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.
Eastman Chemical Company 

P. O. Box 511, B-54D 

Kingsport, Tennessee 37662-5054 

Telephone: 423-229-1863 

Fax: 423-229-4864 

e-mail: rguinn@eastman.com

 

November 24, 2008 

Re: Proposed Rule for Geologic Storage of CO2 (Docket EPA–HQ–OW–2008–0390) 

Eastman Chemical Company is pleased to provide the following comments on USEPA’s 

Proposed Rule for Geologic Storage of CO2 (73 F.R. 43492. July 25, 2008). Eastman Chemical 

Company was founded in 1920 and is a FORTUNE 500 company with 2007 sales of $6.8 billion 

and approximately 10,500 employees. Eastman headquarters are located in Kingsport, 

Tennessee. 

Eastman Chemical Company has over two decades of industry-leading gasification experience 

and knowledge. In 1983, Eastman commercialized the first coal gasification facility in the United 

States at its Kingsport, Tennessee, plant site to produce chemicals from syngas. In addition, 

Eastman owns and operates a gasification facility at its Longview, Texas, site to produce syngas 

from natural gas. Eastman has one of the strongest gasification operating records in the industry 

and is world renowned for its gasification expertise. Eastman also has over 80 years of 

experience building, owning and operating large integrated industrial chemical plant sites. 

Gasification is recognized as the leading clean alternative for utilizing our nation's abundant coal 

and petroleum coke reserves while addressing environmental concerns such as water 

conservation, acid rain, mercury emissions, and global warming. By utilizing abundant 

domestic resources in an environmentally friendly manner to create a wide variety of energybased products, gasification can help provide a solution to the energy and raw materials crisis 

facing the U.S. and can help to stem the tide of moving our industries and their associated jobs 

overseas. 

Industrial gasification is a chemical process that reduces criteria pollutants and is capable of 

capturing and sequestering the vast majority of its carbon dioxide, one of the leading contributors 

to gases often associated with global warming. With Eastman’s long-term commitment to 

gasification technology the company has a vested interest in the geologic storage of CO2 that is 

important for the continued viability of gasification facilities. Eastman Chemical Company 

supports the following comments on the proposed rule generated by the Gasification 

Technologies Council. 

Sincerely, 

Richard J. Guinn, Ph.D. 

Technical Associate 

Corporate Health, Safety, Environment, and Security 
Page 1 of 16

Gasification Technologies Council 

4301 North Fairfax Drive, Suite 300 Arlington, VA 22203 

Ph (703) 276-0110 Fx (703) 276-0141 Email jchildress@gasification.org

Water Docket, Environmental Protection Agency 

Mailcode: 2822T, 

1200 Pennsylvania Ave., NW., 

Washington, DC 20460 

RE: EPA Docket EPA–HQ–OW–2008–0390 FRL–8695–3

Dear Sir: 

The Gasification Technologies Council (GTC) is pleased to provide its comments on 

EPA’s Proposed Rule for Geologic Storage of CO2 (Docket EPA–HQ–OW–2008–0390 

FRL–8695–3) 73 F.R. 43492 (July 25, 2008). 

GTC represents 80 companies involved in the development, licensing, and use of 

gasification technologies. The GTC’s mission is to promote a better understanding of 

how gasification can provide the power, chemical and refining industries with 

economically competitive and environmentally conscious technology options to produce 

electricity, fuels, and chemicals. Our members represent 95% of the world’s gasification 

capacity 

Gasfication is an important technology for the conversion of coal, biomass, petroleum 

coke, municipal solid waste (MSW) and other carbonaceous feedstocks to power, 

chemicals, fertilizers and cleaner fuels. With gasification, CO2 can be captured using 

commercially available technologies. Due to its inherent carbon capture capability, 

gasification can serve a major role in Carbon Capture and Storage (CCS) projects. GTC’s 

interest in EPA’s proposed regulation derives from the importance of CCS to achieving 

future goals of CO2 emissions reduction while using secure and indigenous resources to 

meet our growing national need for chemicals, fertilizers, liquid fuels, hydrogen, and 

electricity. 

EPA is commended for taking this action that begins the process of providing regulatory 

clarity to a complex and important topic. In its decision process, EPA needs to consider 

the importance of CCS to the success of the nation’s overall climate change, energy 

independence and economic growth strategies. Any rule for geologic storage of CO2

needs to provide an unambiguous framework that promotes the development and 

deployment of CCS while protecting the environment. Also, given the current state of 

experience in geologic sequestration, any prescription needs to be flexible and adaptive. 

In addition to regulatory clarity, climate change policy will be needed to define a value 

for CO2 in order to drive deployment of CCS. After policy, cost will determine how 

quickly and widely CCS can be deployed. Currently, the value of CO2 is principally 

limited to its use in Enhanced Oil Recovery (EOR). The cost of CCS needs to be reduced 
Page 2 of 16

by implementing requirements that are necessary and sufficient while not compromising 

the protection of drinking water. 

These are our principal concerns with the draft regulation: 

1. EPA needs to categorically exclude CO2 specifically intended for geologic 

storage from the definition of RCRA hazardous waste. 

2. EPA must emphatically conclude that CO2 containing trace contaminants does 

not open any regulatory pathways to subjecting a geological storage site to 

Superfund liability. 

3. CLASS VI (Underground Injection Control (UIC) permits need to identify the 

potential for hazardous substances that might be generated in geologic 

formations after facility decommissioning and well closure so that should 

releases occur, they would be federally-permitted. 

4. Secondary confinement/containment should not be required. 

5. CO2 injection should not be restricted only to formations below the lowermost 

underground source of drinking water. 

6. EPA needs to clarify how to demonstrate financial responsibility; the 

proposed regulation leaves too much discretion to the Director. 

7. EPA should not adopt a pay-in period of three years. 

8. The period of post-injection site management should be performance-based 

and not be arbitrarily set at 50 years. . 

9. EPA should increase its state stakeholder effort towards uniformity of 

technical requirements; disparate requirements and processes will increase the 

time, cost, and complexity of projects. 

10. EPA should not stigmatize geological storage of CO2 such as can be inferred 

by having requirements for Class VI wells that are more restrictive than for 

Class II wells. 

11. Requirements for conversion of any well to a Class VI well should be site and 

risk dependent. 

12. EPA’s implied 2017 date for completion of the final UIC regulations is too 

late to provide regulatory clarity faced by CCS project developers today. 

These are the details supporting these concerns and recommendations: 

Discussion

#1: Potential Applicability of CFR 40 Part 261 (RCRA). (Ref: page 43503, Section I) 

In the preamble to the ANPR, EPA poses the question of whether injected CO2 might be 

considered a RCRA hazardous waste, but does not answer the question. Any ambiguity 

concerning the applicability of complex and expensive regulatory regimes such as RCRA 

and CERCLA will be a major disincentive to the development and deployment of CCS. 

Regulatory clarity and certainty are critical to companies facing multi-billion dollar 

investment decisions regarding gasification facilities and CO2 sequestration projects. 
Page 3 of 16

EPA should explicitly address these issues in the final rule and not leave open any 

implication that RCRA and CERCLA may or may not apply to CCS. The presence of low 

levels of hazardous contaminants in CO2 as a result of the carbon capture process should 

not limit the storage of the CO2 using Class VI wells, especially taking into account the 

diminimus risk of exposure associated with the disposition of CO2 into deep geological 

formations under the stringent controls required by this proposed regulation. We 

strongly recommend that EPA provide a categorical exclusion in this rulemaking, that 

CO2 streams that are specifically intended to be stored in geologic structures are not 

RCRA hazardous wastes. Such an exclusion would be analogous to the provision of 40 

CFR §261.4(b)(5), which excludes drilling fluids, produced waters, and other wastes 

associated with the development, or production of crude oil, natural gas or geothermal 

energy, and therefore can be injected into Class II wells.

In terms of its approach, we recommend that EPA consider captured CO2 -- inclusive of 

transport, the injection facility and within injection wells -- as material that constitutes a 

stream that is contained within a process and therefore, not a solid waste. Within this 

scope, protection of health and the environment will be provided by controls required 

under other regulatory domains such as OSHA and NESHAPS. 

For purposes of evaluating the potential RCRA status of the captured CO2 that may be 

injected in Class VI wells, the CO2 streams trigger none of the RCRA hazardous waste 

criteria. Specifically, captured CO2 is not a “listed” hazardous waste as set forth in 40 

C.F.R. §261.31 - .35, nor is it “characteristically” hazardous pursuant to 40 C.F.R. § 

261.20 - .24. It is neither “ignitable” nor “corrosive”, and the TCLP test used to 

determine whether a waste is characteristically “toxic” cannot be used on the supercritical 

liquid CO2 stream. In any event, the level of trace contaminants in the CO2 is so low that 

TCLP levels are not even approached when measured on an absolute concentration basis. 

Next, the CO2 stream is not “reactive,” since the injected CO2 stream will not generate 

toxic gases in a quantity sufficient to present a danger to human health or the 

environment. For example, the levels of hydrogen sulfide likely to be present in the CO2

stream (generally less than 0.3%) are an order of magnitude less than those typically 

present in the “acid gas” that is widely injected into Class II underground injection wells 

in the U.S., which have an average hydrogen sulfide concentration of approximately 

40%. See Kleweki (Cadmus Group), Kobelski (U.S. EPA), Karimjee (U.S. EPA), and 

Sham (Cadmus Group): Acid Gas Injection In The United States (Presentation on May 8, 

2006 at the Fifth Annual Conference On Carbon Capture & Sequestration). U.S. EPA 

continues to encourage the underground injection of “acid gas” streams, recently 

including such a requirement in a proposed consent decree that would resolve an 

enforcement case brought under the Clean Air Act. U.S. v. Merit Energy Company, Civil 

Action No. 1:08-CV-917 (W.D. Mich.), proposed Consent Decree lodged on September 

30, 2008 (73 Fed. Reg. 58267 (Oct. 6, 2008) (U.S. EPA’s October 1, 2008 press release 

in this matter stated that the underground injection of the acid gas would result in “zero 

sulfur dioxide emissions.”) 

EPA should take into account the specific disposition of the CO2 that the ruling is 

focused on (i.e., deep underground storage). A well permitted under this rule will be 

protective of underground sources of drinking water. The minimum depth of injection 

required to maintain CO2 in a supercritical state is approximately 2,500 feet. This, in 
Page 4 of 16

conjunction with the controls and safeguards required by this rule throughout the 

injection and post-injection period, will ensure that CO2 injected into a Class VI well 

poses de minimus risk. There is very little likelihood for hazardous constituents to be 

released where they would pose a risk to human health or the environment. (See, e.g., 

Final Risk Assessment for the FutureGen Project Environmental Impact Statement, DOE, 

April, 2007) 

Finally, much higher H2S levels than will be used in CCS have been successfully and 

safely used for EOR injection with Class II wells. For example, in Canada, there are 45 

ongoing projects where high levels (up to 68%) of H2S in CO2 are being injected into 

saline aquifers or producing oilfields1,2,3 for disposal purposes. These combined gas 

streams of H2S and CO2 are commonly referred to as acid gas and originate from 

purification of sour natural gas, are highly toxic and in some cases of high concentration, 

flammable. These projects have been studied in detail and their success is well 

documented3,4. In addition, there have never been any significant safety incidents 

reported, since the start of the first injection of acid gas into a depleted oil reservoir on 

the outskirts of the city of Edmonton, Alberta in the early 1990’s. Nor have there ever 

been any reports of leakage of H2S from these operations4

.

Accordingly, EPA has sufficient information now to conclude that captured CO2 streams 

are not RCRA hazardous wastes and do not pose greater risks that many streams than are 

already being routinely injected in Class II and other UIC wells as non-hazardous wastes. 

Indeed, to conclude otherwise would create the nonsensical result of suggesting that 

sequestering a material in deep geological formations poses more hazards than emitting it 

into the air. It is very important that EPA make this determination as soon as possible to 

remove the implication that CCS might be subject to RCRA regulation, an implication 

that would be extremely damaging to the future of CCS, and to the goal of significantly 

reducing the carbon footprint of the nation’s energy sector. 

Concern #2: Scope of Class VI Permits and the Potential Applicability of Superfund to 

CCS. (Ref: page 43503, Section J) 

EPA raises, but does not answer, the question of whether the underground injection of 

CO2 might trigger Superfund and associated natural resource damages liabilities, and 

appears to suggest that Class VI permits might be written to allow future Superfund 

liability associated with CCS. EPA must emphatically conclude that CO2 containing 

trace contaminants does not open any regulatory pathways for subjecting a geological 

storage site to Superfund liability. As with RCRA, any ambiguity on applicability of 

CERCLA will be potentially fatal to the development and deployment of CCS. It is 

highly unlikely that CCS will be implemented on a meaningful scale if there is a 

possibility that CCS might trigger Superfund. 

CERCLA expressly excludes from Superfund liability “federally permitted releases.” 

Further, “any injection of fluids authorized under the Federal underground injection 

control programs or State programs submitted for Federal approval . . . pursuant to part C 

of the Safe Drinking Water Act” are “federally permitted releases.” 42 U.S.C. § 

9601(10)(G) (CERCLA Section 101(10)(G)). Therefore, any captured CO2 stream that is 

injected in a Class VI well pursuant to a Federal or State permit is a “federally permitted 

release” and not subject to Superfund liability (including natural resource damages). It 
Page 5 of 16

would be inconsistent with existing practice in the UIC program, impractical, and fatal to 

the future of CCS to limit Class VI permits solely to the CO2 portion of the stream and 

explicitly exclude any trace contaminants. 

By its inherent nature, gasification will provide a stream of >90% CO2 having extremely 

low levels of both organic and inorganic hazardous air pollutants (HAPS). There are 

several mechanisms that provide this: 1) destruction of organic HAPS within a gasifier 

due to the extreme (~2,500 oF) gasification temperature, 2) removal of inorganic content 

in the melting and slagging process, 3) particulate scrubbing or filtration, 4) activated 

carbon beds to remove mercury and other condensed metals;, and finally 5) cooling 

followed by acid gas scrubbing. The combination of these HAP reductions is very 

effective. As a point of reference, the total inorganic HAPS that would be injected with 

captured CO2 from an IGCC or gasification process over 30 years of CCS operation will 

be at least an order-of-magnitude lower than the annual limits (both total and individual 

components) of NSPS. 

Concern #3: Potential releases from the well which are outside the scope of the Class VI 

permit. (Ref: page 43504, Section J)

Class VI UIC permits must also be carefully written to identify and address the potential 

post-injection releases of hazardous substances, or the generation of hazardous 

substances from the chemical interaction of the CO2 with the geological storage 

formation (e.g. – leaching of metals) so that they would be federally permitted releases. 

If the potential release or generation of such hazardous substances is viewed as beyond 

the scope of Class VI permits, CCS sites could be subjected to the threat of long—term 

Superfund liability, a threat that could be fatal to the viability of CCS. 

With respect to releases from the well itself, the primary source of such releases could 

occur during injection operation through failure of well seals, flanges and gaskets, piping 

breaches, liners, valve packing and other mechanical components or failure to follow 

operational and safety procedures. Such releases will likely be confined to the injection 

period. During operation and the measurement, monitoring, and validation (MMV) 

period, the injection facility (metering, distribution and injection systems), should be 

classified as a production facility where industrial safety standards, design and operating 

procedures (e.g., – HAZOPS reviews) will apply. Appropriate regulation will be derived 

from permits under the Clean Air Act that are issued to the facility along with protection 

of operating personal as required by OSHA. 

Concern #4: Requirement for secondary confinement/containment. (Ref: page 43505, 1- 

Proposed Geologic Siting Requirements)

The proposal would provide the Director the discretion to require the owner or operator 

to identify and characterize additional confining and containment zones above the 

primary (i.e., lowermost) confining zone that could further impede vertical fluid 

movement and allow for pressure and dissipation. Secondary containment (multiple 

confining structures) should not be required to prevent leakage of CO2. If required, this 

will prevent geologic storage in certain but important geographic regions. It also raises 

doubt concerning procedures and protocols to characterize and validate safe geologic 

storage formations and containment where there is not secondary containment. Under the 
Page 6 of 16

proposed rule, there are measures that provide adequate assurance of formation integrity 

and require operators to demonstrate that their project will not endanger underground 

sources of drinking water (USDWs). If a secondary containment is present, it will be 

detected during site characterization and risk assessment. Such a special case could be 

analyzed to evaluate the potential risks to USDWs and to develop additional evaluation 

criteria to be applied to permit geological storage without going through the aquifer 

exemption process. 

Concern #5: Restriction of injection to formations below the lowermost underground 

source of drinking water or USDW. (Ref: page 43512, 3. Proposed Injection Well 

Construction Requirements) 

This requirement is not necessary for the protection of USDWs. It is in-fact overly 

restrictive and will eliminate many suitable and safe geologic formations for CO2

sequestration or permanent storage. It will also render geological storage impractical 

(pumping power and well costs) for states in the western United States where the 

drinking water aquifers are many thousands of feet deep and well isolated from overlying 

regions. Also, industry has demonstrated that it can operate CO2 injection wells for EOR 

without endangering USDWs that are located below the injection zone (e.g., the Salt 

Creek EOR project in Wyoming, having a USDW below the injection zone). 

Concern #6 Demonstration of financial responsibility. (Ref: page 43520, 9. Proposed 

Financial Responsibility and Long-Term Care Requirements) 

EPA needs to provide clarifying guidance on how to demonstrate financial responsibility. 

The proposed regulation leaves too much to the discretion of the Director. Such openended requirements will effectively discourage carbon capture projects and the 

development of financial pro formas. Of particular concern are those assurances 

necessary to cover the costs of potential long-term stewardship or the potential to have to 

perform remediation at sites that have been previously certified as closed. This 

uncertainty may increase the perceived risk exposure to levels that serve as a barrier to 

investment. A potential approach to share risk and overcome this barrier is the Interstate 

Oil and Gas Compact Commission (IOGCC)5 proposal for an industry-funded and stateadministered trust fund to provide the stewardship during the Post-Closure Period. The 

trust would be funded through an injection fee assessed to the site operator and calculated 

on a per-ton basis, at the point of custody transfer of the CO2 from the generator to the 

site operator. 

Concern #7. EPA is considering a guidance approach that would recommend adopting a 

pay in period of three years for GS projects, consistent with other similar programs in the 

Agency. (Ref: page 43521, Sec. 9. Proposed Financial Responsibility and Long-Term 

Care Requirements, Pay-in period for trust funds)

We strongly urge that the EPA not adopt this approach. CCS projects will be subject to 

their highest financial strain in the first several years of operation. During this period, 

commissioning, systems integration and debugging of mechanical and process systems 

will need to be completed with potential loss of plant operation, production and revenue. 

Projects will likely be burdened with additional initial capital coverage of an already 
Page 7 of 16

expensive facility to contend with an accelerated payment. We therefore recommend that 

any payment schedule be based on a per-ton fee over an amortization period equal to the 

expected operational life of the project and in a framework as recommended by the 

IOGCC (ref: Concern #6). 

Concern #8: The owner or operator shall continue to conduct monitoring as specified in 

the Director-approved post-injection site care and site closure plan for at least 50 years 

following the cessation of injection. At the Director’s discretion, the monitoring will 

continue until the geologic sequestration project no longer poses an endangerment to 

USDWs. (Ref: page 43519, Sec. 8. Post-Injection Site Care Timeframe)

The time required for post-injection site management should not be arbitrarily set at 50 

years. Criteria for defining the time for post-injection management should be 

performance based and site specific. The choice of 50 years is arbitrary and does not take 

into account the data and knowledge and modeling verification obtained over a preceding 

operating and injection period of years and likely decades. The maximum post-injection 

monitoring period should be defined on reasonable but quantitative, performance-based 

metrics - for example, that the validated model predicts that 95% of the plume is or will 

be trapped and that a sensitivity analysis predicts a comfortable margin of safety to 

minimize approach to any USDWs, thus preventing potential endangerment. 

Concern #9: On-going state efforts to regulate GS. (Ref: page 43497, Sec. C. Who 

Implements the UIC Program?) 

Although we recognize that state primacy is integral to the UIC program, we strongly 

recommend that EPA drive its state stakeholder activities towards the goal of unanimity 

and uniformity of technical requirements. Disparate requirements and processes will 

increase cost, delay, and complexity and make the permitting process less predictable. 

Individual states should not develop regulations that are substantially more restrictive or 

prescriptive than that required by the EPA. Many states will also not have technical 

resources that are comparable to that of the US EPA. EPA’s stakeholder technical 

workshops had good representation from the EPA regions, but it appears that many states 

have not yet been engaged. To avoid this and the problems from a patchwork of 

permitting regulations, EPA should carefully but quickly consider and integrate input 

from a majority of state environmental protection and conservation and natural resource 

offices. 

Concern #10: Continuation of Class II for EOR. (Ref: page 43502, Sec. G)

By proposing different and more restrictive requirements for Class VI wells, EPA will 

create economic or operational barriers that prevent a seamless transition from EOR and 

storage operations to wholly storage operations. EOR can make a significant contribution 

to offset the cost of early CCS demonstration projects. For example, EOR can contribute 

to the investment in pipeline infrastructure helping to enable pure CCS operations. Also, 

CO2 storage operations may continue after EOR has ceased, thus reducing the cost of 

storage, site characterization and development. These benefits should be viewed as 

especially significant in light of the difficulties in securing sufficient funds to initially 

deploy CCS. EOR projects could quite feasibly bring CCS deployment forward by many 
Page 8 of 16

years as a considerable quantity of CO2 remains underground during such operations. 

This will reduce the number of target formations where CO2 could be stored. 

Concern #11: Grandfathering of construction requirements at the Director’s discretion for 

existing Class I, Class II, and Class V wells seeking to convert to Class VI wells, and 

whether additional construction requirements would be necessary to prevent 

endangerment to USDWs from the GS of CO2. (Ref: page 43497, Sec. G)

Requirements for conversion of any well to a Class VI well should be site and risk 

dependent. EPA should consider expanding grandfathering scope to more than 

construction requirements and not a-priori require that all other permitting requirements 

be redone. Existing permit holders should be allowed to provide data on the experience 

and characteristics of their site demonstrating that it is suitable for long-term storage of 

carbon dioxide without endangering underground sources of drinking water. This could 

be more acceptable with an end date for grandfathering wells (e.g., - operational before 

2012). 

Concern #12: EPA’s schedule for promulgation of its proposed UIC regulation. (Page 

43499 Sec. E3) 

We reference the following statement from the preamble section of the proposed rule: 

"During the Deployment Phase (2008–2017), the [RCSP] partnerships will conduct large 

volume carbon storage tests to demonstrate that large-scale CO2 injection and storage can 

be achieved safely and economically. EPA will use the data collected from these projects 

to support decisions in the final GS rule." This statement suggests that a final GS rule 

may not be issued until 2017. We believe that this is too late to clear the regulatory 

uncertainty that CCS project developers are facing today. If this reflects EPA’s intention, 

we recommend that EPA abandon a prescriptive approach and instead, favor general and 

performance-based requirements until these demonstration tests are completed. 

Other concerns expressed by our membership and recommendations for improvement of 

the proposed rulemaking are given in Appendix A. Should the EPA have further 

questions, please fell free to contact me. 

Very truly yours, 

James Childress 

Executive Director 

Gasification Technologies Council 
Page 9 of 16

References

1 Keushnig, H. (1995); Hydrogen sulfide – if you don’t like it, put it back. J. Canadian 

Petroleum Technology. 34: 18-20. 

2

 Longworth, H.L., G.C. Dunn, M. Semchuck (1996); Underground disposal of acid gas 

in Alberta, Canada: Regulatory concerns and case histories. SPE 35584. pg 181-192. 

3

 Bachu, S., K. Haug (2005) In situ characteristics of acid-gas injection operations in the 

Alberta Basin, Western Canada: Demonstration of CO2 geological storage. in Carbon 

Dioxide for Storage in Deep Geological Formations. Vol. 3. ed. D.C. Thomas, S.M. 

Benson. Elsevier Ltd. pg 867-876. 

4

 Bachu, S., W.D. Gunter; Overview of Acid-Gas Injection Operations in Western 

Canada. In Proceedings of 7th International Conference on Greenhouse Gas Control 

Technologies. Volume 1: Peer-Reviewed Papers and Plenary Presentations (E.S. Rubin, 

D.W. Keith and C.F. Gilboy, ed.), IEA Greenhouse Gas Programme, Cheltenham, UK, 

2005. 

5 The Interstate Oil and Gas Compact Commission Task Force on Carbon Capture and 

Geologic Storage, Storage of Carbon Dioxide in Geologic Structures - A Legal and 

Regulatory Guide for States and Provinces, September 25, 2007
Page 10 of 16

APPENDIX A 

Additional Comments and Recommendations

§146.81 Applicability. (b) “This subpart applies to wells used to inject carbon dioxide specifically for the 

sequestration, i.e., the long-term containment of a gaseous, liquid or supercritical carbon dioxide stream i

formations.” 

We recommend striking out "gaseous, liquid or supercritical carbon dioxide stream" and replacing with "gaseouor co-mixed carbon dioxide stream" This change will allow for injection of carbon dioxide that is pre-dissolved 

phase separation in the injection zone or with inclusion of flow or pumping enhancement components. 

§146.82 Required Class VI permit information. (b) “A map showing the injection well(s) for which a perm

applicable area of review. Within the area of review, the map must show the number, or name and location producing wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, State or EPA cleanup sites, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells and o

features including structures intended for human occupancy and roads. The map should also show faults, if Only information of public record is required to be included on this map;” 

The note that "only information of public record is required to be included on this map" may leave out departicularly older wells. The presence of such non-public but "known" information may be eligible for inclus144.55(a). §146.82 Required Class VI permit information (e) “A tabulation of all wells within the area of review which pen

confining zone(s). Such data must include a description of each well's type, construction, date drilled, locaplugging and/or completion, and any additional information the Director may require;” 

We recommend striking out "all wells" and replacing with "all known wells". Requiring that all wells or other into injection or confining zones within the AoR be identified and information on depth and closure be provi

sometimes accurate information is difficult to obtain for older wells within the AoR. EPA's assistance in obta

information would be helpful to CCS operators. 
Page 11 of 16

§146.84 Area of review and corrective action. (c) (1) “Predict, using computational modeling, the projecte

migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injecplume movement ceases, pressure differentials sufficient to cause the movement of injected fluids or formatioare no longer present, or after a fixed time period as determined by the Director.” 

We recommend striking out "Predict, using computational modeling, the projected lateral and vertical migration plume" and replacing with "Using computational modeling, provide projected potential ranges of lateral and vecarbon dioxide plume" The use of multiphase groundwater flow and transport models is to predict the composi

each phase state (e.g., liquid, gas ,supercritical fluid) of CO2 in the subsurface, as well as fluid pressures, to defin

concerns with the use of such complex models is that the site may not be fully characterized with respect to hydr

There may be significant uncertainty in one or more hydraulic processes/parameters. Therefore, it is possible to o

model outcomes from different model parameters. The uncertainty in model parameters and sensitivity of modselection should be addressed. §146.84 Area of review and corrective action. (c) (2) “Using methods approved by the Director, identify all p

active and abandoned wells and underground mines, in the area of review that may penetrate the confi

description of each well’s type, construction, date drilled, location, depth, record of plugging and/or completio

information the Director may require; and...” 

We recommend striking out "approved" and replacing with "prescribed". We recommend deleting the second swith "Where such information is available or can be obtained, provide a description of each well’s type, conlocation, depth, record of plugging and/or completion, and any additional information prescribed by the directomethods for identifying deep wells into confining zones within the AoR should be prescribed by the EPA as Accurate information is difficult to obtain for older wells within the AoR. Examples of other information that coDirector should be clearly stated. §146.86 Injection well construction requirements. (b) (2) “Surface casing must extend through the base of the 

be cemented to the surface.” 

We recommend striking out this requirement in its entirety. This will be prohibitively expensive in deep wnecessary at all sites. 
Page 12 of 16

§146.90 Testing and monitoring requirements. (d) Periodic monitoring of the ground water quality and geoch

the confining zone(s) that may be a result of carbon dioxide movement through the confining zone or additiona

We recommend changing to “ Periodic monitoring of the ground water quality and geochemical changes bzone(s) and the USDW that may be a result of carbon dioxide movement through the confining zone or additi“This rewording is consistent with allowing for injection either above or below USDWs §146.90 Testing and monitoring requirements. (g) “Testing and monitoring to track the extent of the carbon d

position of the pressure front by either monitoring for pressure changes in the first formation overlying the co

indirect, geophysical techniques (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down

detection tools);”

We recommend deletion of this requirement in its entirety and replacing with “Testing and monitoring to t

carbon dioxide plume.” Tracking the precise position of a moving pressure front will require a large number of located probes. A limited number of pressure monitors that can provide information on pressures affecting the cmore valuable. The Proposed Rule also requires well owners to monitor periodically groundwater quality and above the confining zone. The requirements for such deep monitor wells could be costly. Requiring both presmonitoring will be costly and provide questionable additional information or warning. §146.90 Testing and monitoring requirements. (h) “At the Director’s discretion, surface air monitoring and/or 

detect movement of carbon dioxide that could endanger a USDW.” 

We recommend deletion of this requirement in its entirety. While this requirement may be suitable for detleakage relevant to monitoring of CO2 in a greenhouse gas policy context, this requirement does not provide any 

to migration to USDW as surface breakthrough will only occur well after the deep-surface migration of CO2 

monitoring to detect CO2 has high uncertainty and seasonal variability that is likely to result in many false pos

distractions. Seismic methods of tracking the CO2 plume are more effective than soil gas monitoring of CO2

many other factors and thus is highly variable. 
Page 13 of 16

§146.93 Post-injection site care and site closure (b)(3) “Prior to authorization for site closure, the owner or op

the Director a demonstration, based on monitoring and other site-specific data, that the carbon dioxide plum

have stabilized and that no additional monitoring is needed to assure that the geologic sequestration projendangerment to USDWs.” 

Clarification of the term "stabilized" is needed. We recommend that the term "stabilized" does not necessarily pressure front are no longer moving, but that the rate and direction as defined by confinement zones no longer pLong-term monitoring should have an "end point" defined. Often termed an "exit strategy", this is a key point tall parties about what is a "stable condition". Monitoring data includes a prescribed amount of error , thus stati

may be required to define a "stable condition". EPA seeks comment on allowing the use of proprietary models for GS sites. EPA Notice 68. 

Proprietary models should be acceptable provided that supporting data for validation are submitted. EPA seeks comment on the applicability of computational fluid flow models for delineating the AoR of GS sites. Computational fluid flow models should be permitted for delineating the AoR of GS sites provided also tsupporting their validation in similar complex structures and flow regimes EPA seeks comment on requiring the reevaluation of the site AoR on a periodic basis, under what conditio

reevaluated, and the appropriateness of a 10-year minimum fixed frequency for AoR reevaluation. EPA Notice 

10 years is a reasonable period of time to reevaluate the site AoR during injection. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of lo

construction with a packer set opposite a cemented interval. EPA Notice 78.. 

The requirements for construction of the proposed Class VI CO2 injection wells should be similar to the Class IThis will expedite the transition of EOR projects to CCS projects. This requirement also unnecessarily stigmatize
Page 14 of 16

EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability 

requirements discussed in this proposal. EPA Notice 80. 

Horizontal wells should be permitted for injection of CO2. The use of horizontal wells may minimize the numbe

injection. A reduced number of wells will reduce both cost and may also reduce potential leakage paths. EPA is requesting comment on the extent and scope to which hydraulic fracturing should be allowed during GS the use of fracturing for the purposes of well stimulation is appropriate. EPA Notice 85. 

Fracturing of GS formations should be permitted, provided confining structures are not negatively impacted anto the injection zone. Exclusion of fracturing of storage formations would often require unnecessary drilling o

The oil industry has sufficient experience in using fracturing technology to avoid negatively impacting confcaprock). EPA seeks comment on whether the Agency should set a minimum injection depth requirement for CO2 GS, ra

such injection take place below the lowermost USDW. EPA Notice 93. 

EPA should neither require injection below the lowermost USDW nor alternately require a minimum depth restructures are likely to be encountered that provide for secure and safe storage. Examples of such storage that are domes and caverns. EPA’s proposal allows Directors’ discretion on whether to require the use of tracers, and if so, what types 

comment on the use of tracers in CO2 GS operations, and any potential impact of tracers on human health 

relate to USDWs. EPA Notice 95. 

Tracers should be permitted, but not required. They are commonly and safely used in the oil and gas industry. EPA seeks comment on the appropriate amount and types of monitoring that should be conducted at a GS site. S

comment regarding the usefulness of indirect geophysical monitoring and surface air and soil gas monitoring. Icomment regarding the use of a Director-approved monitoring plan for GS sites. EPA Notice 111 
Page 15 of 16

Surface air and soil gas monitoring are not useful. Seismic methods of tracking the CO2 plume are more e

monitoring of CO2, which is affected by many other factors and thus is highly variable. Surface breakthrough re

fact” event. While this requirement may be suitable for determining potential air CO2 leakage relevant to monito

context, this requirement does not provide any additional protection to migration to USDW as surface CO2 b

occur well after the deep-surface migration of CO2 to a USDW. Surface monitoring to detect CO2 has high unvariability that is likely to result in many false positives, operational distractions and unduly raise public concernEPA is proposing that permit applications for GS sites include several plans not currently required under exisThese plans include a monitoring and testing plan, an AoR and corrective action plan, and a post-injection site plan. EPA seeks comment on the merits of requiring plans for monitoring, AoR, and post-injection site carapplication. EPA Notice 112. We believe that requiring a monitoring plan is reasonable. However, the EPA should develop such requirements distinct end to operations and monitoring following closure, and consider specific representations and codicils th

“in-perpetuity” responsibility for the operator or owner. EPA seeks comment on the requirement for electronic reporting in its proposed rule. EPA Notice 115. 

We recommend that EPA allow electronic reporting as an alternative to hardcopy submittals. The benefits reduced cost and burden of paperwork, ease of document retrieval, public access, search and storage. Although EPA has not included a requirement for this report in its proposal, EPA seeks comment regarding the annual report. EPA Notice 115. While reports on status are worthwhile, activity and changes in status are not going to be significant on an ann

report after the first year of operation to ensure that requirements for later reporting are being met, once every 10 the periods for AoR review should be adequate. In addition, EPA seeks comment on whether the Director should be allowed to shorten the timeframe binformation, and whether EPA should require a shorter or longer post injection period if data suggests the adjusted. EPA Notice 125-26. 
Page 16 of 16

EPA should allow the Director to shorten the timeframe based on performance information. However, an op

results in a high degree of uncertainty regarding cost exposure to a project developer. It also leaves a site open t

"reopeners" by the regulatory community. To avoid this latter scenario, a maximum monitoring period should clear, performance-based risk metrics - for example, that the validated model predicts that 95% of the plume is 

that a sensitivity analysis predicts a comfortable margin of safety and diminimus risk of endangerment to any USCurrent UIC regulations for Class I hazardous waste injection allow for the use of insurance for purposes of de

responsibility. However, insurance was not included as part of the guidance provided for Class II injection bmechanism was and still is, rarely used for the purpose of demonstrating financial assurance for injection w

whether to provide guidance on the use of insurance providers and, if so, whether to update eligibility require

GS wells consistent with other current Federal agency practices. EPA Notice 131. 

The role of insurance needs to be defined and especially, what is being insured and for what events and risks

being limited to insurance related to decommissioning, plugging of wells and closure of the site. Such costs an

may change as additional wells are needed or the scope of the AoR changes. Absent of Federal or state assliability, and regulatory clarity on the inapplicability of CERCLA, and events and their mitigation, it will be d

provide coverage for any more than a limited scope. EPA is assessing whether a financial ratings threshold for all companies using a self-guarantee, similar to 

Federal agencies, is appropriate. The Agency also is considering what constitutes an appropriate financial whether a financial rating greater than BBB or Baa (i.e., the current rating threshold established under th

appropriate for GS wells. EPA Notice 133. 

Allowing for self-insurance definitely will be helpful to provide another avenue for CCS projects to be deploye

experienced in the recent economic crisis, there are no guarantees of financial continuity for either insurers or othEPA is requesting comments on whether financial responsibility mechanisms to be recommended in EPA guidanin the manner described, whether additional instruments should be included, and whether other adjustmresponsibility mechanisms should be considered, all subject to EPA’s authority under the SDWA. EPA Notice 1

EPA needs to consider and define how it will deal with and allow transfer of financial responsibility between pr

potentially to Federal agencies or other sovereign entities such as states or commonwealths.
Letter ID: 0210 

Commenter: Richard Guinn 

Organization: Eastman Chemical Company 

Letter ID: 0210 Comment ID: 22690 Letter Lines: 46 to 50 ; 71 to 79 

Comment Code: 1330 1.1.3.1 Support use of GS in general 

Comment: warming. With Eastman’s long-term commitment to gasification technology the 

company has a vested interest in the geologic storage of CO2 that is important 

for the continued viability of gasification facilities. Eastman Chemical Company 

supports the following comments on the proposed rule generated by the 

Gasification Technologies Council. 

Gasfication is an important technology for the conversion of coal, biomass, 

petroleum coke, municipal solid waste (MSW) and other carbonaceous feedstocks to 

power, chemicals, fertilizers and cleaner fuels. With gasification, CO2 can be 

captured using commercially available technologies. Due to its inherent carbon 

capture capability, gasification can serve a major role in Carbon Capture and 

Storage (CCS) projects. GTC’s interest in EPA’s proposed regulation derives from 

the importance of CCS to achieving future goals of CO2 emissions reduction while 

using secure and indigenous resources to meet our growing national need for 

chemicals, fertilizers, liquid fuels, hydrogen, and electricity. 

Individual Response: EPA clarifies that GHG emissions reductions and the use of integrated 

gasification combined cycle technologies are outside the scope of the UIC GS rulemaking. The 

purpose of the GS rule is to ensure that, where GS is deployed, the projects are permitted sited, 

constructed, operated, and closed in a manner that protects USDWs from endangerment. The 

requirements apply to owners or operators of injection wells used to inject CO2 for long-term 

storage. 

Please see the remainder of EPA’s responses to this comment 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: 0210 Comment ID: 22691 Letter Lines: 74 to 94 

Comment Code: 1250 1.1.1.4 Flexibility is needed (performance-based standards) 

Comment: captured using commercially available technologies. Due to its inherent carbon 

capture capability, gasification can serve a major role in Carbon Capture and 

Storage (CCS) projects. GTC’s interest in EPA’s proposed regulation derives from 

the importance of CCS to achieving future goals of CO2 emissions reduction while 

using secure and indigenous resources to meet our growing national need for 

chemicals, fertilizers, liquid fuels, hydrogen, and electricity. 

1
EPA is commended for taking this action that begins the process of providing 

regulatory clarity to a complex and important topic. In its decision process, 

EPA needs to consider the importance of CCS to the success of the nation’s 

overall climate change, energy independence and economic growth strategies. Any 

rule for geologic storage of CO2 needs to provide an unambiguous framework that 

promotes the development and deployment of CCS while protecting the environment. 

Also, given the current state of experience in geologic sequestration, any 

prescription needs to be flexible and adaptive. In addition to regulatory 

clarity, climate change policy will be needed to define a value for CO2 in order 

to drive deployment of CCS. After policy, cost will determine how quickly and 

widely CCS can be deployed. Currently, the value of CO2 is principally limited 

to its use in Enhanced Oil Recovery (EOR). The cost of CCS needs to be reduced 

by implementing requirements that are necessary and sufficient while not 

compromising the protection of drinking water. 

Individual Response: EPA clarifies that the Class VI GS requirements are designed to ensure 

that, where deployed, GS is conducted in a manner that protects USDWs from endangerment. 

The requirements apply to owners or operators of injection wells used to inject CO2 for 

permanent storage, and do not apply to generators of CO2. Encouraging investment in CCS 

projects, addressing climate change, and setting a price for carbon are outside the scope of the 

GS rulemaking. 

See the remainder of EPA's responses to this comment and the final rule and preamble for 

additional information on EPA's regulatory approach. 

Letter ID: 0210 Comment ID: 22692 Letter Lines: 98 to 99 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment: 1. EPA needs to categorically exclude CO2 specifically intended for geologic 

storage from the definition of RCRA hazardous waste. 

Individual Response: EPA received many comments regarding the applicability of the RCRA 

regulations and statute to CO2 streams that are geologically sequestered under the final Class VI 

UIC well requirements. As a result, EPA has decided to initiate a separate proposed rulemaking 

specifically to examine the issue of RCRA applicability to CO2 streams being geologically 

sequestered, including the possible option of a conditional exemption from the RCRA 

requirements for CO2 GS in Class VI wells. EPA will consider these comments as part of its 

development of that proposal. The Agency will consider issues particular to RCRA in the context 

of that separate rulemaking, and recommends that the commenter read that proposed rule when it 

is published. The Agency notes that commenters who wish to submit comments on the RCRA 

proposal will need to do so during the comment period for that rule. Finally, EPA also notes that 

the final GS rule, which adds new regulations for Class VI wells under the Safe Drinking Water 

Act (SDWA), is not making any changes to the RCRA regulations. 

2
EPA clarifies that the GS rule requires owner or operators of Class VI wells to characterize their 

injection stream prior to injection, and throughout the operational life of the injection facility. 

Since the GS rule, at §146.81(d), prohibits CO2 streams that meet the definition of a hazardous 

waste under 40 CFR part 261, owners or operators will need to characterize their CO2 stream as 

part of their permit application to determine if the injectate is a RCRA hazardous waste. If so, 

injection may only occur in a Class I hazardous waste injection well. 

Letter ID: 0210 Comment ID: 22693 Letter Lines: 101 to 103 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: 2. EPA must emphatically conclude that CO2 containing trace contaminants does 

not open any regulatory pathways to subjecting a geological storage site to 

Superfund liability. 

Individual Response: CO2 itself is not listed as a hazardous substance under CERCLA 

however, the CO2 stream may contain a listed hazardous substance (such as mercury) or may 

mobilize substances in the subsurface that could react with ground water to produce listed 

hazardous substances (such as sulfuric acid). Whether such substances may result in CERCLA 

liability from a sequestration facility depends entirely on the composition of the specific CO2 

stream and the environmental media in which it is stored (e.g., soil or ground water). CERCLA 

exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain “federally permitted 

releases” (FPR) as defined in CERCLA, 42 U.S.C. 9601(10). Class VI permits will need to be 

carefully structured to ensure that they prevent potential releases from the well which are outside 

the scope of the Class VI permit. 

EPA clarifies that, while the Administrator reserves the right to promulgate regulations 

designating additional substances as hazardous under §102 of CERCLA, EPA intends to avoid 

any potential overlap of SDWA and CERCLA authority through its comprehensive Class VI 

requirements. 

Letter ID: 0210 Comment ID: 22694 Letter Lines: 105 to 108 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: 3. CLASS VI (Underground Injection Control (UIC) permits need to identify the 

potential for hazardous substances that might be generated in geologic 

formations after facility decommissioning and well closure so that should 

releases occur, they would be federally-permitted. 

Individual Response: As described above, CERCLA exempts from liability, under CERCLA 

section 107, 42 U.S.C. 9607, certain “federally permitted releases” (FPR) as defined in 

CERCLA, 42 U.S.C. 9601(10). Class VI permits will need to be carefully structured to ensure 

that they prevent potential releases from the well which are outside the scope of the Class VI 

3
permit. 

Regarding long term liability, once an owner or operator has met all regulatory requirements 

under Part 146 for Class VI wells and the Director has approved site closure pursuant to 

requirements at §146.93, the owner or operator will generally no longer be subject to 

enforcement for regulatory noncompliance. Furthermore, their financial instrument as required 

under §146.85 will be released if it was not used. However, even if a site closure is approved 

under §146.93, an owner or operator may be held liable for regulatory noncompliance (including 

violation of 40 CFR 144.12) in certain circumstances. For example, an owner or operator may be 

held liable for regulatory noncompliance even after site closure was approved if the Director 

relied on erroneous information (e.g., erroneous modeling data) provided by the owner or 

operator when approving site closure. 

Separate from EPA’s authority to enforce regulatory compliance, an owner or operator may be 

subject to a §1431 response order even after proper site closure is approved under §146.93. 

Under §1431 the Administrator may require an owner or operator to take necessary response 

measures if he or she receives information that a contaminant is present or is likely to enter a 

public water system or an USDW, which may present an imminent and substantial endangerment 

to the health of persons, and the appropriate State and local authorities have not acted to protect 

the health of such persons. The action may include issuing administrative orders or commencing 

a civil action for appropriate relief against the owner or operator of a Class VI well. If the owner 

or operator fails to comply with the order, they may be subject to a civil penalty for each day in 

which such violation occurs or failure to comply continues. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

§§7401-7671; CERCLA, 42 U.S.C. §9601-9675; and RCRA, 42 U.S.C. §6901-6992. EPA does 

not have authority to transfer SDWA or other legal liability for Class VI wells to the State or 

federal government or a third-party fund. See the final rule preamble for further discussion of 

EPA's final approach. 

Letter ID: 0210 Comment ID: 22695 Letter Lines: 110 to 110 

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones 

(seeking comment) 

Comment: 4. Secondary confinement/containment should not be required. 

Individual Response: EPA retains the requirement to identify additional containment/confining 

zones, if required by the Director, as proposed (e.g., §146.83(b)). The Agency's decision is 

supported by commenters representing states, water associations, and an electric utility who 

assert that these requirements (at §146.83(b)) promote a flexible, risk-based, site-specific 

approach to characterizing and permitting a site for GS projects. 

The Agency believes that providing the Director discretion will allow consideration of a range of 

sites for GS, based on site-specific conditions and ensure USDW protection. EPA believes that 

4
requiring appropriate site characterization by the owner or operator (under §146.82) and 

providing an appropriate degree of flexibility to the Director to evaluate site-specific geologic 

data will afford the greatest protection of USDWs from endangerment. 

Letter ID: 0210 Comment ID: 22696 Letter Lines: 112 to 113 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: 5. CO2 injection should not be restricted only to formations below the lowermost 

underground source of drinking water. 

Individual Response: EPA acknowledges that there are limited circumstances where injection 

above the lowermost USDW can be performed in a manner that protects USDWs from 

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 

establishes a process by which owners or operators can seek a waiver of the Class VI injection 

depth requirements for injection into non-USDW formations above and/or between USDWs. 

Letter ID: 0210 Comment ID: 22697 Letter Lines: 115 to 116 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: 6. EPA needs to clarify how to demonstrate financial responsibility; the 

proposed regulation leaves too much discretion to the Director. 

Individual Response: EPA has clarified the financial responsibility requirements in the final GS 

rule, and has included at §146.85(a) a list of qualifying financial responsibility instruments, 

including trust funds, surety bonds, letters of credit, insurance, self insurance, escrow accounts, 

or any other instrument(s) satisfactory to the Director. Owners or operators have the flexibility to 

choose from a variety of financial instruments to meet their financial responsibility obligations. 

Owners or operators may use one or multiple financial responsibility instruments for well 

plugging and PISC (§146.85(a)(6)). However EPA will not allow for a separate financial 

responsibility demonstration for well plugging and PISC (i.e., a demonstration submitted prior to 

well plugging and the beginning of the post-injection site care period rather than with the permit 

application). A demonstration of financial responsibility for all phases of the GS project will be 

required prior to the issuance of a Class VI permit (§146.85(a)(5)(i)). 

See the final rule and preamble for further discussion of EPA's final approach to financial 

responsibility. EPA is also developing guidance on financial responsibility for Class VI wells 

that will provide information about the appropriateness of various financial instruments. This 

guidance is available on EPA's website at 

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

5
Letter ID: 0210 Comment ID: 22698 Letter Lines: 118 to 118 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: 7. EPA should not adopt a pay-in period of three years. 

Individual Response: EPA acknowledges that there may be several possible approaches to 

setting pay-in periods for trust funds. The final rule requires that the Director approve the use 

and length of pay-in periods. EPA is developing guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) that describes the types of 

financial instruments that owners or operators can use to meet financial responsibility 

requirements for GS wells. Specifically, the guidance will discuss pay-in periods and provide 

guidance for Directors to use in determining an appropriate pay-in period. EPA adds that owners 

or operators may choose from a variety of financial instruments to meet their financial 

responsibility needs. 

Letter ID: 0210 Comment ID: 22699 Letter Lines: 120 to 121 

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

Comment: 8. The period of post-injection site management should be performance-based and 

not be arbitrarily set at 50 years. 

Individual Response: EPA agrees with commenters that there will be circumstances where it 

can be demonstrated in less than 50 years that the plume and pressure front no longer pose a risk 

of endangerment to USDWs. 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 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 

6
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 disagrees that the post-injection site care timeframe of 50 years in the final rule is excessive 

in most cases or arbitrary. In determining the post-injection site care-timeframe for the proposed 

regulation, EPA reviewed industry reports, existing environmental programs, and initial GS 

research studies. EPA provided a synthesis of pertinent results from GS modeling studies in the 

preamble to the proposed regulation. Further explanation of this analysis was included in an 

EPA-prepared background document that is available in the federal docket, titled 

"Computational Modeling of Underground Injection of Carbon Dioxide for Determination of 

Area-of-Review and Potential Risk to Underground Sources of Drinking Water." Based on 

review of these studies, modeling results indicate that the CO2 plume stabilization may occur on 

the timeframe of 10-100 years after the cessation of injection. EPA believes that a 50-year 

default post-injection site care timeframe is a reasonable midpoint for most GS projects and 

available data, including data submitted by commenters, do not support a different default 

timeframe, and has retained this in the final regulation. 

Letter ID: 0210 Comment ID: 22700 Letter Lines: 123 to 125 

Comment Code: 1930 1.4.4.2 Consultations with State, Tribal, and local Associations (e.g., 

GWPC, IOGCC) 

Comment: 9. EPA should increase its state stakeholder effort towards uniformity of 

technical requirements; disparate requirements and processes will increase the 

time, cost, and complexity of projects. 

Individual Response: EPA will continue to consult with a variety of stakeholders, including the 

National Drinking Water Advisory Council, associations and organizations, ORD, and experts; 

review permits; and continue to hold workshops to build expertise and ensure that that 

implementation of the national program is based on the best available science. The Agency plans 

to collect and review data every six years on GS projects to determine whether the appropriate 

amount and types of information and appropriate documentation are being collected, and to 

determine if modifications to the requirements are appropriate or necessary. 

The GS rule provides flexibility to determine the suitability of a proposed site based on 

extensive, site-specific data. EPA believes that requiring appropriate site characterization by the 

owner or operator and providing an appropriate degree of flexibility to the Director to evaluate 

site-specific geologic data will afford the greatest protection of USDWs. The issuance of a UIC 

Class VI permit is determined based on evaluation of site-specific permit information pursuant to 

the requirements at §§146.82 and 146.83. 

Letter ID: 0210 Comment ID: 22701 Letter Lines: 127 to 129 

7
Comment Code: 1680 1.3.8 Don't overstate risk, don't stigmatize CO2 

Comment: 10. EPA should not stigmatize geological storage of CO2 such as can be inferred 

by having requirements for Class VI wells that are more restrictive than for 

Class II wells. 

Individual Response: EPA disagrees that the requirements in the GS regulation will stigmatize 

GS. EPA recognizes that injecting large volumes of CO2 for GS poses unique challenges that, if 

not properly managed, could endanger drinking water sources and have other adverse impacts. 

However, with proper site selection, the final, tailored, Class VI requirements address the large 

volumes of CO2 injected, its buoyancy, potential corrosivity in the presence of water, and 

potential impurities in the CO2 stream. In addition, EPA expects the tailored permitting, siting, 

construction, operation, monitoring, and post-injection site care requirements in the GS rule to 

prevent leakage from injection formations and protect USDWs. 

EPA believes that injection for the primary purpose of long term storage is sufficiently different 

from Class II ER operations and warrants tailored requirements. For example, the volume of 

CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. 

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 ER projects. 

Letter ID: 0210 Comment ID: 22702 Letter Lines: 131 to 132 

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment) 

Comment: 11. Requirements for conversion of any well to a Class VI well should be site 

and risk dependent. 

Individual Response: EPA agrees that a cautious approach to grandfathering is appropriate, 

particularly given that the converted well will be used for a substantially different process, which 

involves increased reservoir pressures associated with large volumes of stored CO2 and the 

corrosivity of CO2 in the presence of water. The final GS rule provides for the construction of 

these wells to be grandfathered (per 146.81(c)). EPA has included a requirement in the final GS 

rule that owners or operators seeking to convert existing wells for long term storage must 

demonstrate to the Director that the grandfathered wells were engineered and constructed meet 

the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at 

§146.86(b) and §146.87(a). EPA clarifies that only the construction requirements are 

grandfathered and that all other Class VI requirements (reporting, monitoring, mechnical 

integrity testing, etc.) must be met following a determination under §146.81(c). Conversion of 

the well is at the Director's discretion following an evaluation of all other site-specific 

information about the well and the project, e.g., modeling, monitoring, and other data. EPA 

expects that any wells that have deteriorated due to contact with incompatible injected or 

formation fluids would not be approved for conversion. 

8
Letter ID: 0210 Comment ID: 22703 Letter Lines: 134 to 136 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment: 12. EPA’s implied 2017 date for completion of the final UIC regulations is too 

late to provide regulatory clarity faced by CCS project developers today. These 

are the details supporting these concerns and recommendations: 

Individual Response: EPA believes that sufficient data have been collected to inform the final 

GS rule. In addition to laboratory studies and modeling research that provide relevant 

information on GS, the Agency is also collecting and analyzing GS project data and permit 

information from a variety of sources. Most notably, EPA has evaluated permits and reviewed 

operational data and information associated with the seven regional carbon sequestration 

partnerships funded by the U.S. Department of Energy and coordinated through the National 

Energy Technology Laboratory. EPA believes that these projects form a solid basis for finalizing 

the GS requirements, and there is no reason to wait until all phases of the DOE demonstration 

tests are complete. Nevertheless, EPA anticipates that future experimental and full-scale projects 

will continue to inform the technology, and is therefore using an adaptive rulemaking approach. 

EPA plans, every six years, to collect and review data on GS projects to determine whether the 

appropriate amount and types of information and appropriate documentation are being collected, 

and to determine if modifications to the requirements are appropriate or necessary. EPA believes 

that the completion of the DOE pilots in 2017 will allow the incorporation of results of these 

projects into the first review of the rule. 

Letter ID: 0210 Comment ID: 22704 Letter Lines: 140 to 161 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: #1: Potential Applicability of CFR 40 Part 261 (RCRA). (Ref: page 43503, Section 

I) In the preamble to the ANPR, EPA poses the question of whether injected CO2 

might be considered a RCRA hazardous waste, but does not answer the question. 

Any ambiguity concerning the applicability of complex and expensive regulatory 

regimes such as RCRA and CERCLA will be a major disincentive to the development 

and deployment of CCS. Regulatory clarity and certainty are critical to 

companies facing multi-billion dollar investment decisions regarding 

gasification facilities and CO2 sequestration projects. 

EPA should explicitly address these issues in the final rule and not leave open 

any implication that RCRA and CERCLA may or may not apply to CCS. The presence 

of low levels of hazardous contaminants in CO2 as a result of the carbon capture 

process should not limit the storage of the CO2 using Class VI wells, especially 

taking into account the diminimus risk of exposure associated with the 

disposition of CO2 into deep geological formations under the stringent controls 

required by this proposed regulation. We strongly recommend that EPA provide a 

categorical exclusion in this rulemaking, that CO2 streams that are specifically 

9
intended to be stored in geologic structures are not RCRA hazardous wastes. Such 

an exclusion would be analogous to the provision of 40 CFR §261.4(b)(5), which 

excludes drilling fluids, produced waters, and other wastes associated with the 

development, or production of crude oil, natural gas or geothermal energy, and 

therefore can be injected into Class II wells. 

Individual Response: EPA received many comments regarding the applicability of the RCRA 

regulations and statute to CO2 streams that are geologically sequestered under the final Class VI 

UIC well requirements. As a result, EPA has decided to initiate a separate proposed rulemaking 

specifically to examine the issue of RCRA applicability to CO2 streams being geologically 

sequestered, including the possible option of a conditional exemption from the RCRA 

requirements for CO2 GS in Class VI wells. EPA will consider these comments as part of its 

development of that proposal. The Agency will consider issues particular to RCRA in the context 

of that separate rulemaking, and recommends that the commenter read that proposed rule when it 

is published. The Agency notes that commenters who wish to submit comments on the RCRA 

proposal will need to do so during the comment period for that rule. Finally, EPA also notes that 

the final GS rule, which adds new regulations for Class VI wells under the Safe Drinking Water 

Act (SDWA), is not making any changes to the RCRA regulations. 

CO2 itself is not listed as a hazardous substance under CERCLA; however, the CO2 stream may 

contain a listed hazardous substance (such as mercury) or may mobilize substances in the 

subsurface that could react with ground water to produce listed hazardous substances (such as 

sulfuric acid). Whether such substances may result in CERCLA liability from a sequestration 

facility depends entirely on the composition of the specific CO2 stream and the environmental 

media in which it is stored (e.g., soil or ground water). CERCLA exempts from liability, under 

CERCLA section 107, 42 U.S.C. 9607, certain “federally permitted releases” (FPR) as defined in 

CERCLA, 42 U.S.C. 9601(10). Class VI permits will need to be carefully structured to ensure 

that they prevent potential releases from the well which are outside the scope of the Class VI 

permit. 

Letter ID: 0210 Comment ID: 22705 Letter Lines: 163 to 230 ; 446 to 462 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment: In terms of its approach, we recommend that EPA consider captured CO2 -- 

inclusive of transport, the injection facility and within injection wells -- as 

material that constitutes a stream that is contained within a process and 

therefore, not a solid waste. Within this scope, protection of health and the 

environment will be provided by controls required under other regulatory domains 

such as OSHA and NESHAPS. 

For purposes of evaluating the potential RCRA status of the captured CO2 that 

may be injected in Class VI wells, the CO2 streams trigger none of the RCRA 

hazardous waste criteria. Specifically, captured CO2 is not a "listed" hazardous 

waste as set forth in 40 C.F.R. §261.31 - .35, nor is it "characteristically" 

hazardous pursuant to 40 C.F.R. § 261.20 - .24. It is neither "ignitable" nor 

10
"corrosive", and the TCLP test used to determine whether a waste is 

characteristically "toxic" cannot be used on the supercritical liquid CO2 

stream. In any event, the level of trace contaminants in the CO2 is so low that 

TCLP levels are not even approached when measured on an absolute concentration 

basis. Next, the CO2 stream is not "reactive," since the injected CO2 stream 

will not generate toxic gases in a quantity sufficient to present a danger to 

human health or the environment. For example, the levels of hydrogen sulfide 

likely to be present in the CO2 stream (generally less than 0.3%) are an order 

of magnitude less than those typically present in the "acid gas" that is widely 

injected into Class II underground injection wells in the U.S., which have an 

average hydrogen sulfide concentration of approximately 40%. See Kleweki (Cadmus 

Group), Kobelski (U.S. EPA), Karimjee (U.S. EPA), and Sham (Cadmus Group): Acid 

Gas Injection In The United States (Presentation on May 8, 2006 at the Fifth 

Annual Conference On Carbon Capture & Sequestration). U.S. EPA continues to 

encourage the underground injection of "acid gas" streams, recently including 

such a requirement in a proposed consent decree that would resolve an 

enforcement case brought under the Clean Air Act. U.S. v. Merit Energy Company, 

Civil Action No. 1:08-CV-917 (W.D. Mich.), proposed Consent Decree lodged on 

September 30, 2008 (73 Fed. Reg. 58267 (Oct. 6, 2008) (U.S. EPA’s October 1, 

2008 press release in this matter stated that the underground injection of the 

acid gas would result in "zero sulfur dioxide emissions.") 

EPA should take into account the specific disposition of the CO2 that the ruling 

is focused on (i.e., deep underground storage). A well permitted under this rule 

will be protective of underground sources of drinking water. The minimum depth 

of injection required to maintain CO2 in a supercritical state is approximately 

2,500 feet. This, in conjunction with the controls and safeguards required by 

this rule throughout the injection and post-injection period, will ensure that 

CO2 injected into a Class VI well poses de minimus risk. There is very little 

likelihood for hazardous constituents to be released where they would pose a 

risk to human health or the environment. (See, e.g., Final Risk Assessment for 

the FutureGen Project Environmental Impact Statement, DOE, April, 2007) 

Finally, much higher H2S levels than will be used in CCS have been successfully 

and safely used for EOR injection with Class II wells. For example, in Canada, 

there are 45 ongoing projects where high levels (up to 68%) of H2S in CO2 are 

being injected into saline aquifers or producing oilfields [1,2,3] for disposal 

purposes. These combined gas streams of H2S and CO2 are commonly referred to as 

acid gas and originate from purification of sour natural gas, are highly toxic 

and in some cases of high concentration, flammable. These projects have been 

studied in detail and their success is well documented [3,4]. In addition, there 

have never been any significant safety incidents reported, since the start of 

the first injection of acid gas into a depleted oil reservoir on the outskirts 

of the city of Edmonton, Alberta in the early 1990’s. Nor have there ever been 

any reports of leakage of H2S from these operations [4]. 

11
Accordingly, EPA has sufficient information now to conclude that captured CO2 

streams are not RCRA hazardous wastes and do not pose greater risks that many 

streams than are already being routinely injected in Class II and other UIC 

wells as non-hazardous wastes. Indeed, to conclude otherwise would create the 

nonsensical result of suggesting that sequestering a material in deep geological 

formations poses more hazards than emitting it into the air. It is very 

important that EPA make this determination as soon as possible to remove the 

implication that CCS might be subject to RCRA regulation, an implication that 

would be extremely damaging to the future of CCS, and to the goal of 

significantly reducing the carbon footprint of the nation’s energy sector. 

1 Keushnig, H. (1995); Hydrogen sulfide -- if you don’t like it, put it back. J. 

Canadian Petroleum Technology. 34: 18-20. 

2 Longworth, H.L., G.C. Dunn, M. Semchuck (1996); Underground disposal of acid 

gas in Alberta, Canada: Regulatory concerns and case histories. SPE 35584. pg 

181-192. 

3 Bachu, S., K. Haug (2005) In situ characteristics of acid-gas injection 

operations in the Alberta Basin, Western Canada: Demonstration of CO2 geological 

storage. in Carbon Dioxide for Storage in Deep Geological Formations. Vol. 3. 

ed. D.C. Thomas, S.M. Benson. Elsevier Ltd. pg 867-876. 

4 Bachu, S., W.D. Gunter; Overview of Acid-Gas Injection Operations in Western 

Canada. In Proceedings of 7th International Conference on Greenhouse Gas Control 

Technologies. Volume 1: Peer-Reviewed Papers and Plenary Presentations (E.S. 

Rubin, D.W. Keith and C.F. Gilboy, ed.), IEA Greenhouse Gas Programme, 

Cheltenham, UK, 2005. 

Individual Response: EPA received many comments regarding the applicability of the RCRA 

regulations and statute to CO2 streams that are geologically sequestered under the final Class VI 

UIC well requirements. As a result, EPA has decided to initiate a separate proposed rulemaking 

specifically to examine the issue of RCRA applicability to CO2 streams being geologically 

sequestered, including the possible option of a conditional exemption from the RCRA 

requirements for CO2 GS in Class VI wells. EPA will consider these comments as part of its 

development of that proposal. The Agency will consider issues particular to RCRA in the context 

of that separate rulemaking, and recommends that the commenter read that proposed rule when it 

is published. The Agency notes that commenters who wish to submit comments on the RCRA 

proposal will need to do so during the comment period for that rule. Finally, EPA also notes that 

the final GS rule, which adds new regulations for Class VI wells under the Safe Drinking Water 

Act (SDWA), is not making any changes to the RCRA regulations. 

EPA supports the use of CO2 capture technologies that minimize impurities in the CO2 stream. 

However, the GS rule does not apply to CO2 sources. 

12
Letter ID: 0210 Comment ID: 22706 Letter Lines: 232 to 256 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: Concern #2: Scope of Class VI Permits and the Potential Applicability of 

Superfund to CCS. (Ref: page 43503, Section J) 

EPA raises, but does not answer, the question of whether the underground 

injection of CO2 might trigger Superfund and associated natural resource damages 

liabilities, and appears to suggest that Class VI permits might be written to 

allow future Superfund liability associated with CCS. EPA must emphatically 

conclude that CO2 containing trace contaminants does not open any regulatory 

pathways for subjecting a geological storage site to Superfund liability. As 

with RCRA, any ambiguity on applicability of CERCLA will be potentially fatal to 

the development and deployment of CCS. It is highly unlikely that CCS will be 

implemented on a meaningful scale if there is a possibility that CCS might 

trigger Superfund. 

CERCLA expressly excludes from Superfund liability "federally permitted 

releases." Further, "any injection of fluids authorized under the Federal 

underground injection control programs or State programs submitted for Federal 

approval . . . pursuant to part C of the Safe Drinking Water Act" are "federally 

permitted releases." 42 U.S.C. § 9601(10)(G) (CERCLA Section 101(10)(G)). 

Therefore, any captured CO2 stream that is injected in a Class VI well pursuant 

to a Federal or State permit is a "federally permitted release" and not subject 

to Superfund liability (including natural resource damages). It would be 

inconsistent with existing practice in the UIC program, impractical, and fatal 

to the future of CCS to limit Class VI permits solely to the CO2 portion of the 

stream and explicitly exclude any trace contaminants. 

Individual Response: As described above, whether the presence of hazardous substances in the 

CO2 may result in CERCLA liability from a sequestration facility depends entirely on the 

composition of the specific CO2 stream and the environmental media in which it is stored (e.g., 

soil or ground water). CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 

9607, certain “federally permitted releases” (FPR) as defined in CERCLA, 42 U.S.C. 9601(10). 

Class VI permits will need to be carefully structured to ensure that they prevent potential releases 

from the well which are outside the scope of the Class VI permit. 

EPA adds that promoting the use of GS is outside the scope of the GS rule. Rather, the purpose 

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

USDWs from endangerment. 

Letter ID: 0210 Comment ID: 22707 Letter Lines: 258 to 269 

Comment Code: 1614 1.3.1.2 Impurities in captured CO2; purity standards for CO2 

13
Comment: By its inherent nature, gasification will provide a stream of >90% CO2 having 

extremely low levels of both organic and inorganic hazardous air pollutants 

(HAPS). There are several mechanisms that provide this: 1) destruction of 

organic HAPS within a gasifier due to the extreme (~2,500 oF) gasification 

temperature, 2) removal of inorganic content in the melting and slagging 

process, 3) particulate scrubbing or filtration, 4) activated carbon beds to 

remove mercury and other condensed metals;, and finally 5) cooling followed by 

acid gas scrubbing. The combination of these HAP reductions is very effective. 

As a point of reference, the total inorganic HAPS that would be injected with 

captured CO2 from an IGCC or gasification process over 30 years of CCS operation 

will be at least an order-of-magnitude lower than the annual limits (both total 

and individual components) of NSPS. 

Individual Response: EPA recognizes that many CO2 streams may be relatively pure, and 

research indicates that the estimated amounts of impurities in a CO2 stream are likely to be low. 

However, these estimates are based on limited information, and uncertainties remain about the 

expected concentrations of impurities from the various types of CO2 streams. The concentrations 

of minor and trace elements in CO2 streams for GS projects are likely to vary by facility, coal 

composition, plant operating conditions, and pollution removal technologies. 

The GS rule does not set generic purity standards for CO2 injectate streams (e.g., a percent 

CO2). Instead, the GS rule addresses the quality and quantity of impurities by requiring owners 

or operators to submit information on the source of the CO2 and its physical and chemical 

properties. Specifically, the GS rule requires the owner or operator to submit data about the site, 

including an analysis of the chemical and physical characteristics of the CO2 stream, as required 

at §146.82(a)(7)(iv), and information on the compatibility of the CO2 stream with fluids in the 

injection zone and minerals in both the injection and the confining zones and the materials used 

to construct the well, per §146.82(c)(3). This information can help the Director determine the 

potential for geochemical reactions between the injectate (CO2) and the host geologic 

formations, which could result in the plugging of pore spaces or the dissolution of formation 

minerals. 

Letter ID: 0210 Comment ID: 22708 Letter Lines: 271 to 281 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: Concern #3: Potential releases from the well which are outside the scope of the 

Class VI permit. (Ref: page 43504, Section J) 

Class VI UIC permits must also be carefully written to identify and address the 

potential post-injection releases of hazardous substances, or the generation of 

hazardous substances from the chemical interaction of the CO2 with the 

geological storage formation (e.g. - leaching of metals) so that they would be 

federally permitted releases. If the potential release or generation of such 

hazardous substances is viewed as beyond the scope of Class VI permits, CCS 

sites could be subjected to the threat of long-term Superfund liability, a 

14
threat that could be fatal to the viability of CCS. 

Individual Response: As described above, whether the presence of hazardous substances in the 

CO2 may result in CERCLA liability from a sequestration facility depends entirely on the 

composition of the specific CO2 stream and the environmental media in which it is stored (e.g., 

soil or ground water). CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 

9607, certain “federally permitted releases” (FPR) as defined in CERCLA, 42 U.S.C. 9601(10). 

Class VI permits will need to be carefully structured to ensure that they prevent potential releases 

from the well which are outside the scope of the Class VI permit. 

Letter ID: 0210 Comment ID: 22709 Letter Lines: 283 to 293 

Comment Code: 1660 1.3.6 Ecosystem impacts (soil, air, surface water) 

Comment: With respect to releases from the well itself, the primary source of such 

releases could occur during injection operation through failure of well seals, 

flanges and gaskets, piping breaches, liners, valve packing and other mechanical 

components or failure to follow operational and safety procedures. Such releases 

will likely be confined to the injection period. During operation and the 

measurement, monitoring, and validation (MMV) period, the injection facility 

(metering, distribution and injection systems), should be classified as a 

production facility where industrial safety standards, design and operating 

procedures (e.g., - HAZOPS reviews) will apply. Appropriate regulation will be 

derived from permits under the Clean Air Act that are issued to the facility 

along with protection of operating personal as required by OSHA. 

Individual Response: EPA acknowledges that there are potential risks associated with GS. The 

purpose of the Class VI requirements is to minimize and mitigate potential/identified risks 

through proper site characterization, well construction, operation, monitoring, post-injection site 

care, and site closure and to ensure protection of USDWs. The Agency clarifies that, under 

SDWA authority, the requirements do not explicitly protect against CO2 leakage to the surface. 

However, the GS rule requires that CO2 injected for GS remain confined in the injection zone. 

Leakage outside of the injection zone/to the surface would be a permit violation. 

The Agency clarifies that compliance with OSHA guidelines for GS is outside of the scope of the 

GS rule. However, EPA believes that the measures in the GS rule that mitigate the possibility of 

CO2 leakage out of the injection zone will also mitigate the risks to humans, both on-site and 

off-site. 

Letter ID: 0210 Comment ID: 22710 Letter Lines: 295 to 313 

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones 

(seeking comment) 

Comment: Concern #4: Requirement for secondary confinement/containment. (Ref: page 

15
43505, 

1- Proposed Geologic Siting Requirements) 

The proposal would provide the Director the discretion to require the owner or 

operator to identify and characterize additional confining and containment zones 

above the primary (i.e., lowermost) confining zone that could further impede 

vertical fluid movement and allow for pressure and dissipation. Secondary 

containment (multiple confining structures) should not be required to prevent 

leakage of CO2. If required, this will prevent geologic storage in certain but 

important geographic regions. It also raises doubt concerning procedures and 

protocols to characterize and validate safe geologic storage formations and 

containment where there is not secondary containment. Under the proposed rule, 

there are measures that provide adequate assurance of formation integrity and 

require operators to demonstrate that their project will not endanger 

underground sources of drinking water (USDWs). If a secondary containment is 

present, it will be detected during site characterization and risk assessment. 

Such a special case could be analyzed to evaluate the potential risks to USDWs 

and to develop additional evaluation criteria to be applied to permit geological 

storage without going through the aquifer exemption process. 

Individual Response: EPA clarifies that secondary confining zones are not required for all GS 

sites. Rather, secondary confining zones are required when the Director determines that these 

zones are needed to maximize the protection of USDWs from endangerment. EPA retains the 

requirement to identify additional containment/confining zones, if required by the Director, as 

proposed (e.g., §146.83(b)). EPA 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. EPA disagrees that the requirement would reduce the number of sites available for 

GS. The intent of this requirement is to ensure that a proposed site provides adequate protection 

of USDWs from endangerment; if this protection cannot be demonstrated, the Director would not 

issue a permit for GS at the site. 

Letter ID: 0210 Comment ID: 22711 Letter Lines: 315 to 327 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: Concern #5: Restriction of injection to formations below the lowermost 

underground source of drinking water or USDW. (Ref: page 43512, 3. Proposed 

Injection Well Construction Requirements) 

This requirement is not necessary for the protection of USDWs. It is in-fact 

overly restrictive and will eliminate many suitable and safe geologic formations 

for CO2 sequestration or permanent storage. It will also render geological 

storage impractical (pumping power and well costs) for states in the western 

16
United States where the drinking water aquifers are many thousands of feet deep 

and well isolated from overlying regions. Also, industry has demonstrated that 

it can operate CO2 injection wells for EOR without endangering USDWs that are 

located below the injection zone (e.g., the Salt Creek EOR project in Wyoming, 

having a USDW below the injection zone). Concern #6 Demonstration of financial 

Individual Response: EPA acknowledges that there are limited circumstances where injection 

above the lowermost USDW can be performed in a manner that protects USDWs from 

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 

establishes a process by which owners or operators can seek a waiver of the Class VI injection 

depth requirements for injection into non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to 

UIC program Directors and owners or operators who undertake CO2 injection for GS. The 

Agency believes this approach: 1) responds to concerns about local and regional geologic storage 

capacity limitations imposed by the proposed injection depth requirements; 2) allows for a more 

site-specific assessment of injection depth for GS projects; 3) accommodates injection into 

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or 

between USDWs when appropriate and where it can be demonstrated that USDWs will be 

protected; and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, 

EPA’s approach to addressing injection depth variability through a waiver process responds to 

concerns about future drinking water resource availability and the need to ensure that high 

quality water remains available in sufficient quantities to supply drinking water needs. For 

additional information on the waiver approach, please see the final rule and preamble, as well as 

EPA's responses to comments on the Notice of Data Availability and Request for Comment. 

Letter ID: 0210 Comment ID: 22712 Letter Lines: 327 to 344 ; 464 to 466 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: having a USDW below the injection zone). Concern #6 Demonstration of financial 

responsibility. (Ref: page 43520, 9. Proposed Financial Responsibility and LongTerm Care Requirements) 

EPA needs to provide clarifying guidance on how to demonstrate financial 

responsibility. The proposed regulation leaves too much to the discretion of the 

Director. Such openended requirements will effectively discourage carbon capture 

projects and the development of financial pro formas. Of particular concern are 

those assurances necessary to cover the costs of potential long-term stewardship 

or the potential to have to perform remediation at sites that have been 

previously certified as closed. This uncertainty may increase the perceived risk 

exposure to levels that serve as a barrier to investment. A potential approach 

to share risk and overcome this barrier is the Interstate Oil and Gas Compact 

Commission (IOGCC)[5] proposal for an industry-funded and state-administered trust 

fund to provide the stewardship during the Post-Closure Period. The trust would 

17
be funded through an injection fee assessed to the site operator and calculated 

on a per-ton basis, at the point of custody transfer of the CO2 from the 

generator to the site operator. 

5 The Interstate Oil and Gas Compact Commission Task Force on Carbon Capture and 

Geologic Storage, Storage of Carbon Dioxide in Geologic Structures - A Legal and 

Regulatory Guide for States and Provinces, September 25, 2007 

Individual Response: EPA believes that minimum financial responsibility requirements are 

necessary to hold well owners or operators accountable for the safe operation, site closure, and 

post-injection site care of wells while protecting USDWs and avoiding extra public expense. 

EPA anticipates that the availability of a variety of financial responsibility providers and thirdparty GS financial instruments will grow in response to demand for GS technology. 

EPA believes that the financial responsibility requirements provided in the final rule do not leave 

too much discretion to the Director. Owners or operators may choose from a variety of financial 

instruments to meet their financial responsibility obligations under the rule, provided the 

Director determines that the operator's proposed financial responsibility demonstration is 

adequate to protect USDWs from endangerment throughout the life of the project. The final GS 

rule specifies at §146.85(a)(1) the permitted types of financial responsibility instruments. See the 

final rule and preamble for further discussion of EPA's final approach to financial responsibility. 

EPA is developing guidance on financial responsibility for GS wells that will provide 

information about the appropriateness of various financial instruments. The guidance will be 

available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. This guidance will consider 

the recommendations in the Office of the Inspector General report on financial assurance and 

will include recommendations to help permitting authorities determine whether an owner or 

operator's plan for financial responsibility is adequate. 

Under SDWA, EPA has the general authority to set financial responsibility requirements for 

injection well owners or operators. However, this authority does not extend to allowing the 

Agency to create a financial instrument with EPA as the trustee, due to the restrictions of the 

Miscellaneous Receipts Act (MRA). The MRA requires that EPA deposit the funds it receives 

for the use of the government into the Treasury, therefore funds would not necessarily be 

available for GS financial responsibility. Additionally, EPA does not have authority under 

SDWA to establish a trust fund for purposes of financial responsibility for Class VI projects. The 

Agency clarifies that the trust funds that are addressed as financial responsibility instruments in 

the GS rule are set up by individual owners or operators and are different from a national-level 

trust described by the commenters that would cover large numbers of GS projects. 

Under SDWA authority, owners or operators of injection wells must ensure protection of 

USDWs from endangerment and are subject to liability for enforcement under the Act. The final 

rule requires that an owner or operator conduct monitoring as specified in the Director-approved 

PISC and site closure plan following the cessation of injection until he or she can demonstrate to 

the Director that the geologic sequestration project no longer poses an endangerment to USDWs. 

18
For additional information about the PISC and site closure requirements, see the preamble to the 

final GS rule. 

Once an owner or operator has met all regulatory requirements under Part 146 for Class VI wells 

and the Director has approved site closure pursuant to requirements at §146.93, he or she will 

generally no longer be subject to enforcement for regulatory noncompliance. Furthermore, the 

financial instrument required under §146.85 will be released if it has not been used. However, 

even if site closure is approved under §146.93, an owner or operator may be held liable for 

regulatory noncompliance (including violation of 40 CFR 144.12) in certain circumstances, for 

example if the Director relied on erroneous information provided by the owner or operator when 

approving site closure. 

Additionally, an owner or operator may always be subject to any action the Administrator deems 

necessary to protect the health of persons under §1431 of the SDWA after site closure if there is 

unanticipated migration towards or into a USDW that causes or threatens imminent and 

substantial endangerment to public health. The action may include issuing administrative orders 

or commencing a civil action for appropriate relief. If the owner or operator fails to comply with 

the order, he or she may be subject to a civil penalty for each day in which such violation occurs 

or failure to comply continues. 

The Agency clarifies that Class VI well permits may be transferred to another owner or operator 

pursuant to §144.38 whereby generally all other regulatory responsibilities are transferred to that 

new owner and operator, including all potential liabilities associated with meeting the 

requirements of that permit. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

§§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. EPA 

does not have authority to transfer SDWA or other legal liability for Class VI wells to the State 

or federal government or a third-party fund. See the final rule preamble for further discussion of 

EPA's final approach. 

Letter ID: 0210 Comment ID: 22713 Letter Lines: 346 to 360 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: Concern #7. EPA is considering a guidance approach that would recommend 

adopting 

a pay in period of three years for GS projects, consistent with other similar 

programs in the Agency. (Ref: page 43521, Sec. 9. Proposed Financial 

Responsibility and Long-Term Care Requirements, Pay-in period for trust funds) 

We strongly urge that the EPA not adopt this approach. CCS projects will be 

subject to their highest financial strain in the first several years of 

operation. During this period, commissioning, systems integration and debugging 

19
of mechanical and process systems will need to be completed with potential loss 

of plant operation, production and revenue. Projects will likely be burdened 

with additional initial capital coverage of an already expensive facility to 

contend with an accelerated payment. We therefore recommend that any payment 

schedule be based on a per-ton fee over an amortization period equal to the 

expected operational life of the project and in a framework as recommended by 

the IOGCC (ref: Concern #6). 

Individual Response: EPA acknowledges that there may be several possible approaches to 

setting pay-in periods for trust funds. The final rule requires that the Director approve the use 

and length of pay-in periods. EPA is developing guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) that describes the types of 

financial instruments that owners or operators can use to meet financial responsibility 

requirements for GS wells. Specifically, the guidance will discuss pay-in periods and provide 

guidance for Directors to use in determining an appropriate pay-in period. EPA adds that owners 

or operators may choose from a variety of financial instruments to meet their financial 

responsibility needs. 

Letter ID: 0210 Comment ID: 22714 Letter Lines: 362 to 378 

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: Concern #8: The owner or operator shall continue to conduct monitoring as 

specified in the Director-approved post-injection site care and site closure 

plan for at least 50 years following the cessation of injection. At the 

Director’s discretion, the monitoring will continue until the geologic 

sequestration project no longer poses an endangerment to USDWs. (Ref: page 

43519, Sec. 8. Post-Injection Site Care Timeframe) 

The time required for post-injection site management should not be arbitrarily 

set at 50 years. Criteria for defining the time for post-injection management 

should be performance based and site specific. The choice of 50 years is 

arbitrary and does not take into account the data and knowledge and modeling 

verification obtained over a preceding operating and injection period of years 

and likely decades. The maximum post-injection monitoring period should be 

defined on reasonable but quantitative, performance-based metrics - for example, 

that the validated model predicts that 95% of the plume is or will be trapped 

and that a sensitivity analysis predicts a comfortable margin of safety to 

minimize approach to any USDWs, thus preventing potential endangerment. Concern 

Individual Response: EPA agrees that there will be circumstances where it can be demonstrated 

in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to 

USDWs. 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 

20
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 however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in most cases. The 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 disagrees that a post-injection site care timeframe of 50 years is excessive in most cases or 

arbitrary. EPA proposed a default post-injection site care timeframe of 50 years based on a 

review of research studies, industry reports, and existing environmental programs. This analysis 

was included in an EPA-prepared background document that is available in the federal docket, 

titled Computational Modeling of Underground Injection of Carbon Dioxide for Determination 

of Area-of-Review and Potential Risk to Underground Sources of Drinking Water. EPA assessed 

various default timeframes based on additional review of research studies and evaluation of 

public comments. While numerous commenters suggested that EPA shorten the monitoring 

timeframe, none of the commenters provided sufficient data or other evidence to warrant a 

change in the proposed timeframe. While the 10- or 30-year timeframe suggested by some of 

these commenters may be within the timeframe suggested in some studies, there are 

circumstances (e.g., little development of mineral trapping of CO2) under which the potential 

risks of endangering USDWs will likely not decline within these timeframes and available data, 

including data submitted by commenters, do not support a different default timeframe. 

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 recognizes that there are challenges associated with assuring funding for activities that will 

occur far in the future. However, the Agency believes that operators must demonstrate that 

financial resources are available to plug the injection well and provide post-injection care at the 

point in time that the first CO2 is injected. EPA also recognizes the concerns associated with 

assuring financial responsibility for the long time frames over which post-injection site care will 

be conducted. EPA is developing guidance on financial responsibility to assist owners or 

operators in evaluating the requirements of §146.85 and to assist Directors in evaluating financial 

responsibility demonstrations. The guidance describes the types of financial mechanisms that 

operators may choose to use when evaluating the financial responsibility requirements for GS 

wells and it will also include a section on how to estimate costs to support accurate financial 

responsibility demonstrations. The guidance will be available at 

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

21
Letter ID: 0210 Comment ID: 22715 Letter Lines: 378 to 394 

Comment Code: 1530 1.2.3.1 State regulatory efforts on GS (seeking comment) 

Comment: minimize approach to any USDWs, thus preventing potential endangerment. 

Concern 

#9: On-going state efforts to regulate GS. (Ref: page 43497, Sec. C. Who 

Implements the UIC Program?) 

Although we recognize that state primacy is integral to the UIC program, we 

strongly recommend that EPA drive its state stakeholder activities towards the 

goal of unanimity and uniformity of technical requirements. Disparate 

requirements and processes will increase cost, delay, and complexity and make 

the permitting process less predictable. Individual states should not develop 

regulations that are substantially more restrictive or prescriptive than that 

required by the EPA. Many states will also not have technical resources that are 

comparable to that of the US EPA. EPA’s stakeholder technical workshops had good 

representation from the EPA regions, but it appears that many states have not 

yet been engaged. To avoid this and the problems from a patchwork of permitting 

regulations, EPA should carefully but quickly consider and integrate input from 

a majority of state environmental protection and conservation and natural 

resource offices. 

Individual Response: EPA agrees that a consistent approach to regulating GS activities across 

the United States is important. For this reason, the Agency has finalized minimum federal 

requirements for GS projects that owners or operators of Class VI (GS) wells must meet. EPA 

clarifies that states and tribes seeking to implement the Class VI program may apply for primary 

enforcement responsibility (primacy) under Section 1422 of SDWA. States and tribes must meet 

EPA's minimum federal requirements for UIC programs by establishing permitting, geologic site 

characterization, AoR and corrective action, well construction, operation, mechanical integrity 

testing, monitoring, financial responsibility, injection well plugging, post-injection site care, and 

site closure of GS well owners or operators. Following primacy approval, programs will need to 

implement these minimum requirements. 

EPA clarifies that SDWA, under section 1422(b)(3)(9)(A), requires that the regulations of the 

Administrator "permit or provide for varying geologic, hydrological, or historical conditions in 

different states and in different areas within a state." EPA has provided the Director discretion in 

applying the GS requirements, taking into account varying conditions, particularly with regard to 

the evaluation of site characteristics. 

To promote consistency while providing the Director with an appropriate level of discretion, 

EPA is developing guidances for states and tribes that describe the process of applying for and 

receiving primacy for GS Class VI wells under Section 1422 of SDWA, as well as the technical 

and administrative issues associated with developing GS regulations that are the equivalent of 

22
minimum federal criteria and requirements. These are available on EPA’s website at 

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

Letter ID: 0210 Comment ID: 22716 Letter Lines: 396 to 409 

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: Concern #10: Continuation of Class II for EOR. (Ref: page 43502, Sec. G) 

By proposing different and more restrictive requirements for Class VI wells, EPA 

will create economic or operational barriers that prevent a seamless transition 

from EOR and storage operations to wholly storage operations. EOR can make a 

significant contribution to offset the cost of early CCS demonstration projects. 

For example, EOR can contribute to the investment in pipeline infrastructure 

helping to enable pure CCS operations. Also, CO2 storage operations may continue 

after EOR has ceased, thus reducing the cost of storage, site characterization 

and development. These benefits should be viewed as especially significant in 

light of the difficulties in securing sufficient funds to initially deploy CCS. 

EOR projects could quite feasibly bring CCS deployment forward by many years as 

a considerable quantity of CO2 remains underground during such operations. This 

will reduce the number of target formations where CO2 could be stored. 

Individual Response: EPA believes that injection for the primary purpose of long term storage 

is sufficiently different from Class II ER operations and warrants tailored requirements in order 

to protect USDWs from endangerment. For example, the volume of CO2 anticipated to be 

injected in Class VI wells is significantly greater than for Class II wells. 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 ER projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. 

EPA is developing guidance on transitioning permits from Class II to Class VI. The guidance 

will assist Directors in determining whether an injection project should be transitioned from 

Class II where the primary purpose is oil and gas production to Class VI where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes recommended 

methods the Director may use to evaluate changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

23
UIC program. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells in the preamble to the final GS rule. 

In response to the comment that establishing a new well class will create economic and 

operational barriers, EPA clarifies that the purpose of the GS rule is to ensure protection of 

USDWs from endangerment and not to promote or incentivize GS. However, the Agency 

believes that establishing a regulatory framework for the future development and deployment of 

CCS technology can provide the regulatory and jurisdictional certainty needed to foster 

development and deployment of CCS while ensuring USDW protection. 

Letter ID: 0210 Comment ID: 22717 Letter Lines: 411 to 422 

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment) 

Comment: Concern #11: Grandfathering of construction requirements at the Director’s 

discretion for existing Class I, Class II, and Class V wells seeking to convert 

to Class VI wells, and whether additional construction requirements would be 

necessary to prevent endangerment to USDWs from the GS of CO2. (Ref: page 43497, 

Sec. G) Requirements for conversion of any well to a Class VI well should be 

site and risk dependent. EPA should consider expanding grandfathering scope to 

more than construction requirements and not a-priori require that all other 

permitting requirements be redone. Existing permit holders should be allowed to 

provide data on the experience and characteristics of their site demonstrating 

that it is suitable for long-term storage of carbon dioxide without endangering 

underground sources of drinking water. This could be more acceptable with an end 

date for grandfathering wells (e.g., - operational before 2012). 

Individual Response: EPA disagrees that other requirements (e.g., MITs, siting, monitoring, 

operational, and AoR requirements) should also be grandfathered. Following re-permitting of the 

project as GS, many of the unique factors of GS sites (e.g., increased reservoir pressures 

associated with large volumes of stored CO2 and the corrosivity of CO2 in the presence of 

water) will result in an increased risk profile, warranting the specific requirements in the final GS 

rule. Therefore, following re-permitting as Class VI wells, these projects must be subject to the 

operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure 

requirements in the final GS rule. See the discussion of EPA's final regulatory approach in the 

preamble to the GS rule for additional detail on these requirements. 

EPA does not plan to institute an "end date" for this requirement since conversion is a sitespecific decision. EPA encourages owners or operators and Directors to coordinate on repermitted wells to ensure that all wells used for GS are constructed and operated in a manner that 

protects USDWs from endangerment. 

Letter ID: 0210 Comment ID: 22718 Letter Lines: 424 to 439 

24
Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment: Concern #12: EPA’s schedule for promulgation of its proposed UIC regulation. 

(Page 43499 Sec. E3) 

We reference the following statement from the preamble section of the proposed 

rule: "During the Deployment Phase (2008-2017), the [RCSP] partnerships will 

conduct large volume carbon storage tests to demonstrate that large-scale CO2 

injection and storage can be achieved safely and economically. EPA will use the 

data collected from these projects to support decisions in the final GS rule." 

This statement suggests that a final GS rule may not be issued until 2017. We 

believe that this is too late to clear the regulatory uncertainty that CCS 

project developers are facing today. If this reflects EPA’s intention, we 

recommend that EPA abandon a prescriptive approach and instead, favor general 

and performance-based requirements until these demonstration tests are 

completed. Other concerns expressed by our membership and recommendations for 

improvement of the proposed rulemaking are given in Appendix A. Should the EPA 

have further questions, please fell free to contact me. 

Individual Response: EPA believes that sufficient data have been collected to inform the final 

GS rule. In addition to laboratory studies and modeling research that provide relevant 

information on GS, the Agency is also collecting and analyzing GS project data and permit 

information from a variety of sources. Most notably, EPA has evaluated permits and reviewed 

operational data and information associated with the seven regional carbon sequestration 

partnerships funded by the U.S. Department of Energy and coordinated through the National 

Energy Technology Laboratory. EPA believes that these projects form a solid basis for finalizing 

the GS requirements, and there is no reason to wait until all phases of the DOE demonstration 

tests are complete. Nevertheless, EPA anticipates that future experimental and full-scale projects 

will continue to inform the technology, and is therefore using an adaptive rulemaking approach. 

EPA plans, every six years, to collect and review data on GS projects to determine whether the 

appropriate amount and types of information and appropriate documentation are being collected, 

and to determine if modifications to the requirements are appropriate or necessary. EPA believes 

that the completion of the DOE pilots in 2017 will allow the incorporation of results of these 

projects into the first review of the rule. 

Letter ID: 0210 Comment ID: 22719 Letter Lines: 473 to 483 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: §146.81 Applicability. (b) 

"This subpart applies to wells used to inject carbon dioxide specifically for 

the purpose of geologic sequestration, i.e., the long-term containment of a 

gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic 

formations." 

We recommend striking out "gaseous, liquid or supercritical carbon dioxide 

25
stream" and replacing with "gaseous, liquid, supercritical or co-mixed carbon 

dioxide stream" This change will allow for injection of carbon dioxide that is 

pre-dissolved with water to prevent phase separation in the injection zone or 

with inclusion of flow or pumping enhancement components. 

Individual Response: EPA disagrees with the suggested edit. The Agency has modified 

§146.81(b) to read as follows: “This subpart applies to any wells used to inject carbon dioxide 

specifically for the purpose of geologic sequestration, i.e., the long-term containment of a 

gaseous, liquid, or supercritical carbon dioxide stream in subsurface geologic formations.” 

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: 0210 Comment ID: 22720 Letter Lines: 485 to 512 

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82) 

Comment: §146.82 Required Class VI permit information. (b) "A map showing the injection 

well(s) for which a permit is sought and the applicable area of review. Within 

the area of review, the map must show the number, or name and location of all 

injection wells, producing wells, abandoned wells, plugged wells or dry holes, 

deep stratigraphic boreholes, State or EPA approved subsurface cleanup sites, 

surface bodies of water, springs, mines (surface and subsurface), quarries, 

water wells and other pertinent surface features including structures intended 

for human occupancy and roads. The map should also show faults, if known or 

suspected. Only information of public record is required to be included on this 

map;" 

The note that "only information of public record is required to be included on 

this map" may leave out deep oil and gas wells, particularly older wells. The 

presence of such non-public but "known" information may be eligible for 

inclusion as "known" under 144.55(a). 

§146.82 Required Class VI permit information (e) "A tabulation of all wells 

within the area of review which penetrate the injection or confining zone(s). 

Such data must include a description of each well's type, construction, date 

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

additional information the Director may require;" 

We recommend striking out "all wells" and replacing with "all known wells". 

Requiring that all wells or other artificial penetrations into injection or 

confining zones within the AoR be identified and information on depth and 

closure be provided can be costly and sometimes accurate information is 

difficult to obtain for older wells within the AoR. EPA's assistance in 

obtaining and storing this information would be helpful to CCS operators. 

26
Individual Response: EPA believes that a determination about whether information necessary 

(for a specific GS project) is outside or within the public record will be site-specific and based on 

knowledge of the site, data availability, and data quality. For instance, in meeting the 

requirement to tabulate information on wells in the AoR, the Director has the discretion to 

require the owner or operator to supplement a data records search if there is reason to believe 

that the incompleteness of available information could compromise USDW protection from 

endangerment. 

Letter ID: 0210 Comment ID: 22721 Letter Lines: 514 to 534 

Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking 

comment) 

Comment: §146.84 Area of review and corrective action. (c) (1) "Predict, using 

computational modeling, the projected lateral and vertical migration of the 

carbon dioxide plume and formation fluids in the subsurface from the 

commencement of injection activities until the plume movement ceases, pressure 

differentials sufficient to cause the movement of injected fluids or formation 

fluids into a USDW are no longer present, or after a fixed time period as 

determined by the Director." 

We recommend striking out "Predict, using computational modeling, the projected 

lateral and vertical migration of the carbon dioxide plume" and replacing with 

"Using computational modeling, provide projected potential ranges of lateral and 

vertical migration of the carbon dioxide plume" The use of multiphase 

groundwater flow and transport models is to predict the composition and movement 

of each phase state (e.g., liquid, gas ,supercritical fluid) of CO2 in the 

subsurface, as well as fluid pressures, to define the AoR. One of the concerns 

with the use of such complex models is that the site may not be fully 

characterized with respect to hydro-geologic properties. There may be 

significant uncertainty in one or more hydraulic processes/parameters. 

Therefore, it is possible to obtain a wide-range of model outcomes from 

different model parameters. The uncertainty in model parameters and sensitivity 

of model results to parameter selection should be addressed. 

Individual Response: EPA has clarified this language in the final rule. It now reads, “Predict, 

using existing site characterization, monitoring and operational data, and computational 

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

fluids in the subsurface from the commencement of injection activities until the plume 

movement ceases, until pressure differentials sufficient to cause the movement of injected fluids 

or formation fluids into a USDW are no longer present, or until the end of a fixed time period as 

determined by the Director.” 

EPA agrees that modeling results are prone to varied degrees of uncertainty. As discussed in the 

preamble to the proposed GS regulation and the associated background document 

27
"Computational Modeling of Underground Injection of Carbon Dioxide for Determination of 

Area-of-Review and Potential Risk to Underground Sources of Drinking Water" (cited in the 

proposed rule preamble as USEPA, 2008d), model predictions depend largely on the values of 

key parameters. Often these parameter values are estimated or averaged from several data 

sources. EPA also agrees that sensitivity analyses and "worst case scenario" modeling runs 

should be presented by the owner or operator and evaluated by the Director. If during the permit 

review, the Director determines that modeling results are too wide-ranging, further information 

will be required of the owner or operator. 

EPA clarifies that models are tools to help predict the movement of a CO2 plume over long time 

frames. However, EPA recognizes that it cannot be expected that modeling something as 

complex as a CO2 plume can be done with complete certainty; therefore EPA is also requiring 

that the AoR be reevaluated to verify the CO2 plume is moving as predicted and to allow for 

model calibration and necessary revisions to the required GS project plans (e.g., AoR and 

corrective action, testing and monitoring, injection well plugging, post-injection site care and site 

closure, and emergency and remedial response). EPA believes that near-term predictions (e.g., 

over the subsequent 5 years) will have the highest degree of certainty. Periodic model calibration 

will allow refinement to the AoR delineation based on real-world conditions and operating data 

and monitoring results, and thus increase confidence in the modeled predictions. EPA adds that 

the final GS regulation includes a requirement at §146.84(e) that the AoR be reevaluated at least 

every 5 years (an adjustment from the ten year interval in the proposal), which should further 

address the commenters' concerns regarding model uncertainty. 

Letter ID: 0210 Comment ID: 22722 Letter Lines: 536 to 552 

Comment Code: 3200 2.2 Proposed Area of Review and Corrective Action Requirements (40 

CFR 146.84) 

Comment: §146.84 Area of review and corrective action. (c) (2) "Using methods approved by 

the Director, identify all penetrations, including active and abandoned wells 

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

zone. Provide a description of each well’s type, construction, date drilled, 

location, depth, record of plugging and/or completion, and any additional 

information the Director may require; and..." 

We recommend striking out "approved" and replacing with "prescribed". We 

recommend deleting the second sentence and replacing with "Where such 

information is available or can be obtained, provide a description of each 

well’s type, construction, date drilled, location, depth, record of plugging 

and/or completion, and any additional information prescribed by the director, 

and..." Acceptable methods for identifying deep wells into confining zones 

within the AoR should be prescribed by the EPA as part of the regulation. 

Accurate information is difficult to obtain for older wells within the AoR. 

Examples of other information that could be required by the Director should be 

28
clearly stated. 

Individual Response: The final rule retains the language in 146.84(c)(2) as proposed. EPA 

disagrees that the Director should prescribe the corrective action methods to be used. Instead, all 

corrective action must be performed pursuant to the approved AoR and corrective action plan, 

which affords the Director the discretion to review and approve planned corrective action 

techniques and require any additional information needed to ensure that all necessary corrective 

action is performed (e.g., information that is not publically available). EPA is issuing guidance 

on how to identify all wells that require corrective action. The guidance describes EPA's 

recommended approaches for the data to be considered in an initial AoR delineation, how to 

apply computational modeling to delineate the AoR, performing corrective action at GS sites, 

and, when appropriate, completing AoR reevaluations. The guidance will be available on EPA's 

web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA clarifies that any well that penetrates the confining zone, even if it does not extend all the 

way through the confining formation, is to be included in the tabulation. EPA is issuing guidance 

on how to identify all wells that require corrective action. EPA adds that the Director has the 

discretion to require the owner or operator to supplement a data records search, including 

requiring ground or airborne surveys for wells, if there is reason to believe, based on knowledge 

of the site or of available data bases, that the incompleteness of available information could 

compromise USDW protection from endangerment. 

Letter ID: 0210 Comment ID: 22723 Letter Lines: 554 to 558 

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment) 

Comment: §146.86 Injection well construction requirements. (b) (2) "Surface casing must 

extend through the base of the lowermost USDW and be cemented to the surface." 

We recommend striking out this requirement in its entirety. This will be 

prohibitively expensive in deep wells, and may not be necessary at all sites. 

Individual Response: EPA disagrees with the suggested edit. Protection of USDWs, regardless 

of their depth or stratigraphic location, is the primary mission and mandate of the UIC 

program—as specified by Congress in the SDWA—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 a demonstration cannot be made, then the activity will not be allowed 

under UIC requirements or the SDWA. Water agencies commenting on the proposed rule noted 

that diminishing water supplies are requiring water utilities to use deeper and more saline 

sources, and the SDWA mandates EPA to set regulations that protect USDWs from 

endangerment. 

The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the 

lowermost USDW and be cemented to the surface through the use of a single string or multiple 

strings of casing and cement. It does not, however, specify how cementing must be 

29
accomplished, and it allows the owner or operator to propose alternate methods that provide a 

sufficient amount of cement to meet the standard that USDWs are protected from endangerment. 

EPA notes that there are many potential ways to meet the requirement, such as the use of staged 

cementing. 

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. 

Letter ID: 0210 Comment ID: 22724 Letter Lines: 560 to 571 

Comment Code: 4660 2.6.6 Geochemical monitoring 

Comment: §146.90 Testing and monitoring requirements. (d) Periodic monitoring of the 

ground water quality and geochemical changes above the confining zone(s) that 

may be a result of carbon dioxide movement through the confining zone or 

additional identified zones: 

We recommend changing to " Periodic monitoring of the ground water quality and 

geochemical changes between the confining zone(s) and the USDW that may be a 

result of carbon dioxide movement through the confining zone or additional 

identified zones: " 

This rewording is consistent with allowing for injection either above or below 

USDWs 

Individual Response: Regarding monitoring locations, section §146.90(d) requires periodic 

monitoring of the ground water quality and geochemical changes above the confining zone(s). 

EPA clarifies that this monitoring requirement does not include the confining layer itself. 

Monitoring above the confining layer will provide an indication of upward movement of CO2 

that might endanger a USDW. The exact number of formations to be tested must, however, be 

based on site-specific characteristics and vulnerabilities and described in the Director-approved 

testing and monitoring plan. 

Letter ID: 0210 Comment ID: 22725 Letter Lines: 573 to 589 

Comment Code: 4650 2.6.5 CO2 plume and pressure front tracking (seeking comment) 

Comment: §146.90 Testing and monitoring requirements. (g) "Testing and monitoring to 

track the extent of the carbon dioxide plume and the position of the pressure 

front by either monitoring for pressure changes in the first formation overlying 

30
the confining zone or using indirect, geophysical techniques (e.g., seismic, 

electrical, gravity, or electromagnetic surveys and/or down-hole carbon dioxide 

detection tools);" 

We recommend deletion of this requirement in its entirety and replacing with 

"Testing and monitoring to track the extent of the carbon dioxide plume." 

Tracking the precise position of a moving pressure front will require a large 

number of expensive and deeply located probes. A limited number of pressure 

monitors that can provide information on pressures affecting the confinement 

layers are more valuable. The Proposed Rule also requires well owners to monitor 

periodically groundwater quality and geochemical changes above the confining 

zone. The requirements for such deep monitor wells could be costly. Requiring 

both pressure and geochemical monitoring will be costly and provide questionable 

additional information or warning. 

Individual Response: EPA maintains that plume tracking and pressure monitoring are key 

components of monitoring at GS sites. A rigorous plume tracking and pressure monitoring 

scheme, such as one that meets the requirements at §146.90(g), is imperative for ensuring that 

the CO2 plume is contained within the injection zone. Pressure monitoring in the injection zone 

is necessary to track the development and movement of the pressure front and CO2 plume. When 

combined with information on temperature, pressure data provide an indication of the phase 

(e.g., gas, supercritical) and distribution of the injected CO2 (73 FR 43515). Monitoring can also 

identify needed remedial actions, provide inputs for AoR reevaluation modeling, evaluate 

predictions of plume movement, and target additional geochemical and surface monitoring 

needs. 

EPA recognizes that installation of monitoring wells entails additional resources. However, the 

Agency believes that such monitoring is necessary to ensure that GS projects are appropriately 

operated and monitored and to protect USDWs from endangerment. Knowledge of the location 

of the CO2 plume and the associated pressure front will assure the public that GS projects are 

proceeding according to plan, provide sufficient information to the owner or operator and 

Director, or allow for appropriate actions to address any indication that USDWs may be 

endangered. 

Letter ID: 0210 Comment ID: 22726 Letter Lines: 591 to 603 

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: §146.90 Testing and monitoring requirements. (h) "At the Director’s discretion, 

surface air monitoring and/or soil gas monitoring to detect movement of carbon 

dioxide that could endanger a USDW." 

We recommend deletion of this requirement in its entirety. While this 

requirement may be suitable for determining potential air leakage relevant to 

monitoring of CO2 in a greenhouse gas policy context, this requirement does not 

31
provide any additional protection to migration to USDW as surface breakthrough 

will only occur well after the deep-surface migration of CO2 to a USDW. Surface 

monitoring to detect CO2 has high uncertainty and seasonal variability that is 

likely to result in many false positives and operational distractions. Seismic 

methods of tracking the CO2 plume are more effective than soil gas monitoring of 

CO2, which is affected by many other factors and thus is highly variable. 

Individual Response: EPA acknowledges that surface air and soil gas measurements are subject 

to variability and may not be suitable in all settings as a method to ensure USDW protection. 

However, EPA does not believe that this should entirely preclude their use. The decision to use 

surface monitoring and the selection of monitoring methods will be site-specific (e.g., may be 

influenced by geology, injection depth, and operational conditions) and must be based on 

potential risks to USDWs within the AoR. The Agency believes that surface air and soil gas 

monitoring, when coupled with subsurface monitoring, may be appropriate at some GS projects 

to ensure USDW protection. 

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring at the 

discretion of the Director as a means of identifying leaks that may pose a risk to USDWs and 

informing emergency notification of a Class VI owner or operator and UIC Director in the event 

of a USDW endangerment, pursuant to requirements at §146.91(c). EPA clarifies that the 

decision to use surface monitoring and the selection of monitoring methods will be site-specific 

(e.g., may be influenced by geology, injection depth, and operational conditions) and must be 

based on potential risks to USDWs within the AoR. 

Letter ID: 0210 Comment ID: 22727 Letter Lines: 605 to 619 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: §146.93 Post-injection site care and site closure (b)(3) "Prior to authorization 

for site closure, the owner or operator must submit to the Director a 

demonstration, based on monitoring and other site-specific data, that the carbon 

dioxide plume and pressure front have stabilized and that no additional 

monitoring is needed to assure that the geologic sequestration project does not 

pose an endangerment to USDWs." 

Clarification of the term "stabilized" is needed. We recommend that the term 

"stabilized" does not necessarily mean the plume and pressure front are no 

longer moving, but that the rate and direction as defined by confinement zones 

no longer place an USDW at risk. Long-term monitoring should have an "end point" 

defined. Often termed an "exit strategy", this is a key point that is agreed 

upon by all parties about what is a "stable condition". Monitoring data includes 

a prescribed amount of error , thus statistics or other analyses may be required 

to define a "stable condition". 

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 

32
to USDWs. It is for this reason that EPA believes that individual UIC 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 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 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 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: 0210 Comment ID: 22728 Letter Lines: 622 to 626 

Comment Code: 3350 2.2.1.5 Use of proprietary models for GS sites (seeking comment) 

Comment: EPA seeks comment on allowing the use of proprietary models for GS sites. EPA 

Notice 68. 

Proprietary models should be acceptable provided that supporting data for 

validation are submitted. 

Individual Response: EPA agrees with commenters that available proprietary models may meet 

the complex needs for calculating the AoRs of GS sites, and shares their concern about the need 

to evaluate the inputs and assumptions used. EPA will allow the use of proprietary models in 

meeting the requirements for the GS regulation, as long as GS well operators using a proprietary 

model clearly disclose, to the Director's satisfaction, the code assumptions, relevant equations, 

and scientific basis. EPA adds that its Confidential Business Information requirements at 40 CFR 

144.5 will apply to the use of proprietary models. 

In response to comments suggesting that history matching or validation of these models is 

needed, EPA believes this is true for any model. EPA notes that the GS rule requires at 

§146.84(e) that the AoR be reevaluated to verify the CO2 plume is moving as predicted and to 

allow for necessary revisions to the AoR and corrective action, testing and monitoring, injection 

well plugging, post-injection site care and site closure, and emergency and remedial response 

plans. EPA clarifies, however, that the Agency will not perform independent validation of 

individual modeling products. 

33
The Agency plans, every six years, to collect and review data on GS projects to determine 

whether the appropriate amount and types of information and appropriate documentation are 

being collected, and to determine if modifications to the requirements are appropriate or 

necessary. 

Letter ID: 0210 Comment ID: 22729 Letter Lines: 629 to 634 

Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking 

comment) 

Comment: EPA seeks comment on the applicability of computational fluid flow models for 

delineating the AoR of GS sites. EPA Notice 69. 

Computational fluid flow models should be permitted for delineating the AoR of 

GS sites provided also that data are provided supporting their validation in 

similar complex structures and flow regimes 

Individual Response: EPA agrees that a detailed geologic assessment is essential to evaluating 

the presence and adequacy of a proposed site to receive and confine the CO2. The AoR and 

corrective action plan required at §146.84(b) must describe the site characterization data on 

which the model will be based. The Director has discretion to require the use of existing data if it 

is not initially included. 

The Agency believes that predicting the complex multiphase buoyant flow of the CO2, coinjectates, and compounds that may be mobilized due to injection requires the sophistication of 

computational models. Models can predict CO2 fate and transport, as well as changes in 

formation pressure, in three dimensions, as a function of time in order to delineate the subsurface 

storage site and the AoR. Models can account for site-specific and predicted operating conditions 

as well as geologic heterogeneities and potential migration through faults, fractures, and artificial 

penetrations. 

EPA clarifies that the model inputs must include actual geologic information, data collected 

during the site characterization process (e.g., information about artificial penetrations), and 

anticipated operating parameters (e.g., injection rates) submitted with the permit application 

under §146.82. Models will be revised and recalibrated during subsequent AoR reevaluations, 

which must account for all available monitoring and operational data, as required at §146.84(e). 

Letter ID: 0210 Comment ID: 22730 Letter Lines: 637 to 643 

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

Comment: EPA seeks comment on requiring the reevaluation of the site AoR on a periodic 

basis, under what conditions the AoR should be reevaluated, and the 

34
appropriateness of a 10-year minimum fixed frequency for AoR reevaluation. EPA 

Notice 72. 

10 years is a reasonable period of time to reevaluate the site AoR during 

injection. 

Individual Response: Based on evaluation of the public comments on this topic, EPA has 

changed the minimum frequency for the AoR reevaluation at §146.84(e) from 10 years to at least 

every 5 years. EPA believes that this revised frequency addresses concerns raised by commenters 

representing water associations, an energy company, associations, industries, states, and 

environmental groups about the inherent uncertainties in modeling CO2 movement, the emerging 

nature of GS technology, risk-based targeting of monitoring activities, and the unique nature of 

CO2 GS. 

The 5-year reevaluation frequency, particularly during early stages of GS deployment, will also 

support EPA's adaptive approach to the GS rulemaking. EPA is using an adaptive approach to 

regulating GS. The Agency plans, every six years, to collect and review data on GS projects to 

determine whether the appropriate amount and types of information and appropriate 

documentation are being collected, and to determine if modifications to the requirements are 

appropriate or necessary. 

Letter ID: 0210 Comment ID: 22731 Letter Lines: 646 to 653 

Comment Code: 3820 2.3.1 Well construction procedures 

Comment: EPA seeks comment on the proposed GS well requirements for depth of surface 

casing, the cementing of long-string casing, and construction with a packer set 

opposite a cemented interval. EPA Notice 78. 

The requirements for construction of the proposed Class VI CO2 injection wells 

should be similar to the Class II wells used for EOR. This will expedite the 

transition of EOR projects to CCS projects. This requirement also unnecessarily 

stigmatizes CO2. 

Individual Response: EPA recognizes that many early GS projects will be in depleting or 

depleted oil and gas fields and that grandfathering of wells used for ER, where appropriate and 

protective, can facilitate the transition from ER to GS. 

However, EPA believes that injection for the primary purpose of long term storage is sufficiently 

different from Class II ER operations and warrants tailored requirements for Class VI wells at 

§146.86. For example, the volume of CO2 anticipated to be injected in Class VI wells is 

significantly greater than for Class II wells. 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 ER projects. 

35
The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. 

The final GS rule, at §146.81(c), allows the construction of ER wells to be grandfathered, 

provided the owner or operator can demonstrate to the Director that the wells were engineered 

and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu 

of requirements at §146.86(b) and §146.87(a). Only the cemented-in-place construction 

requirements would be grandfathered under the final GS rule; following conversion, these wells 

must be permitted as Class VI wells and be subject to the operational, MIT, monitoring, 

reporting, plugging, and post-injection site care and site closure requirements in the final GS 

rule. 

EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist 

Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI 

transition. The guidance describes the methods available for the Director to determine the risk 

posed to USDWs from a GS/ER project, and how the Director may determine if a project should 

be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's 

web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA disagrees that the construction requirements for Class VI wells will stigmatize CO2. 

Although the requirements are based on the existing regulatory framework for deep wells, 

including Class I wells, EPA believes that GS is sufficiently different from other injection 

operations to warrant the tailored requirements Class VI Class VI wells at §146.86. 

Letter ID: 0210 Comment ID: 22732 Letter Lines: 656 to 662 

Comment Code: 3840 2.3.2 Horizontal well drilling techniques (seeking comment) 

Comment: EPA seeks comment on the merits of horizontal well drilling techniques for GS 

wells and the applicability of well construction requirements discussed in this 

proposal. EPA Notice 80. 

Horizontal wells should be permitted for injection of CO2. The use of horizontal 

wells may minimize the number of wells required for injection. A reduced number 

of wells will reduce both cost and may also reduce potential leakage paths. 

Individual Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In 

the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques 

for Class VI wells, and commenters representing energy companies, electric utilities, the oil and 

36
gas industry, CCS associations, states, and the public, unanimously supported the concept and 

provided many reasons why horizontal wells could be beneficial at GS sites. Based on an 

evaluation of these comments and additional research by EPA, the Agency has concluded that 

horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to 

meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment. 

Letter ID: 0210 Comment ID: 22733 Letter Lines: 665 to 674 

Comment Code: 4120 2.4.1.2 Allowing hydraulic fracturing during GS (seeking comment) 

Comment Code: 4130 2.4.1.3 Appropriateness of using fracturing for well stimulation (seeking 

comment) 

Comment: EPA is requesting comment on the extent and scope to which hydraulic fracturing 

should be allowed during GS injection, and whether the use of fracturing for the 

purposes of well stimulation is appropriate. EPA Notice 85. 

Fracturing of GS formations should be permitted, provided confining structures 

are not negatively impacted and fracturing is limited to the injection zone. 

Exclusion of fracturing of storage formations would often require unnecessary 

drilling of new injection wells. The oil industry has sufficient experience in 

using fracturing technology to avoid negatively impacting confining structures 

(e.g., caprock). 

Individual Response: EPA recognizes that there may be well completions which require 

intermittent treatments that include stimulation to improve wellbore injectivity. Stimulation of 

the injection zone during a well workover will be permissible, if approved by the Director 

(operators seeking to use stimulation must submit the proposed stimulation program as part of 

the permit application under §146.82(a)(9) where injection pressure limits will be set). EPA has 

also added a requirement that owners or operators notify the Director in advance of any planned 

stimulation activities, as specified at §146.91(d). During injection, the injection pressure must 

not exceed 90 percent of the fracture pressure, as specified in §146.88(a). EPA clarifies that the 

injection pressure limit at §146.88(a) applies only to the period of injection, not well stimulation. 

Letter ID: 0210 Comment ID: 22734 Letter Lines: 677 to 684 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth 

Comment: EPA seeks comment on whether the Agency should set a minimum injection depth 

requirement for CO2 GS, rather than require that such injection take place below 

the lowermost USDW. EPA Notice 93. 

EPA should neither require injection below the lowermost USDW nor alternately 

require a minimum depth requirement as geologic structures are likely to be 

37
encountered that provide for secure and safe storage. Examples of such storage 

that should be acceptable are domes and caverns. 

Individual Response: EPA agrees that it is not appropriate to set a minimum injection depth for 

GS projects and the Agency believes that a determination of site-suitability for GS (i.e., that 

subsurface formations will receive and confine injected CO2) should be made on a site-specific 

basis. The GS rule, at §146.82, requires the owner or operator to provide extensive site- and 

project-specific information to the Director to demonstrate that the site meets the minimum site 

criteria at §146.83, that the CO2 will be contained within the injection formation, and that 

USDWs will be protected from endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs, as long as appropriate protections 

are in place. The final GS rule at §146.95 establishes a process by which owners or operators can 

seek a waiver of the Class VI injection depth requirements for injection into non-USDW 

formations above and/or between USDWs. The waiver approach requires the submission of 

extensive, site-specific information (in conjunction with the permit application submission) to 

demonstrate that injection of CO2 into a non-USDW that is above or between USDWs can be 

done in a manner that is protective of USDWs. The requirements are designed to ensure that the 

owner or operator, the Director, and the Regional Administrator consider, on a site specific basis, 

the implications, benefits, and challenges associated with GS and ensuring water availability and 

USDW protection. For additional information on the waiver approach, please see the final rule 

and preamble, as well as EPA's responses to comments on the Notice of Data Availability and 

Request for Comment. 

Letter ID: 0210 Comment ID: 22735 Letter Lines: 687 to 693 

Comment Code: 4490 2.4.5 Use of tracers and potential impact on human health or ecosystems 

(seeking comment) 

Comment: EPA’s proposal allows Directors’ discretion on whether to require the use of 

tracers, and if so, what types of tracers. EPA seeks comment on the use of 

tracers in CO2 GS operations, and any potential impact of tracers on human 

health or ecosystems as they relate to USDWs. EPA Notice 95. 

Tracers should be permitted, but not required. They are commonly and safely used 

in the oil and gas industry. 

Individual Response: EPA agrees that the use of tracers should not be required at all GS sites, 

but should be available as an option. For this reason, EPA does not require the use of tracers at 

all GS sites; however, the Director has discretion to require their use if he/she determines that the 

use of tracers could improve monitoring of the site and enhance USDW protection from 

endangerment. The rule will also allow their use if proposed by the owner or operator and 

approved by the Director. 

38
Letter ID: 0210 Comment ID: 22736 Letter Lines: 696 to 711 

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: EPA seeks comment on the appropriate amount and types of monitoring that should 

be conducted at a GS site. Specifically, EPA seeks comment regarding the 

usefulness of indirect geophysical monitoring and surface air and soil gas 

monitoring. In addition, EPA seeks comment regarding the use of a Directorapproved monitoring plan for GS sites. EPA Notice 111 

Surface air and soil gas monitoring are not useful. Seismic methods of tracking 

the CO2 plume are more effective than soil gas monitoring of CO2, which is 

affected by many other factors and thus is highly variable. Surface breakthrough 

represents an "after-the-fact" event. While this requirement may be suitable for 

determining potential air CO2 leakage relevant to monitoring of CO2 in a GHG 

context, this requirement does not provide any additional protection to 

migration to USDW as surface CO2 breakthrough will only occur well after the 

deep-surface migration of CO2 to a USDW. Surface monitoring to detect CO2 has 

high uncertainty and seasonal variability that is likely to result in many false 

positives, operational distractions and unduly raise public concern. 

Individual Response: EPA agrees that subsurface geochemical and pressure monitoring in the 

subsurface formations are the first line of monitoring that would allow detection of potential 

endangerment to USDWs from GS activities (this is required at all GS sites, as described at 

§146.90(d)). The Agency also believes that surface air and soil gas monitoring, when coupled 

with subsurface monitoring, may be appropriate at some GS projects to ensure USDW 

protection. 

EPA clarifies that surface air and soil gas monitoring are not required at all GS sites. However, 

the GS rule at §146.90(h) gives the Director discretion to require surface air and/or soil gas 

monitoring as a means of identifying leaks that may pose a risk to USDWs and informing 

emergency notification of a Class VI owner or operator and UIC Director in the event of a 

USDW endangerment, pursuant to requirements at §146.91(c). EPA clarifies that the decision to 

use surface monitoring and the selection of monitoring methods will be site-specific (e.g., may 

be influenced by geology, injection depth, and operational conditions) and must be based on 

potential risks to USDWs within the AoR. 

Letter ID: 0210 Comment ID: 22737 Letter Lines: 714 to 725 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: EPA is proposing that permit applications for GS sites include several plans not 

currently required under existing UIC regulations. These plans include a 

monitoring and testing plan, an AoR and corrective action plan, and a post39
injection site care and site closure plan. EPA seeks comment on the merits of 

requiring plans for monitoring, AoR, and post-injection site care as part of a 

permit application. EPA Notice 112. 

We believe that requiring a monitoring plan is reasonable. However, the EPA 

should develop such requirements with recognition of a distinct end to 

operations and monitoring following closure, and consider specific 

representations and codicils that recognize an end of "in-perpetuity" 

responsibility for the operator or owner. 

Individual Response: EPA clarifies that the owner or operator's approved testing and 

monitoring plan and post-injection site care and site closure plan will be incorporated as a 

condition of the UIC permit. GS well operators will be required to perform monitoring pursuant 

to the plans throughout the life of the facility (i.e., the duration of the Class VI permit). EPA adds 

that §146.93(b) requires operators to perform post-injection site monitoring until it can be 

demonstrated that the CO2 and pressure front no longer pose a risk of endangerment to USDWs. 

EPA notes that the post-injection monitoring may be different from monitoring that occurs 

during the operational phase (i.e., as required at §146.90). Once this demonstration is made, site 

closure may be authorized and monitoring is no longer required. EPA adds that owners or 

operators must maintain financial responsibility until site closure has been authorized. 

Please see the final rule and preamble, including the discussion of post-injection site care 

monitoring and financial responsibility for additional information. 

Letter ID: 0210 Comment ID: 22738 Letter Lines: 728 to 733 

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment) 

Comment: EPA seeks comment on the requirement for electronic reporting in its proposed 

rule. EPA Notice 115. 

We recommend that EPA allow electronic reporting as an alternative to hardcopy 

submittals. The benefits are speed, efficiency, reduced cost and burden of 

paperwork, ease of document retrieval, public access, search and storage. 

Individual Response: EPA agrees and believes that electronic formatting is the most appropriate 

format for submitting Class VI project information to the Director, and based on comments 

received on the proposed rule, the majority of Class VI well owners or operators will have the 

capability to report electronically, and requires this at §146.91(e). 

EPA is developing guidance for states that describes the recordkeeping, reporting, and additional 

data management needs associated with GS activities and provides recommended guidelines on 

the types of data to be collected for tracking GS projects, reporting to EPA for compliance 

tracking, and transfer of data to EPA's GS data system. The recordkeeping and reporting 

guidance will be available on EPA's web site, at 

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

40
Letter ID: 0210 Comment ID: 22739 Letter Lines: 736 to 743 

Comment Code: 4750 2.7.5 Comments on the merit of annual reports (seeking comment) 

Comment: Although EPA has not included a requirement for this report in its proposal, EPA 

seeks comment regarding the necessity for such an annual report. EPA Notice 115. 

While reports on status are worthwhile, activity and changes in status are not 

going to be significant on an annual basis. Following a report after the first 

year of operation to ensure that requirements for later reporting are being met, 

once every 10 years coincident with the periods for AoR review should be 

adequate. 

Individual Response: EPA is requiring semi-annual reporting in addition to periodic 

reevaluations of required Class VI projects plans. The final GS rule, at §§146.84(c), 146.90(j), 

and 146.94(d), requires owners or operators to 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. 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. In no case can reviews occur less often than once every five years. EPA adds that it 

has modified the AoR reevaluation frequency in the final rule, from 10 years to 5 years. For 

additional information, please see the final rule and the preamble for a discussion of EPA's final 

approach to AoR and corrective action. 

Letter ID: 0210 Comment ID: 22740 Letter Lines: 746 to 759 

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

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: In addition, EPA seeks comment on whether the Director should be allowed to 

shorten the timeframe based on performance information, and whether EPA should 

require a shorter or longer post injection period if data suggests the time 

frame should be adjusted. EPA Notice 125-26. 

EPA should allow the Director to shorten the timeframe based on performance 

information. However, an open-ended time period results in a high degree of 

uncertainty regarding cost exposure to a project developer. It also leaves a 

site open to future liability from "reopeners" by the regulatory community. To 

avoid this latter scenario, a maximum monitoring period should be defined in 

terms of clear, performance-based risk metrics - for example, that the validated 

model predicts that 95% of the plume is or will be trapped and that a 

sensitivity analysis predicts a comfortable margin of safety and diminimus risk 

of endangerment to any USDWs. 

41
Individual Response: EPA disagrees that the Director should not have discretion to shorten or 

lengthen the post-injection site care monitoring period. Because of the variety of site-specific 

circumstances at GS sites, EPA believes that Directors, in consultation with operators, will be in 

the best position to determine whether additional post-injection site care monitoring is needed (or 

whether the timeframe may be shortened), based on the circumstances of a particular project. 

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

potentially impacted parties to ensure USDW protection. The final GS regulation retains the 

provision that the Director may, at his or her discretion, shorten the post-injection site care 

timeframe if the owner or operator can demonstrate that the GS project does not pose an 

endangerment to USDWs, as specified in §146.93(b)(2). 

Alternatively, the final rule at §146.93(c), also allows the Director to approve an alternative postinjection site care timeframe where an owner or operator can demonstrate during the permitting 

process that an alternative post-injection site care timeframe, other than the 50 year default, is 

appropriate and ensures non-endangerment of USDWs. The demonstration must be based on 

site-specific information, including the results of site-specific computational modeling; the 

predicted timeframe for pressure decline; the predicted rate of carbon dioxide plume migration; 

site-specific chemical processes that will result in carbon dioxide trapping; the predicted rate of 

carbon dioxide trapping; characterization of the confining zone(s); laboratory analyses or studies 

to verify the information on trapping; the presence of potential conduits for fluid movement and 

the quality of abandoned well plugs within the AoR; the distance between the injection zone and 

the USDWs above and/or below the injection zone; and any additional site-specific factors 

determined by the Director. The demonstration must meet the criteria at §146.93(c)(2) for 

ensuring the quality and accuracy of the data and models on which the demonstration is based. 

This demonstration would be submitted as part of the permit application, per §146.82(a)(18), in 

addition to the PISC and site closure plan required at §146.82(a)(17). 

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. 

Letter ID: 0210 Comment ID: 22741 Letter Lines: 762 to 791 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: Current UIC regulations for Class I hazardous waste injection allow for the use 

of insurance for purposes of demonstrating financial responsibility. However, 

insurance was not included as part of the guidance provided for Class II 

injection because this insurance mechanism was and still is, rarely used for the 

purpose of demonstrating financial assurance for injection wells. EPA is 

42
assessing whether to provide guidance on the use of insurance providers and, if 

so, whether to update eligibility requirements for insurers for GS wells 

consistent with other current Federal agency practices. EPA Notice 131. 

The role of insurance needs to be defined and especially, what is being insured 

and for what events and risks. We interpret this as being limited to insurance 

related to decommissioning, plugging of wells and closure of the site. Such 

costs and insurance coverage may change as additional wells are needed or the 

scope of the AoR changes. Absent of Federal or state assumption of long term 

liability, and regulatory clarity on the inapplicability of CERCLA, and events 

and their mitigation, it will be difficult for insurers to provide coverage for 

any more than a limited scope. 

EPA is assessing whether a financial ratings threshold for all companies using a 

self-guarantee, similar to those used by other Federal agencies, is appropriate. 

The Agency also is considering what constitutes an appropriate financial rating 

threshold, and whether a financial rating greater than BBB or Baa (i.e., the 

current rating threshold established under the UIC regulations) is appropriate 

for GS wells. EPA Notice 133. 

Allowing for self-insurance definitely will be helpful to provide another avenue 

for CCS projects to be deployed. However, as we’ve experienced in the recent 

economic crisis, there are no guarantees of financial continuity for either 

insurers or other economic entities. 

Individual Response: EPA will retain self insurance as an option for financial responsibility for 

Class VI wells. EPA believes that if properly used, the financial test can be an appropriate option 

for some owners or operators. EPA recognizes that it is important for self-insurers to be creditworthy, otherwise USDWs may not be adequately protected. Owner or operators who choose to 

self-insure and use the financial test must be able to demonstrate profitability, with a margin 

sufficient to cover contingencies and unknown obligations, and stability. If the owner or operator 

meets corporate financial test criteria, this is an indication that the owner or operator can 

guarantee its ability to satisfy financial obligations based solely on the strength of the company’s 

financial condition. If an operator or operator is not able to meet the corporate financial test 

criteria may arrange a corporate guarantee by demonstrating that its corporate parent meets the 

financial requirements on its behalf. 

Additionally, owners or operators may choose from a variety of financial instruments to meet 

their financial responsibility obligations under the rule, provided the Director determines that the 

operator's proposed financial responsibility demonstration is adequate to protect USDWs from 

endangerment, which means the ability of the owner or operator to pay for each activity for 

which financial responsibility must be demonstrated, including corrective action on wells in the 

AoR, injection well plugging, PISC and site closure, and emergency and remedial response 

throughout the life of the project. The final GS rule specifies at §146.85(a)(1) the permitted types 

of financial responsibility instruments. See the final rule and preamble for further discussion of 

43
EPA's final approach to financial responsibility. 

EPA is developing guidance that describes the types of financial instruments, including 

insurance, that owners or operators can use to meet financial responsibility requirements for 

Class VI wells. The financial responsibility guidance will include considerations for Directors 

regarding how best to evaluate the appropriateness of a specific financial responsibility 

instrument for a given project, such as potential concerns regarding companies with relatively 

small capitalization or the experiences of states in approving self-insurance instruments. The 

guidance will also include consideration of how best to evaluate the appropriateness of a specific 

financial responsibility instrument for a project. This guidance will be available on EPA's 

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

EPA agrees that it is important for the owner or operator to reassess the needs for coverage when 

there are changes at the site. The GS regulation, at §146.85(c), requires the owner or operator to 

provide annual updates to the cost estimate to account for any amendments to the AoR and 

corrective action plan, the injection well plugging plan, the PISC and site closure plan, and the 

emergency and remedial response plan. 

Letter ID: 0210 Comment ID: 22742 Letter Lines: 775 to 778 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: scope of the AoR changes. Absent of Federal or state assumption of long term 

liability, and regulatory clarity on the inapplicability of CERCLA, and events 

and their mitigation, it will be difficult for insurers to provide coverage for 

any more than a limited scope. 

Individual Response: EPA acknowledges the commenter’s concern regarding the applicability 

of multiple statutes to GS projects and the need for a single clear liability regime for owners or 

operators. EPA is working to create a nationally consistent financial responsibility regime within 

its authority to ensure that financial resources are available to protect USDWs throughout the life 

of the GS project. However, the authority under the SDWA does not extend to release owners or 

operators from long-term responsibility for the potential economic costs of impacts unrelated to 

USDWs. EPA does not have authority to transfer liability from one entity to another and SDWA 

does not provide for the creation of a third party financial instrument where EPA is the trustee. In 

the UIC program, liability under SDWA §1423 remains with the owner or operator for all well 

classes until all regulatory requirements have been met. EPA understands that Congress is 

considering legislation that may address the liability issue. 

As described above, whether the presence of hazardous substances in the CO2 may result in 

CERCLA liability from a sequestration facility depends entirely on the composition of the 

specific CO2 stream and the environmental media in which it is stored (e.g., soil or ground 

water). CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain 

“federally permitted releases” (FPR) as defined in CERCLA, 42 U.S.C. 9601(10). Class VI 

permits will need to be carefully structured to ensure that they prevent potential releases from the 

well which are outside the scope of the Class VI permit. Class VI permits will need to be 

44
carefully structured to ensure that they prevent potential releases from the well which are outside 

the scope of the Class VI permit. 

The UIC program Director has authority under SDWA §1423 to address potential compliance 

issues (e.g., potential releases that may endanger USDWs) resulting from injection violations in 

the unlikely event that a remedial response is necessary. Although EPA anticipates that the need 

for emergency or remedial actions at GS sites will be rare, the GS rule requires, at §146.94, that 

emergency and remedial response plans be developed and updated to address such events and 

that owners or operators demonstrate that financial resources are set aside to implement the plans 

if necessary, per §146.85. As described above, once an owner or operator has met all regulatory 

requirements under Part 146 for Class VI wells and the Director has approved site closure 

pursuant to requirements at §146.93, the owner or operator will no longer be subject to 

enforcement under specific sections of the Act as they relate to the UIC regulatory requirements. 

Furthermore, their financial instrument will be released if was not used. However, the Agency 

clarifies that an owner or operator may be held liable, even after site closure is approved under 

§146.93, under §1423 of the SDWA for violating §144.12. 

Letter ID: 0210 Comment ID: 22743 Letter Lines: 794 to 802 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: EPA is requesting comments on whether financial responsibility mechanisms to be 

recommended in EPA guidance should be adjusted in the manner described, whether 

additional instruments should be included, and whether other adjustments to the 

financial responsibility mechanisms should be considered, all subject to EPA’s 

authority under the SDWA. EPA Notice 133. 

EPA needs to consider and define how it will deal with and allow transfer of 

financial responsibility between private entities and also potentially to 

Federal agencies or other sovereign entities such as states or commonwealths. 

Individual Response: Under the final GS rule, once an owner or operator has met all regulatory 

requirements under Part 146 for Class VI wells and the Director has approved site closure 

pursuant to requirements at §146.93, the owner or operator will generally no longer be subject to 

enforcement for regulatory noncompliance. Furthermore, their financial instrument as required 

under §146.85 will be released if it was not used. However, even if a site closure is approved 

under §146.93, an owner or operator may be held liable for regulatory noncompliance (including 

violation of 40 CFR 144.12) in certain circumstances. For example, an owner or operator may be 

held liable for regulatory noncompliance even after site closure was approved if the Director 

relied on erroneous information (e.g., erroneous modeling data) provided by the owner or 

operator when approving site closure. 

Separate from EPA’s authority to enforce regulatory compliance, an owner or operator may be 

subject to a §1431 response order even after proper site closure is approved under §146.93. 

Under §1431 the Administrator may require an owner or operator to take necessary response 

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46

measures if he or she receives information that a contaminant is present or is likely to enter a 

public water system or an USDW, which may present an imminent and substantial endangerment 

to the health of persons, and the appropriate State and local authorities have not acted to protect 

the health of such persons. The action may include issuing administrative orders or commencing 

a civil action for appropriate relief against the owner or operator of a Class VI well. If the owner 

or operator fails to comply with the order, they may be subject to a civil penalty for each day in 

which such violation occurs or failure to comply continues. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

§§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. EPA 

does not have authority to transfer SDWA or other legal liability for Class VI wells to the State 

or federal government or a third-party fund. See the final rule preamble for further discussion of 

EPA's final approach.