This comment letter response contains two parts:   

(1) The original submittal from the commenter.

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

Notes about the response letters:

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

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

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

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

• Each response letter includes: comment text; an EPA‐assigned comment code; and an

individual response. These are described and explained below.  

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

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

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

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

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

appropriately addressed.

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

Comment ID.  Additionally, one or more Comment Codes (i.e., unique topic area ID) was

assigned to each discrete point raised by a commenter. This information was added to

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

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

construction requirements).  

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

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

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

commenter was given a unique response.

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

Each letter response is a compilation of each comment and its individual response,

compiled in the order of the original comment letter.  As a result of this process, there is

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

and attention to each comment letter that was submitted.   

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

Responses on each topic area are compiled and are also available in the rulemaking docket.
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), Docket ID No. EPA–

HQ–OW–2008–0390. 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. 
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 
Letter ID: 0191 

Commenter: Kyle Isakower 

Organization: American Petroleum Institute 

Letter ID: 0191 Comment ID: 23878 Letter Lines: 55 to 122 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: 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 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: 

[In the paragraphs below, the text in all CAPS denotes added text.] 

§ 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; 

1
(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.[FN1/] 

[FN1/: Please note that well classification for geologic sequestration in 

certain formations is a matter still under discussion within the multistakeholder 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.] 

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 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. 

Individual Response: EPA did not make the suggested change. The Agency disagrees that wells 

injecting CO2 for the primary purpose of long term storage should be regulated under Class II 

requirements. The Agency believes that the nature and risks of CO2 injection for the primary 

purpose of long term storage poses different risks than injection for the primary purpose of EOR, 

and therefore has developed new Class VI regulations to address these unique risks. For 

example, the volume of CO2 anticipated to be injected for long term storage is significantly 

greater than for EOR operations. Reservoir pressure conditions will also be different, with Class 

VI injection operations involving large volumes of CO2 and likely having higher pressures 

within their storage formations than Class II EOR projects. 

2
Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and 

preamble for further discussion on EPA's final approach to transitioning from Class II to Class 

VI. 

Letter ID: 0191 Comment ID: 23879 Letter Lines: 124 to 155 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Comment: 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). 

Individual Response: EPA notes that because determination of the injection pressure limit is 

based on the fracture pressure of the injection zone, the limit is site-specific and not arbitrary and 

is appropriate to protect USDWs from endangerment. EPA emphasizes that injection pressure 

3
limits are important to protect against fracturing of the confining zone, and that the requirement 

at §146.88(a) that the pressure in the injection zone not exceed 90 percent of the fracture 

pressure provides a margin of safety in the well operation and protects USDWs from 

endangerment. If the Director determines, based on a review of the information collected as part 

of site characterization, that a lower injection pressure limitation is appropriate, the Director has 

the authority to set a lower limit in the operating permit than the limit established in the rule. 

EPA notes that during the site characterization process, owners or operators must submit data 

about the geology of the site, as specified at §146.82(a), including data on known or suspected 

faults and fractures and geomechanical information on fractures, stress, ductility, rock strength, 

and in situ fluid pressures within the confining zone. The Director will use these data to 

determine appropriate limits on injection. 

In response to the concern about reopening of faults at lower pressures than 90 percent of 

fracture pressure, EPA believes that the requirement for the owner or operator to submit data on 

known or suspected faults and fractures and information on the seismic history of the site will 

inform the determination of an appropriate pressure limitation in the permit. Any sites with the 

potential for reopening or reactivation of faults or unacceptable seismic risk that could otherwise 

interfere with containment will not be permitted as GS sites. 

EPA is developing guidance on site characterization for GS projects to assist owners or operators 

in meeting the requirements of §146.82 and to assist directors in evaluating permit applications. 

The guidance will describe recommended approaches for characterizing the regional geology and 

hydrogeology of a proposed site and performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. EPA is also developing guidance for 

primacy agencies that will include recommended approaches for evaluating owner or operatorsubmitted data in setting permit conditions. The guidance will be available on EPA's web site, at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0191 Comment ID: 23880 Letter Lines: 157 to 164 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment: 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 

Individual Response: The post-injection site care requirements in the final GS rule, §146.93(b), 

incorporate a combination of a 50-year default post-injection site care timeframe, in conjunction 

with a performance standard, for Class VI wells. The GS rule offers owners or operators 

flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion 

4
to shorten or lengthen the PISC timeframe during the post-injection period based on site-specific 

data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a 

Class VI well owner or operator to demonstrate, during the permitting process based on 

substantial data, that an alternative PISC timeframe may be appropriate if it ensures nonendangerment of USDWs pursuant to requirements at §146.93(c). 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in all but a limited number of cases. This default 50 

year post-injection site care timeframe represents a reasonable and protective monitoring period 

based on a review of research studies, industry reports, and existing environmental programs, 

and evaluation of public comments. 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. EPA expects that the Director will consider the types of information the commenter 

describes in determining whether the plume and pressure front no longer pose a risk of 

endangerment to USDWs and post-injection site care monitoring may be discontinued. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; perform 

post-injection monitoring; demonstrate the appropriateness of an alternative post-injection site 

care time frame; demonstrate non endangerment; and perform site closure activities. The 

guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA adds that the purpose of the GS rule is not to incentivize the use of GS; rather, the purpose 

of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that protects 

USDWs from endangerment. 

Letter ID: 0191 Comment ID: 23881 Letter Lines: 164 to 169 

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

Comment: 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 

5
plume is not expected to encounter a leakage pathway. Third, the required 

Individual Response: EPA agrees that a complete cessation of plume movement may not occur 

at some sites for long time periods due to density differences, natural formation flow gradients 

and diffusion. EPA clarifies that under the final rule, a complete cessation of plume movement is 

not required, only a demonstration that the plume and pressure front no longer pose a risk of 

endangerment to USDWs. 

EPA acknowledges that many site-specific factors will influence the determination of when the 

CO2 plume and pressure front no longer pose a risk of endangerment to USDWs. It is for this 

reason that EPA believes that Directors, in consultation with operators, will be in the best 

position to determine whether additional post-injection site care is needed. EPA expects this 

decision to be made based on relevant site data and in consultation with all potentially impacted 

parties. EPA also recognizes that there may be sites where the 50 year post injection site care 

timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. For this reason, the GS rule offers owners or operators flexibility regarding 

the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or 

lengthen the PISC timeframe during the post-injection period based on site-specific data, 

pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class 

VI well owner or operator to demonstrate, during the permitting process based on substantial 

data, that an alternative PISC timeframe may be appropriate if it ensures non-endangerment of 

USDWs pursuant to requirements at §146.93(c). 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; perform 

post-injection monitoring; demonstrate the appropriateness of an alternative post-injection site 

care time frame; demonstrate non endangerment; and perform site closure activities. The 

guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0191 Comment ID: 23882 Letter Lines: 169 to 172 

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

Comment: plume is not expected to encounter a leakage pathway. Third, the required 

showing 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. 

Individual Response: EPA acknowledges that many site-specific factors will influence the 

determination of when the CO2 plume and pressure front no longer pose a risk of endangerment 

to USDWs. It is for this reason that EPA believes that Directors, in consultation with operators, 

will be in the best position to determine whether additional post-injection site care is needed. 

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EPA expects this decision to be made based on relevant site data and in consultation with all 

potentially impacted parties. 

EPA agrees that a complete cessation of plume movement may not occur at some sites for long 

time periods due to density differences, natural formation flow gradients and diffusion. EPA 

clarifies that under the final rule, a complete cessation of plume movement is not required, only a 

demonstration that the plume and pressure front no longer pose a risk of endangerment to 

USDWs is. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; perform 

post-injection monitoring; demonstrate non endangerment; and perform site closure activities. 

The guidance will be available at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0191 Comment ID: 23883 Letter Lines: 174 to 198 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: 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). 

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(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. 

Individual Response: EPA disagrees with the suggested edits, but believes that the provisions of 

the final GS rule at §146.93(b) address the commenter’s suggestions. Specifically, the owner or 

operator must monitor the site until it can be demonstrated that the CO2 plume and pressure front 

no longer pose a risk of endangerment to USDWs and that monitoring must continue until the 

owner or operator demonstrates, based on monitoring and other site-specific data, that no 

additional monitoring is needed to ensure that the GS project does not pose a risk of 

endangerment to USDWs, as required at §146.93(b)(3). See the final rule and preamble for 

further discussion on EPA's final approach. 

Letter ID: 0191 Comment ID: 23884 Letter Lines: 200 to 218 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

Comment: (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 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. 

Individual Response: EPA disagrees that the rule should specify the criteria for setting the 

monitoring timeframe. Instead, EPA believes that such determinations are site-specific and 

should be described in a project specific post-injection site care and site closure plan. EPA also 

believes that periodic reviews and updates, where necessary, to the plan are important to 

ensuring that the site continues to be managed effectively and to determine whether shortening 

the monitoring timeframe is appropriate. 

The post-injection site care requirements in the final GS rule offer owners or operators flexibility 

regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten 

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or lengthen the PISC timeframe during the post-injection period based on site-specific data, 

pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class 

VI well owner or operator to demonstrate, during the permitting process based on substantial 

data, that an alternative PISC timeframe may be appropriate if it ensures non-endangerment of 

USDWs pursuant to requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; perform 

post-injection monitoring; demonstrate the appropriateness of an alternative post-injection site 

care time frame; demonstrate non endangerment; and perform site closure activities. The 

guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0191 Comment ID: 23885 Letter Lines: 220 to 251 

Comment Code: 5600 2.11 Comments related to UIC Program primacy for Class VI wells 

Comment: 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 

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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.[FN2/] 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. 

[FN2/: GWPC, Class V Resource Needs Survey, Summary (September 2004).] 

Individual Response: EPA acknowledges that there may be technical and administrative 

challenges including resource concerns, and will work closely with the states to assist them in 

resolving funding issues or acquiring the resources, personnel, and training needed to address the 

unique technical challenges associated with GS. 

EPA will also incorporate Class VI wells into the UIC Program's grant allocation process. The 

States/Tribes/Territories must also demonstrate that they have adequate resources to implement 

the program through matching resources against those allocated by the UIC Program's grant 

allocation formula. Currently, primacy programs are required to meet a minimum of 25 percent 

matching requirement.