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individual response. These are described and explained below.  

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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.
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: 

__ n Fr. 0 120 0 8 

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

EPA's Proposed Rule for Geologic Storage of COZ (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, COZ 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 COZ 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 C02 

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

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

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

Page 1 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 COZ specifically intended for geologic 

storage from the definition of RCRA hazardous waste. 

2. EPA must emphatically conclude that COZ 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 . COZ 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 COZ 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 1) 

In the preamble to the ANPR, EPA poses the question of whether injected COZ 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 COZ sequestration projects . 

Page 2 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 COZ as a result of the carbon capture process should 

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

diminimus risk of exposure associated with the disposition of C02 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 C02 -- 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 COZ that may be 

injected in Class VI wells, the C02 streams trigger none of the RCRA hazardous waste 

criteria . Specifically, captured C02 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 C02 stream. In any event, the level of trace contaminants in the COZ is so low that 

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

Next, the COZ stream is not "reactive," since the injected COZ 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 COZ 

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 11 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 C02 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 COZ in a supercritical state is approximately 2,500 feet . This, in 

Page 3 of 16 
conjunction with the controls and safeguards required by this rule throughout the 

injection and post-injection period, will ensure that COZ 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 HZS 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 (uV to 68%) of HZS in COZ are being injected into 

saline aquifers or producing oilfields 'Z'3 for disposal purposes. These combined gas 

streams of HZS and COZ 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 operations4. 

Accordingly, EPA has sufficient information now to conclude that captured COZ 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 

COZ 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 C02 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 C02 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 4 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 COZ portion of the stream and 

explicitly exclude any trace contaminants . 

By its inherent nature, gasification will provide a stream of >90% COZ 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 °F) 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 COZ 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 COZ 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 C02. 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 5 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 C02 

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 COZ 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 C02 from the generator to the 

site operator . 

Concern #7. EPA is considering a guidance approach that would recommend adonting 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 6 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, 

COZ 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 7 of 16 
years as a considerable quantity of COZ remains underground during such operations . 

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

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

existing Class 1, Class 11, 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 CO,. (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 COZ 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. 

James Childress 

Executive Director 

;Gasification Technologies Council 

Page 8 of 16 
References 

' 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 C02 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 

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Letter ID: 0158 

Commenter: James Childress 

Organization: Gasification Technologies Council (GTC) 

Letter ID: 0158 Comment ID: 23754 Letter Lines: 50 to 57 

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

Comment Code: 1410 1.2.1 Comments in support of EPA/rulemaking 

Comment: 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. 

Individual Response: While EPA agrees with commenters that a stable, predictable, nationally 

consistent, and workable regulatory framework is important, EPA stresses that the focus of the 

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

from endangerment. 

EPA agrees that an adaptive and flexible approach is appropriate. To protect USDWs from 

endangerment and meet the potentially fast pace of GS deployment, EPA is using an adaptive 

approach to regulating CO2 injection for GS. 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. An adaptive approach will allow regulatory 

development to proceed in time to meet the current and future demands for Class VI permits 

while EPA continues to gather data from pilot projects and other research as it becomes 

available. 

Letter ID: 0158 Comment ID: 23755 Letter Lines: 59 to 104 

Comment Code: 1380 1.1.3.6 Deployment of GS 

Comment: 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. These are 

our principal concerns with the draft regulation: 

1
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. 

Individual Response: The purpose of the Class VI GS regulation is to ensure consistency in 

permitting underground injection of CO2 at GS operations across the United States and provide 

requirements to prevent endangerment of USDWs in anticipation of the eventual use of GS to 

reduce CO2 emissions. The UIC program’s authority under SDWA is focused on ensuring that 

GS projects are sited, constructed, operated, monitored, and closed in a manner that is protective 

of USDWs. EPA adds that setting a value for CO2 (i.e., a price per ton) is outside of the scope of 

the Class VI GS rulemaking. 

2
EPA acknowledges that GS falls within the broader context of CCS and the need for regulatory 

clarity to ensure that USDWs are protected from endangerment. In developing the final GS rule, 

the Office of Water coordinated with other Agency program offices and across federal agencies 

(e.g., with the Department of Energy; United States Geological Survey; Bureau of Ocean Energy 

Management, Regulation, and Enforcement, formerly the Minerals Management Service; Bureau 

of Land Management). The Agency continues to evaluate areas of potential applicability of other 

Federal environmental statutes including, but not limited to: the Clean Air Act; the Resource 

Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, 

and Liability Act; and the Marine Protection, Research and Sanctuaries Act to various aspects of 

GS and CCS. The Agency will continue to coordinate on GS and CCS related issues to minimize 

redundancy and maximize efficiencies for owners or operators. For additional information, 

please see the discussion entitled "How Does This Rulemaking Relate to Other Federal 

Authorities and GS and CCS Activities?" in the preamble to the final GS rule. 

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: 0158 Comment ID: 23756 Letter Lines: 110 to 204 ; 424 to 440 

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

Comment: #1: Potential Applicability of CFR40 Part 261 (RCRA). (Ref: page 43503, Section 

1) 

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 di minimus 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 of40 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 

3
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 

maybe 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 May8, 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 

4
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 ofH2S from these operations[4]. 

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 

5
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: 0158 Comment ID: 23757 Letter Lines: 206 to 243 

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)). 

6
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. 

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 °F) 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: The Agency thanks the commenter for their detailed comments regarding 

the scope and possible impacts of CERCLA liability on CCS activities, and in particular 

comments related to the CERCLA exemption for federally-permitted releases. EPA notes that 

the GS rule is not promulgated under CERCLA, therefore the applicability of that statute will not 

be determined under the SDWA or the terms of the GS rule, but rather according to the 

CERCLA statute itself and any implementing regulations that may apply. To the extent the 

commenter is seeking interpretations of RCRA or CERCLA, such interpretations are beyond the 

scope of this rulemaking. 

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, 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: 0158 Comment ID: 23758 Letter Lines: 245 to 267 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

7
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 

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. 

Individual Response: Again, the Agency thanks the commenter for their detailed comments 

regarding the scope and possible impacts of CERCLA liability on CCS activities, and in 

particular comments related to the CERCLA exemption for federally-permitted releases. EPA 

notes that the GS rule is not promulgated under CERCLA, therefore the applicability of that 

statute will not be determined under the SDWA or the terms of the GS rule, but rather according 

to the CERCLA statute itself and any implementing regulations that may apply. Additionally, 

comments related to permitting under the CAA are outside the scope of this rulemaking. 

Letter ID: 0158 Comment ID: 23759 Letter Lines: 269 to 287 

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 43505, 

1Proposed 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 

8
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 retains the requirement to identify additional containment/confining 

zones, if required by the Director, as proposed (§146.83(b)). EPA acknowledges that such 

additional zones may not be needed in all circumstances, and clarifies that this requirement is at 

the Director's discretion, based on his or her understanding of a particular site. 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. The Agency's decision is supported 

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

these requirements promote a flexible, risk-based, site-specific approach to characterizing and 

permitting a site for GS projects, and are intended to improve understanding of the project as a 

whole and promote better modeling of the site. 

Letter ID: 0158 Comment ID: 23760 Letter Lines: 289 to 301 

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 

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). 

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 

9
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. It 

establishes: 1) requirements specifying information that owners or operators must submit, and 

Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of 

a waiver application and for Director-Regional Administrator communication; 3) the waiver 

issuance process; and, 4) additional requirements that apply to owners or operators of Class VI 

wells granted a waiver of the injection depth requirements to ensure USDW protection above and 

below the injection zone. 

While the Agency acknowledges the experience gained by the oil and gas industry and other 

injection activities, EPA identified unique challenges posed by large-scale GS including large 

injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the 

potential presence of impurities in captured CO2, and its mobility within subsurface geologic 

formations that warrant the tailored approach in the GS rule. Furthermore, the Agency believes 

that wells that inject into non-USDW formations above and between USDWs presents additional 

challenges that warrant additional requirements. 

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: 0158 Comment ID: 23761 Letter Lines: 303 to 319 ; 442 to 444 

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

CFR 146.85) 

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

comment) 

Comment: 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 open-ended 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. 

10
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. 

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 

11
and the site closure has been approved 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: 0158 Comment ID: 23762 Letter Lines: 321 to 335 ; 442 to 444 

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 

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 

12
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). 

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 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 so that the financial 

benefits to the owner or operator of a longer pay-in period are balanced with the increased 

financial risk to the public. EPA adds that owners or operators may choose from a variety of 

financial instruments to meet their financial responsibility needs. 

Letter ID: 0158 Comment ID: 23763 Letter Lines: 337 to 353 

Comment Code: 5240 2.8.2.2 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. 

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 final GS regulation 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 PISC period based on site-specific data, pursuant to 

13
requirements at §146.93(b); or (2) affording the Director discretion to allow a Class VI well 

owner or operator to demonstrate, based on substantial data during the permitting process, that an 

alternative PISC timeframe may be appropriate if it ensures non-endangerment of USDWs 

pursuant to requirements at §146.93(c). 

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

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

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

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

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

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

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

impacts. 

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

for post-injection site care is necessary in most cases. A 50 year post-injection site care 

timeframe represents a reasonable and protective monitoring period for most GS sites 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, EPA believes 

that 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. However, EPA recognizes that alternative timeframes may be appropriate under 

limited, specific circumstances, which is why EPA is providing the Director discretion to 

approve an alternative post-injection site care timeframe as long as the owner or operator can 

meet the requirements provided at §146.93(c). 

Letter ID: 0158 Comment ID: 23764 Letter Lines: 355 to 370 

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

Comment: 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 

14
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 recognizes the importance of consistency in state regulations. Under 

Section 1421 of the SDWA, EPA is responsible for the development of minimum federal 

requirements for underground injection wells to ensure protection of USDWs from 

endangerment. In order to receive primacy the States, Tribes, and Territories must then 

demonstrate that their programs are at least as stringent as the minimum Federal requirements, 

which helps to ensure consistency between State UIC programs. The Agency acknowledges that 

Section 1422 of the SDWA provides that States, Tribes and Territories may develop 

requirements that are more stringent than the federal requirements –for Class VI GS and other 

UIC well classes. 

Furthermore, EPA believes that it is appropriate to allow Director's discretion, given the variety 

of geologic settings even within each State in which GS will be applied. The Agency believes 

that the GS rule balances the need for these site-specific decisions with the need for minimum 

standards to ensure national consistency. 

When a State applies for Class VI Primacy, it must demonstrate that it has sufficient and 

appropriate technical capacity (e.g., personnel, infrastructure, technical expertise) to implement a 

Class VI program that meets EPA's minimum requirements. EPA is developing guidance 

materials and plans to conduct on-line and in-person training for States, Tribes, and Territories 

that describe the process of applying for and receiving primary enforcement responsibility 

(primacy) for GS Class VI wells under Section 1422 of SDWA, as well as the technical and 

administrative issues on developing GS regulations that are the equivalent of minimum federal 

criteria and requirements. The guidance will be available at 

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

Letter ID: 0158 Comment ID: 23765 Letter Lines: 372 to 385 

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 

15
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: 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. The Agency believes that establishing a regulatory 

framework for the future development and deployment of CCS technology may provide the 

regulatory and jurisdictional certainty needed to foster development and deployment of CCS 

while ensuring USDW protection. However, this is not the purpose of the rule and the comment 

is outside the scope of the rulemaking. 

Regarding the comment that Class VI requirements will reduce the number of available target 

formations where CO2 can be stored, EPA reiterates that the regulation is meant to ensure that 

proposed sites are suitable for safely injecting, and confining CO2, and avoid sites not suited for 

GS. EPA notes the final GS rule contains a provision at §146.95 for owners or operators the 

ability to apply for waivers from the requirement that injection takes place below the lowermost 

USDW. EPA believes this waiver provision will reduce potential limitations on the re-permitting 

of Class II wells as Class VI wells, provided they meet the requirements at §146.95 while still 

protecting USDWs from endangerment. 

Letter ID: 0158 Comment ID: 23766 Letter Lines: 387 to 400 

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 ofCO2. (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). 

16
Individual Response: EPA agrees that many Class I, Class II, and Class V experimental 

technology wells are designed and constructed to withstand exposure to CO2. The final GS rule 

provides for the construction of these wells to be grandfathered per §146.81(c), 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). EPA clarifies that only the construction requirements are 

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

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

EPA disagrees with commenters who suggest that other requirements (e.g., MITs, siting, 

monitoring, operational, and AoR requirements) should also be grandfathered. Following repermitting 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 would 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. 

Letter ID: 0158 Comment ID: 23767 Letter Lines: 402 to 415 

Comment Code: 1200 1.1 General comments about the rulemaking 

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. 

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

GS rule. 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. 

17
Letter ID: 0158 Comment ID: 23768 Letter Lines: 448 to 457 

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

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 longterm containment of a gaseous, liquid or supercritical carbon dioxide stream in 

subsurface geologic formations." 

We recommend striking out "gaseous, liquid or supercritical carbon dioxide 

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 change. EPA believes that this 

paragraph, along with the definition of a CO2 stream at §146.81(d), appropriately convey the 

allowable injection activities that may be permitted as Class VI. For additional information on 

EPA's final regulatory approach, please see the final rule and preamble as well as the rulemaking 

docket. 

Letter ID: 0158 Comment ID: 23769 Letter Lines: 460 to 474 

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

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). 

Individual Response: EPA believes that a determination about whether or what information 

may be necessary (for a specific GS project) is outside of the public record will be site-specific 

and based on knowledge of the site, data availability, and data quality. For instance, in meeting 

18
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: 0158 Comment ID: 23770 Letter Lines: 477 to 489 

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

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82) 

Comment: §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. 

Individual Response: The Agency believes that the requirement to provide a tabulation of wells 

and geologic information (at §146.82(a)), along with a description of each well's type, 

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

appropriately inform a determination of the risk associated with wells in the AoR. EPA believes 

that it is important to have information on all wells in the AoR. 

Letter ID: 0158 Comment ID: 23771 Letter Lines: 492 to 512 

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

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 protected 

19
lateral and vertical migration of the carbon dioxide plume" and replacing with 

"Using computational modeling, provide protected 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 

"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. 

20
Letter ID: 0158 Comment ID: 23772 Letter Lines: 515 to 531 

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

Comment Code: 3440 2.2.2.2 Evaluation of wells in the AoR (e.g., types of data to be 

reviewed) 

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 clearly 

stated. 

Individual Response: EPA is retaining the language in §146.84(c)(2) as proposed. Based on its 

evaluation of all public comments and input on the proposed rule and NODA and Request for 

Comment, EPA has made many other revisions to the GS Rule. See the final rule and preamble 

for further discussion on EPA's final approach. 

EPA acknowledges that public records may not contain data on every artificial penetration in the 

AoR (or all of the data on each well that is required for the tabulation), particularly in areas with 

many older wells. However, the Agency recognizes that there may be situations where additional 

surveys or research to locate information on wells may be appropriate. For example, there may 

be cases where the Director may determine that ground or airborne surveys for wells are 

appropriate, e.g., if there is reason to believe that the incompleteness of information on known 

wells could compromise USDW protection from endangerment. In order to preserve the 

Director's discretion to require an operator to supplement a records search, EPA did not make the 

suggested change. EPA adds that all corrective action must be performed pursuant to the 

approved AoR and corrective action plan, which affords the Director the discretion to require 

any additional information needed (including information that may not be publically available) to 

ensure that all necessary corrective action is performed. 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 

21
Letter ID: 0158 Comment ID: 23773 Letter Lines: 534 to 538 

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

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 that protecting deep USDWs underlying multiple, more 

shallow USDWs is unnecessary. 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 

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: 0158 Comment ID: 23774 Letter Lines: 541 to 550 

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

Comment Code: 4400 2.4.4.3 Allowing injection above or between USDWs (seeking comment) 

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 

22
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: EPA disagrees that the GS rule should specify the zones to be monitored. 

EPA clarifies that §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 will, however, be based on site-specific characteristics and vulnerabilities 

and described in the Director-approved testing and monitoring plan. 

EPA is developing guidance on testing and monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

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

In the final GS rule, owners or operators granted injection depth waivers are subject to additional 

requirements at §146.95(f)(3) to monitor above and below the injection zone in order to ensure 

protection of USDWs underlying and overlying the injection zone during both well operation 

and the post-injection site care period. 

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: 0158 Comment ID: 23775 Letter Lines: 553 to 569 

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

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 

the confining zone or using indirect, geophysical techniques (e.g., seismic, 

electrical, gravity, or electromagnetic surveys and/or down-hole carbon dioxide 

detection tools); - 

23
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. 

The final rule (at §146.90(g)) requires owners or operators to perform monitoring to track the 

extent of the CO2 plume and pressure front. The owner or operator must use direct methods to 

monitor for pressure changes in the injection zone. Indirect methods (e.g., seismic, electrical, 

gravity, or electromagnetic surveys and/or down-hole CO2 detection tools) are also required 

unless the Director determines, based on site-specific geology, that such methods are not 

appropriate 

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. EPA believes that pressure 

monitoring in the injection zone is necessary to track the development and movement of the 

pressure front and CO2 plume. 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. 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. 

The combination of site characterization and predictive modeling will help guide the siting of 

monitoring wells and enable operators to optimize the number and position of wells. The 

Director-approved testing and monitoring plan will describe the use and installation of 

monitoring wells at the site. 

24
EPA acknowledges the commenters' concern about the cost of pressure monitoring. However, 

EPA believes that this monitoring is essential for protection of USDWs at GS sites Although a 

significant cost in absolute terms, monitoring costs are expected to be a small fraction of site 

operating costs, according to EPA's cost analysis for the GS rulemaking (which is available in 

the docket). 

Letter ID: 0158 Comment ID: 23776 Letter Lines: 572 to 585 

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

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: §146.90 Testing and monitoring requirements. (71) "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 

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. 

25
Letter ID: 0158 Comment ID: 23777 Letter Lines: 587 to 601 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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 

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: 0158 Comment ID: 23778 Letter Lines: 605 to 609 

Comment Code: 3350 2.2.1.5 Use of proprietary models for GS sites (seeking comment) 

26
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. 

Letter ID: 0158 Comment ID: 23779 Letter Lines: 612 to 617 

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. EPA encourages 

owners and operators to submit (and Directors to review) any available data on the site, such as 

seismic or off-set well data. 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. Furthermore, the owner 

or operator's testing and monitoring plan required at §146.90 should provide for site-specific data 

(which may include seismic and direct measurements) that can be used to inform updates to the 

model and support AoR reevaluations. 

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 

27
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: 0158 Comment ID: 23780 Letter Lines: 620 to 626 

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 

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: 0158 Comment ID: 23781 Letter Lines: 629 to 636 

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 

28
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. 

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 will be grandfathered under the final GS rule; following conversion, these wells 

will 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 GS. 

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 for Class VI wells at §146.86. 

Letter ID: 0158 Comment ID: 23782 Letter Lines: 639 to 645 

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 

29
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 

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: 0158 Comment ID: 23783 Letter Lines: 648 to 657 

Comment Code: 4120 2.4.1.2 Allowing hydraulic fracturing during GS (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: 0158 Comment ID: 23784 Letter Lines: 660 to 667 

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 

30
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 

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: 0158 Comment ID: 23785 Letter Lines: 670 to 676 

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 tracer use is not appropriate in all situations. 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 

31
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. 

Letter ID: 0158 Comment ID: 23786 Letter Lines: 679 to 694 

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 clarifies 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. 

EPA acknowledges that air and soil gas monitoring 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, 

32
injection depth, and operational conditions) and must be based on potential risks to USDWs 

within the AoR. 

Letter ID: 0158 Comment ID: 23787 Letter Lines: 697 to 708 

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 postinjection 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 Class VI permit. Class VI 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. 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: 0158 Comment ID: 23788 Letter Lines: 711 to 716 

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. 

33
Individual Response: EPA believes that electronic formatting is the most appropriate format for 

submitting Class VI project information to the Director, and that, 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. 

Letter ID: 0158 Comment ID: 23789 Letter Lines: 719 to 726 

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: The final GS regulation retains the reporting requirements as proposed, 

which does not include a requirement for an annual report. Instead, EPA believes that periodic 

reevaluation of the AoR, as required at §146.84(e), along with any revisions to the required plans 

that may be necessary based on the AoR reevaluation, will promote an ongoing relationship 

between the permitting authority and the owner or operator. 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. For 

additional information, please see the final rule and the preamble for a discussion of EPA's final 

approach to recordkeeping and reporting. 

While the Agency recognizes some concerns expressed by commenters about the burden 

associated with an annual report, the Agency's decision to retain the semi-annual reporting 

requirement at §146.91(a) is because the semi-annual report in conjunction with the continued 

dialogue associated with AoR reevaluations and periodic updates to the plans is a preferred 

approach to an annual report. 

34
EPA encourages and expects owners and operators to share monitoring and operating data with 

the public voluntarily (e.g., through the Internet), however. Providing the public with 

information throughout the Class VI project will help clear up and avoid public misperceptions 

about the nature and safety of GS. 

Letter ID: 0158 Comment ID: 23790 Letter Lines: 729 to 742 

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. 

Individual Response: EPA disagrees that the Director should not have discretion to shorten or 

lengthen the post-injection site care monitoring period or that it creates a “high degree of 

uncertainty regarding cost exposure.” Because of the variety of site-specific circumstances at GS 

sites, EPA believes that individual UIC 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. 

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. 

35
Letter ID: 0158 Comment ID: 23791 Letter Lines: 745 to 761 

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 

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. 

Individual Response: EPA clarifies that owners or operators must demonstrate and maintain 

financial responsibility for corrective action on wells in the AoR, injection well plugging, PISC 

and site closure, and emergency and remedial response for Class VI wells, as specified at 

§146.85(a). Owners or operators may choose a combination of instruments, including insurance, 

for various GS activities for purposes of meeting their regulatory obligations under §146.85. 

EPA agrees that it is important for insurance terms to be clear and for that reason requires 

owners or operators 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. 

Furthermore, 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 guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) will include considerations 

of how to evaluate the appropriateness of a specific financial responsibility instrument for a 

project. 

Letter ID: 0158 Comment ID: 23792 Letter Lines: 764 to 774 

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

36
CFR 146.85) 

Comment: 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 believes that the GS rule provides a flexible approach for financial 

responsibility. Under the final GS rule 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)). 

EPA is developing guidance that describes the types of financial instruments, including self 

insurance, which owners or operators may choose to use to meet financial responsibility 

requirements for Class VI wells. EPA recognizes that there are some concerns about the use of 

self insurance, including those mentioned by the commenters. The financial responsibility 

guidance will include considerations for Directors regarding how 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 is available on EPA's website at 

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

EPA acknowledges the commenter's concern regarding the current economic crisis, but notes 

that such unpredictable events are outside of the scope of this rulemaking and the Agency's 

control or authority. 

Letter ID: 0158 Comment ID: 23793 Letter Lines: 777 to 785 

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 

37
38

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 

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. Please 

note that EPA does not have authority under SDWA 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.