and all ot her plans required by the regulations should be revise d, requiring an annua l certification stat ing that the owner or operator has reviewed the circumstances (including operating and monitoring data) during the preceding year to determine whethe r these circumstances warranted a revision of the AoR and any plans, and requiring th at revisions be done when required by the Director as well as when the operator determines that conditions warrant. To accomplish this, it is useful to break down the con cept of “reevaluation” into two ideas – “assessment” of the need to revise the AoR and all plans and the actual process of

“revision.” We believe that these suggestions will result in increased accuracy and reliability in the site performance data while avoiding work that is not warranted by the site data and site performance. Moreover, a continuous obligation to assess whether revisions are needed, when coupled with an annual certificati on requirement (see proposed §146.91(d) below) will create a clear accountability trail for both operator and Director in case of disputes. Given this a nnual certification proce ss, we believe it is unnecessary to require a reeval uation on a fixed basis ever y 10 years in every case.

An annual certification requirement can also be used to enhance the ability of both Director and operators to k eep track of which plans requi re updating and whether or not plans that ought to be update d have in fact been revised. Such a shared understanding is essential if there is to be the “ongoing di alogue” between regulator s and operators that EPA anticipates. We considered the inclusi on of an annual report as described in the preamble at 73 Fed. Reg. 43518, but concluded that the benefits of that particular report would be outweighed by the burden. The an nual certification we are recommending would be much simpler. We recommend:

That §146.84(f) be revised to read as follows:

“(f) (1) Notwithstanding the requirement in paragraph (2)(i) of this subsection to perform a reevaluation of the area of review at the frequency set forth in the area of review and corrective action plan, the owner or operator must also conduct the following whenever warranted by material change in the monitoring and operational data or in the evaluation of the monitoring and operational data by the owner or operator:

“(i) reevaluate the area of review by performing all of the actions specified in paragraphs (c)(1) through (3 ) of this section to delineate the area of review and identify all wells that require corrective action;Cynthia C. Dougherty May 14, 2009 Page 7 of 12

“(ii) perform corrective action on wells requiring corrective action in

the reevaluated area of review in the same manner specified in paragraph (d)
of this section; and

“(iii) submit an amended area of review and corrective action plan or demonstrate to the Director through m onitoring data and modeling results that no change to the area of review and corrective action plan is needed.

“(2) Except as provided in paragraph (3) of this subsection, the owner or operator shall also conduc t a reevaluation by perfor ming all of the actions specified in subparagraphs (1)(i) through (iii) of this subsection:

“(i) Within the time periods specified in the area of review and corrective action plan for conducting su ch a reevaluation of the area of review; or

“(ii) If an area of review eval uation or reevaluation has not been performed pursuant to § 146.84(c) and (d) for the ge ologic sequestration project during the preceding ten (10) y ears, then within six months after the passage of that 10-year period.

“(3) The Director shall waive the re quirement for a reevaluation pursuant to either §146.84(f)(2)(i) or (ii) if th e owner or operator demonstrates to the Director through monitoring and operational data and modeling results, such as those reviewed an nually pursuant to section 146.95, that

such a reevaluation is not wa rranted by material change.”

In addition, we recommend the following new §146.95 :

“146.95 Plan Maintenance and Update

“(a) Owners or operators must submit an annual statement, signed by an appropriate company official, confirming that the company has:

“(i) reviewed the monitoring and operational data that are relevant

to a decision on whether to reevalua te the area of review and the monitoring and operational da ta that are relevant to a decision on whether to update a plan identified in §146.82(p) or (u) through (x) or the quality assurance plan for all testing a nd monitoring requirements; and “(ii) determined whether any updates were warranted by material change in the monitoring and operationa l data or in the evaluation of the monitoring and operational data by the owner or operator.Cynthia C. Dougherty May 14, 2009 Page 8 of 12

“(b) Owners or operators must su bmit either the updated plan or a summary of the modifications for each plan for which an update was determined to be warranted pursuant to subsection (a) of this section. The Director may require submission of copies of any updated plans and/or additional information regarding whethe r or not updates of any particular plans are warranted.

“(c) The Director may require the re vision of any required plan whenever

the Director determines that such a revision is necessary to comply with the requirements of this subchapter.”

9. Emergency Response

With respect to the emergency and remedial response section, we propose two changes – change §146.94(b)(4) to read:

“Implement the emergency and reme dial response plan approved by the

Director , and keep the Director apprized of the implementation .”

and §146.94(d) to read:

“The owner or operator must notify the Director and obtain his approval prior to conducting any well workover or other remedia tion measures not listed in the emergency and remedial response plan .”

It should be noted that the language chosen here for §146.94(d) relates specifically to remediation measures and not to emergency responses, which should not be delayed to seek approval when immediate response actio n is necessary. Ever y effort should be taken to ensure that emergency responses are comprehensively a ddressed in the plan, including appropriate notification provisions and timeframes, but emergency responses should not be delayed when awaiting approvals could impair the effectiveness of the

response.Cynthia C. Dougherty May 14, 2009 Page 9 of 12

Conclusion

The undersigned submit these recommendations with the request that the

recommendations be considered for inclusion in a potential notice of data availability and as a basis for revising the respective provi sions in the final rule . In addition, we are committed to continuing our discussions with an objective of developing additional specific recommendations for improvement of a final rule that coul d be adopted by no later than your scheduled da te in late 2010 or early 2011.

Sincerely,

John McManus Vice President, Environmental Services

American Electric Power

Kyle Isakower Director, of Policy Analysis

American Petroleum Institute

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

Blue Source LLC

D. Brian Williams CO2 Storage Manager BP Alternative Energy North America Inc.Cynthia C. Dougherty May 14, 2009 Page 10 of 12

Karen St. John Director Regulatory Affairs

BP America Inc.

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

Kurt Waltzer Carbon Storage Development Coordinator

Clean Air Task Force

Jeff W. Sheets Sr. Vice President, Planning & Strategy ConocoPhillips

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

Darlene Radcliffe Director, Environmental Technology & Fuel Policy Duke EnergyCynthia C. Dougherty May 14, 2009 Page 11 of 12

William L. Fang Deputy General Counsel

Edison Electric Institute

Scott Anderson Senior Policy Advisor, Climate and Air Program

Environmental Defense Fund

Michael S. Beer Vice President, Federa l Regulation and Policy

E.ON U.S. LLC

Tiffany Rau Manager, Policy & Communications Hydrogen Energy International LLC

George Peridas

Scientist Climate Center

Natural Resources Defense CouncilCynthia C. Dougherty May 14, 2009 Page 12 of 12

Al Collins Senior Director, Regulatory Affairs Occidental Petroleum Corporation

Kevin Wanttaja Manager, Environmental Services Salt River Project

John A. King CO2 Manager - Americas Shell Exploration and Production

Karl R. Moor

Vice President and Asso ciate General Counsel Southern Company

L. Stephen Melzer

President Texas Carbon Capture & Storage Association

cc: Steve Heare Ann Codrington

Bruce Kobelski Suzanne Kelly

Lee WhitehurstMay 15, 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 EPA–HQ–OW–2008–0390

Dear Director Dougherty:

The organizations identified by the signature s at the end of this letter have been participating in multi-stakeholder group (MSG ) discussions of the proposed rule for geologic sequestration (GS) of carbon dioxi de under the Safe Drinking Water Act (SDWA), 73 Fed. Reg. 43491-541 (July 25, 2008). Ot her participants in the MSG process recently submitted a letter with consensus reco mmendations on a number of issues in the GS rulemaking. The signatories to this le tter have achieved consensus on additional

recommendations for the issues addressed in th is letter and request that you provide these

recommendations to the EPA rule deve lopment workgroup for consideration in conjunction with the preparation of the Notice of Data Availability (NODA) and the final

GS rule.

As noted in previous letters , the consensus recommendations presented in this letter address only the objective of protecting unde rground sources of dr inking water (USDWs) under the Safe Drinking Water Act and do not address verifica tion requirements for

carbon credits.

1. Pressurized annulus

Agency and industry experience with the Class II UIC program does not support a requirement to “maintain on the annulus a pr essure that exceeds th e operating injection pressure.” The standard proposed by EPA is co nsistent with neither the risk level related

to CO 2 nor the specifications needed to mon itor the annular space for leakage. We suggest revising section 146.88(c) to read:

“(c) The owner or operator must fi ll the annulus between the tubing and the long string casing with a corrosion inhibiting fluid approved by the Director. The owner or operator must maintain a positive pressure on the

annulus .”

2. Down-hole shutoff valves

Over-pressure protection is best achieved by ensuring compatibility of the casing/tubing material design strength with the surface injection (compr ession) system. Down-holeCynthia C. Dougherty May 15, 2009 Page 2 of 5

shut-in devices may be appropriate for site-spe cific situations of uni que potential impact (such as offshore or near airports), but they should not be mandated for all injection sites. Accordingly, we recommend the following language for §146.88(e):

“(e) The owner or operator must install and use c ontinuous recording devices to monitor: the injection pressure and the rate, volume, and temperature of the carbon dioxide stream. The owner or operator must regularly monitor the pressure on the annulus between 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 shutin the well in a prudently safe manner when operating parameters such as injection rate, injection pressure, or other parameters approved by the Director exceed ranges and/or gradients specified in the permit;”

Conclusion

The undersigned submit these recommendations with the request that the

recommendations be considered the bases fo r revising the respectiv e provisions in the final GS rule. In addition, we are committed to continuing our discussions with an objective of developing additi onal specific recommendations fo r improvement of a final rule that could be adopted by your sche duled date in late 2010 or early 2011.

Sincerely,

John McManus Vice President, Environmental Services

American Electric Power

Kyle Isakower Director, of Policy Analysis

American Petroleum Institute

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

Blue Source LLCCynthia C. Dougherty May 15, 2009 Page 3 of 5

D. Brian Williams 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)

Kurt Waltzer Carbon Storage Development Coordinator

Clean Air Task Force

Jeff W. Sheets Sr. Vice President, Planning & Strategy ConocoPhillips

Ronald T. Evans Senior Vice President, Reservoir Engineering Denbury Resources Inc.Cynthia C. Dougherty May 15, 2009 Page 4 of 5

Darlene Radcliffe Director, Environmental Technology & Fuel Policy Duke Energy

William L. Fang Deputy General Counsel

Edison Electric Institute

Scott Anderson Senior Policy Advisor, Climate and Air Program

Environmental Defense Fund

Michael S. Beer Vice President, Federa l Regulation and Policy

E.ON U.S. LLC

Tiffany Rau Manager, Policy & Communications Hydrogen Energy International LLC

Al Collins Senior Director, Regulatory Affairs Occidental Petroleum CorporationCynthia C. Dougherty May 15, 2009 Page 5 of 5

Kevin Wanttaja Manager, Environmental Services Salt River Project

John A. King CO2 Manager - Americas Shell Exploration and Production

Karl R. Moor

Vice President and Asso ciate General Counsel Southern Company

L. Stephen Melzer

President Texas Carbon Capture & Storage Association

cc: Steve Heare Ann Codrington

Bruce Kobelski Suzanne Kelly

Lee WhitehurstOctober 9, 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 Seque stration, 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 to add a new section 146.25 to 40 C.F.R. Part 146 with the recommendation that these be adopted as the requirements for we lls used for geologic seque stration (GS) in oil and gas reservoirs that do not meet the provisi ons of the (b)(4) language recommended in the joint letter submitted by a number of particip ants in the Multi-Stakeholder Discussion (MSD) group on December 23, 2008 (copy attached). The recommendations are conditioned on our expectation that the delegation standard for pr imacy will be based on section 1422 as explained

in this letter. An earlier version of these recommendations was submitted on March 31, 2009 by some of the signatories to this letter. Since that time, we have conducted further discussions among many of the participants in the MSD pr ocess and have now reached a broader consensus

on the attached revised recommendations. In addition, these recommen dations respond to the discussion of geologic sequestration under Clas s II and EPA’s proposed Class VI regarding varying risk profiles and appeari ng in the Agency’s Notice of Data Availability and Request for Comment, 74 Fed. Reg. 44802, 44810 (August 31, 2009).

Background

As indicated in the joint MSD participants letter submitted on December 23, 2008 and in the letters submitted to you on March 17, 2009 by the Clean Air Task Force (CATF), the Environmental Defense Fund (EDF) and jointly by the American Petroleum Institute (API), the Edison Electric Institute (EEI) and the Car bon Sequestration Council (CSC), the MSD had continued efforts toward developing recommenda tions reflecting common views on a number of additional issues in this rulemaking. Some of those discussions also resulted in the additional recommendations with respect to EPA’s proposed Class VI requirements submitted to you on May 14 and 15, 2009.

The March 17 letters noted that the MSD group followed a modi fied—and truncated—approach to focus on earlier submission of some recommendations in case the Agency wanted to publish those recommendations in conjunction with its pl anned Notice of Data Availability (NODA). The December 23, 2008 letter from MSD particip ants explained the agreement reached on the proposed language describing wells in classificati on (b)(4) that would establish a “bright line”Cynthia C. Dougherty October 9, 2009 Page 2

definition distinguishing (1) wells that inject CO 2 for EOR/EGR and those that inject CO 2 for GS in conjunction with EOR/EGR from (2) wells that inject CO 2 for GS where EOR/EGR activities and any hydrocarbon production would be minimal.. Th e signatories to that letter recommended, consistent with EPA’s intent, that wells used for EOR/EGR should remain in Class II and that

wells used for EOR/EGR with GS – that meet the (b)(4) definition – should also remain in Class II and be subject to the current requirements for Class II. Signatories to that letter also agreed that the wells used for GS in oil and gas reservoi rs that do not meet the criteria of (b)(4) should be subject to additional requirements. That lette r noted an agreement to define such wells as wells used “for geologic sequestration in oil a nd gas formations and where the criteria of paragraph (b)(4) are not met.” This letter and the attached provis ions provide specific recommended requirements for GS in oil and gas re servoirs when the criteria of paragraph (b)(4)

are not met.

In the Multi-Stakeholder Discussions since March 31, 2009, the signatories to this letter have agreed that wells used for GS in oil and gas rese rvoirs that do not meet th e criteria of paragraph (b)(4) should be subject to a set of additional requ irements different from those that would apply under the current Class 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 also reflected in the four letters you received on Ma rch 17, 2009 from MSD participants. Each of those March 17 letters asks EPA to include this approach in its final GS rule.

The March 31, 2009 MSD letter included a smaller num ber of signatories than this letter because consensus on all of the attached requirements to th at letter had not been achi eved at that time. A broader consensus has now been achieved, a llowing submission of the attached revised

recommendations.

Recommended Provisions for GS in Oil and Gas Reservoirs

Specifically, the undersigned recommend that the attached proposed requirements be added to Class II through an amendment to add a new section 146.25, as shown. Although the MSD process had also considered that these requireme nts might be promulgated as a new Class VII in a new Part 146, Subpart I, the undersigned MSD part icipants have now agre ed that the addition to Class II through a new 146.25 is the better ap proach provided that EPA adopts the delegation standard for primacy explained in this letter.

The addition of the attached recommended requirements as a new section 146.25 should be accompanied by the addition of the word “and” at the end of the new paragraphs 144.5(b)(4), 144.80(b)(4) and 146.5(b)(4) proposed in the December 23 MSG letter and by 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 ga s formations and where the criteria of paragraph (b)(4) are not met.

And—consistent with the further recommendati ons presented by MSD participants on May 14, 2009—subsections 144.5(f), 144.80(f) and 146.5(f) should be revised to read as follows:Cynthia C. Dougherty October 9, 2009 Page 3

“(f) Class VI. Wells used for geologic sequestration but not including those wells used for geologic sequestration that are regulated under another Class. Wells used for geologic sequestration in basalts, coal seams, salt caverns or shales are regulated under Class V as experime ntal wells until such time as the Administrator establishes separate require ments by rule for the specific type of formation or determines, following public notice and opportunity for comment, that wells used for geologic sequestra tion of carbon dioxide streams into the specific type of formation should be regulated under another class. ”

Under this approach, wells used “[f]or geologic sequestration in oil and gas formations and where the criteria of paragra ph (b)(4) are not met” would be “wells used for geologic sequestration that are regulated under another Class”—namely Class II. In conjunction with these revisions and the implementation of these requirements, the undersi gned MSD participants have agreed that the attached proposed section 146.25 requiremen ts should be subject to state primacy approval under the sta ndard of section 1422 of the Safe Drinking Water Act (SDWA)

rather than the alternative standard of section 14 25, especially where it will be clear that injection for geologic sequestration in an oil and gas rese rvoir will be done without recovery of oil or natural gas. If the crit eria of (b)(4) are not satisfied, any production of oil and gas would be an incidental function of the GS injection activit ies subject to our prop osed requirements, and accordingly such injection would not relate —within the meaning of section 1425—to:

(1) the underground injection of brine or other fluids which are brought to the surface in connection with oil or natural gas production or natural gas storage operations, or

(2) any underground injection for the seconda ry or tertiary recovery of oil or natural gas.

It should be noted that – as doe s EPA’s proposal for Class VI – th e attached proposal for section 146.25 requirements relies on the continued applicab ility of other provisi ons of EPA’s existing UIC regulations, including in particular the prov isions of 144.51, which impose the requirements for maintenance of mechanical integrity (MI) and for reporting losses of MI. 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).Cynthia C. Dougherty October 9, 2009 Page 4

Conclusion

The undersigned respectfully submit the attached recommendations and request that EPA promulgate a new section 146.25 be adopted as the regulatory requ irements applicable to wells used for geologic sequestration (GS) in oil and gas reservoirs that do not meet the provisions of the (b)(4) language recommended in the joint letter submitted by participants in the MultiStakeholder Discussion (MSD) group on Decembe r 23, 2008. As previously noted in the December 23, 2008 letter, the consensus recommendati ons presented in this letter are solely for the purpose of GS regulation under the Safe Dri nking Water Act to protect USDWs and not for the purpose of addressing verificatio n requirements for carbon credits.

Sincerely,

John McManus Vice President, Environmental Services

American Electric Power

Kyle Isakower Director, of Policy Analysis

American Petroleum Institute

D. Brian Williams

CO 2 Storage Manager BP Alternative Energy North America Inc.

Karen St. John Director Regulatory Affairs

BP America Inc.Cynthia C. Dougherty October 9, 2009 Page 5

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

Kurt Waltzer Carbon Storage Development Coordinator

Clean Air Task Force

Sarah A. Edman Manager, CCS Policy and Project Development ConocoPhillips

Darlene Radcliffe Director, Environmental Technology & Fuel Policy Duke Energy

William L. Fang Deputy General Counsel

Edison Electric Institute

Scott Anderson Senior Policy Advisor, Climate and Air Program

Environmental Defense FundCynthia C. Dougherty October 9, 2009 Page 6

Michael S. Beer Vice President, Federa l Regulation and Policy

E.ON U.S. LLC

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

John A. King

CO 2 Manager - Americas Shell Exploration and Production

Karl R. Moor

Vice President and Asso ciate General Counsel Southern CompanyCynthia C. Dougherty October 9, 2009 Page 7

Darrick W. Eugene

General Counsel Texas Carbon Capture & Storage Association

cc: Stephen Heare Ann Codrington Dina Kruger Anhar Karimjee

Bruce Kobelski Suzanne Kelly

Lee WhitehurstMulti-Stakeholder Discussions Recommendation on Requirements for Geologic Sequestrat ion in Oil and Gas Reservoirs where Class II(b)(4) Requirements Are Not Met [Revised to incorporate additi onal MSD recommendations] October 9, 2009

§ 146.25 Geologic sequestration in oil or gas rese rvoirs for wells classified under 146.6(b)(5).

Except as otherwise provided in this section, injection wells used for geologic sequestration and meeting the classification criteria of 40 CFR § 146.5(b)(5) shall be subject to the following requirements in lieu of the re quirements of 40 CFR §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 we lls will be, sited in areas with a suitable geologic system. The geologic syst em must be comprised of:

(1) An injection zone of sufficient areal exte nt, 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 the movement of fluids that endangers an
USDW;

(b) Area of Review and Corrective Action

(1) The area of review is based on computati onal modeling, as well as monitoring and other operational data, that considers the volumes an d the physical and chemical properties of all phases 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 sequestration project under this section, reevaluate the delineation, 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 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 data (e.g., injection rate and pressure) will be used to inform an area of review reevaluation; andGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 2 (B) How corrective action will be conducted to meet the requirements of §146.25(b)(4), including what correctiv e action will be performed prior to injection and what, if any, portions of the area of review will have corrective action addressed on a phased basis and how the phasing will be determined; how corrective action will be adjusted if there are changes in the area of review; and how site access will be assured for future corrective action.

(3) The owner or operator must perform the following actions to delineate the area of review and identify all wells that require corrective action:

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

fluids in the subsurface from the comm encement 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 an USDW are no longer present. The model must:

(A) Be based on detailed geologic data co llected to characterize the injection and confining zones, available monitoring 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;

(C) Consider potential migration through faults, fractures, and artificial penetrations and beyond lateral spill points; and

(D) Consider the physical and chemical properties of all injected and

formation fluids in the subsurface.

(ii) Using methods approved by the Director, identify all known or reasonably discoverable artificial penetrations into the confining zone, including active, inactive and abandoned wells and underground mine s, in the area of review that may penetrate the confining zone. Provide a desc ription of each well’s type, construction, date drilled, location, depth, record of plugging and/or completion, and any additional information or evaluations the Director may require; and

(iii) Determine which abandoned wells iden tified 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 active and inactive we lls 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.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 3 (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 acco rdance with 146.25(b)(2)(ii)(B).

(5) (a) Notwithstanding the requirement in subpa ragraph (2)(i) of this paragraph to perform

a reevaluation of the area of review at the frequency set forth in the area of review and corrective action plan, the owner or operator must also conduct the following whenever warranted by material change in the monitoring and operational data or in the evaluation of the monitoring and operational data by the owner or operator:

“(i) reevaluate the area of review by pe rforming all of the actions specified in subparagraphs (3)(i) through (iii) of this su bsection to delineate the area of review and identify all wells that require corrective action;

“(ii) perform corrective action on wells requiring corrective action in the reevaluated area of review in the same manner specified in paragraph (4) of this subsection; and

“(iii) submit an amended area of review an d 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.

“(b) Except as provided in subparagraph (c) of this subsection, the owner or operator shall also conduct a reevaluation by performing a ll of the actions specified in clauses (i)(A) through (C) of this subsection:

“(i) Within the time periods specified in the area of review and corrective action plan for conducting such a reevaluation of the area of review; or

“(ii) If an area of review evaluation or reevaluation has not been performed pursuant to §146.84(c) and (d) for the geologic se questration project during the preceding ten (10) years, then within six months afte r the passage of that 10-year period.

“(c) The Director shall waive the requirem ent for a reevaluation pursuant to either §146.25(5)(b)(i) or (ii) if the owner or opera tor demonstrates to the Director through monitoring and operational data and modeling results, such as those reviewed annually pursuant to section 146.25(m), that such a reev aluation is not warranted by material change.”

(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 responsibility and resources for: corrective action (that meets the requirements of § 146.25 (b)), inject ion well plugging (that meets the requirementsGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 4 of § 146.25(j)), and post-injection site care an d site closure (that m eets the requirements of § 146.25 (k) and emergency and remedial re sponse (that meets the requirements of § 146.25(l) in a manner prescribed by the Director until:

(i) The Director receives a well plugging report identified 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 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 up or down to the cost estimate to account for any change s to the area of review and corrective action plan (§146. 25(b)(2)), the injection well pluggi ng plan (§146. 25(j)(2)), and the post-injection site care and site closure plan (§146. 25(k)(1)) and for actions taken or changes in conditions that reduce the estimated costs of such plans.

(3) The owner or operator must notify the Direct or of adverse financial conditions that may affect the ability to carry out injection well pl ugging 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 plugging (as required by §146. 25(j)) and post-injection site care and site closure (as required by §146. 25(k)).

(5) In conjunction with the submission under (c)(2) and (m), the owner or operator may request, and the Director may approve, an adju stment to the financial responsibility required by (c)(1) to account for actions or changes in conditions that have reduced the estimated costs of the plans referenced in (c)(1).

(d) Well Construction Requirements

(1) Applicability

(i) the requirements of this subsection appl y to newly drilled injection wells and any existing well except to the extent the well is exempted pursuant to (ii)

(ii) the Director may exempt an existing we ll from any of the provisions of (d)(2) if:

(A) the well meets the construction requirements of 40 CFR 146.22; and

(B) the Director determines, after evaluating the significance of any logs, surveys and tests which may be available for the well and the extent to which the well does or does not meet the provisions of (d)(2), that requiring the well to satisfy a particular provision is not necessary to avoid endangerment

of an USDW.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 5 (2) Construction Requirements for newly-drilled injection wells.

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

(A) Prevent the movement of fluids into any unauthorized zones or an USDW as a result of the planned injection operation;

(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 us ed 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 well. All well materials must be compatible with fluids with which the materials 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 compar able standards acceptable to the Director. The casing and cementing program must be designed to prevent the movement of fluids that endangers USDWs. In order to allow the Director to evaluate and approve casing and cementing requirements, the owner or operator must provide the following information:

(A) Depth to the injection zone;

(B) Hole size;

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

(D) Predicted corrosive characteristics 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 surf ace. Cement may be staged. Surface casing need not extend through the base of the lowermost USDW above the injection zoneGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 6 if a combination of cement ar ound the surface casing and intermediate or long-string casing achieves continuous cement throug h the base of the lowermost USDW above the injection zone.

(iv) At least one long string casing, using a sufficient number of centralizers, which at a minimum must be sealed from within the injection zone upward through the overlying confining zone, and must provide adequate isolation of the injection zone and other intervals as necessary for protection of USDWs using cement and/or other isolation techniques. The Director may approve the use of packers or alternative isolation techniques, provided th ese are demonstrated to be equivalent to cement or more effective to provide adequate isolation and to protect 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 life the well. The integrity and location of the cement shall be verified using technology capable of eval uating 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 interva l at the location approved by the

Director.

(B) In order to allow the Director to evaluate and approve tubing and packer requirements, the owner or operator must provide the following

information::

(1) Depth of setting and the depth 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 (intermittent or continuous) and volume of the carbon dioxide stream;

(6) Size of casing; and

(7) Tubing tensile, burst, and collapse strengths.

(e) Logging, sampling, and testing prior to new well operation – The following requirements apply only to newly-drilled wells.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 7 (1) During the drilling and construction of an injection well, the owner or operator must run appropriate logs, surveys and tests to determin e 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 agains t which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. The Director may approve such additional or alternative logs and tests as may be requested by the owner or operator after taking into accoun t the availability of similar data in the area of the drilling site, the construction plan, and the need for additional information as the construction of the well progresses and these may include the following:

(i) Deviation checks during drilling must be at sufficiently frequent intervals to determine the location of the borehole;

(ii) In conjunction with installation of the surface casing:

(A) Resistivity, gamma ray, and caliper logs before the casing is installed; and

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

(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 before the casing is installed; and

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

(iv) Test(s) designed to demonstrate the internal and external mechanical integrity of injection wells, which may include one or more of the following:

(A) A pressure test with liquid or gas;

(B) Oxygen-activation logging;

(C) Tracer surveys;

(D) A temperature or noise log; or

(E) A casing inspection log.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 8 (v)Any alternative methods that provide reliable, 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 zone 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 c onfining zones and conduct tests to verify hydrogeologic and geomechanical characteristics of the injection zone as necessary to satisfy the requirements of (f)(1).

(5) The owner or operator must provide the Di rector with the opportunity to witness all logging and testing required by this subpart. Th e owner or operator must submit a schedule of such activities to the Director upon spu dding 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 zone or cause otherwise non-transmissive faults transecting the confining zone to become tran smissive. In no case may injection pressure cause movement of injection or formation fluids in a manner prohibited by 40 CFR §144.12(a).

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

(3) The owner or operator must fill the annulu s between the tubing and the long string casing with a corrosion inhibiting fluid appr oved 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. The owner or operator must regularly monitor the pressure on the annulus between the tubing and the long string casing. The owner or ope rator must install, test and use alarms andGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 9 automatic shut-off systems, designed to alert the operator and shut-in the well when operating parameters such as injection rate, in jection pressure, or other parameters approved by the Director diverge beyond ranges and/or gradients specified in the permit.

(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 movement into an 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 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 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 Administra tor, 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 m echanical 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 rest ricted 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 tests to the Director, he/she shall include a description of the test(s) and the method(s) used. In making his/her evaluation, the Director must review monitoring and othe r 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 orGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 10 packer or significant movement of fluid into or between USDWs resulting from the injection activity as stated in paragr aphs (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 poten tial 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 to verify that th e geologic sequestration project is operating as permitted and is not endangering USDWs. The testing and monitoring plan must be submitted with the permit application for Director approval, and must include a description of how the owner or operator will meet the requirements of this section.

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

(i) analysis of the carbon dioxide stream with sufficient frequency to yield data representative of its chemical 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 pressure, rate and volume; and to record at least daily the pressure on the annulus between the tubing and the 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) quality assurance provisions.

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

(i) Monitoring for pressure changes in an appropriately porous and permeable formation overlying the confining zone;

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

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

(iv) Periodic monitoring of water quality for constituents specified in the plan in one
or more USDWs;GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 11 (v) Corrosion monitoring of the well materials that will come into contact with water for loss of mass, thickness, cracking, pitti ng and other signs of corrosion performed and recorded at least quarterly which may be modified to be less frequent as approved by the Director based on construc tion 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 construction 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 required by the Director, based on site-specific conditions and risk-based factors, necessary to support, upgrade, and improve computational modeling of the area of review evaluation required under § 146.25(b)(2); and

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

(h) Reporting 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 determ ined 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 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 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; andGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 12 (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) The owner or operator must prepare, maintain, and update required plans in accordance with the provisions of this section.

(i) Owners or operators must submit an annual statement, signed by an appropriate company official, c onfirming that the company has:

(A) reviewed the monitoring and operational data that are

relevant to a decision on whether to reevaluate the area of review and the monitoring and operational data that are relevant to a decision on whether to update a plan identified in §146.25(i)(16) or ( 20) through (23); and

(B) determined whether any updates were warranted by material change in the monitoring and operational data or in the evaluation of the monitoring and operational data by the

owner or operator.

(ii) Owners or operators must subm it either the updated plan or a summary of the modifications for each plan for which an update was determined to be warranted pursuant to subparagraph (i) of this paragraph. The Director may require submission of copies of any updated plans and/or additional information regarding whether or not updates of any particular plans are warranted.

(iii) The Director may require the revision of any required plan whenever the Director determines that such a revision is necessary to comply with the requirements of this subchapter.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 13 (i) Required permit application 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 pe rmit for construction and operation of an injection well or for authorization to operate an existing 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 bod ies of water, springs, mines (surface and subsurface), quarries, water wells and other pert inent 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 ba sed upon modeling, using all available data including data available from any logging and testing of wells.

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

(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 properties 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 seismi c 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 e ffectiveness of the injection and confining zone(s), including data on the depth, ar eal extent, thickness, mineralogy, porosity, vertical permeability reservoir pressure an d 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;GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 14 (v) Geomechanical information representative of the confining zone(s) in the area of review, such as information on fractures, stress, ductility, rock strength, and in situ fluid pressures; and

(vi) Geologic and topographic maps and cross sections illustrating geology, hydrogeology, and the geologic structure 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 should 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 indica ting 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:

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

(10) The compatibility of the carbon dioxide st ream 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;

(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;GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 15 (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 area of review and corrective action plan required by §146.25(b)(2);

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

(18) The proposed demonstration method for mech anical 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 monitori ng plan required by §146.25(g);

(21) Proposed injection and monitor 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);

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

(24) Any other information requested by the Director necessary to ensure protection of

USDWs.

(j) Injection and monitor well plugging

(1) Prior to the well plugging, the owner or ope rator must flush each injection well with a buffer fluid, determine bottomhole reservoir 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 well plugging plan for injection and monitor wells that is acceptable to the Director. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requireme nt 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) For injection wells and any monitor we lls that penetrate the injection zone:

(A) Appropriate testing or determination of bottomhole reservoir pressure;GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 16 (B) Appropriate testing or determination of reservoir pressure (including, for example, through additional perforations) in other formations only if required by the Director;

(C) Appropriate testing methods to ensure final external mechanical integrity as specified in §146.25(f)(5);

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

(E) The placement of each plug including the elevation of the top and bottom of each plug;

(F) The type and grade and quantity of ma terial to be used in plugging. The material must be suitable for use with the carbon dioxide stream, reservoir and fluid conditions; and

(G) The method of placement of the plugs.

(ii) For monitor wells that do not penetrate the injection zone, information to demonstrate that the wells will be plugged in compliance with applicable state requirements.

(3) Notice of intent to plug. The owner or ope rator must notify the Director at least 60 days before plugging of a well. At this time, if an y changes have been made to the original well plugging plan, the owner or operator must also provide the revised well plugging plan. At the discretion of the Director, a shorter notice period may be allowed.

(4) Plugging report. Within 60 days after plu gging 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

(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 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 projected pressure differential between pre-injection and projected post-injection pressures in the injection zone;GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 17 (B) The projected position of the carbon dioxide plume and associated pressure front at site closure as demons trated 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 cl osure 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 perform monito ring following the cessation of injection as

follows:

(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 may request and demonstrate to the satisfaction of the Director that the post-injection site care an d 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, other site-specific data, and modeling that is reasonably consistent with site performance 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 monitoring data and/or modeling, all of the following: (A) the estimated magnitude and extent of the project footprint (carbon dioxide plume and the area of elevated pr essure) ; (B) the estimated location of the detectable carbon dioxide plume ; (C) that there is no significant leakage of either carbon dioxide or displaced formation fluids that is endangering USDWs; (D) that the injected or displaced fluids are not exp ected to migrate in the future in a manner that encounters a potential leakage pathway into an 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 used and managed pursuant to a plan approved by the Director in accordance with §146.25(k)(4).GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 18 (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 , the owner or operator must also provide the revised plan. At the discretion of the Direct or, a shorter notice period may be allowed.

(4) After the Director has authorized site cl osure, the owner or operator must plug all monitoring wells in a manner which will not allow movement of injection or formation fluids that endangers an USDW except that designated wells may remain unplugged pursuant to §146.25(k) (2)(iii)(F) with th e consent of the owner and operator and pursuant to a postclosure monitoring and plugging plan approved by the Director which shall provide for, and designate the person responsible for, operating and plugging all such monitoring wells in a manner which will not allow movement of injection or formation fluids that endangers an

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

(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

(iii) The volume of fluid injected, the injection zone or zones into which it was injected, and the period over which injection occurred.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 19 (7) The owner or operator must retain for three years following site closure, records collected during the post-injection site care pe riod. The owner or operator must deliver the

records to the Director at the conclusion of the retention period, and the records must thereafter be retained at a location designated by the Director for that purpose.

(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 ta ken to address movement of the injection or formation fluids that may cause an endanger ment to an 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 an associated pressure front endangers an 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 design ated 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 re sume injection prior to remediation if the owner or operator demonstrates that the in jection operation will not endanger USDWs.

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

(5) If an owner or operator obtains eviden ce that a pressure front associated with one geologic sequestration project intersects or will more likely than not intersect the pressure front or area of review associ ated with another project, the owner or operator obtaining such evidence must notif y the Director. The Director shall notify the owner or operator of the other geologic sequestration project. If the Director determines that the pressure front associated with one project interferes or will more likely than not interfere with the ability of another project to comply with the terms of its permit(s), the Director may require the owners or operators of the interfering or potentially interfering projects to modify operations as necessary to mitigate or

avoid such interference. Such modifications may also include modifications mutually agreed upon by the respective owners and operators and approved by the Director.”March 17, 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 Sequestration of Carbon Dioxide

Dear Director Dougherty:

The organizations identified by the signatures at the end of this letter are writing to advise you of our further progress in addressing through a multi-stakeholder process issues raised by the Environmental Protection Agency (EPA) pr oposed rule for geologic sequestration of carbon dioxide under the Safe Drinking Water Act (SDWA). "Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells," 73 Fed. Reg . 43491-541 (July 25, 200 8), Docket ID No. EPA– HQ–OW–2008–0390. As indicated in the December 23, 2008 letter that we signed along with a number of other organizations, we have continued the multi-stakeholder discussions and have made great progress toward developing additional recommendations reflecting

common views on a number of the issues in this rulemaking, including specifically: whether GS should be restricted to formations below the lowermost underground source of drinking water (USDW); GS in basalts, coal seams, salt caverns, and shales; potential for interference between GS projects; coverage for area of re view and corrective action requirements; well construction requirements, cement bond assessm ents; annulus pressure; shut-off valves; emergency response requirements, and definitions for transmissive faults and fractures, carbon dioxide stream, confining zone, and area of review. We are working diligently toward submitting consensus recommendations on these issues that should help the Agency develop a rule that will allow GS technology to be pe rmitted under appropriate injection well classes while also ensuring protection of underground so urces of drinking water as well as human

health and the environment.

Following the December 23, 2008 submission, the stakeholders have foc used in part on the potential publication of a Notice of Data Availability (NODA) that your Office has included—albeit with the qualifier “if appropr iate”—on a rulemaking schedule discussed at various meetings of organizations over the past year. In the December 23 letter, the stakeholders described the agreement to include in Class II a classification (b)(4) that establishes a “bright line” definition for wells that inject CO 2 for EOR/EGR and GS. The participating stakeholders agree that this appr oach is preferable to the approach in the proposed rule and recommended, consistent with EPA’s intent, that these wells should remain in Class II and be subject to the current re quirements of Class II. We also agreed that wells used for GS in oil and gas reservoirs that do not meet the criteria of (b)(4) should be subject to additional requirements beyond current Class II requirements. That letter notedCynthia C. Dougherty, Director March 17, 2009 Page 2

agreement to define such wells as wells used “for geologic sequestration in oil and gas

formations and where the criter ia of paragraph (b)(4) are not met.” In our discussions since December, we have agreed that these wells should be regulated in a separate class or subclass, and we recommend that the Agency incl ude in its plans for both publication of a NODA and the final rule the approach of regu lating these wells used for GS in oil and gas reservoirs under a separate classification. We are still committed to and making progress in

our multi-stakeholder discussions toward de veloping recommendations on the specific requirements that should be applied to this category of wells.

Sincerely,

Kyle Isakower Director, of Policy Analysis

American Petroleum Institute

William L. Fang Deputy General Counsel

Edison Electric Institute

Robert F. Van Voorhees Counsel to Carbon Sequestration Council (CCS Contact Group)18 Tremont St., Suite 530 | Boston, MA 02108 | www.catf.us | 617.624.0234 March 1 7 , 2009

Cynthia C. Dougherty, Director Office of Ground Water and Drinking Water U.S. Environmental Protection Agency Ariel Rios Building 1200 Pennsylvania Avenue, NW Washington, DC 20460

RE: Notice of Proposed Rulemaking Federal Requirements for Carbon Dioxide (CO2) Geologic Sequestration Wells, 73 Fed. Reg. 43492 (July 25, 2008), EPA HQ

- OW

- 2008

- 0390

Dear Ms. Dougherty:

Clean Air Task Force is a national non

- profit organization dedicated to restoring clean air and healthy environments, in cluding securing advances against climate change, through scientific research, public education, and legal advocacy. Our efforts on climate change focus on reducing the carbon footprint of coal

- fired power plants and other industrial facilities that are a mong the largest contributors to U.S. domestic climate change emissions, through advocacy related to the capture and geologic sequestration of carbon dioxide (“CO2”) emissions.

CATF submitted comments jointly with other environmental organizations on

th e proposed rule referenced above on December 24, 2008. In addition, at that time we signed a letter filed by a larger group of stakeholders, including both environmental and industry representatives, indicating our participation in discussions

with that l arger group on a series of issues related to the rule. Those multi

stakeholder group (“MSG”) discussions are ongoing, and substantial progress has been made toward fleshing out areas of potential agreement among the broader

collection of stakeholders.

We understand that your Agency is coming to a decision point in the near term about whether or not to reopen the rule, for further comment on the idea of designing a distinct regulatory regime applicable to what we would refer to as high capacity oil and gas sequestration (HCOGS)

- projects that maximize the use of potential CO2 sequestration capacity in an oil or gas field and, as result, have a higher injection pressure and different risk profile than is typical for a “business as usual”

enhanced oil r ecovery or enhanced gas recovery (EOR/EGR) project. HCOGS differ from EOR/EGR BAU in that they do not meet the following criteria:(i). there is reasonable expectation of more than insignificant future production

volumes or rates as a result of carbon diox ide injection and (ii) operating pressures are no higher than reasonably necessary to produce such

volumes or rate s

.

We support the concept of a d istinct regulatory scheme for HC OGS, as

described further below. Furthermore, we will continue to engage with the MSG to develop what we hope will be a mutually agreed set of recommendations for that new regulatory cl ass.

At this time, however, we would like to reiterate the point that we made in our earlier comments, that a well

- reasoned regulatory scheme for CO2 sequestration must be grounded not only in the Safe Drinking Water Act (“SDWA”), but also explicitly

grou nded in Clean Air Act (“CAA”) authority, as it is and should be part of a system for the capture and sequestration of CO2 from atmospheric release. To satisfy both SDWA and CAA requirements, it is furthermore appropriate for EPA to design a regulatory sch eme for HC OGS that is distinct both from the existing Class II regulations applicable to EOR /EGR BAU , and from the Class VI provisions proposed for regulating other geologic sequestration projects undertaken apart from oil production, for example , in saline formations. Specifically, a final rule should set out not only for Class VI wells but also for HC OGS , requirements that must be met in order to confirm sequestration of the CO2 from atmospheric release and to satisfy SDWA requir ements.

We hope to be able to offer the Agency a set of recommendations for the

details of an HC OGS specific rule in the coming months, jointly or in conjunction

with the other MSG stakeholders.

Respectfully submitted,

Kurt Waltze r CCS Coordi nator
Clean Air Task ForceCynthia C. Dougherty

Director

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

Mar 17, 2009

Proposed Rule on Geologic Sequestration of Carbon Dioxide

Dear Director Dougherty,

Now that the public comment period for EP A’s Proposed Rule on Geologic Sequestration of Carbon Dioxide (GS) has closed and the Ag ency is considering next steps, we are writing to summarize our views in relation to a few key points fo llowing our individual and joint comments of Dec24, 2008 and to bring them to the attention of the workgroup for its upcoming work and meetings.

First we stress again the importance of prom ulgating adequate regu lations for GS in a timely fashion. GS has an important role to play in reducing carbon dioxide emissions in the U.S. and, although projects can be permitted under existing rules, a dedicated set of regulations is needed both to increase certain ty further but also adequately to safeguard human health and the environment. Therefore, in considering whet her a Notice of Data Availability (NODA) is needed, we urge EPA to choose the most expeditious option that is accountable, transparent, legally robust and defensible, and also to ensure that whichever option is chosen does not delay the promulgation of the rule.

Second, we highlight that the fi nal rule needs to cater for GS in hydrocarbon reservoirs as well, and not just saline formations as propos ed. Hydrocarbon reservoi rs are likely to be among the first ones to be used for GS, and th ey need to be regulat ed appropriately. We do not believe that automatic delegation to Class II “as long as any production is occurring” is suitable. Under the economic dr iver of carbon constraints, additional risks might be posed in these reservoi rs if operators inject larger volumes or at higher rates and pressures than they have been doing to date under Class II. Moreover, site characterization, operation, monitoring and cl osure requirements over and above the existing Class II will be needed to certify and assure “geologic sequestration” of injected carbon dioxide in hydrocarbon reservoirs.

Third, we raise the issue of authority. The rulemaking to date has only cited authority under the Safe Drinking Water Act (SDWA). As we stated in our comments of Dec24, 2008, an appropriate regulatory regime for GS must also be grounded on authority to prevent re-emissions of inject ed carbon dioxide to the atmosphere. The proposed rule defines GS solely for the purposes of prot ecting Underground Sources of Drinking Water (USDWs). Climate legislation is presently be ing drafted in Congre ss however, and will very likely rely on EPA’s injection classes to certify GS. Specifically, the legislation willvery likely exempt carbon dioxide emissions fr om large facilities that are geologically sequestered according to regulations promul gated by EPA and/or other agencies. We stress the importance of EPA being ready and prepared to meet such requirements. Accounting protocols for carbon allowances is an issue that can be dealt with outside the scope of the current rulemaking, and is likel y to have a far narrower remit than the current rule’s specific requirements for si te screening, monitoring, and various plans. EPA, therefore, must define and regulate GS from the outset in a way that assures not only that USDWs are not endangered, but that GS for the purposes of climate protection is also taking place.

To that effect, we make the following recommendations:

• EPA must promulgate appropriate require ments for GS in hydrocarbon reservoirs in the current rulemaking. The mere c ontinuation of hydrocarbon production in

those fields is not a valid cr iterion for well classification;

• “Geologic sequestration” s hould not be defined only fo r the purpose of protecting USDWs, but also for the purpose of pr eventing re-emissions of injected carbon dioxide to the atmosphere according to a defined permanence standard, as NRDC stated in its Dec24, 2008 comments;

• Class II as it exists today s hould continue to apply to operations that inject carbon

dioxide for the sole purpose of enhanced oil r ecovery as opposed to GS;

• Class II as it exists toda y should not be associated with the definition or the purpose of GS;

• A separate injection class or subclass with appropriate site characterization, operation, monitoring and closur e provisions should govern all injection in hydrocarbon reservoirs for the (sole or concurrent) purpose of GS as defined above (which includes earning carbon credits) and injection that exceeds business-as-usual Class II volume, pressure or other key thresholds that result in greater risk;

• The primacy delegation criteria for this cl ass or subclass should be subject to the primacy delegation requirements that appl y to Class VI as proposed, and not to the more general showing used for Class II; and

• In order to be able to ut ilize existing wells in hydrocar bon reservoirs for GS, this

class or subclass could allow for the tran sition of existing Class II wells into the class or subclass, provided that appropriate construction and mechanical integrity parameters are met, and provided that those wells begin compliance with the added site characterization, operation, monitoring, closur e and other requirements

in the new class or subclass.

We thank you for your ongoing work and efforts on this rulemaking.

Sincerely,

George Peridas, Natural Resources Defense CouncilMarch 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

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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:

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(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)).

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(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;

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(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;

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(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

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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).

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(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

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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

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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

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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:

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(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:

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(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:

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(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);

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(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

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(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 19Ground Water Protection Council

13308 N. MacArthur Blvd. Oklahoma City, OK 73142

Tel: (405) 516-4972 Fax: (405) 516-4973

www.gwpc.org Dedicated to protecting our nation’s ground water.

March 31, 2009

Cynthia C. Dougherty, Director

Office of Ground Water and Drinking Water

USEPA Ariel Rios Building 1200 Pennsylvania Avenue, N. W. Washington, DC 20460

Dear Ms. Dougherty:

On December 23, 2008, the Ground Water Protecti on Council (GWPC) signed a letter submitted by a Multi-Stakeholder Group (MSG) supporting th e concept of creating a new class of UIC wells to manage the geologic sequestration of carbon dioxide. As part of that letter, the GWPC also supported the development of new subclass of the Class II progra m for the purposes of geologic sequestration of carbon diox ide in oil and gas reservoirs.

One of the topics discussed in the December 23 le tter was the need for a way to determine when a well permitted under the Class II program w ould cross a “bright line” for purposes of distinguishing between a well used primarily for enhanced recovery and one used primarily for geosequestration. It is our understanding that members of the MSG are submitting language to EPA suggesting the criteria unde r which wells would transitio n from Class II Enhanced Recovery to a new class or subc lass of well for geosequestration.

Since much of the proposal being submitted by the MSG is based upon the concepts expressed by the GWPC in its December 23, 2008 submissi on of recommendation to EPA concerning the proposed Class VI rule, we expect to support some portion or portions of the MSG language. Regardless, to insure the process of rule de velopment proceeds at an appropriate pace, we recommend that EPA publish the la nguage proposed by the MSG as part of its Notice of Data Availability (NODA). The GWPC will continue to work with the MSG on this issue and we look forward to submitting more detailed co mments as the process moves forward.

Respectfully,

Mike Paque

GWPC Executive Director

cc: Robert F. Van Voorhees

Scott Anderson18 Tremont St., Suite 530 | Boston, MA 02108 | www.catf.us | 617.624.0234 TO: Bob Van Voorhees FR: Bruce Hill, Senior Scientist/Geologist, bruce@catf.us (603) 383-6400 DA: February 1, 2010

RE: Potential Issues for the Multi-Stakeh older Group to Address Relative to Airside Monitoring, Verification a nd Accounting for Saline and EOR GCS

As a follow up to our meeting in Austin on January 25, 2010, this memo outlines some CATF thoughts on issues for discussi on relative to airside MVA, including the two-stage approach mentioned at the meeti ng. I hope you find this to be helpful in drafting recommendations for the group’s consideration.

I. Establishing a Guiding Principle:

CO 2 that remains trapped below the confining zone poses no risk to atmosphere and should be considered 100% sequestered.

As Sally Benson (Stanford) put it:

“A monitoring program, which demonstr ated containment within the storage reservoir should suffice as “proof” that th ere are no [air] emissions from the storage

reservoir”

II. Some Challenges to Address:

 MVA must be cost-effective so cost is not a CCS project deterrent.

 UIC may not apply to some GCS sc enarios with no USDWs. UIC rules

needed as a baseline to demonstrate sequestration from the atmosphere, and therefore, whether or not a USDW exists , the UIC rules must apply to GCS as part of the airside requirements. In addition, UIC rules should apply when GCS is above USDW zone injection.

 Above-USDW injection poses risk that potential future water supply wells will bisect the pressurized injection zone.

 Class 2b and class 6 may have different airside MVA needs.

 Today’s best available subsurface plume tracking techniques cannot directly quantify in the subsurface volumes to 1% (implied by the IPCC 1% conclusion. (CO 2 injected can be indirectly quantified based on injection accounting, however).

 Surface airside monitoring tools (such as flux monitors) are more qualitative than quantitative over a large area, depend heavily on local CO 2 fluxes, and may be impractical for ro utine airside monitoring.

 Need rigorous accounting for CO 2 retention taking into account recycling in EOR. EOR industry and historic record s needed to help develop methodology.

 Potential failure of primary CO 2 reservoir. The applicant should identify secondary CO 2 storage option (or pipeline) in event of reservoir leakage and attendant permanent field shut down, as part of the airside permitting process.2  Areas characterized by numerous / hi storic or pre-historic formation penetrations. Survey for old wells /iden tify old well bores, establish baseline air / flux monitoring.

 De-pressuring at end of project may pose risk. Prohibit to keep all CO 2 immobile.

III. Establishing Geological Context .

 Not explicitly discu ssed in UIC proposal.

 Objective of geological investigation are to reduce risk of fracturing confining layer and to investigate rock mechanics of damaged cap rock if over-pressured during a prior production pha se in the reservoir.

 During initial characterization, under standing regional geology, tectonic setting and rock mechanics should not be overlooked as an important tool to provide the most secure locations for GCS.

 Understanding of tectonic buria l / confining pressure regimes as part of risk assessment will help predict rock mechanics at injection pressure.

 Elevated regional pressure gradients at proposed GCS reservoir sites may mean some reservoirs are risky and pi peline transport to another site makes

more sense.

 Understanding the regional geologic c ontext will also inform planning and help avoid political pressure to accept marginal sites.

IV. Defining and Measurement of Retention In EOR applications, developing methods to accurately and reproducibly measure retention is key to quantif ying CO2 sequestered in Cl ass IIb wells (wells for “sequestration with inci dental oil production”).

“CO 2 Retention” should be rede fined as the amount of CO 2 injected into a reservoir

that remains in the reservoir permanently . Note that the time frame for GCS is much longer than for a typical EOR field, so es timates of permanent retention should be based on a long time frame ( e.g. 1,000 yrs).

In EOR “recycled” CO 2 returns with produced fluids and is then processed and reused. Over time progressively more CO 2 is permanently sequestered, asymptotically approaching 100%. Data n eeded from EOR industry to substantiate

this.

Sum [injected] – sum [Recy cled] = Net Sequestered

V. Two-Stage MVA approach In order to reduce the expense of MVA, we recommend a two-stage method, beginning with exhaustive reservoir charac terization and risk assessment followed by cost-effective MVA techniques to test the reservoir model and to look for potential leakage into the next reser voir layer above the confining zone. If the Stage 1 data suggests potential for leakage or pressure fr ont migration, then a more costly Stage 2 is triggered, requiring bestavailable MVA techniques, including focused surface3 measurements. We believe this approach will result in reduced MVA expense and will make full scale GCS application more attractive as a climate change remedy. The approach also provides an incentive to c hoose low risk sites to reduce MVA intensity. Higher risk sites require higher diligence a nd expense. The process would treat EOR largely same as saline, but the existing reservoir knowledge should mean that this approach reduces expense to EOR operators.

Rationale:

 Uses best available tools to establis h a baseline model of the subsurface projected plume / storage geometry (e .g. 3D seismic), and record baseline

surface and near-surface data. Scient ifically exhaustiv e initial site characterization to develop a “h igh degree of confidence” is key.

 Identifies potential leakage pathways (both natural and engineered hazards)

and allows for focus MVA on vulnerabilities.

 In principal, if CO 2 remains contained, need for other tools beyond UIC rule

should be minimal.

 Develops, in advance, a plan for 2 stag es of MVA: a) first stage to detect leakage, second stage (triggered in event of leakage or adverse pressure front migration) to quantify and remediate.

 Identifies stage 1 methods with a cost effective focus on leakage and

CO 2 /pressure front surveillance, reser voir model testing and surveillance, using tools as identified in UIC Rule. If no evidence of leakage or adverse migration, 100% storage assumed, no need to go to stage 2.

 If all CO 2 remains confined in injection z one, Stage 1 airside requirements are

met and GCS is credited at 100%.

Stage 1 Details:

 Must follow reporting timelines synchronous with UIC rules.

 Focus airside/surface monitoring on vul nerabilities identified in initial

characterization.

 Establish ” layer above” leakage monitoring—monitoring of secondary reservoir rock layer above the inject ion layer but below secondary seals.

 Focus stage 1 surface measurements only in areas of vulnerabilities ( e.g. )

 Shallow well vadose zone (layer above water table) pressure and geochemistry baselines established in advance.

 Surface flux measurements, if thought to be useful, based on indentified vulnerabilities, and efficacy of methods given local geography.

 Establish basics for all sites ( e.g. ):

o Adequate # of monitoring wells are needed for characterization.

o Borehole logs: investig ating integrity of t ubing and annulus, cement bond log, etc.

o Wellhead pressure and target ed borehole flux monitoring.

o Preexisting well surveillance in AOR.

 Examples of Stage 1 Options in tool ba g potentially lower cost than 4d

seismic:4 o Multi-well integrated geochemical /geophysical borehole logs (e.g. Utube).

o Vertical seismic profili ng to correlate geology to seismic signature.

o Cross-well 3D methods.

o Tracers between injection and monitoring wells.

o Caprock strain assessment using microseismic tools.

Stage 2 Details:

 Triggered by leakage evidence or pressure front migration.

 Injection immediately shut dow n to relieve pressure until investigation/mitigation complete. (If pressure front migration, shutdown only in presence of risk 2010-2020).

 Triggers more intensive airside surface and subsurf ace monitoring see (next slide).

 Prior to recommencement of injection, pub lic health and welfare risk must be deemed to acceptable to the Regulator or site is shut down permanently.

 Before injection recommences, requires extensive re-characterization of the subsurface including CO 2 volumes in place, lost and pathway, using best

available tools required regard less of cost and must include robust remedy. (e.g. 4D seismic, 9-component seismic sh ear, gravity, EnSAR, tracers, etc. as appropriate for region and needs).

 Methods must overlap with init ial characteriza tion for precision (repeatability).

 Stage 2 steps:

o Identify location of probable leakage pathway with initial baseline characterization methods, and stage 1 data, moving toward use of best

available methods until leak located.

o Surface surveys to identify location of leakage, remote sensing.

o Surface groundwater geochemistry. E.g. Carroll et al. 2009.

o Subsurface methods (e.g. cross-well seismic tomography, 3D seismic, gravity) to identify fault, failed stratigraphic traps etc.

o To narrow location, initiate inte nsive surface flux monitoring or remote sensing ( e.g lidar for vegetative stre ss) in region identified to be leaking ( e.g faulted area, old or existing well bore.)

o Quantify leakage rates via focus on area with probable leakage (from investigations above) using e ddy covariance towers and flux accumulation monitoring.

o Quantify volumetric changes and plume migration (subsurface methods).

o To account lack of accurac y, quantify in deciles ( or other appropriate rounding increments based on methodological accuracy and precision.) E.g. IF accuracy is 10%, round up: (0-10% measured round to 10%, 11-20% measured rounds to 20%, etc). Rounded % represents

% CO 2 compensation to make atmosphere “whole”.5 o >10% loss = permanent shut down, quantification and remediation/compensation (unless loss is through a clea rly identifiable pathway such as a well that can be readily plugged).

o CO 2 Loss Compensation Penalty = 100% of tons projected to be lost from above approach.

o Alternative storage plan desira ble in event of field failure.

VI. Additional Needs

Facility Loss Accounting

-

 Important for both EOR storage applications and saline.

 Examples of facility losses:

o Process inefficiencies: Amine system “blow by” drives CO 2 off molecule by reheating—not 100% e fficient due to some escape to atmosphere (<<1%).

o Power outage in compressors; CO 2 flaring is already reported by law.

o Maintenance shut down flaring.

o Wellhead control problems (during well workovers).

RE: Surface Flux Monitoring:

 Purpose: Direct detection of any at mospheric emissions. Establish pre - injection baselines.

 To date, surface measurements at SA CROC EOR field sugge st near zero flux (TX BEG).

 Surface flux study at Cranfield/TX BEG DOE Phase 2 site in MS, suggests

wide variations in natural surface flux of CO 2 in part due to microbial activity, rainfall and thus, in some regions, noisy background fluxes mean difficult detection of potential leakage.

 Surface flux methods, where effective, should focus on vulnerabilities (wells, faults, etc) and developing methods. If CO 2 is contained in well-characterized low-risk storage layer, av oid costly broad surface flux surveys. If potential for leakage detected in subsurface, locati on can be determined using flux or soil gas monitors, remote sensing ( e.g. hyper-spectral imaging in vegetated areas).

 If CO 2 flux detected then may be able to measure emissions rates via covariance towers, chambers etc.

 Airside Monitoring: H 2 S monitors—already in use in some fields--may be a sensitive indicator in an acid gas field. May work in relatively sweet oil/gas fields. Uniform facility release accounting needed for all reportable events ( e.g. Flaring, amine leak-by).