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.
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

 
Letter ID: 0294 

Commenter: John McManus 

Organization: American Electric Power 

Letter ID: 0294 Comment ID: 25305 Letter Lines: 37 to 46 

Comment Code: 1000 1. General and Administrative Comments 

Comment: [FN: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). 

Individual Response: EPA acknowledges the comment. Please see the remainder of EPA's 

responses to this comment letter and responses to comments from CATF, EDF, and NRDC for 

further details. For additional information on EPA's final regulatory approach, please see the 

final rule and preamble as well as the rulemaking docket. 

Letter ID: 0294 Comment ID: 25306 Letter Lines: 50 to 55 

Comment Code: 2123 1.6.1.1 Comments in favor of injection into deep saline 

Comment: 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. 

Individual Response: EPA acknowledges the comment and agrees that GS into hydrocarbon 

reservoirs and saline formations is appropriate where a geologic system (e.g., injection and 

confining zones) is identified, characterized, and demonstrated to be suitable for receiving and 

confining injected CO2 without endangering USDWs under §146.82. 

Letter ID: 0294 Comment ID: 25307 Letter Lines: 57 to 73 

Comment Code: 2048 1.5.2.4 Oppose Class VI/ Support Class V experimental technology well 

Comment Code: 2200 1.6.4 Other formation types 

1
Comment: 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 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. 

Individual Response: EPA clarifies that the final GS rule does not categorically preclude 

injection of CO2 into any formation types. Experimental research projects will continue to be 

regulated as Class V experimental technology wells as long as they remain of an experimental 

nature. EPA clarifies that existing experimental GS projects may be permitted as described in 

UIC Program Guidance #83: Using the Class V Experimental Technology Well Classification 

for Pilot Carbon Geologic Sequestration Projects, which provided information for permitting 

authorities to consider when permitting experimental GS projects (i.e., those projects that are 

designed to test new, unproven technologies, per the definition of a Class V experimental 

technology well). EPA adds that, following finalization of the GS rule, all GS projects that are 

not for experimental purposes must be re-permitted as Class VI wells and be subject to the final 

GS requirements. EPA expects that, after promulgation of the final rule, a limited number of 

experimental injection projects to test GS technology will continue, e.g., to inform the 

technology associated with GS into basalts, coal seams, and salt domes. 

EPA clarifies those Class V experimental projects subject to Guidance #83 will be those wells 

that test new technologies for purposes of GS. The Agency also clarifies that it does not consider 

it appropriate to permit CO2 injection wells that are testing the injectivity or appropriateness of 

an individual formation (e.g., as a prelude to a commercial-scale operation) as Class V 

experimental technology wells. Such wells must be permitted as Class VI wells. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental 

technology well classification to clarify permitting for Class V wells. This addendum will 

address shifting of Class V experimental projects to full-scale GS projects and the future use of 

the Class V experimental technology well subclass for research and testing of new GS 

technologies. This guidance will be available on EPA’s website at 

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

2
Letter ID: 0294 Comment ID: 25308 Letter Lines: 75 to 89 

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

Comment Code: 2048 1.5.2.4 Oppose Class VI/ Support Class V experimental technology well 

Comment Code: 2200 1.6.4 Other formation types 

Comment: 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 nonexperimental 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." 

Individual Response: The text at 144.15 is retained in the final regulation; the construction, 

operation or maintenance of any non-experimental Class V GS well is prohibited under the final 

rule. The final rule contains tailored requirements for Class VI wells to ensure that GS projects 

are permitted, sited, constructed, operated, and closed in a manner that protects USDWs from 

endangerment. 

As described above, EPA clarifies that the final GS rule does not categorically preclude injection 

of CO2 into any formation types. EPA clarifies that experimental research projects will continue 

to be regulated as Class V experimental technology wells as long as they remain of an 

experimental nature. 

Letter ID: 0294 Comment ID: 25309 Letter Lines: 91 to 112 

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

Comment Code: 5800 2.13 Comments on emergency and remedial response (40 CFR 146.94) 

Comment: 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 

3
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 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." 

Individual Response: EPA agrees with the commenter that there are a variety of factors that 

may affect the need for emergency and remedial response at GS sites. The Agency believes that 

a site-specific emergency and remedial response plan that is informed by required site 

characterization data (per §146.82), modeling for AoR evaluations and reevaluations (per 

§146.84), and monitoring data (per §146.90) will appropriately address commenter concerns 

regarding the potential impacts of multiple GS projects. EPA has added a requirement at 

§146.94(d) that owners or operators must review their emergency and remedial response plan 

within one year of an AoR reevaluation required under 146.84 or following significant changes 

to the facility. Subsequently, the owners or operators must submit an amended plan or 

demonstrate to the Director that no amendment to the plan is needed based on the AoR 

reevaluation or any significant changes made to the facility. 

EPA also encourages owners or operators and permitting authorities to communicate planned GS 

activities during initial permitting activities to maximize coordination and minimize pressure 

interference. If a permit applicant (or the permitting authority) is aware of pending GS projects 

near a proposed well, the AoR delineation performed pursuant to 146.84 should account for the 

impacts of multiple owners and operators injecting within a single basin. EPA expects that, 

where multiple operators are involved, the Director will not approve modeling that does not 

account for changes that may result from all injection operations. 

EPA expects that changes within the AoR, such as the addition of new wells or projects that 

could potentially interfere with a GS project, would be identified as part of the AoR 

reevaluations required at §146.84(e) and would need to be addressed in a revised emergency and 

remedial response plan. EPA is developing guidance on the development and implementation of 

project plans for GS sites, including emergency and remedial response plans. 

Letter ID: 0294 Comment ID: 25310 Letter Lines: 115 to 126 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

4
Comment: 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." 

Individual Response: EPA disagrees with the suggested edit. The final definition of 

transmissive fault or fracture at §146.81(d) is unchanged and reads as follows: “[A] fault or 

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

formations.” 

The confining zone definition at §146.83(a)(2) also is unchanged and reads as follows: “Free of 

transmissive faults or fractures and of sufficient areal extent and integrity to contain the injected 

carbon dioxide stream and displaced formation fluids and allow injection at proposed maximum 

pressures and volumes without initiating or propagating fractures in the confining zone(s).” 

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

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0294 Comment ID: 25312 Letter Lines: 128 to 139 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment: 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." 

Individual Response: EPA acknowledges the comment and disagrees that the definition of 

5
confining zone is too strict. EPA clarifies that §146.83(a) requires that any GS project must have 

at least one confining zone (i.e., impermeable layer) between the injection zone and the 

lowermost USDW. EPA further believes that, in some situations, the presence of additional 

confining and containment zones above the primary (i.e., lowermost) confining zone can 

improve USDW protection. These layers could further impede vertical fluid movement and 

allow for pressure dissipation, and also provide additional sites for monitoring, mitigation, and 

remediation. 

Letter ID: 0294 Comment ID: 25313 Letter Lines: 141 to 168 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: 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 with any intervening 

formations,] [FN2] and the surface area above that delineated region." 

[FN2] 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. 

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. 

Individual Response: EPA disagrees that the AoR definition needs to specifically include the 

overlying formations and surface area above the delineated region. The intent of the AoR, a 

long-standing concept within the UIC Program, is to delineate the surface area and all subsurface 

formations below it that may potentially be impacted by injection activity. Acceptable 

6
delineation models will provide predictions of CO2 fate and transport, as well as changes in 

formation pressure, in three dimensions as a function of time that can be used to delineate the 

subsurface storage site and the AoR. 

Although EPA disagrees with the commenter's suggested change, the Agency has carefully 

considered all comments on the AoR definition at 146.84(a) and modified it to read as follows: 

The region surrounding the geologic sequestration project where USDWs may be endangered by 

the injection activity. The area of review is delineated using computational modeling that 

accounts for the physical and chemical properties of all phases of the injected CO2 stream and is 

based on available site characterization, monitoring, and operational data. EPA believes that this 

definition is sufficiently broad and describes both the intent of the computational modeling and 

the relationship of the AoR to areas that are subject to the risks associated with injection. 

Letter ID: 0294 Comment ID: 25314 Letter Lines: 171 to 215 

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

Comment Code: 3420 2.2.2.1 Scope of the inventory process (e.g., reliance on publicly 

available information, depth of wells) 

Comment: 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 

7
are necessary to prevent movement of 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)][FN3] 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." 

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. 

Individual Response: The final rule leaves §144.55 unchanged from the existing UIC 

requirements; i.e., Class VI wells are not addressed in this provision. 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. 

Letter ID: 0294 Comment ID: 25315 Letter Lines: 217 to 240 

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

Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment) 

Comment: 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): 

8
"(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." 

Individual Response: EPA does not believe that the cementing requirements at §146.86 would 

prevent monitoring, operation and remediation of Class VI wells. Cementing of deep wells has 

been performed successfully in the past by owners or operators of Class I hazardous and Class I 

municipal waste disposal wells. Some of these wells, which must meet the same cementing and 

casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully 

cemented in a manner that maintains integrity and allows for all required well testing, operation, 

and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in 

the preamble to the final GS rule for additional information. Additionally, EPA is developing 

guidance on the construction of Class VI wells. This guidance will be available on EPA’s 

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

Section 146.86(b)(3) requires that the long-string casing extend to the injection zone and be 

cemented by circulating cement to the surface in one or more stages. It does not, however, 

specify how cementing should be accomplished, and gives flexibility to the owner or operator to 

propose alternate methods to provide a sufficient amount of cement to meet the standard that 

USDWs are protected from endangerment, subject to the approval of the Director. EPA notes 

that there are many potential ways to meet the requirement in deep wells, such as the use of 

staged cementing. 

EPA also received comments from stakeholders representing states, a water association, and 

industry supporting this provision, saying that it provides, at a reasonable cost, corrosion 

protection of the casing; prevents undesirable migration of fluids behind the casing; provides 

support to the casing; and provides multiple barriers against endangerment of USDWs. 

EPA stresses that protection of USDWs is the primary mission and mandate of the UIC program 

and the purpose of all requirements for injection wells. Any injection activity must be 

demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment 

cannot be shown, then the activity will not be allowed under UIC requirements or the SDWA. 

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW 

is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 

includes requirements for owners or operators that seek a waiver of the injection depth 

requirements. Owners or operators of wells operating under injection depth waivers must comply 

with additional construction requirements to ensure that wells used to inject above or between 

USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS 

rule for additional information. 

9
Letter ID: 0294 Comment ID: 25316 Letter Lines: 242 to 313 

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

Comment Code: 3530 2.2.3.1 AoR reevaluation frequency (seeking comment) 

Comment: 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 

uch 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 

10
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; 

"(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." 

Individual Response: EPA disagrees with the proposed changes and believes that periodic AoR 

reevaluation at a set frequency of at least every 5 years is necessary to ensure protection of 

USDWs from endangerment and address the uncertainties inherent in predictive modeling. 

Periodic AoR reevaluations at §146.84(e) ensure that a deliberate effort is made to verify, based 

on monitoring and operational data, that the CO2 plume is moving within the subsurface as 

predicted. EPA believes that less frequent reevaluations may not be sufficient to appropriately 

model plume and pressure front movement, establish conditions for corrective action, and ensure 

protection of USDWs from endangerment. 

EPA agrees that site-specific information will influence the need for AoR reevaluations, and 

clarifies that if site monitoring data agrees with the existing AoR delineation, a model 

recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration 

11
that the current AoR delineation is adequate based on site monitoring data. 

Letter ID: 0294 Comment ID: 25317 Letter Lines: 315 to 340 

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

Comment Code: 3500 2.2.3 Area of Review Reevaluation (seeking comment) 

Comment Code: 4700 2.7 Proposed Recordkeeping and Reporting Requirements (40 CFR 

146.91) 

Comment: 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. 

"(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." 

Individual Response: EPA agrees with the commenter that review of the GS project plans is 

appropriate. The final rule includes provisions that owners or operators review and update the 

AoR and corrective action plan, the testing and monitoring plan, and the emergency and remedial 

response plan throughout the life of the project (these provisions are added at §146.84(c), 

§146.90(j), and §146.94(d)). Owners or operators must review each plan and identify necessary 

amendments to the plan or demonstrate to the Director that no amendment is needed. These 

reviews must be performed within one year of an AoR reevaluation, following any significant 

changes to the facility (e.g., the addition of monitoring or injection wells), or when required by 

the Director. 

12
Letter ID: 0294 Comment ID: 25318 Letter Lines: 344 to 349 

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

Comment Code: 5800 2.13 Comments on emergency and remedial response (40 CFR 146.94) 

Comment: 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." 

Individual Response: The final rule retains the language in §146.94(b)(4) as proposed. EPA 

agrees that the Director should be kept apprised of progress on the implementation of the 

emergency and remedial response plan but expects that the plan itself will include provisions on 

communications with the Director. The requirements for an emergency and remedial response 

plan at §146.94(a) are designed to ensure that owners or operators, as part of their permit 

application, comprehensively plan what actions would be necessary in the unlikely event of an 

emergency. The plan will ensure that operators know what entities and individuals must be 

notified and what actions must be taken to expeditiously mitigate any emergency situations. The 

rule sets forth triggers for notification to the Director that initiates consultation on appropriate 

responses. EPA expects that the owner or operator and Director would discuss the necessary 

response action and maintain a dialogue and communication throughout the conclusion of any 

needed actions. EPA is developing guidance on the development and implementation of 

emergency and remedial response plans for GS sites. 

Letter ID: 0294 Comment ID: 25319 Letter Lines: 350 to 362 

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

Comment Code: 5800 2.13 Comments on emergency and remedial response (40 CFR 146.94) 

Comment: 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. 

13
14

Individual Response: Since proposal, EPA has modified the final regulatory language at 

§146.94(d) to clarify what constitutes a workover to address a well failure (which invokes 

remedial actions) and what constitutes a maintenance-type workover. For maintenance-type 

workovers (i.e., those that are scheduled in advance), the owner or operator must notify and gain 

approval from the Director prior to beginning the workover. In the final GS regulation, EPA has 

moved this requirement to the reporting requirements at §146.91(d) to clarify its intent. 

Regarding concerns that notification could delay responses, EPA clarifies that the GS rule (at 

§146.94(b)) describes procedures owners or operators must take in emergency situations. 

Specifically, upon determining that there is a problem with the well that may endanger a USDW, 

the owner or operator must first cease injection, then take all steps reasonably necessary to 

identify and characterize any release, notify the Director, and implement the approved 

emergency and remedial response plan, which may include a well workover. EPA believes that 

ceasing injection (which the owner or operator would do immediately and before notifying the 

Director) is the action necessary to prevent or mitigate endangerment of USDWs, as required 

under the SDWA.