Memorandum 

To: Docket EPA-HQ-OAR-2009-0926 

From: Barbora Master, EPA 

Attached are documents that EPA received from stakeholders about geologic 

sequestration (GS) while the Mandatory Reporting Rule on Injection and GS of Carbon 

Dioxide (RIN 2060-AP88) was undergoing Office of Management and Budget (OMB) 

review. The documents contained herein are as follows: 

1. Material distributed during a meeting on January 26, 2010, between the Texas 

Clean Energy Project and EPA (contact Anhar Karimjee), including a meeting 

agenda and attendee list. 

2. Material distributed during a meeting on February 4, 2010, between the MultiStakeholder Discussion Group, represented by Robert Van Voorhees (Bryan 

Cave) and Scott Anderson (Environmental Defense Fund), and EPA (contact 

Mark de Figueiredo). 

3. A memorandum sent to Dina Kruger (EPA) by Ann Weeks (Clean Air Task 

Force) on February 22, 2010. The memorandum was originally authored on 

February 1, 2010, by CATF and presented to the Multi-Stakeholder Discussion 

Group. 

 



















February 4, 2010 

GS Multi-Stakeholder Discussions 1 sanderson@edf.org 

rfvanvoorhees@bryancave.com 

Overview of the GS Multi-Stakeholder Recommendations 

The Geologic Sequestration Multi-Stakeholder 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 recommendations to the U.S. Environmental 

Protection Agency (EPA) and states 

• A changing group of participants 

Participating organizations have varied 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 oil 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 effort was facilitated by a number of other 

activities that provided opportunities for stakeholders to interact. 
February 4, 2010 

GS Multi-Stakeholder Discussions 2 sanderson@edf.org 

rfvanvoorhees@bryancave.com 

• Facilitated by EPA’s technical workshops on carbon capture and geologic 

sequestration 

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

• Enabled by the Interstate Oil and Gas Compact Commission’s Workgroup that 

included state regulators, ENGOs and industry 

• Enhanced by the efforts of the Ground Water Protection Council through its CO2

Workgroup and Committee (also included state regulators, ENGOs and industry) 

• World Resources Institute’s development of CCS Guidelines 

• DOE Regional Carbon Sequestration Partnerships 

The November 17, 2008 comment extension request included a broad group of 

organizations, not all of which chose to participate in the subsequent MSDs. 

• 15 organizations requested 25 day extension 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 Capture and Storage Association 

The Sierra Club 

• Advised EPA and incoming Obama Administration: 

Agreed that EPA’s proposal provides a solid foundation on 

which to develop the regulatory 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 

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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 and 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 promulgation of the rule under the 

proposed 2010-2011 timeline. 

VI. The discussions will address issues relating directly to EPA's proposed 

GS rule, including establishment of injection pressure limitations for 

geologic sequestration injection wells; how various types of target 

formations should be addressed within 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; protection of underground sources of 

drinking water, and any other issues that participants agree should be 

added to this list. 

VII. Each participant agrees not to disclose (1) any information about the 

discussions to the press or to EPA during 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 obtaining the permission of the speaker. 

General approach to the MSD recommendations 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 site 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 appropriate 
February 4, 2010 

GS Multi-Stakeholder Discussions 4 sanderson@edf.org 

rfvanvoorhees@bryancave.com 

The first recommendation letter – December 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 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 provide a ‘bright line’ definition as to 

the applicable class of wells where CO2 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 reservoirs should change when projects are injecting 

more CO2 than needed for “business as usual” EOR operations: 

The “bright line” distinguishes between “business 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 oil or natural gas where geologic 

sequestration is occurring during or in connection 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;” 

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 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. 

• [These] Signatories . . . 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. That letter noted an 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.” The October 9, 2009 letter and the attached 
February 4, 2010 

GS Multi-Stakeholder Discussions 5 sanderson@edf.org 

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provisions provide specific recommended 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) should be subject to a set of additional 

requirements different from those that would apply under the current Class II 

provisions to wells that inject CO2 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 requirements to that letter had not been achieved 

at that time. A broader consensus was achieved for the October 9 letter, allowing 

submission of the comprehensive recommendations attached to that letter. 

• Specifically, the October 9, 2009 letter recommend that requirements be added to 

Class II through an amendment to add 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 that the proposed section 146.25 requirements 

should be subject to state primacy approval under the standard of section 1422 of 

the Safe Drinking Water Act (SDWA) rather than the alternative standard of 

section 1425, especially where 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 regulated under another Class. Wells 

used for geologic sequestration 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 specific type of formation should be regulated under 

another class.” 

The resulting MSD recommendations anticipate the following breakdown of GS wells: 

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

GS Multi-Stakeholder Discussions 6 sanderson@edf.org 

rfvanvoorhees@bryancave.com 

• Class V – “Experimental” – Wells used for in basalts, coal seams, salt caverns or 

shales would be regulated as experimental wells until appropriate requirements 

are established by rule – and other experimental wells 

• Class VI - Wells used for GS unless regulated under another Class 

Another major accomplishment of the MSD process involves the development of the 

process for maintaining the plans that incorporate the adaptive performance measures that 

must be implemented by operators: 

• Although the proposed §146.84(f) would require “reevaluation” of the AoR at a 

“minimum” fixed frequency of ten years or “when operational and monitoring 

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 and any of the plans required by the regulations – including but not 

limited to the monitoring plan – should be revised, 

requiring an annual statement that the owner or operator 

has reviewed the circumstances (including operating and 

monitoring data) during the preceding 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 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 or improved understanding of both. 

• Moreover, a continuous obligation to assess whether revisions are needed, when 

coupled with an annual review and confirmation requirement will create a clear 

accountability trail for both operator and Director in case of disputes. 

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

reevaluation on a fixed basis every 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 updated 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 benefits of that particular report would 
February 4, 2010 

GS Multi-Stakeholder Discussions 7 sanderson@edf.org 

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be outweighed by the burden. The recommended 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 Transmissive 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-Stakeholder 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 CO2 

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 sequestration (GS) in oil and gas 
reservoirs 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 Discussion (MSD) group on 

December 23, 2008 

APPENDIX: Letters Relating to the Interim 40 CFR 146.25 Recommendations 

1. March 17, 2009 Letter from American Petroleum Institute, Carbon 

Sequestration Council and Edison 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 Ground Water Protection Council 



December 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 response to the proposed 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 (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 these recommendations represent a broad array of 

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

interests and issues in an effort to reach consensus or at least narrow our differences. We used this 

extension period to continue efforts toward developing 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 that 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 underground sources of drinking water as well as 

human health and the environment. 

EPA has noted that the proposed rules do not address "accounting or certification for greenhouse 

gas (GHG) reductions." 73 Fed. Reg. 43492, 43495 (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 CO2

EPA’s Proposal would continue to regulate and permit injection of CO2 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 operators of some Class II EOR/EGR wells may wish to 

use wells for the purposes of production and GS prior to the field being completely depleted.” 73 

Fed. Reg. at 43502. We recommend that the rules 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 provide a “bright line” definition as to the applicable 
Cynthia 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 connection 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 connection 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 dioxide 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 language 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-stakeholder 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 their views if a consensus can be reached. 
Cynthia C. Dougherty 

December 23, 2008 

Page 3 

requirements should apply to these wells. We are 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 the 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 specifically 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 fractures), is dealt with in a potentially arbitrary 

fashion (the 90% of fracture pressure limit), which 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 failure and shear failure only “where appropriate” 

because there will be locations where experience or existing information 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 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 reasonable 

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 transmissive. In no case may injection pressure cause movement of injection 

or formation fluids in a manner prohibited by 40 CFR Part 144.12(a). 

Closure Standard

We believe there are three problems with the closure 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 showing 
Cynthia 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 alternative language for section 146.93(b) below 

because it sets forth detailed criteria, all of which must be satisfied, to demonstrate that the site does 

not pose an endangerment to USDWs. The specific criteria listed in our proposal will serve to 

provide the Director with the requisite information to make the appropriate determination. The 

advantage of this approach is that it establishes 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 standard 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 closure 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 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 and is 

not expected to pose an endangerment to USDWs. The Director shall approve 

closure if the owner or operator demonstrates, 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 project footprint (CO2 plume and the area of 

elevated pressure) ; (ii) the estimated location of the detectable CO2 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 encounters 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 these 
Cynthia 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 addressing 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 agencies 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 regional agencies are asked to take on the additional 

workload of CO2 injection, while ensuring careful scientific review as well as an expeditious 

processing time, they will require additional trained staff and other resources. 

If the nation is serious about controlling CO2 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 and managers, must be trained in subjects that will 

enable them to make prudent permitting, management, and oversight decisions. As momentum 

grows to begin sequestering CO2 underground, EPA and states will need to develop new regulatory 

requirements for CO2 wells and prepare to review applications and make permitting decisions. 

Failure to provide sufficient resources will likely create permitting backlogs, resulting in a bottleneck 

in the overall geologic sequestration effort. 

The Ground Water Protection Council (GWPC) estimated in 2004 that an annual funding increase 

to $56 million would be needed just to meet the needs of the existing UIC program at the state level 

even without the addition of geologic sequestration project permitting.2/ GWPC has further 

estimated that EPA will need 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 relevant issues and to reach 

significant agreement on how these issues can be addressed 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 continuing 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 scheduled date in late 2010 or early 2011, including 

development of the requirements to be applied to oil and gas reservoir geologic sequestration that is 

 

2/ GWPC, Class V Resource Needs Survey, Summary (September 2004).
Cynthia C. Dougherty 

December 23, 2008 

Page 6 

not conducted in conjunction with enhanced oil and 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 LLC 
Cynthia 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 Institute 
Cynthia 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 Codrington 
May 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 Sequestration, Docket EPA–HQ–OW–2008–0390 

Dear Director Dougherty: 

The organizations identified by the signatures 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 dioxide 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 underground sources of drinking water (USDWs) 

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

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

We agree that EPA has ample basis for adopting 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 characterize sites, how to select sites, how to conduct injection 

operations, how to model the behavior of CO2 in the reservoir, and how to monitor 

project performance. 

There is less technical support 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 CO2 and/or operational engineering 

involved in basalts, coal seams, salt caverns and shales may be significantly 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 efforts 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 signatories 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 reserve the respective views they have expressed 

regarding the appropriate legal authority for the rule, the definition of geologic 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 under Class V, recognizing that completing the 

process of research, development and demonstration likely will require initial full scale 

experimental projects in addition to pilot projects. 

Keeping these wells under Class V would allow 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) and 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 scale of any experimental GS operation. 

“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 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 specific 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 CO2 into formations that are hydraulically 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 revision 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 geologic sequestration project intersects 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 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 

 
Cynthia C. Dougherty 

May 14, 2009 

Page 3 of 12 

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.” 

3. Transmissive faults or fractures 

The proposed rule in §146.83(a)(2) requires a confining zone(s) that is free of 

transmissive faults or fractures, while §146.81 defines this term as “A fault or fracture 

that has sufficient permeability and vertical extent to allow fluids to move between 

formations”. We recommend the following modification to the definition 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 fluid 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-dimensional extent of the 

carbon dioxide stream plume and the associated pressure front, as well as 

the overlying formations, [any USDWs underlying an injection zone along 

 
Cynthia 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 included 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 modeling, 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 duplicates the definition of area of review, 

should be deleted from section 146.84(a) and retained in the definition with the 

modifications presented above. 

6. Area of review and corrective action requirements

In proposed §144.55(a) the rule would 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 injection zone” or, in the case of Class II wells 

operating over the fracture pressure of the injection formation, “all known wells within 

the area of review penetrating formations affected by the increase in pressure.” 

Since injection in deep saline formations will result in an area of elevated pressure (above 

the original reservoir pressure) that will be larger than the CO2 plume and could 

conceivably affect overlying or underlying formations, we have agreed that the 

requirement for Class II wells operating above the fracture pressure should also apply to 

Class VI wells. This would help prevent the unwanted migration of reservoir fluids from 

the injection zone as a result of the pressure increase. We therefore 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 shall identify the location of all known wells within 

the injection well's area of review which 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 are 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 drinking water (‘‘corrective action’’). 

Where the plan is adequate, the Director shall incorporate it into the 

permit as a condition. Where the Director’s review of an application 

indicates that the permittee’s plan is inadequate (based on the factors in 

§146.07), the Director shall require the applicant to revise the plan, 

prescribe a plan for corrective action as a condition of the permit under 

paragraph (b) of this section, or deny 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 geologic 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 penetrating the injection zone and all known 

wells within the area of review which penetrate formations affected by the 

pressure front and shall perform corrective 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. There are also potential disadvantages of this 

approach with regard to the weight of the cement 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 mandatory requirement. The requirement should 

also recognize that there may be other technologies 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 technologies the use of 

which should not be foreclosed. Accordingly, we recommend the following language for 

§146.86(b)(3): 

“(3) 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 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 and 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 monitoring 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 other plans required by 

the regulations should be revised, requiring an annual certification stating that the owner 

or operator has reviewed the circumstances (including operating and monitoring data) 

during the preceding year to determine whether these circumstances warranted a revision 

of the AoR and any plans, 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 – 

“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 certification requirement (see 

proposed §146.91(d) below) will create a clear accountability trail for both operator and 

Director in case of disputes. Given this annual certification process, we believe it is 

unnecessary to require a reevaluation on a fixed basis every 10 years in every case. 

An annual certification 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 updated 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 benefits of that particular report 

would be outweighed by the burden. The annual 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 monitoring 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 conduct a reevaluation by performing 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 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 sequestration 

project during the preceding ten (10) years, then within six months after 

the passage of that 10-year period. 

“(3) The Director shall waive the requirement for a reevaluation pursuant 

to either §146.84(f)(2)(i) or (ii) if the owner or operator demonstrates to 

the Director through monitoring and operational data and modeling 

results, such as those reviewed annually pursuant to section 146.95, that 

such a reevaluation is not warranted 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 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 §146.82(p) or (u) through (x) or the quality 

assurance plan for all testing and monitoring requirements; and 

 “(ii) 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. 

 

 
Cynthia C. Dougherty 

May 14, 2009 

Page 8 of 12 

“(b) Owners or operators must submit 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 whether or not updates of any particular 

plans are warranted. 

“(c) 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.” 

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 remedial 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 remediation 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 action is necessary. Every effort should be 

taken to ensure that emergency responses are comprehensively addressed 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 provisions 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 could be adopted by no 

later than your scheduled 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 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 Sequestration 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 Energy 

 
Cynthia 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, Federal 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 Council 

 
Cynthia 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 Associate General Counsel 

Southern Company 

L. Stephen Melzer 

President 

Texas Carbon Capture & Storage Association 

cc: Steve Heare 

 Ann Codrington 

 Bruce Kobelski 

 Suzanne Kelly 

 Lee Whitehurst

 
May 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 Sequestration, Docket EPA–HQ–OW–2008–0390 

Dear Director Dougherty: 

The organizations identified by the signatures 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 dioxide under the Safe Drinking Water Act 

(SDWA), 73 Fed. Reg. 43491-541 (July 25, 2008). Other participants in the MSG process 

recently submitted a letter with consensus recommendations on a number of issues in the 

GS rulemaking. The signatories to this letter have achieved consensus on additional 

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

recommendations to the EPA rule development 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 underground sources of drinking water (USDWs) 

under the Safe Drinking Water Act and do not address verification 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 pressure that exceeds the operating injection 

pressure.” The standard proposed by EPA is consistent with neither the risk level related 

to CO2 nor the specifications needed to monitor the annular space for leakage. We 

suggest revising section 146.88(c) to read: 

“(c) 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. 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 (compression) system. Down-hole 
Cynthia C. Dougherty 

May 15, 2009 

Page 2 of 5 

shut-in devices may be appropriate for site-specific situations of unique 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 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 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 for revising the respective provisions in the 

final GS 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 could be adopted by your scheduled 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 LLC 
Cynthia 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 Sequestration 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, Federal 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 
Cynthia 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 Associate General Counsel 

Southern Company 

L. Stephen Melzer 

President 

Texas Carbon Capture & Storage Association 

cc: Steve Heare 

 Ann Codrington 

 Bruce Kobelski 

 Suzanne Kelly 

 Lee Whitehurst 
October 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 Sequestration, 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 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 a number of participants 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 primacy 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 process and have now reached a broader consensus 

on the attached revised recommendations. In addition, these recommendations respond to the 

discussion of geologic sequestration under Class II and EPA’s proposed Class VI regarding 

varying risk profiles and appearing 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 Carbon Sequestration Council (CSC), the MSD had 

continued efforts toward developing recommendations 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 modified—and truncated—approach 

to focus on earlier submission of some recommendations in case the Agency wanted to publish 

those recommendations in conjunction with its planned Notice of Data Availability (NODA). 

The December 23, 2008 letter from MSD participants explained the agreement reached on the 

proposed language describing wells in classification (b)(4) that would establish a “bright line” 
Cynthia C. Dougherty 

October 9, 2009 

Page 2 

definition distinguishing (1) wells that inject CO2 for EOR/EGR and those that inject CO2 for GS 

in conjunction with EOR/EGR from (2) wells that inject CO2 for GS where EOR/EGR activities 

and any hydrocarbon production would be minimal.. The 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 reservoirs that do not meet the criteria of (b)(4) should 

be subject to additional requirements. That letter noted an 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 provide specific 

recommended 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 this letter have 

agreed that wells used for GS in oil and gas reservoirs that do not meet the criteria of paragraph 

(b)(4) should be subject to a set of additional requirements different from those that would apply 

under the current Class II provisions to wells that inject CO2 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 March 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 number of signatories than this letter because 

consensus on all of the attached requirements to that letter had not been achieved at that time. A 

broader consensus has now been achieved, allowing 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 requirements might be promulgated as a new Class VII in 

a new Part 146, Subpart I, the undersigned MSD participants have now 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 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 gas formations and where the criteria of 

paragraph (b)(4) are not met. 

And—consistent with the further recommendations 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 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 

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 paragraph (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 undersigned MSD participants 

have agreed that the attached proposed section 146.25 requirements should be subject to state 

primacy approval under the standard of section 1422 of the Safe Drinking Water Act (SDWA) 

rather than the alternative standard of section 1425, especially where 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. If the criteria of (b)(4) are not satisfied, any production of oil and gas would be an 

incidental function of the GS injection activities subject to our proposed 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 secondary or tertiary recovery of oil or 

natural gas. 

It should be noted that – as does EPA’s proposal for Class VI – the attached proposal for section 

146.25 requirements relies on the continued applicability of other provisions of EPA’s existing 

UIC regulations, including in particular the provisions 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 requirements 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 December 23, 2008. As previously noted in the 

December 23, 2008 letter, 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. 

Sincerely, 

John McManus 

Vice President, Environmental Services 

American Electric Power 

Kyle Isakower 

Director, of Policy Analysis 

American Petroleum Institute 

D. Brian Williams 

CO2 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 Fund 
Cynthia C. Dougherty 

October 9, 2009 

Page 6 

Michael S. Beer 

Vice President, Federal 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 

CO2 Manager - Americas 

Shell Exploration and Production 

Karl R. Moor 

Vice President and Associate General Counsel 

Southern Company 
Cynthia 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 Whitehurst 
Multi-Stakeholder Discussions

Recommendation on 

Requirements for Geologic Sequestration in Oil and Gas Reservoirs 

where Class II(b)(4) Requirements Are Not Met 

[Revised to incorporate additional MSD recommendations] 

October 9, 2009 

§ 146.25 Geologic sequestration in oil or gas reservoirs 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 requirements 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 wells will be, sited in areas with a suitable geologic 

system. The geologic system must be comprised of: 

(1) An injection zone of sufficient areal extent, thickness, porosity, and permeability to 

receive the total anticipated volume of the carbon dioxide stream; 

(2) A confining zone(s) that is laterally continuous 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 computational modeling, as well as monitoring and other 

operational data, that considers the volumes and 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; and 
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Multi-Stakeholder Discussions 2 

 

(B) How corrective action will be conducted to meet the requirements of 

§146.25(b)(4), including what corrective action will be performed prior to 

injection and what, if any, portions of 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 commencement 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 collected 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 mines, in the area of review that may 

penetrate the confining zone. Provide a description of each well’s type, construction, 

date drilled, location, depth, record of plugging and/or completion, and any 

additional information or evaluations 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 movement of carbon dioxide or displaced 

formation fluids that may endanger USDWs; 

(iv) Determine which active and 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. 
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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 accordance with 146.25(b)(2)(ii)(B). 

(5) (a) Notwithstanding the requirement in subparagraph (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 performing all of the actions specified in 

subparagraphs (3)(i) through (iii) of this subsection 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 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. 

“(b) Except as provided in subparagraph (c) of this subsection, the owner or operator shall 

also conduct a reevaluation by performing all 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 sequestration project during the preceding ten 

(10) years, then within six months after the passage of that 10-year period. 

“(c) The Director shall waive the requirement for a reevaluation pursuant to either 

§146.25(5)(b)(i) or (ii) if the owner or operator 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 reevaluation 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 the adequacy of existing financial responsibility 

or provide and maintain financial responsibility and resources for: corrective action (that 

meets the requirements of § 146.25 (b)), injection well plugging (that meets the requirements 
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Multi-Stakeholder Discussions 4 

 

of § 146.25(j)), and post-injection 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 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 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)) and for actions taken or changes in conditions 

that reduce the estimated costs of such plans. 

(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 adjustment of the cost estimate to the Director if 

the Director has reason to believe that the most recent demonstration is no longer adequate 

to 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 adjustment 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 apply 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 well 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. 
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Multi-Stakeholder Discussions 5 

 

(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 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 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 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 comparable 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 strings (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 surface. Cement may be staged. Surface casing 

need not extend through the base of the lowermost USDW above the injection zone 
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Multi-Stakeholder Discussions 6 

 

if a combination of cement around the surface casing and intermediate 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, 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 these 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 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 fluids through tubing with a packer set 

at a depth opposite a cemented interval 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. 
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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 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 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 account 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 the 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 any 

other 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 the 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. 
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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 Director may accept data from cores and fluid 

samples from nearby wells if the owner or operator can demonstrate that such data are 

representative of conditions in the wellbore. 

(3) Prior to injection well operation, 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 confining 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 Director with the opportunity to witness all 

logging and testing required 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 reasonable 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 transmissive. 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 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. 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 
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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, injection 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 significant 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. including 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 enumerated in this section or others to be 

allowed by the Director, the owner or operator and the Director must apply methods 

and standards generally accepted in the industry. When the owner or operator 

reports the results of mechanical integrity tests to the Director, he/she shall include a 

description of the test(s) and the method(s) used. In making his/her evaluation, the 

Director must review monitoring and other test data submitted since the previous 

evaluation. 

(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 
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Multi-Stakeholder Discussions 10 

 

packer or significant movement of fluid into or between USDWs resulting from the 

injection activity as stated in paragraphs (i)(A) and (i)(B) of this section. 

(g) Testing and Monitoring

(1) Based on a site-specific assessment of the potential for fluid movement from the 

injection well or injection zone, 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 to verify that the geologic sequestration project is operating as 

permitted and is not endangering USDWs. The testing and monitoring plan must be 

submitted with the permit application for Director approval, and must include a description 

of how the owner or operator will meet the requirements of this section. 

(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 techniques 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; 
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(v) Corrosion monitoring of the well materials that will come into contact with water 

for loss of mass, thickness, cracking, pitting 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 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 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 determined 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 triggers a shutdown device required pursuant 

to §146.25(f)(4) and the response taken; 

(v) The monthly volume of the carbon dioxide stream injected over the reporting 

period and project cumulatively; 

(vi) Monthly annulus fluid volume added; and 
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(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 Director, 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, confirming 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 submit 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. 
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(i) Required permit application information 

This section sets forth the information which the owner 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 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 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 based 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 injection 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 review 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 have affected the proposed area of review 

including knowledge of previous seismic events and history of these events, 

including the presence and depth of seismic sources and a determination that the 

seismicity would not compromise containment; 

(iv) Data sufficient to demonstrate 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, seismic 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 indicating the general vertical and lateral limits of 

all USDWs, the location of water wells and perennial springs within the area of review, their 

positions relative to the injection zone(s) and the direction of water movement, where 

known; 

(7) A compilation of available baseline geochemical data on the proposed injection zone and 

nearest adjacent porous and permeable formation 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 physical characteristics of the carbon dioxide 

stream; 

(9) Proposed formation testing program to obtain an analysis of the chemical and physical 

characteristics of the injection zone and confining zone; 

(10) The compatibility of the carbon dioxide stream with fluids in the injection zone and 

minerals in both the injection and the confining zone(s), based on the results of the 

formation testing program 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 program data on the well required by §146.25(e)(1); 

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

(19) A demonstration, satisfactory to the Director, that the applicant has met the financial 

responsibility requirements under §146.25(c); 

(20) Proposed testing and monitoring 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 operator 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 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) For injection wells and any monitor wells 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 material 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 operator must notify the Director at least 60 days 

before plugging of a well. At this time, if any changes have been made to the original well 

plugging plan, the owner or operator must also provide the revised well plugging plan. At 

the discretion of the Director, a shorter notice period may be allowed. 

(4) Plugging report. Within 60 days after plugging the owner or operator must submit a 

plugging report to the Director. The report must be certified as accurate by the owner or 

operator and by the person who performed the plugging operation (if other than 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 demonstrated 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 closure plan or demonstrate to the Director 

through monitoring data and modeling results that no amendment to the plan is 

needed. 

(iv) The owner or operator may modify 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 monitoring 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 and site closure plan should be revised to 

reduce the frequency of monitoring. 

(iii) Prior to authorization for site closure, 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 pressure) ; (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 expected 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 owner or operator must notify the Director at least 

120 days before site closure. At this time, if any changes have been made to the original 

post-injection site care and site closure plan, the owner or operator must also provide the 

revised plan. At the discretion of the Director, a shorter notice period may be allowed. 

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

monitoring wells in a manner which will not allow movement of injection or formation 

fluids that endangers an USDW except that designated wells may remain unplugged pursuant 

to §146.25(k) (2)(iii)(F) with the 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 closure, the owner or operator must submit a site 

closure report within 90 days after completion of all closure operations. The report must 

include: 

(i) Documentation of appropriate 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 submitted 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 Regional 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) 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 period. The owner or operator must deliver the 

records to the Director at the conclusion of the retention period, and the records must 

thereafter be retained at a location designated by the Director for that purpose. 

(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 endangerment 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 designated 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 remediation 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 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 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) proposed 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 (CO2) Geologic 

Sequestration (GS) Wells," 73 Fed. Reg. 43491-541 (July 25, 2008), 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 review and corrective action requirements; well 

construction requirements, cement bond assessments; 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 permitted under appropriate injection well classes 

while also ensuring protection of underground sources of drinking water as well as human 

health and the environment. 

Following the December 23, 2008 submission, the stakeholders have focused in part on the 

potential publication of a Notice of Data Availability (NODA) that your Office has 

included—albeit with the qualifier “if appropriate”—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 CO2 for EOR/EGR and GS. The 

participating stakeholders agree that this approach 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 requirements 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 noted 
Cynthia 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 criteria 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 include in its plans for both publication of a 

NODA and the final rule the approach of regulating 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 developing 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 17, 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, including 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 among 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 

the 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 larger group on a series of issues related to the rule. Those multistakeholder 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 recovery 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 dioxide injection and 

(ii) operating pressures are no higher than reasonably necessary to produce such 

volumes or rates.

We support the concept of a distinct regulatory scheme for HCOGS, 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 class.

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 

grounded 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 scheme for HCOGS 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 HCOGS, requirements that must be met in 

order to confirm sequestration of the CO2 from atmospheric release and to satisfy 

SDWA requirements.

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

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

with the other MSG stakeholders. 

Respectfully submitted, 

Kurt Waltzer

CCS Coordinator

Clean Air Task Force


Cynthia 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 EPA’s Proposed Rule on Geologic Sequestration 

of Carbon Dioxide (GS) has closed and the Agency is considering next steps, we are 

writing to summarize our views in relation to a few key points following 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 promulgating adequate regulations 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 certainty further but also adequately to safeguard 

human health and the environment. Therefore, in considering whether 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 final rule needs to cater for GS in hydrocarbon reservoirs as 

well, and not just saline formations as proposed. Hydrocarbon reservoirs are likely to be 

among the first ones to be used for GS, and they need to be regulated appropriately. We 

do not believe that automatic delegation to Class II “as long as any production is 

occurring” is suitable. Under the economic driver of carbon constraints, additional risks 

might be posed in these reservoirs 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 closure 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 injected carbon dioxide to the atmosphere. The proposed rule 

defines GS solely for the purposes of protecting Underground Sources of Drinking Water 

(USDWs). Climate legislation is presently being drafted in Congress however, and will 

very likely rely on EPA’s injection classes to certify GS. Specifically, the legislation will 
very likely exempt carbon dioxide emissions from large facilities that are geologically 

sequestered according to regulations promulgated 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 likely to have a far narrower remit than the 

current rule’s specific requirements for site 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 requirements for GS in hydrocarbon reservoirs 

in the current rulemaking. The mere continuation of hydrocarbon production in 

those fields is not a valid criterion for well classification; 

• “Geologic sequestration” should not be defined only for the purpose of protecting 

USDWs, but also for the purpose of preventing 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 should continue to apply to operations that inject carbon 

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

• Class II as it exists today 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 closure 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 class or subclass should be subject to the 

primacy delegation requirements that apply to Class VI as proposed, and not to 

the more general showing used for Class II; and 

• In order to be able to utilize existing wells in hydrocarbon reservoirs for GS, this 

class or subclass could allow for the transition 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, closure 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 Council

March 31, 2009 

Cynthia C. Dougherty 

Director 

Office of Ground Water and Drinking Water 

U. S. Environmental Protection Agency 

1200 Pennsylvania Ave., NW. 

Washington, DC 20460 

Re: Proposed Rule for Geologic Sequestration, 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 recommendation that these be adopted as the 

requirements for geologic sequestration (GS) in oil 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 Force (CATF), the Environmental Defense Fund 

(EDF) and jointly by the American Petroleum Institute (API), the Edison Electric Institute (EEI) 

and the Carbon Sequestration Council (CSC), the MSG has continued efforts toward developing 

recommendations reflecting common views on a number of the issues in this rulemaking. 

The March 17 letters noted that the MSG has followed a modified approach to focus in part on 

the potential publication of a NODA. The undersigned organizations are sending this letter at 

this time because we understand that the publication of a NODA is still contemplated. The 

December 23, 2008 joint MSG letter explained the agreement reached on the proposed language 

describing wells in classification (b)(4) that establishes a “bright line” definition for wells that 

inject CO2 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 subject 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 address 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 Class II provisions to wells that inject CO2 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 March 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 opportunity to publish proposed regulations for this 

category of wells for public review and comment in conjunction with a NODA, allowing others 

to address this recommendation in responding to the 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 include 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 discussion 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 review and comment, it seemed more beneficial at this point to 

provide you a set of provisions that reflect the efforts to date, address the appropriate issues, and 

provide a good basis for seeking comment on this 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 participants 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 letter 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) and 146.5(b)(4) as proposed in the December 23 

MSG letter and the addition of a new paragraph (5) in subsections 144.5(b), 144.80(b) and 

146.5(b) reading: 

(5) For geologic sequestration in oil and gas formations and where the criteria of 

paragraph (b)(4) are not met. 

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

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

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

(f) Class VI. Wells injecting a carbon dioxide stream for geologic sequestration 

except those wells described in subsections (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 developing additional specific recommendations for 

improvement of a final rule that could be adopted, consistent with your previously published 

schedule, by late 2010 or early 2011 or sooner. 

As noted in the December 23, 2008 letter, 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. Accordingly, 

we specifically recommend that these requirements be published for comment in conjunction 

with a NODA if one is published. 

Sincerely, 

Kyle Isakower 

Director, of Policy Analysis 

American Petroleum Institute 
Cynthia 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 Sequestration 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 Associate General Counsel 

Southern Company 
Cynthia 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 Whitehurst 
ATTACHMENT A 

Requirements for Geologic Sequestration 

Oil and Gas Reservoirs 

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

 

Except as otherwise provided in this section, injection wells used for geologic sequestration and 

meeting the 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 system must be comprised of: 

(1) An injection zone of sufficient areal extent, thickness, porosity, and permeability to 

receive the total anticipated volume of the carbon dioxide stream; 

(2) A confining zone(s) that is laterally continuous and free of known transmissive faults or 

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

(b) Area of Review and Corrective Action

(1) The area of review is based on computational 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 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; and 

(B) How corrective action will be conducted to meet the requirements of 

§146.25(b)(4), including what corrective action will be performed prior to 

injection and what, if any, portions of the area of review will have corrective 

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

action addressed on a phased basis and how the phasing will be determined; 

how corrective action will be adjusted if there are changes in the area of 

review; and how site access will be assured for future corrective action. 

(3) The owner or operator must perform the following actions to delineate the area of 

review, identify all wells that require corrective action, and perform corrective action on 

those wells: 

(i) Project, using computational modeling and available monitoring data, the 

projected lateral and vertical migration of the carbon dioxide plume and formation 

fluids in the subsurface from the commencement 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 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; 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, including active, inactive and abandoned wells 

and underground mines, in the area of review that may penetrate the confining zone. 

Provide a description of each well’s type, construction, date drilled, location, depth, 

record of plugging and/or completion, and 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 movement 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 conditions warrant, including in conjunction with 

reviews conducted pursuant to §146.25(h)(4), the owner or operator must: 

Multi-Stakeholder Discussions 2 

 
GS in Oil and Gas Reservoirs March 31, 2008 

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

(ii) Identify all wells in the reevaluated area of review that require corrective action in 

the same manner specified in §146.25(b)(3)(ii). 

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

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

(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 the adequacy of existing financial responsibility 

or provide and maintain financial responsibility and resources for: corrective action (that 

meets the requirements of § 146.25 (b)), injection well plugging (that meets the requirements 

of § 146.25(j)), and post-injection 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-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 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 adjustment of the cost estimate to the Director if 

the Director has reason to believe that the most recent demonstration is no longer adequate 

to 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)).

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GS in Oil and Gas Reservoirs March 31, 2008 

(d) Well Construction Requirements 

(1) Applicability 

(i) Existing wells must meet the construction 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 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 comparable 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 determine and specify casing and cementing requirements, the owner or 

operator must provide the following information: 

(A) Depth to the injection zone; 

(B) Hole size; 

Multi-Stakeholder Discussions 4 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(C) Size and grade of all casing strings (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 intermediate 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, using 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 capable 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 fluids through tubing with a packer set 

at a depth opposite a cemented interval at the location approved by the 

Director. 

(B) In order for the Director to determine and specify requirements for 

tubing and packer, the owner or operator must submit the following 

information: 

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

Multi-Stakeholder Discussions 5 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(2) Composition of the carbon dioxide stream. 

(3) Maximum proposed Injection temperature and pressure; 

(4) Maximum proposed Annular pressure; 

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

and volume of the carbon dioxide stream; 

(e) Logging, sampling, and testing prior to new well operation – The following requirements apply 

only to newly-drilled wells. 

(1) During the drilling and construction of an injection well, the owner or operator must run 

appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, 

permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic 

formations to evaluate conformance with applicable injection well construction requirements 

and to establish accurate baseline data against which future measurements may be compared. 

The owner or operator must submit to the Director a descriptive report prepared by a 

knowledgeable log analyst that includes an interpretation 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 data having similar quality and reliability as would 

be obtained with new logs and tests, the construction plan, and the need for additional 

information that may arise from time to time as the construction of the well progresses and 

these may include the following: 

(i) Deviation checks during drilling on all holes constructed by drilling a pilot hole 

that is enlarged by reaming or another method. Such checks must be at sufficiently 

frequent intervals to determine the location of the borehole and to assure that 

vertical avenues for fluid movement in the form of diverging holes are not created 

during drilling; 

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

(A) Resistivity, spontaneous potential, and 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 any 

other 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) and/or map(s) after the casing is set and 

cemented to evaluate cement quality with sufficient radial resolution to 

Multi-Stakeholder Discussions 6 

 
GS in Oil and Gas Reservoirs March 31, 2008 

identify channels or missing cement that would prevent compliance with 

§146.25(d)(2). 

(iv) Test(s) designed to demonstrate the internal 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 zone and confining system and formation fluid 

samples from the injection zone(s). The Director may accept data from cores and fluid 

samples from nearby wells if the owner or operator can demonstrate that such data are 

representative of conditions in the wellbore. 

(3) Prior to injection well operation, 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 confining zones and conduct tests to verify 

hydrogeologic and geomechanical characteristics of the injection zone. 

(5) The owner or operator must provide the Director with the opportunity to witness all 

logging and testing by this subpart. The owner or operator must submit a schedule of such 

activities to the Director upon spudding the well and submit any changes to the schedule 48 

hours prior to the scheduled test. 

(f) Injection well operating requirements

(1) The owner or operator must comply 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 reasonable 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 transmissive. In no case may injection pressure 

cause movement of injection or formation fluids in a manner prohibited by 40 C.F.R. 

§144.12(a). 

Multi-Stakeholder Discussions 7 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(2) Injection of the CO2 stream into any annulus or between the outermost casing 

protecting USDWs and the well bore is prohibited. 

(3) For injection wells constructed with injection tubing and packer, the owner or operator 

must fill the annulus between the tubing and the long string casing with a corrosion 

inhibiting fluid approved by the Director and must maintain a positive pressure on the 

annulus. 

(4) The owner or operator must install and use continuous recording devices to monitor: the 

injection pressure and the rate, volume, and temperature of the carbon dioxide stream. For 

injection wells constructed with injection tubing and packer, the owner or operator must 

regularly monitor the pressure on the annulus 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 shut-in the well when operating parameters such as 

injection rate, injection pressure, or other parameters 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 lack of mechanical integrity are imposed under 

40 C.F.R. §144.51(q). 

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

(5) Mechanical integrity 

(i) A well has mechanical integrity if: 

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

(B) There is no significant fluid movement into a USDW through channels 

adjacent to the injection well bore. 

(ii) To evaluate the absence of significant 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 and packer – pressure on the annulus between 

tubing and long stem casing and annulus fluid volume as specified in 

§146.25(g)(2)(ii); 

(iii) At least once per year, the owner or operator must confirm the absence of 

significant fluid movement under paragraph (5)(i)(B) of this section using a method 

Multi-Stakeholder Discussions 8 

 
GS in Oil and Gas Reservoirs March 31, 2008 

acceptable to the Director (e.g. including 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 enumerated in this section or others to be 

allowed by the Director, the owner or operator and the Director must apply methods 

and standards generally accepted in the industry. When the owner or operator 

reports the results of mechanical integrity tests to the Director, he/she shall include a 

description of the test(s) and the method(s) used. In making his/her evaluation, the 

Director must review monitoring and other test data submitted since the previous 

evaluation. 

(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 paragraphs (i)(A) and (i)(B) of this section. 

(g) Testing and Monitoring

(1) Based on a site-specific assessment of the potential for fluid movement from the 

injection well or injection zone, 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 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, for wells constructed with 

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GS in Oil and Gas Reservoirs March 31, 2008 

injection tubing and packer, to record at least daily the pressure on the annulus 

between the tubing and 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) a quality assurance plan. 

(3) Where appropriate, the testing and monitoring 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 operator 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 techniques 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 performed 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 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 

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GS in Oil and Gas Reservoirs March 31, 2008 

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

and 

(vii) Any additional testing and monitoring necessary to determine whether fluid 

movement is occurring that would endanger a USDW. 

(h) Reporting and Certification Requirements

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

permitted well: 

(1) Semi-annual or less frequently as determined 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 triggers a shutdown device required pursuant 

to §146.25(f)(4) and the response taken; 

(v) The monthly volume of the carbon dioxide stream injected over the reporting 

period and project cumulatively; 

(vi) Monthly annulus fluid volume added; and 

(vii) The results of 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 Director, other formats may be accepted. 

(4) Owners or operators must submit an annual certification, signed by the appropriate 

company official, that the company has: 

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GS in Oil and Gas Reservoirs March 31, 2008 

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

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

certification that are relevant to a decision 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 copies 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 owner 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 based 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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GS in Oil and Gas Reservoirs March 31, 2008 

(i) Isopach maps of the proposed injection 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 review 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 have affected the proposed area of review 

including knowledge of previous seismic events and history of these events, 

including the presence and depth of seismic sources and a determination that the 

seismicity would not compromise containment; 

(iv) Data sufficient to demonstrate 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, seismic 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 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 must include a description of each well’s type, 

construction, date drilled, location, depth, record of plugging and/ or completion, and any 

additional information the Director may require; 

(6) Maps and stratigraphic cross sections indicating the general vertical and lateral limits of 

all USDWs, the location of water wells and perennial springs within the area of review, their 

positions relative to the injection zone(s) and the direction of water movement, where 

known; 

(7) A compilation of available baseline geochemical data on the proposed injection zone and 

nearest adjacent porous and permeable formation to the confining zone, existing utilized 

water supply aquifers and any other USDWs designated by the Director. 

(8) Proposed operating data: 

Multi-Stakeholder Discussions 13 

 
GS in Oil and Gas Reservoirs March 31, 2008 

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

stream; 

(ii) Average and maximum surface injection pressure; 

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

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

stream; 

(9) The compatibility of the carbon dioxide stream with fluids in the injection zone and 

minerals in both the injection and the confining 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 obtain 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 artificial penetrations within the area of review, if 

necessary; 

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

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

(19) A demonstration, satisfactory to the Director, that the applicant has met the financial 

responsibility requirements under §146.25(c); 

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

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

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

Multi-Stakeholder Discussions 14 

 
GS in Oil and Gas Reservoirs March 31, 2008 

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

(24) Any other information requested by the Director. 

(j) Injection well plugging

(1) Prior to the well plugging, the owner or operator 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 plan that is acceptable to the Director. The requirement to maintain and implement 

an approved plan is directly enforceable regardless of whether the requirement is a condition 

of the permit. The well plugging plan must be submitted as part of the permit application 

and must include the following information: 

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

(ii) Appropriate testing methods to ensure final external mechanical integrity as 

specified in §146.25(f)(5); 

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

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

each plug; 

(v) The type and grade and quantity of material to be used in plugging. The material 

must be suitable for use with the carbon dioxide stream, reservoir and fluid 

conditions; and 

(vi) The method of placement of the plugs. 

(3) Notice of intent to plug. The owner or operator must notify the Director at least 60 days 

before plugging of a well. At this time, if any changes have been made to the original well 

plugging plan, 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 plugging the owner or operator must submit a 

plugging report to the Director. The report must be certified as accurate by the owner or 

operator and by the person who performed the plugging operation (if other than the owner 

or operator.) 

(k) Post-injection site care and site closure

Multi-Stakeholder Discussions 15 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(1) The owner or operator of a well must prepare, maintain, and comply with a plan for 

post-injection site care and site closure that 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 pressure differential between 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 demonstrated 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 closure plan or demonstrate to the Director 

through monitoring data and modeling results that no amendment to the plan is 

needed. 

(iv) The owner or operator may modify 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-injection site care and site closure plan, pursuant to the 

performance based criteria described in §146.25(k)(2)(iii). 

(ii) The owner or operator can request 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 closure, 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 

Multi-Stakeholder Discussions 16 

 
GS in Oil and Gas Reservoirs March 31, 2008 

following: (A) the estimated magnitude and 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 significant 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 owner or operator must notify the Director at least 

120 days before site closure. At this time, if any changes have been made to the original 

post-injection site care and site closure plan, the owner or operator must also provide the 

revised plan. At the discretion of the Director, a shorter notice period may be allowed. 

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

monitoring wells in a manner which will not allow movement of injection or formation 

fluids that endangers a USDW. 

(5) Once the Director has authorized site closure, the owner or operator must submit a site 

closure report within 90 days after completion of all closure operations. The report must 

include: 

(i) Documentation of appropriate 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 submitted 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 Regional 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 17 

 
GS 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 period. The owner or operator must deliver the 

records to the Director at the conclusion of the retention period, and the records must 

thereafter be retained at a location designated by the Director for that purpose. 

(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 endangerment 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 designated 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 remediation 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 determines that the pressure front associated 

with one project will interfere with the ability of another project to comply with the 

terms of its permit(s), the Director may require the owner or operator of the 

potentially interfering project to modify operations as necessary to avoid such 

interference. Such modification may include 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 18 

 
GS 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 19 

 
 

Ground Water Protection Council 

13308 N. MacArthur Blvd. 

Oklahoma City, OK 73142 

Tel: (405) 516-4972 

Fax: (405) 516-4973 

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

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 Protection Council (GWPC) signed a letter submitted 

by a Multi-Stakeholder Group (MSG) supporting the 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 program for the purposes of 

geologic sequestration of carbon dioxide in oil and gas reservoirs. 

One of the topics discussed in the December 23 letter was the need for a way to determine when 

a well permitted under the Class II program would 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 under which wells would transition from Class II Enhanced 

Recovery to a new class or subclass 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 submission 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 development proceeds at an appropriate pace, we 

recommend that EPA publish the language 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 comments as the process moves forward. 

Respectfully, 

Mike Paque 

GWPC Executive Director 

cc: Robert F. Van Voorhees 

 Scott Anderson 
18 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-Stakeholder Group to Address Relative to 

Airside Monitoring, Verification and 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 discussion relative to airside MVA, including the 

two-stage approach mentioned at the meeting. I hope you find this to be helpful in 

drafting recommendations for the group’s consideration. 

I. Establishing a Guiding Principle:

CO2 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 demonstrated containment within the storage 

reservoir should suffice as “proof” that there 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 scenarios 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. (CO2 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 CO2 fluxes, and 

may be impractical for routine airside monitoring. 

 Need rigorous accounting for CO2 retention taking into account recycling in 

EOR. EOR industry and historic records needed to help develop methodology. 

 Potential failure of primary CO2 reservoir. The applicant should identify 

secondary CO2 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 / historic or pre-historic formation 

penetrations. Survey for old wells /identify old well bores, establish baseline 

air / flux monitoring. 

 De-pressuring at end of project may pose risk. Prohibit to keep all CO2

immobile. 

III. Establishing Geological Context . 

 Not explicitly discussed 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 phase in the reservoir. 

 During initial characterization, understanding 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 burial / 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 pipeline transport to another site makes 

more sense. 

 Understanding the regional geologic context 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 quantifying CO2 sequestered in Class IIb wells (wells for 

“sequestration with incidental oil production”). 

“CO2 Retention” should be redefined as the amount of CO2 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 estimates of permanent retention should be 

based on a long time frame (e.g. 1,000 yrs). 

In EOR “recycled” CO2 returns with produced fluids and is then processed and 

reused. Over time progressively more CO2 is permanently sequestered, 

asymptotically approaching 100%. Data needed from EOR industry to substantiate 

this. 

Sum [injected] – sum [Recycled] = 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 characterization and risk assessment followed by 

cost-effective MVA techniques to test the reservoir model and to look for potential 

leakage into the next reservoir layer above the confining zone. If the Stage 1 data 

suggests potential for leakage or pressure front migration, then a more costly Stage 2 

is triggered, requiring best available MVA techniques, including focused surface 
3

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 choose low risk sites to reduce MVA intensity. 

Higher risk sites require higher diligence and 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 establish a baseline model of the subsurface 

projected plume / storage geometry (e.g. 3D seismic), and record baseline 

surface and near-surface data. Scientifically exhaustive initial site 

characterization to develop a “high degree of confidence” is key. 

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

and allows for focus MVA on vulnerabilities. 

 In principal, if CO2 remains contained, need for other tools beyond UIC rule 

should be minimal. 

 Develops, in advance, a plan for 2 stages 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 

CO2/pressure front surveillance, reservoir 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 CO2 remains confined in injection zone, 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 vulnerabilities identified in initial 

characterization. 

 Establish ”layer above” leakage monitoring—monitoring of secondary 

reservoir rock layer above the injection 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: investigating integrity of tubing and annulus, cement 

bond log, etc. 

o Wellhead pressure and targeted borehole flux monitoring. 

o Preexisting well surveillance in AOR. 

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

seismic: 
4

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

o Vertical seismic profiling 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 down 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 subsurface monitoring see (next 

slide). 

 Prior to recommencement of injection, public 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 CO2 volumes in place, lost and pathway, using best 

available tools required regardless of cost and must include robust remedy. 

(e.g. 4D seismic, 9-component seismic shear, gravity, EnSAR, tracers, etc. as 

appropriate for region and needs). 

 Methods must overlap with initial characterization 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 intensive surface flux monitoring or 

remote sensing (e.g lidar for vegetative stress) 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 eddy covariance towers and flux 

accumulation monitoring. 

o Quantify volumetric changes and plume migration (subsurface 

methods). 

o To account lack of accuracy, 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 

% CO2 compensation to make atmosphere “whole”. 
5

o >10% loss = permanent shut down, quantification and 

remediation/compensation (unless loss is through a clearly identifiable 

pathway such as a well that can be readily plugged). 

o CO2 Loss Compensation Penalty = 100% of tons projected to be lost 

from above approach. 

o Alternative storage plan desirable 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 CO2 off 

molecule by reheating—not 100% efficient due to some escape to 

atmosphere (<<1%). 

o Power outage in compressors; CO2 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 atmospheric emissions. Establish pre -

injection baselines. 

 To date, surface measurements at SACROC EOR field suggest 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 CO2 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 CO2 is contained in well-characterized 

low-risk storage layer, avoid costly broad surface flux surveys. If potential for 

leakage detected in subsurface, location can be determined using flux or soil 

gas monitors, remote sensing (e.g. hyper-spectral imaging in vegetated areas). 

 If CO2 flux detected then may be able to measure emissions rates via 

covariance towers, chambers etc. 

 Airside Monitoring: H2S 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).